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~0080306-0053

FERC

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(Unofficial)

03/06/2008

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SAN DIEGO
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BOSTON
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The Honorable Kimberly D. Bose
Secretary
Federal Energy Regulatory Commission
888 First Street, NE, Room 1A
Washington, DC 20426
Re:

PIUNCM-ION
LAKE TANOE
HO CIg M ~ C/I"Y

Midwest Independent Transmission System Operator, Inc., and Transmission
Owners of the Midwest Independent Transmission System Operator, Inc.
Revisions to Open Aeeess Transmission and Energy Markets Tariffto Implement
the Midwest ISO's Western Markets Proposal
Docket No. E R ~

Dear Secretary Bose:
Pursuant to Section 205 of the Federal Power Act ("FPA"), 16 U.S.C. § 824d, and Part 35
of the regulations of the Federal Energy Regulatory Commission ("FERC" or "Commission"),
18 C.F.R. § 35.1 et seq. (2007), the Midwest Independent Transmission System Operator, Inc.
("Midwest ISO") submits for filing six copies of proposed revisions to its Open Access
Transmission and Energy Markets Tariff ("EMT" or "Tariff') to expand its Energy and

Operafmg Reserve Markets. l The proposed changes will enhance reliability and "seams"
coordination in the Midwest and will permit closer integration of members of the Mid-Continent
Area Power Pool ("MAPP") and other utilities and market participants in the region into the

Midwest ISO's Energy and Operating Reserves Markets. 2
The Midwest ISO proposes an effective date of June 1, 2008, for this filing. As fmlher
discussed in Part VI of this transmittal letter, the Midwest ISO Transmission Owners ("Midwest
ISO Transmission Owners" or "Transmission Owners")3 possess the exclusive filing rights under
i
2
3

The caphalized terms that are not otherwise defined herein shall have the meaning as set forth in the Teriffor
the revisions thereto proposed in this or other pending proceedings.
This filing letter and the attached testimony refer to the Midwest ISO'E submission in the instant proceeding as
the "Western Markets Proposal."
For purposes of this filing, the Midwest ]SO Transmission Owners include: American Transmission Systems,
Incorporated, a subsidiary of F i r s t ~
Corp.; Duke Energy Shared Services for Duke Energy Ohio, Inc.,
Duke Energy Indiana, Inc., and Duke Energy Kentucky, Inc.; Hoosier Energy Rural Electric Cooperative, inc.;

D U A N E M O R R I S LuP
SOS 9"PrlSTREET. N W., SUITE ]000

W A S H I N G T O N , D C 20004-2166

PHONE: 202 ??6?| 00

FAX: 202 "/76 7|01

~0080306-0053

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DuaneM_orris
The Hon. Kimberly D. Bose
March 4, 2008
Page 2
Appendix K of the ISO Agreement4 with respect to certain rate aspects of the Western Markets
Proposal. To the extent these filing rights ate implicated, the Midwest ISO Transmission
Owners join the Midwest ISO in this submission, s
!.

EXECUTIVE SUMMARY

Since its creation, the Midwest ISO has sought to extend its services and scope to utilities
located in the upper and western regions of the Midwest through the provision of reliable and
elTlcient system operations. Unlike other regional transmission organizations ("RTOs") that
were formed on the basis of"fight" power pools, with long histories of regional cooperation and
centralized dispatch, the Midwest ISO has faced unique challenges in building a successful
regional energy market virtually from scratch. One such challenge has been to create the
demand for the Midwest ISO's services and markets by transmission providers that are not yet
ready to transfer their facilities under the Midwest ISO's functional control.
Although some of the utilities in the upper Midwest joined the Midwest ISO as
Transmission Owners, many have declined to do so for a variely of reasons and remain unwilling
or unable to take that step in the foreseeable future.6 When approved by the Commission, the
Western Markets Proposal will enable the Midwest ISO to provide enhanced reliability and
"seams" management services on a broader, uniform basis, not only to parties in the MAPP
region but also to other eligible customers. In addition, several MAPP parties and other
interested entities that are not signatories to the ISO Agreement have concluded that the Midwest
ISO's Energy and Operating Reserve Markets may provide substantial benefits to them in the
event of their closer integration with the Midwest ISO. The Locational Marginal Price ("LMP")congestion management mechanisms and the efficient Security Constrained Economic
Dispatch ("SCED') utilized in the Midwest ISO are of particular value to these customers, who
Manitoba Hydro; Michigan Public Power Agency; Minnesota Power (and its subsidiary Superior Water, L&P);
Montana-Dakota Utilities Co.; Notlbern Indiana Public Servioe Company; Northern SUResPower Company, a
Minnesota corporation, and Nordiem Stat~ Power Company, a Wisco~in cotpocation, subsidiaries of Xcel
Energy Inc.; Northwe~ern Wisconsin Electric Company; Otter Tall Power Company: Southern Illinois Power
Cooperative; Southern Indiana Gas & Elec~ic Company (d/b/a Vectren Energy Delivery of Indlana); Southern
Minnesota Municipal Power Agency; and Wabash Valley Power Assnciation, Inc.
The full name of the ISO Agreement is the Agreement of Transmission Facilities Owners to Organize the
Midwest Independent Transmission System Operator, Inc., a Delaware Non-Stock Corporat/on. The ISO
Agreement is on file with the Commission as Midw~t ISO FERC Electric Tariff, First Revised Rate Schedule
No. 1.
Specifically, the Midwest ISO Transmission Owners join this submission solely to file Schedule 32 (Market
Integration Transmission Service). The Midwest ISO Transmission Owners' support for Schedule 32 does not
necessarily indicate support by each individual Transmission Owner for the entire filing. The Transmission
Owners reserve the right to intervene and comment on the filing.
In MAPP, these transmission providers were parties to various lariff administration, reliability, and "seams"
management agreements with the Midwest ISO, which expired on February l, 2008. Pending finalization and
review of the Western Markets Proposal, the "seams" agreement has been extended on an interim basis and a
new short term agreement to provide reliability coordination has been implemented, so that the Midwest [SO
can continue providing these services to the MAPP region during the intervening period.

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The Hon. Kimberly D. Bose
March 4, 2008
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currently have to rely on far less efficient Transmission Loading Relief ("TLR") procedures to
manage congestion.
The Western Markets Proposal represents a break-through that extends the benefits of the
Midwest ISO's Energy and Operating Reserve Markets to a potentially large group of new
customers while allowing them to remain transmission providers in their own footprints, thereby
removing the principal obstacle to their fuller participation in the Midwest ISO. The Western
Markets Proposal allows these entities and their customers to utilize the existing reliability

services and offers market-to-non-market "seams" coordination service in a form that includes
the opportunity to redispatch generation as an economic alternative to TLRs. It also extends the
reach and benefits of the Midwest ISO's Energy and Operating Reserve Markets to footprints of
other transmission providers.
The core of the Western Markets Proposal is contained in a new Module F of the Tariff,
which has three major parts that correspond to the three types of Coordination Services proposed
in this filing: (1) Reliability Coordination Service; (2) Interconnected Operations and Congestion
Management Service; and (3) Market Coordination Service. While these Coordination Services
are discussed in detail below, as well as the supporting testimony, they can be briefly
summarized as follows:
Reliability Coordination Service. Part I of proposed Module F addresses
Reliability Coordination Service. This is the same reliability coord'matiun service
that the Midwest ISO currently provides to its Transmission Owners and to
MAPP members, and it is now extended to all eligible customers. To be eligible,
a customer must be a NERC-Registered Balancing Authority or NERCRegistered Transmission Operator. Because the Transmission Owners already
receive comparable reliability coordination services from the Midwest ISO
pursuant to the ISO Agreement and other Modules of the Tariff, they will not be
eligible for Reliability Coordination Service as long as they remain signatories to
the ISO Agreement. Reliability Coordination Service may be taken as a "standalone" service or in combination with Interconnected Operations and Congestion
Management Service under Part II ofModule F. A Market Coordination
Customer taking service under Part IIl of Module F is required to take Reliability
Coordination Service.
Interconnected Operations and Congestion Management Servic(~. Part II of
proposed Module F ad(L-essesInterconnected Operations and Congestion
Management Service. This service is intended to/hake available to all eligible
customers the Midwest ISO's "seams" coordination services that are currently
provided under individual "seams" coordination or joint operation agreements. 7
7

The MidwestISO has a numberof FERC-approved"seams"coordinatio~agreementswithneighboring
systems, including MAPP. Generally, these agreements provide a mechanism to mansge marke~..to-non-market

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DuaneMorris
The Hon. Kimberly D. Bose
March 4, 2008
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Importantly, the proposed Interconnected Operations and Congestion
Management Service adds the option for redispatch of generation by the Midwest
ISO or the non-market entity if that is economically superior to curtailment or
other re.dispatch to meet a TLR obligation. To be eligible to receive
Interconnected Operations and Congestion Management Service, a customer must
be a NERC-Registered Transmission Provider providing service pursuant to an
open access ~-ansmission tariff or other similar tariff over ~ansmission facilities
that are interconnected with the Midwest ISO's Transmission System or with the
facilities of a Market Coord'mation Customer taking service under Part 111 of
Module F. Interconnected Operations and Congestion Management Service may
be taken as a stand-alone service or in combination with Reliability Coordination
Service under Part 1 of Module F, but may not be combined with Market
Coordination Service under Part Ill of Module F. A Congestion Management
Customer may not be a signatory to the ISO Agreement.
Market Coordination Service. Part IIl of proposed Module F addresses Market
Coordination Service. This service extends the Midwest ISO's Energy and
Operating Reserve Markets to the footprints of Market Coordination Customers
by allowing them to integrate into the Midwest ISO's Energy and Operating
Reserve Markets resources and loads interconnected with their designated
transmission facilities while retaining the functional control of their transmission
grid. To be eligible to receive Market Coordination Service, a customer must be a
transmission provider providing transmission service on facilities that are: (i)
interconnected with the facilities of a Transmission Owner; (ii) interconnected
with the facilities of another Market Coordination Customer; or (iii)
interconnected with the facilities of a Congestion Management Customer that
offers a transmission service that is adequate to enable the Midwest ISO to
provide the SCED. A Market Coordination Customer cannot be a signatory Io the
ISO Agreement and must take Reliability Coordination Service under Part I of
Module F concurrently with its Part Ill service.
To complement Module F, certain additional Tariffrevisions are proposed in this filing.
By way o f summary, these revisions include: three proforma serviceagreements corresponding
to each type o f Coordination Services, Tariff Schedules providing the necessary mechanisms for
determination of charges under Parts I and III of Module F, the standard CMP to be used in
connection with the provision of service under Part H o f Module F, and certain proforma
transmission service provisions that must be included in Market Coordination Customer
transmission tariffs to enable the Midwest ISO to provide service under Part 111 of Module F.
Other Tariff Modules (except portions of Module B dealing with traditional transmission service
that will be provided under the tariffofthe Market Coordination Customer) will be applicable to
interfacesand specifyan array of coogestionmanagementtools that are utilizedfor that purpose,includinga
standardized Congestion Management Process ("CMP").

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DuaneMorris
The Hon. Kimberly D. Bose
March 4, 2008
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customers taking service under Module F. The Midwest ISO also proposes a number of new
definitions and various conforming changes throughout the Tariff.
The Western Markets Proposal is expected to produce substantial benefits. In their
respective testimonies, Mr. T. Graham Edwards, the Chief Executive Officer ("CEO") of the
Midwest ISO, and Mr. Clair J. Moeller, the Midwest ISO's Vice President of Transmission
Assets, explain that the expected benefits include: (1) improved regional reliability; (2) more
efficient congestion management procedures; (3) reduced administrative costs for existing
Midwest ISO stakeholders; (4) increased revenues for Transmission Owners and lesser financial
burdens on existing customers; and (5) additional new sources of power and more power
supplies for the entire region, s The Western Markets Proposal is consistent with Order No.
20009 and is not expected to have any adverse effects on the current Midwest ISO membership
or operations, l0
Finally, the Midwest ISO's Ancillary Services Markets ("ASM") proposal, which has
now been conditionally accepted by the Commission, 11 has a direct effect on the Midwest ISO's
submission in this proceeding with respect to Market Coordination Service proposed under Part
III of Module F. As explained by Mr. Moeller, while proposed Reliability Coordination Service
and Interconnected Operations and Congestion Management Service can be provided even prior
to the implementation of the ASM, Market Coordination Service may be provided only a~er the
ASM proposal goes into effect. 12

II.

DESCRIPTION OF THE WESTERN MARKETS PROPOSAL

A.

Background

As detailed by Mr. Moeller, 13the origins of the Westem Markets Proposal lie in the
existing relationship between MAPP and the Midwest ISO. Both organizations have overlapping
footprints and historically have maintained close ties in diverse areas, such as reliability
coordination and "seams" management. Many MAPP members trade in the Midwest ISO
markets and some MAPP transmission owners have transferred their facilities to Midwest ISO's
functional control. The Western Markets Proposal seeks to take existing cooperation a step
further, both by expanding the "menu" of available services and by bringing such services to a
broader array of customers.

s

See Prepared Direct Testimony of T. Graham Edwards, Ex. MISO-1 ("Edwards Testimony"), at 3-4; Prepared

Direct Testimony of Clair J. Moeller, Ex. MISO-2 ("Moeller Testimony"), at 18-22.
Regional Transmission Organizations, Order No. 2000, FERC Stats & Regs ¶ 31,089 (1999), order on reh 'g,
Order No. 2000-A, FERC Stats & Regs ¶ 31,092 (2000).
~o See Edwards Testimony, at 4-8.
ll See Midwest Independent Transmission System Operator, Inc., 122 FERC ¶ 61,172 (2008)("ASM Order").
12 See Moeller Testimony, at 10-11.
13 See id., at 11-16.

9

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Duane_morris
The Hon. Kimberly 1). Bose
March 4, 2008
Page 6
MAPP was fornlcd in 1972 as a "loose" power pool to provide reserve sharing and backup generation for its members, but without the centralized dispatch that was more common in
"'tight" power pools in the east) ~ The Commission approved the original MAPP Agreement on
June 15, 1977,15 and a Restated Agreement was accepted for filing on September 12, 1996.16
The Restated MAPP Agreement created a regional transmission group ("RTG"), established a
NERC reliability council for MAPP, provided for generation and planning reserves coordination,
included a regional transmission tariff for short-term point-to-point transmission service, known
as "Schedule I:," and provided for certain other functions and internal governance mechanisms.
In 1999, the then-existing MAPP Schedule F was superseded by a regional open access shortterm point-to-point transmission service tariff, which remains in effect, t7 In 1990, MAPPCOR,
Inc. ("MAPPCOR") was incorporated as a not-for-profit organization to provide transmission
and reliability services to the MAPP members as a contractor and to administer the MAPP
Agreement.
After the Midwest ISO was formed as an independent systcm operator ("IS()") in 1998,
some, but not all, MAPP transmission-owning members joined the Midwest ISO as Transmission
Owners, requiring the two organizations to improve coordination and cooperation. In
anticipation of the Midwest lSO's launch as the regional transmission service provider on
February 1,2002, the Midwest ISO purchased the majority of the MAPPCOR assets and entered
into a Transmission Services Agreement ("TSA") ~ with MAPPCOR on Dccember 1, 2001.
Under the TSA, thc Midwest IS() acted as the NFRC Reliability Coordinator tbr the MAPP
members that had not joined the Midwest ISO and provided rclated reliability coordination
servtces. 19 When the TSA expired on February 1, 2008, a new, more detailed agrecment
specitically addressing reliability coordination services took its place. The Reliability
Coordination Service proposed under Part I of Module F is patterned closely on the rcliability
coordination services the Midwest ISO provides under the new "Reliability Coordination
Agreement between Contractor and Reliability Coordinator" dated January 23, 2008.
•

Similarly, MAPP and the Midwest ISO have cooperated with respect to "seams"
management, which was put on the agenda by the Midwest ISO's launch of its Energy Markets
on April 1, 2005. In anticipation of that date, discussions began in the region seeking to ensure
that the benefits of market participation accrued to entities that had joined the Midwest ISO
I~
is

Mid-Continent Area Power Pool, 48 FPC 607 (! 972).
Mid-Continent Area Power Pool. Opinion No. 806. 581~7~C 2622, reh 'g denied. Opinion No. 806-A, 59 FPC
1651 (1977). aff'd, sub nora.. Central Iowa Power Coop v. FERC; 606 F~2d 1156 (D.C. C'ir 1979)
I~ Mtd-Contment Area Power Pool, 76 FERC ¶ 61,261 (1996).
17 Mid-Continent Area Power Pool, 87 FERC ¶ 61,075, reh 'g denied, 89 FERC ¶ 61,135 (1999), order on
compliance, 91 FERC ¶ 61,065 (2000).
,i l'he full name of the Transmission Services Agreement was the Amended Agreement for Provision of
Transmission-Related Services by the Midwest IS() to MAPPCOR.
~ Originalb, the Midwest ISO also provided staffsupport for MAPP committee activities and administered
MAPP's regional tariff Schedule F, but in November 2007, MAPPCOR resumed the tariff administration tot
Schedule F and several key committee support functions, leaving reliability coordination as the primary service
under the I'SA.

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M a r c h 4, 2008
Page 7

while not placing a disproportionate burden on the non-market region. The Commission also
encouraged the Midwest IS() to address comprehensively "seams" issues as a prelude to the
initiation of its Energy Markets. 2° As a result, the Midwest ISO and MAPPCOR cntcred into a
Seams Operating Agreement ("SOA') which was executed on January 31, 2004, accepted for
tiling on March 16, 2005, n and expired on February, I, 2008. 2:
In anticipation of the TSA's and the SOA's expiration, representatives of the Midwest
ISO and MAPP began discussions in late 2007 to explore the contours of their prospective
relationship. While still unwilling or unable to join the Midwest ISO as Transmission Owners,
many MAPP members saw substantial benefits accruing not only from the continuation ofthe
Midwest ISO's traditional reliability and seams coordination, but also from the operation of the
M i d w e s t IS() s p r o p o s e d E n e r g y and O p e r a t i n g R e s e r v e M a r k e t s and the c o n s e q u e n t L M P - b a s e d

congestton management tools made posstble. In the sptrtt of the open architecture that has
been a hallmark of the Midwest ISO, the parties have jointly developed Module F to provide a
flexible menu of options for entities that are not ready to become Transmission Owners, but want
to obtain reliability coordination and/or congestion management services from the Midwest ISO
or if they so choose, join and participate in the Midwest ISO Energy and Operating Reserve
•

•

23

•

•

•

Markets. 24

Finally, it is important to note that although the idea of Module t" was rooted in
negotiations with MAPP, whose members actively participated in the development of this filing.
20

In its order approving the design of the Midwest ISO markets, the Commission stated: "[TJhough we agree with
the Midwest ISO that the absence of seams agreements should not impede market startup, the markets cannot
start without the Midwest ISO having at least a specific, transparent plan for how it will handle the interface of
multiple transmission tariffs and market-to-non-market seams. We encourage market participants to use the
PJM-Midwest ISO JOA as a model or starting point for seams agreements, particularly with respect to the
seams with the various utilities in the MAPP region[.]" Midwest Independent 7)'ansmt.s*ion System Operator,
lnc., 108 FERC ¶ 6 l, 163, P. 639 (2004)
:l Midwest Independent 7)'ansmls.*ion SyMem Operator, Inc, I I 0 FERC ¶ 61,290 (2005)
22 The substantive provisions of the SOA established protocols for the exchange of real-time data and projected
information; allowed the parties to coordinate and exchange calculations of total transfer capability ("TTC"),
available transmission capability ("ATC") and available flowgate capability ("AFC"); provided for reciprocal
coordination of flowgates through a binding congestion management process ("CMP"); and provided for market
redispatch to offset the effects of loop flow.
2~ Under the SOA, redispatch of market flows is available for congestion management, but most relief is secured
through TLR orders. As the Commission has recognized on numerous occasions, these are blunt instruments
that imp~)se significant costs on parties to energy transactions. See, e g., Midwest Independent Transmission
Sy.~tem Operator, Inc., 108 FERC ¶ 61,236, PP 30 and 32 (2004) ("[R]eliaoce on TLRs for congestion
management inherently leaves transmission capacity under-utilized because the TLR approach relies on
imprecise flow estimates" and "each TLR curtailment.., may curtail too many or too few transactions." The
uncertainty of the TLR process undermines the reliability of the grid because it made it "'more difficult to
maintain power flows within operating security limits.")
2, As noted above, the Midwest ISO also has negotiated a "'bridge" agreement with MAPPCOR to ensure that the
reliability coordination services continue without interruption, and has agreed to extend the formal termination
of the SOA to provide congestion management alter the expiration of the TSA and the SOA, pending the
approval and implementation of Module F.

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"[he tlon. Kimbcrly D. Bose
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Page 8
the serviccs offcrcd would not be limited to MAPl ) members. Instcad, each of the proposed
Coordination Services in Module F will be available to all eligible custnmcrs. As explained
below, thc Midwest ISO has consulted with a broad array of stakeholders, including its
Transmission Owners, with respect to this proposal.
B.

Proposed Coordination Services
1.

Rcliability Coordination Service
a.

Eligibility

To be ciigible for service under Part I of Module F, a Reliability Coordination Customer
must be an operating entity that is: (i) a Market Coordination Customer taking servicc under Part
I11 of Module F or (it) a NERC Registered Balancing Authority or a NERC Registered
Transmission Operator that is not a signatoD' to the ISO Agreement at the same time it receives
service under Module 4:. As a condition for obtaining service, the Reliability Coordination
Customer is reqt, ired to execute a Service Agreement and provide to the Midwest IS() certain
essential operating information.
b.

Nature q/'Service

Under Part I of Module F, the Midwest ISO is required to continuously maintain its status
as Reliability Coordinator with NERC and to act as the Reliability Coordinator of the Reliability
Coordination Customer Transmission Facilities throughout the term of its Service Agreement
with the Reliability Coordination Customer. In general, Reliability Coordination Service
consists of the specific tasks and functions required of Reliability Coordinators by thc NERC
Reliability Standards, as they may be amended from time to time. The principal tasks include,
but are not limited to, the following: (i) monitoring of the Reliability Coordination Customer
Transmission Facilities to ensure operational reliability of the Combined Reliability Systems; (it)
providing on-line network modeling using state estimation and real-time contingency analysis in
the operating time frame; (iii) providing operations engineering services, such as analyses of the
Combined Reliability Systems' adequacy and security for day-ahead operations, conducting
voltage collapse studies when requested, and support for Operating Guides as needed; (iv)
monitoring and advising the Reliability Coordination Customer of voltage support and supplies
of reactive power; (v) monitoring and assessing abnormal Reliability Coordination Customer
ACE deviations and system frequency deviations; (vi) using TLR procedures to relieve actual or
potential operating security limit violations; (vii) supporting power system restoration activitics;
(viii) supporting transmission map maintenance for the Reliability Coordination Customer
"l"ransmission Facilities; and (ix) monitoring the Reliability Coordination Customer's compliance
with applicable NERC and Regional Entity standards and supporting such compliance with data
as rcquired.

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As the Reliability Coordinator, the Midwest IS() will have the authority to monitor and
direct the Reliability Coordination Customer's actions with respect to the Reliability
Coordination Customer Transmission Facilities in order to preserve the integrity and reliability
of the Bulk Electric System and to ensure that operating parameters are maintained in accord
with NERC and Rcgional Entity standards. The Midwest ISO will periodically pertorm loadflow and stability studies of the Reliability Coordination Customer Transmission Facilities to
identify and address reliability problems; will be responsible for the exchangc of operating
information related to the Reliability Coordination Customcr Transmission Facilities with
adjoining Reliability Coordinators and other operating entities within the Combined Reliability
Systems that require Reliability Coordination Customer operational data tbr reliability-related
purposes or for calculation of ATC and its components; and will develop, for approval by the
NERC Operating Committee, a regional reliability plan and procedures for responding to
emergencies that include the Reliability Coordination Customer Transmission Facilities.
For the purposes of mitigating an lnterconnection Reliability Operating I.imit ("IROL")
violation or a System Operating Limit ("SO12') violation so as to return the Combined Reliability
Systems to a rcliable state, the Midwest ISO will have authority to direct thc Reliability
Coordination Customer to: (i) redispatch generating facilities interconnected to thc Combined
Rcliability Systems in specified circumstances; (ii) reconfigure the Reliability Coordination
Customer Transmission Facilities, including requiring changes to the transmission maintenance
and outage schedules of the Reliability Coordination Customer; (iii) modify interchange; (iv)
reduce load to mitigate a critical condition, up to and including shedding of firm load; (v) direct
actions to be taken by transmission operators, balancing authorities, generator operators,
transmission service providers, load-serving entities, and purchasing-selling entities within the
Combined Reliability Systems to preserve the integrity and reliability of the Combined
Reliability Systems, which are required to be taken without delay, but within no longer than 30
minutes; and (vi) initiate the control action or emergency procedure necessary to relieve a
tx~tential or actual IROL violation within stated time limits. The Reliability Coordination
Customer is required to comply with the Midwest ISO's directives issucd to mitigate an IROL or
SOL violation, consistent with the Operating Guides for the Reliability Coordination Customer
Transmission Facilities. The Midwest ISO's authority to direct these actions is limited to
circumstances where such action is necessary to prevent or manage emergency situations and is
subject to existing operating restrictions on transmission facilities and existing operating and
environmental restrictions that limit a generator's ability to change its dispatch.
The Reliability Coordination Customer will retain the authority to receive, confirm, and
implement interchange and other transmission service schedules, subject to the Midwest ISO's
authority to modify interchange. While it will not have authority to institute a "II.R or EEA, the
Reliability Coordination Customer may request that the Transmission Provider take such action.

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The lion. Kimbcrly D. Bose
March 4, 2008
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c.

Reliability Coordination Customer Obligations

Under Part I of Module F, the Reliability Coordination Customer is required to notify the
Midwest IS() without undue delay of any operating difficulty that could prevent the Reliability
Coordination Customer from understanding and communicating to the Midwest ISO the real
time conditions existing in the Reliability Coordination Customer's balancing authority area or
transmission system. The Reliability Coordination Customer also is required to comply with the
operating policies and reliability standards of NERC and of the applicable Regional Entity. In
the event that NERC or a Regional Entity conducts an audit of the Reliability Coordination
Customer's balancing authority or transmission operation or facilities during the term of the
Service Agreement, the Reliability Coordination Customer is required to implement, without
undue delay, all reasonable mitigation or remedial measures required to address deficiencies, if
any, identified by such reliability or similar audit.
Concurrently with its execution of its Service Agreement, the Reliability Coordination
Customer is required provide the Midwest ISO with all such information as is reasonably
necessary for the Midwest 1SO to provide the Reliability Coordination Service. The Reliability
Coordination Customer is also responsible lbr developing, maintaining and implementing a set
of plans to mitigate operating emergencies and for developing a system restoration plan tbr the
Reliability Coordination Customer Transmission Facilities that is consistent with the
Transmission Provider's Reliability Coordinator Area system restoration plan.
Unless otherwise agreed, the Reliability Coordination Customer is required to submit its
transmission and generation facility maintenance and outage schedules to the Midwest ISO in
accordance with existing Midwest ISO outage coordination procedures. The Midwest IS() may
disapprove or revise these transmission and generation schedules if they fail to meet established
reliability standards or if necessary to respond to emergency conditions.
d

Term

The Midwest ISO proposes that the initial term of Reliability Coordination Service be tbr
a period of three years. The Service Agreement will be automatically renewed tbr successive
one year terms and may be terminated upon one year's notice. One exception to this requirement
is that public power entities are permitted to terminate Reliability Coordination Service on
shorter notice if the Tariff is modified in a manner that causes a conflict with state law,
regulations, or rate schedules of the public power entity. 25

lhe public power exceptionsin proposed Section 12E are based on existing Section 12D of the Tariff, v,hich
v,as approved by the Commissionin 2003 as Section 41 ofthe Midwest ISO's then-effectiveOATT to facilitate
the participation of Nebraska utilities in the proposedTRANSI.ink Appendix I II'C. See Mt~*'est Independent
Transmission System Operator. Inc., 103 FIiRC¶ 61,207 (2003).

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e.

('ongestion Management

Under Part I of Module F, the Midwest IS() will use the then-current NERC TLR
procedures and related NAESB business practices to mitigate congestion on the Reliability
Coordination Customcr Transmission Facilities. Ifthe Reliability Coordination Service under
Part I of Module F is combined with thc Interconnected Operations and Congestion Management
Service under Part II of Module F, then the congestion management procedures under Part II of
Module F"are used. The congestion management procedures set forth in Part I of Module 1: are
not applicable to customers that take combined service under Parts I and lit of Module F because
the Midwest ISO's SCH) is used to relieve congestion on such customers' thcilitics.

f

Compensation and Billing for Reliability Coordination Service

In general, the Midwest ISO proposes that the charge for Reliability Coordination Service
under Part 1 of Module F, the Reliability Coordination Cost Recovery Adder, be the portion of
Tariff Schedule 10 fees26 that are attributable to the reliability coordination functions performed
by the Midwest IS(). This portion is currently estimated to be approximately 51 percent of the
Schedule 10 fi:cs. The Reliability Coordination Cost Recovery Adder is set tbrth in proposed
Schedule 31 of the Tariff. Mr. Michael P. Holstein, the Midwest ISO's Chief Financial Officer,
explains how the Reliability Coordination Cost Recovery Adder is derived in his Prepared Direct
Testimony, which is included in this filing as Exhibit MISO-3. 27 The Midwest IS() will bill
Reliability Coordination Customers on a monthly basis pursuant to the procedures set forth in
proposed Section 7.19 of the l'arift: 28

g.

Withdrawal Fee Obl~ation/br Reliability Coordination
Customers

Reliability Coordination Customers will be required to pay a withdrawal fee upon
termination of their Service Agreement with the Midwest ISO. In general, proposed Section
77.3 of the Tariff requires the withdrawing customer to pay an allocated share of the remaining
book value of all incremental capital assets associated with the provision of the services under
Part I of Module F and the applicable Service Agreement that are under development or inservice as of the termination date including certain financing costs associated with such assets.
Mr. Holstein provides further specifics with respect to how the withdrawal payment is
determined. 2'~

26
?"
2~
?~

Schedule 10 ofthc Tariffcontains the Midwest ISO's Cost Recovery Adder.
Prepared Direct Testimony of Michael P. Ilolstein, Ex. MISO-3 ("llolstein Testimony"), al 3-5
Id. at 6-7
Id. at 7-9

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h

Reliability Coordination Technical Committee

Part I of Module F also provides for a Reliability Coordination Technical Committee
("RCTC"), which will be composed of representatives of the Midwest IS() and of all Reliability
Coordination Customers. The RCTC is designed as an advisory technical committee and will
not a part of the formal stakeholder governance process. Any recommendations for changes to
Part I service would be tariff changes, and would be reviewed by the appropriate Midwcst ISO
stakeholder committees prior to any filing. The Midwest IS() and the Reliability Coordination
Customers retain their rights under Sections 205 and 206 of the FPA.
2.

Interconnected Qperations and Congestion Management Ser~'i~.c_
a.

Eligibility

"Fo be eligible for Interconnected Operations and Congestion Management Service under
Part II of Module F, a Congestion Management Customer must be a NFRC Registered
Transmission Provider providing reciprocal transmission service using transmission lhcilitics
that are physically connected to the Midwest ISO's Transmission System or to the transmission
facilities of an entity taking service under Part III of Module F of the Tariff. A Congestion
Management Customer may not be a signatory to the ISO Agreement because congestion
management is achieved using the SCED for Transmission Owning members of the Midwest
1SO. As a condition to obtaining service, the Congestion Management Customer is required to
execute a Service Agreement under Part 11 of Module F and provide certain required intbrmation
to the Midwest IS().
b.

Nature ofService

Interconnected Operations and Congestion Management Service is designed for "seams"
management between market and non-market areas and is based on a standard, Fl'R(2-approved
CMP. The terms of Part II of Module F are taken, in a large part, from the existing MAPP
Seams Operating Agreement, with the exception of the newly created redispatch provisions. The
CMP found in proposed Attachment LL is identical to the recently standardized (2Mp approved
by the Commission in two other Midwest ISO seams agreements.
lnterconnection Operations and Congestion Management Service involves the following
major components and obligations:
Transfer of Information and Data. The Midwest ISO and the Congestion
Management Customer are obligated to transfer to each other the following types
of data and information: (a) Real-Time and Projected Operating Data; (b)
SCADA Data; (c) EMS Models; and (d) Operations Planning Data. Section 80
of the Tariff details the specific data items tbr each category and establishes
necessary rules for the exchange.

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TTC/A[C/AFC Protocols. The Midwest ISO and each Congestion Management
Customer will establish a TI'C/ATC/AI.'C Protocol, which will bc included in thc
customer's Service Agreement exccuted under Part I1 of Module F, Io coordinate
their I'I'C/ATC/AFC calculation models. The Midwest ISO and the Congestion
Management Customer will provide each other with various generation,
transmission, load, outage and interchange data and will coordinate their
transmission service requests.
Reciprocal Coordination of Flowgates. To coordinate congestion managcmcnt
proactively, the Midwest ISO and the Congestion Management Customer will be
obligated to respect each other's determinations of AFC/ATC and curtailment
priorities for real-time operations applicable to their Coordinated Flowgates
("CFs'). Additionally, the Midwcst ISO and the Congestion Management
Customer will be obligated to respect the allocations defined by the reciprocal
allocation process set forth in the Congestion Management Process, which is
included in this filing as proposed Attachment LL to the Tarift: The Midwest ISO
will utilize its Unit Dispatch System ("UDS") and Security-Constrained Unit
Commitment ("SCUC") in effect at the time to manage the portion of the flows on
an RCF allocated to the Midwest ISO. The Congestion Management Customer's
Reliability Coordinator will utilize NERC TLR process to manage the portion of
the flows on an RCF allocatcd to the Congestion Management Customer.
Generation Redispatch. Part I1 of Module F contains a generation redispatch
obligation that makes it unique among other seams agreements. Under Part 11 of
Module F, the Midwest ISO and the Congestion Management Customer may
confi:r to identify: (i) transmission operating constraints that could result in TI,R
or other emergency procedures in order to alleviate the transmission constraints,
the need for which could be reduced or eliminated by the redispatch of generation
controlled by the Congestion Management Customer, and (ii) the generation units
on the Congestion Management Customer's system, the redispatch of which
would alleviate the identified transmission constraints. Where such redispatch
opportunities are identified, Sections 83.3 and 83.4 of the Tariff describc the
procedures applicable to such generation redispatch and the applicable
compensation. These provisions have been closely modeled on the voluntary
redispatch procedures that the Commission approved for the Redispatch
Agreement between the Midwest IS() and East Kentucky Power Cooperativc. 3°
The chief distinction in this proposal is that the redispatch obligations in Part II of
Module F are not voluntary, but, once the parties mutually agree to designate a
target flowgate and develop applicable operating procedures, must be offcred

~o

See ;~..fidwe.st l n d e p e n d e m TransmA.~ion,~.stem Operator, h w , 119 |:ERC ¶ 61,338 t2007).

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(subject to certain legal and reliability limitations) by the respective parties if the
redispatch price is lower than the cost of relieving the congestion using
traditional TI,R or other redispatch solutions. In some cases, in order to effect the
redispatch solution, it may be necessary tbr the Congestion Management
Customer to purchase energy from the Midwest ISO market. Section 83.3.4
requires mutual agreement that such energy will be available and deliverable, and
that the energy purchase will not create adverse conditions on the systems of
either party. This section provides a mechanism to avoid redispatch that could
result in scarcity pricing in the Midwest ISO market.
Additional Coordination. The Midwest ISO and the Congestion Management
Customer will also engage in: voltage control and reactive power coordination,
regional transmission and generation outage coordination, planning coordination
and reserve sharing coordination.
c.

Term

The Midwest IS() proposes that the initial term of Interconnected Operations and
Congestion Management Service under Part II of Module F be for a period of three years. The
Part II Service Agreement will be automatically renewed tbr successive one year terms after the
efli:ctivc date of the Part II Service Agreement and may be terminated upon one year notice. An
exception to this requirement is that public power entities are permitted to terminate
Interconnected Operations and Congestion Management Service on shorter notice if the Midwest
ISO's Tariffis moditied in a manner that causes a conflict with state law, regulations, or rate
schedules of the public power entity. 3t
d

Compensation

Mr. I tolstein explains that any costs incurred to provide Interconnected Operations and
Congestion Management Service will be allocated to and recovered under current Tariff
Schedule 17 - Energy Market Administrative Cost Recovery Adder. Other than the redispatch
provisions described above, there is no separate compensation or cost recovery mechanism for
this proposed service. 32
3.

Market Coordination Service
a.

Eligibility

To be eligible for service under Part 111 of Module F, a Market Coordination Customer
must be a transmission provider providing transmission service on facilities that are: (i)
~' Seen. 25, supra
~:' HolsteinTestimony,at 5-6

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interconnected with the thcilities o f a Transnaission Owner; (ii) interconnected with the facilities
of another entity taking service pursuant to this Part 111;or (iii) interconnected with the thcilities
of certain Congestion Management Customers taking service under Part 11 of Module F. The
intent of these eligibility requirements is to capture one or more of the situations that will ensure
an electrical path sufficient to permit the Midwest ISO to dispatch resources and loads using the
SCEI) and perform its Balancing Authority obligations. Further, service under Part II1 of
Module F can only be taken in combination with Reliability Coordination Service under Part I of
Module F. This requirement aligns Market Coordination Customers with existing Transmission
Owners who now obtain reliability coordination service under the Tariff and it will ensure
reliable operation of the Energy and Operating Reserve Markets by combining these related
functions in one operation. Finally, signatories to the ISO Agreement are not eligible for Market
Coordination Service, as long as they remain Transmission Owners of the Midwest ISO.
b.

Nature o f Service

The purpose of Market Coordination Service is to extend the Midwest [SO's market
footprint to the transmission systems of Market Coordination Customers while leaving the
provision of transmission service over these systems in the hands of those customers. The
Midwest ISO will integrate the resources and loads in the Customer Zone with the Energy and
Operating Reserve Markets by including the Market Coordination Customer Transmission
Facilities, and loads and resources in the Customer Zone in the Midwest ISO's Network Model
and Commercial Model. Further, the requirements set forth in Module C of the Tariffare
applicable to all resources and loads in the Customer Zone, which must register as Market
Participants (including resources and loads Pseudo Tied into, but excluding those Pseudo Tied
out of, the Midwest ISO Balancing Authority) Market Coordination Customers will be
participating in the ASM market and thus the Midwest ISO will become the Balancing Authority
tbr those customers. Section 90.2.5 sets forth specific requirements in this regard, including the
requirement that all loads and resources in the Customer Zone must either register as Market
Participants to facilitate this function or make alternative arrangements to obtain Balancing
Authority service from another entity. The Midwest ISO will manage transmission congestion in
the Market Provider Region using its SCED, which includes redispatching Generation Resources
as set tbrth in Module C of the Tariff. A specific exception to this process is the North Dakota
Export ("NI)EX') flowgate. Module F provides that the current congestion management system
in place for NDEX under the current MAPP seams agreement will continue.
c.

Eligibilityfi)r ARRs/1;TRs/LTTRs

As set forth in proposed Section 90.2.3, transmission customers of a Market Coordination
Customer ',','ill be eligible to receive ARR Entitlements under Module C of the Midwest ISO
tariff, provided they are taking firm service comparable to that provided by the Midwest ISO
under its Tariff, have entered into a long-term agreement tbr firm transmission service on the
system of the Market Coordination Customer, timely submit necessary information, and meet the

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othcr requirements of the Tariff and Business Practices Manuals. In addition, the customers of
the Market Coordination Customer may be eligible to participate in the Stage 1A allocation of
ARRs (i.e., Long Term Transmission Rights or "LTrRs") ifsuch customers participate in the
transmission planning and expansion process ofthc Market Coordination Customer, under terms
that seek to ensure that its transtrrission system can support the simultaneous fcasibility of all
Stage IA ARRs tbr their full term, consistent with the Commission's requirements for LTTRs.
Mr. Richard l)oying, the Midwest ISO's Vice President of Market Operation, explains in detail
the proposed allocation of ARRs and F I R s in his Prepared Direct Testimony. ~
d

Preexisting Contracts

Some of the Market Coordination Customers' preexisting contractual arrangements lbr
transmission service will need to be modified as a precondition to receiving service under Part 11I
of Module F. Specifically, proposed Section 90.2.4.1 provides that, if an eligible customer
applies for Part III service and is a party to an existing "Carved-Out GFA'" with a Midwest ISO
Transmission Owner or another Market Coordination Customer, as listed in Attachment 1' of the
"I'aritt] that applicant will bc required, as a precondition to receiving under Part 11I of Module F,
to convert its rights to Option A or Option C treatment (as defined in Module C of the Midwest
ISO Tarift) or to tariffservice undcr the appropriate tariff(s). As Mr. Doying explains, the
reason lbr this requirement is straightforward: a Carved-Out GFA that has Midwest ISO
Transmission Owner(s) and Market Coordination Customer(s) as parties is incompatible with
participation in the Midwest ISO's Energy and Operating Reserve Markets. 34
In addition, the Midwest ISO proposes a process tn ensure that other preextsting
contractual arrangements (i.e., those that are not currently listed in Attachment P as GFAs) arc
identified by the Market Coordination Customers, and are given the appropriate GFA treatment.
The GFA treatments selecled by Market Coordination Customers tbr their preexisting
agreements will be reviewed by the Midwest ISO pursuant to the criteria and process that are
similar to that applied in the GFA proceeding at the inception of the Midwest ISO's Energy
Markets in 2004-05. Such preexisting agreements that are subject to the "just and reasonable"
standard of review are required to select either Option A or C GFA treatment, or full conversion
to service under the E M r and/or under the Market Coordination Customer's tariff. Other such
agreements are eligible to be classified as Carved-Out GFAs under the EMT if they are:
(1) subject to the "public interest" standard of review; (2) silent on the applicable standard of
review; or (3) contracts for the provision of transmission service by an entity that is not a public
utility. Although such agreements are eligible to be classified as Carved-Out GFAs, the parties
may voluntarily select Option A or C GFA treatment, or conversion to service under EMT and/or
under the Market Coordination Customer's tariff. Upon such voluntary conversion, the GFA can
no longer revert to carved-out status. On the other hand, preexisting agreements that are eligible
to be carved out and choose to remain in that status shall be treated like other Carved-Out GFAs,
~

I:'reparcdDirect "restmmnyof Richard Doying,Ex MISO4 ("DoyingTestimon>"),at 3-8.

~a ld. at 10-1I.

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with one difference. If there is any inadequacy in the revenue needed to cover the congestion
costs of such carved-out preexisting agreements, the revenue inadequacy ",,,'ill not bc funded by
the shortfall's allocation to all Market Participants across the Midwest 1SO's Region, but instead
shall be assessed on the load in the relevant Customer Zone that is not served under a preexisting
agreement. Mr. Doying explains in detail the proposed preexisting contract arrangements and
procedures in his testimony, ts
e.

Market Integration Transmission Service

The transmission arrangements that are needed to accommodate a single energy market
over diverse transmission service footprints are quite complex. As explained by Mr. Mocller,
the key element of these arrangements is Market Integration Transmission Service ("MITS"). 36
MITS is a unique firm transmission service that shares certain attributes of network service from
resources located in one transmission provider's tbotprint to serve loads in another transmission
provider's tbotprint. MITS will be provided by the Midwest ISO over its tbotprint, as set forth
in proposed Section 93.1 and Schedule 32 of the Tariff. Market Coordination Customers will
provide a comparable version of MITS over their transmission systems, under the provisions that
they will adopt in their own transmission tariffs pursuant to proposed Attachment MM. The
Midwest IS() and Market Coordination Customers also may use other types of transmission
service available under their respective tariffs to complete bilateral transactions.
In his testimony, Mr. Moeller explains that lbr transmission service sourced in the
Midwest ISO, MITS will provide the necessary vehicle for market flows from the Midwest ISO
Transmission System to a Market Coordination Customer's transmission system) 7 From the
border, transmission service would be provided on the Market Coordination Customer's
transmission system under the terms of that customer's tariff. For transmission service that is
sourced in the Market Coordination Customer's footprint and sinks either in the Midwest 1SO's
footprint or another Market Coordination Customer's footprint, each Market Coordination
Customer will be required to adopt comparable provisions in its transmission tariff, as set forth in
proposed Attachment MM. 3s The adopted provisions will set the terms and conditions Ibr: (1)
the transmission service necessary for energy market flows from the Market Coordination
Customer's transmission system to the Midwest ISO and (2) the transmission service for "drive
through" flows across the transmission system of another Market Coordination Customer, to the
extent flows are related to the Midwest ISO Energy and Operating Reserve Markets SCED. The
transmission service within the Midwest ISO transmission system for energy flowing from the
Market Coordination Customer's transmission system would be provided under MITS or other
types of Transmission Service.

3~
it,
3;
~s

/d. at 8-14.
M o c l l c r ' l e s t i m o n y , at 28.
Id. at 28-29.
I d at 29-30

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Mr. Moeller further explains that MITS is needed because the standard transmission
services offered under the proforma OA'I'I', the point-to-point transmission service and the
network integration transmission service, cannot be used to accommodate the proposed market
design. ~9 Due to its unique characteristics, it will not be necessary to request, schedule, or tag
MITS or post or decrement on the OASIS the ATC or AFC associated with MIIS. ~° Further,
MITS is not intended to replace or convert existing transmission service between Market
Coordination Customers and customers within the Midwest ISO Tariff footprint. Nor will a
separate service agreement be necessary to receive M1TS. 41
The MITS charge is set forth in proposed Schedule 32. As described by Mr. Moeller, 42
the MITS charge is not transaction-based and is designed to recover the Midwest ISO
Transmission Owners' current "out" revenue requirement from Market Coordination Customers
in proportion to their historic (previous year's) share of the net hourly real-time exports from
resources located in the Midwest ISO footprint and that sink in that entity's balancing authority.
A three-year Transition Period is proposed for the MITS charges under Schedule 32 because the
actual market flows needed to develop the MITS charge can only be determined following the
integration of the Market Coordination Customer's resources and loads into the real-time Energy
and Operating Reserve Market and, for that reason, some transitional period of time is necessary
to obtain the required actual flow data. 43 Each Market Coordination Customer will be
responsible for the applicable Midwest ISO MITS transmission charges, but is free to establish a
means to recover these charges from entities on its transmission system. The Midwest ISO's
MITS revenues will be distributed to Transmission Owners by using existing revenue
distribution mechanisms.
The MITS charge for a Market Coordination Customer tbr each year during the
Transition Period is equal to charges collected at the External Transaction Deliver), Point tbr
Point-To-Point Transmission Service and its applicable schedules that represent an Export to the
Market Coordination Customer during the calendar year prior to the effective date of the Market
Coordination Customer's Service Agreement executed under Part III of Module F. 44 However, if
the MITS charge for any year during the Transition Period equals zero lbr any Market
Coordination Customer, the Transition Period will not apply to such a customer. Instead, the
MITS charge for that customer will be calculated based on the methodology for post Transition
Period charges. The applicable MITS charge is then prorated on a monthly basis and reduced by
any monthly charges collected at the Internal Delivery Points for Point-To-Point Transmission
Service and its applicable schedules that represent a delivery to the Market Coordination
Customer at the Internal Delivery Points.

39

Id. at 30-31.

4o

hL at 30.

.u

Id

~:
4,

hi. a t 3 1 .
/d. at 31-32.

4~

hi. at 32-33.

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After the Transition Period ends, the Midwest IS() will determine the applicable MITS
charge through an algorithm set forth in Part B of Schedule 32. First, the Mid,,vcst ISO will
determine the average hourly usage by a Market Coordination Customer by summing the
positive hourly demand over the previous calendar year from the Transmission System to the
Market Coordination Customer's transmission system and dividing this annual sum by the
number of hours in a year. 4s In the tirst step, the Midwest ISO will reduce each positive hourly
MITS demand by the amount of reserved Point-To-Point Transmission Service that coincides
with that same hour and it is to an Internal Delivery Point(s) that represents delivery to that
Market Coordination Customer at such Internal Delivery, Point(s). Second, the Midwest ISO will
determine the applicable single system-wide rate for MITS service. This rate will consist of.' (1)
the undiscounted Schedule 7 Drive Through and Out Rate in $/MW-YR; and (2) Schedule 1, 2,
and 26 charges and any other Tariff schedules applicable to Point-To-Point Transmission
Service. The rate is calculated using the formula set forth in the generic Attachment O of the
Tariff(Transmission Provider Formulaic Rate Description), pages I and 2, and recalculated
whenever any Transmission Owner updates its revenue requirement calculation, at a minimum
twice each year on January I and June 1. Third, the Midwest IS() will calculate a charge for
MITS for each Market Coordination Customer by multiplying the applicable Single - System
Wide Rate by the average hourly usage determined above in the first step.
Outside of the Midwest ISO footprint, each Market Coordination Customer would
determine its own charge for service over its facilities and provide the mechanism to allocate that
charge to customers on its system. In the proposed Attachment MM, the Midwest 1SO
establishes certain proforma provisions that all Market Coordination Customers must agree to
include in their tariffs as a precondition for being eligible to receive service under Part II1 of
Module F. These proforma provisions represent the necessary minimum safeguards to ensure
that the Midwest ISO may provide Market Coordination Service et/iciently and without
disruption. Although each Market Coordination Customer may further expand these provisions
when they are adopted in its tariff, all such amendments should be consistent with or comparable
to the original language set tbrth in Attachment MM.

f

Compensationand Billingfor Market Coordination Service

The MITS charges, together with all other applicable charges under the Tariff will
constitute compensation for Market Coordination Service. The Midwest ISO will bill Market
Coordination Customers pursuant to the procedures set forth in proposed Section 7.21 of the
Tariff. 46

4~
4,,

For the purposes o f this calculation a negative hourly demand is se! to zero.
I|olstcin t'estimony, at 6

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g.

Withdrawal Fee Obligation/or Enerbg, and Operating Reserve
Market ('oordination Customers

Customers under Part III of Module F are required to pay a withdrawal fee upon
termination of their Service Agreement with the Midwest ISO. In general, the withdrawing
customer will be responsible tbr payment of: (a) an allocated share of the remaining book value
of all Incremental Reliability Coordination Assets, and (b) an allocated share of the remaining
book value of all incremental capital assets associated with the provision of Market Coordination
Service and for certain financing costs associated with those assets. Mr. ltolstein provides
further specifics with respect to how the withdrawal payment is determined) 7
h

Joint Coordination Committee

Part III of Module F also provides for a Joint Coordination Committee ("JCC"), which
will be composed of representatives of the Midwest ISO and of all Market Coordination
Customers. The functions of the JCC will be advisor':' only. Any suggestions for tariffchanges
to Part III, Module F would be handled as other tariff changes in the Midwest IS() stakeholder
process prior to filing with the Commission. The Midwest ISO and the Market Coordination
Customers retain their rights under Sections 205 and 206 of the FPA. Market Coordination
Customers are eligible to participate in the existing stakeholder process in the "Coordination
Customer" segment. Today, only Manitoba }lydro occupies this seat, and Manitoba llydro has
agreed that Market Coordination Customers share sufficient characteristics to logically inhabit
this segment.
4.

Other Revisions

To enable the Midwest IS() to provide the Coordination Services set forth in Module F, a
number of additional Tariffchanges are proposed. The key revisions are as tbllows:
a.

Module A Revisions

Module A of the Tariffcontains definitions and general provisions. The Midwest ISC)
proposes to amend the definitional portion of Module A to include the defined terms used in
Module F. The Midwest ISO also proposes revisions to Article 7 of the Tariffto provide for
billing procedures for the three types of Coordination Customers under Module F. As previously
noted, the Midwest ISO has included new Section 12E to address issues that are unique to public
power entities' participation in Module F.

4~

/d. at 9

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b.

Schedule 31

Proposed Schedule 31 "'Reliability Cost Adder" sets forth the fees tbr the provision of
Reliability Coordination Service. The Reliability Cost Adder is described by Mr. Holstein in his
testimony, and represents an allocated portion of the Schedule 10 costs for the reliability
coordination function perfomled by the Midwest ISO tbr all tariffcustomers.
c.

Schedule 32

As described above, proposed Schedule 32 sets forth the Midwest ISO's MITS charge
and is described in detail by Mr. Moeller in his testimony.
d

Attachment KK

Proposed Attachment KK contains three pro/orma Service Agreements that
correspond to the three types of Coordination Services offered in Module F. Any nonconforming service agreements would be filed with the Commission consistent with the
Commission's regulations and Order No. 2001.
e.

Attachment LL

Proposed Attachment 1,I. contains the Midwest ISO's newly revised standard CMP
• )
48
now in effect on the TVA seam, the SPP seam and the I JM seam.
f

Attachment MM

Proposed Attachment MM contains the proforma transmission service provisions that
Market Coordination Customers will be required to adopt in their tariffs as a precondition to
receiving service under Part Ill of Module F.
g.

Module C Revisions

Certain conforming revisions to Module C are required to implement the Western
Markets Proposal, including the recognition of Market Participants taking transmission service
under a Market Coordination Customer's tariff as eligible to receive ARR Entitlements.

~

See Letter Order, Docket Nos. ER08-55-000 and -001 (February 4, 2008); I,etter Order, Docket Nos. ER071417-001 (February 2 I, 2008).

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h.

Credit Policy Revisions

The Midwest ISO proposes revisions to its Credit Policy, which is set forth in
Attachment L of the Tariff, to ensure that Coordination Customers are subject to appropriate
credit requirements.
IlL

BENEFITS OF TilE WESTERN MARKETS PROPOSAL

The Western Markets Proposal is expected to result in significant benefits to both
existing and new Midwest ISO members. Mr. Moeller explains a number of such benefits in his
testimony, including reliability benefits, improvements in congestion management procedures,
and reduction in energy and administrative c o s t s . 49
With respect to the reliability benefits of the Western Markets Proposal, Mr. Moeller
observes that closer coordination with MAPP members and a more seamless integration into the
Midwest ISO/:nergy and Operating Reserve Markets will improve regional reliability in several
ways. s~ To the extent entities choose Energy and Operating Reserve Market Coordination
Service, the inclusion of the expanded footprint in the Day-Ahead Energy and Operating Reserve
Market will enable the application of the SCUC within the next-day Reliability Assessment
Commitment ("RAC") process to access generators that today the market cannot assess. This
will ensure that there is a set of generators on line at the appropriate times to be able to manage
the power system within safe parameters. Further, the Midwest ISO's SCEI) will significantly
enhance the resolution of congestion, which in turn reduces the probability of system failure. 51
Even with respect to customers taking only Reliability Coordination Service under Part I of
Module F, the Midwest ISO will enhance its ability to "see" developments in the entire Midwest
region, which allows preemptive rather than reactive action. In addition, the Midwest ISO will
be providing a standard form of service rather than entering into separately negotiated
agreements with terms and conditions that could lead to differing interpretations by operators
during an emergency. Mr. Moeller notes that there would be erosion in reliability in the region if"
MAPP transmission owners were to choose not to participate in services provided under Module
F.
With respect to the congestion management benefits of Part III service, Mr. Moeller
observes that the Western Markets Proposal will extend the efficiency benefits of [,MP-based
congestion management mechanisms to a broader array of customers. 52 In Order No. 2000, the
Commission recognized the superiority of market-based congestion management over its non-

4,~ Moeller Testimony, at 18-22.
7o Id. at |g-|9.
~ As noted supra, the Commission has recognized that SCED-bascd congestion toanagement is a more advanced
and precise instrument than "['[.Rs.
'~2 Moelh:r l',.:slinlony, at 19-21.

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market alternativcs, such as "I'LRs.53 The Western Markets Proposal would replace, to a large
extent, the inefficient TLR mechanisms with generation-based congestion management, which
uses both the electrical effects of dispatch and thc cost effects of dispatch to solve congestion in
the least-cost or most efficient manner on a five-minute interval with very little manual
intervention. Mr. Mocllcr explains that managing what was previously a market-to-non-market
"seam" by using the Midwest ISO's SCUC and SCEI) protocols will reduce the Revenue
Sufficiency Guarantee ("RSG") cost of managing congestion and will bc more consistent with
cost causation principles.
Another significant benefit of the Western Markets Proposal is the addition of new
sources of low-cost power. Mr. Moeller explains that this will reduce energy costs for both
existing and new market participants, as the most efficient mix of resources available for both
energy production and ancillary services is committed and dispatched within the Energy and
Operating Reserve Markets. 54 Further, the Western Markets Proposal will benefit existing
customers by reducing their administrative costs due to economies of scale because the Midwest
ISO's systems arc scaleable and can provide service to Module F customers at a modest
incremental cost. In their testimony, Mr. Moeller and Mr. l IuIstein further discuss certain
financial benefits associated with the Western Markets proposal. $5
IV.

CONSISTENCY WITI! ORDER NO. 2000

Although the Western Markets Proposal represents a novel approach towards regional
and market coordination, it is consistent with the principles underlying Order No. 2000. The
Commission has emphasized in Order No. 2000 the importance of sufficient scope and regional
configuration for an RTO to be able to "maintain reliability, effectively pertbrm its functions and
support efficient and non-discriminatory power markets. ''~6 In his testimony, Mr. Edwards
explains that this issue is particularly salient for the Midwest region and that the Western
Markets Proposal is a bold step towards closer voluntary integration for the benefit of all
customers and participants, ensuring better reliability coordination in the region. 57

S3

Mr. Moener explains that unlike generation-basedcongestion management, TI,R does not investigate the leastcost alternative for congestion management, but simply continues to curtail transactions in the offending
direction until the congestion is solved. Under a TLR regime, there is no process or capability to seek energy
flow in a defensive direction. Since there is no economic information associated with the hourly transmission

~4
55
'6

5"

schedules used to eft~:ctcurtailment, it is not possibleto determine an economicoptimizationand it is not
possible to affect flow tbr 30 to 60 minutesfi'omthe time that intervention for congestionmanagementwas
required. Id. at 19-20.
Id at 21-22.
Id. at 18-22, IlolsteinTestimony,at 10.
Regional 7)'ansmission Organizations, Order No 2000, FERC Stats & Regs ¶ 31,089, at 31,079 (1999), order
on rch'g, Order No. 2000-A, FI'.'RCSlats & Regs¶ 31,092, at 31,372 (2000). See also 18 C I:.R. § 35 34(jX2)
(2007).
Edwards l'estimony, at 5

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Under Order No. 2000, RTOs are required to "ensure the development and operation of
market mechanisms to manage transmission congestion. ''s8 These mechanisms "must
accommodate broad participation by all market participants, and must provide all transmission
customers with efficient price signals that show the consequences of their transmission usage
decisions. ''~9 Mr. Edwards explains that by extending the benefits of the Midwest ISO's IMPbased congestion management system to contiguous transmission provider territories, the
Midwest ISO will t'urther enhance this important principle. 6°
Order No. 2000 also requires RTOs to address parallel path flow issues and emphasizes
interregional coordination. ~'l Mr. Edwards notes that the comprehensive menu of Coordination
Services that the Midwest IS() offers in its Western Market Proposal goes to the heart of this
requirement by replacing disparate a d h o c reliability arrangements with standardized tariff"
services open to all eligible customers.62 In addition, the Western Markets Proposal will make
efficient, market-based congestion management mechanisms available to a broadcr array of
membcrship.
Mr. Edwards further explains that although a measure of pancaking would remain in the
region because customers that take proposed Coordination Services would retain their own
transmission tariffs and continue to be providers oftransmissinn service on their thcilities, the
appropriate yardstick to measure progress in this area is to compare the Western Markets
Proposal with the s t a t u s quo. 63 Many customers that have expressed an interest in Market
Coordination Service, particularly non-jurisdictional entities, would not be intercstcd in
becoming signatories to the ISO Agreement and transferring control over their facilities to the
Midwest ISO, at least in the foreseeable future. As a result, rate pancaking will continue to exist
in the region in any event. The Western Markets Proposal recognizes this reality while taking a
substantial step towards closer integration. This is consistent with Order No. 2000, which
provides that "non-participating transmission owners" arc not required to de-pancake thcir
transmission rates. 64 In addition, the Commission also made it clear that it would not deny RTO
status merely because some transmission owners in the region have not transferred control over
their facilities to the RTO. 65 Further, in approving the Western Markets Proposal, the
Commission may properly take into account the fact that it is an improvement on the status quo
by a successful RTO rather than a start-up proposal. While non-pancaked transmission rates
may be a "central attribute of RTO formation,''66 Mr. Edwards notes that a more flexible
approach is warranted for evaluating proposals by functioning RTOs that seek to expand their
~s 18 C.FR. § 35.34(kX2) (2007).
~9 ld
Edwards Testimony, at 5-6.
6e See 18 C.FR. §§ 35.34(kX3) and (8) (2007).
62 I'dwards Testimony, at 6.
~ Id. at 6-8.
,4 See. e g . OrderNo 2000, FERCStats&Regs¶31,O89, at31,180(2000).
~ See Order No. 2000, FERC Stats & Regs ¶ 31,089, at 31.086 (I 999).
Order .Vo 2000-..1. I:FR(" Stats & Regs $. 31.092. at 3 I. 383 (2000)

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footprints to benefit customers and market participants. Importantly, the Commission's principle
of open architecture also supports the Western Markets Proposal. This principle holds that
Order No. 2000 does not limit the capability of an RTO to evolve in ways that would improve its
efficiency or to evolve with respect to its organizational design, market design, geographic
scope, ownership arrangements or methods of operational control to the extent consistent with
the foundational principles. 6~
Finally, the C'ommission should not fear that the availability of Module F services would
unravel the Midwest ISO or some other RTO. Mr. Edwards explains that the exit fee that ,,,,'ill
apply to a withdrawing Midwest ISO Transmission Owner pursuant to the ISO Agreement ,,,,'ill
operate to discourage casual withdrawals. 6s In addition, the Commission may always limit the
benefits of retaining control of transmission assets by prohibiting resumption of rate pancaking,
and by reviewing any withdrawal proposals to determine whether market power or other
problems would ensue. Conditions that might be imposed to remedy such problems would be
another factor tbr any Transmission Owner weighing the decision to withdraw from the IS()
Agreement to switch to service under Part Ill of Module F.
V.

S T A K E H O L D E R PROCESS

In his testimony, Mr. Moellcr explains that the Midwest ISO has used an open,
cooperative approach to develop the Western Markets Proposal. 69 The proposal development
process included numerous telephone conferences and face-to-face meetings with interested
MAPP participants and other parties. The Midwest ISO posted its drafts and discussion papers
on its website and sought and received input from interested parties. The Midwest ISO also
discussed the proposal with its Transmission Owner constituency, which provided input to the
Midwest ISO, both in oral and written form. The proposal was considered by the Advisory
Committee, the Midwest ISO's highest stakeholder forum, on two occasions. On December 10,
2007, the Mid,vest ISO presented a draft proposal to the Advisory Committee for review and
discussion. On February 20, 2008, the Advisory Committee formally considered the proposal
and adopted a resolution supporting the Midwest ISO's effort. Finally, the nearly completed
package of documents were reviewed by the Midwest ISO Tariff& Business Practices
Workgroup at its February 22, 2008 meeting.
VI.

FILING RIGHTS

Under Section l i d of Appendix K of the ISO Agreement, the Midwest ISO Transmission
Owners "possess the full and exclusive right to submit filings under FPA Section 205 with
regard to transmission rate design associated with rates affecting more than one zone as well as
for transactions going through or out of the Midwest ISO." The Midwest ISO and the Midv,'est
~'
S e e 18 CFR. §§ 35.34(kX8X2)(2007).
~'~ EdwardsTestimony,at 8-9.
"'J Moellcrlestimony, at 39-40.

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ISO Transmission Owners agree thal the Market Integration Transmission Service rates set forth
in proposed Schedule 32 fall within this provision. The Midwest IS() Transmission Owners
have tbllowcd the governance process required under the IS{) Agreement with respect to such
filings and the proposed Scheduled 32 was approved at a meeting of the Midwest IS(.)
Transmission Owners held on February 27.2008. The Midwest ISO Transmission ()wncrs
hereby join the Midwest ISO as a tiling entity solely for purposes of proposed Schedule 32. 70
VII.

EFFECTIVE DATE

The Midwest ISO respectfully requests that the proposed EMI" revisions become
effective on June 1. 2008, which dale is not less than sixty (60) days from the date of this filing.
VIII. SUPPORTING DOCUMENTS
This Transmittal Letter is intended to provide the Commission with an overview of the
Western Markets Proposal and the corresponding Tariff changes. The attached testimony
provides a more detailed discussion of the proposed Tariff design and corresponding Tariff
changes. The Transmittal Letter and testimony should not, however, be relied upon to detail each
and every change that is proposed by the Midwest ISO in the instant filing. The attached Tariff
sheets contain all of the proposed Midwest ISO Tariff changes. The supporting documents
submitted with this filing are as follows:
Attachment A

Redlined Tariff S h e e t s 71

Attachment B

Clean Tariff Sheets

Attachment C

Prepared Direct Testimony of T. Graham l';dwards {Ex. MISO-1)

Attachment D

Prepared Direct Testimony of Clair J. Moeller {Ex. MISO-2)

Attachment F,

Prepared Direct Testimony of Michael P. Holstein (Ex. MISO-3)

Atlachment F

Prepared Direct Testimony of Richard Doying (Ex. MISO-4)

~0 "I'hc Mids~cst ISO Transmission Owners' support for Schedule 32 does not necessarily indicate suppon by each
individual Transmission Owner for the entire filing. The Transmission Owners reserve the right to inlcrvenc
and ~omnlcnl orl the filing.
~ Existing "I ariff sheets are the only documenls that reflect redlines

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IX.

SERVICE AND WAIVERS

Thc Midwest ISO has served all panics provided in the Commission's cScrvice list tbr
the above-referenced docket. In addition, the Midwest ISO notes that it has served a copy of this
filing electronically, including attachments, upon all TariffCustomcrs under the EMf, Midwest
1SO Members, Member representatives of Transmission Owners and Non-Transnlission Owners,
the Midwest ISO Advisory Committee participants, as well as all state commissions within the
Region. In addition, the filing has been posted electronically on the Midwest ISO's websitc at
www.midweslmarket.org under the heading "Filings to FERC" for other interested panics in this
matter.
The Midwest IS() requests waiver of Section 35.13 of the Commission's regulations, 18
C.F.R. § 35.13 (2007), to the extent applicable to this filing and requests waiver of any other
applicable requirement of 18 C.F.R. Part 35 for which waiver is not specifically requested, if
necessary, in order to permit Commission acceptance of this filing.
X.

COMMUNICATIONS

Communications regarding this filing should bc addressed to the following individuals,
whose names should be placed on the official service list established by the Secretary with
respect to this submittal:
For the Midwest IS():
Stephen G. Kozcy*
Gregory Troxcll
Midwest Independent Transmission
System Operator, Inc.
701 City Center Drive
Carmel, Indiana 46032
Telephone: (317) 249-5400
Fax: (317) 249-5912
skozey@midwestiso.org
gtroxellCq)midwestiso.org

For the Midwest ISO Transmission Owners:

Wendy N. Reed*
Wright & Talisman, P.C.
1200 G Street N.W.
Suite 600

Stephen L. Teichlcr*
Ilia Levitine
Duane Morris LI.P
505 9 ~h Street, N.W., Suite 1000
Washington, D.C. 20004-2166
Telephone: (202) 776-7800
Fax: (202) 776-7801
slteichler@duanemorris.com
ilevitine@duanemorris.com

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.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

DuaneMorris
The Hon. Kimberly D. Bose
March 4, 2008
Page 28
Washington, D.C. 20005
202-393-1200
reed@wrightlaw.com
* Persons authorized to receive service

XI.

CONCLUSION

Wherefore, for all the reasons stated above, the Midwest ISO respectfully requests that
the proposed Tariff revisions be approved as set forth herein.

Very truly yours,

-~t~phen L. Teichler
Counsel for the Midwest Independent
Transmission System Operator, Inc.

SLT/srs
Attachments
CC:

Jennifer Amerkhail, FERC
Susan J. Court, FERC
Patrick Clarey, FERC
Christopher Miller, FERC
Penny Murrell, FERC
Melissa Lord, FERC
Michael Donnini, FERC
John Rogers, FERC

DM2\1387475.1

Wendy N. Reed
Counsel for the Midwest ISO
Transmission Owners

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Midwest ISO
FFRC Electric Tariff, third P-.eviscdVolume No. 1

Original Sheet No. 85()Q

77.3.4 The Reliabilit> Coordination Customer shall also be responsible
tbr payment o f an allocated share o f the accrued current liabilities on the
balance sheet of the l ransmission Provider as of the date o f termination of
the Ser'~ice Agreement.

77.3.5 The Reliability Coordination Customer shall pa,, a load ratio share
of these incremental financial obligations. The load ratio share shall be
calculated as the Reliability Coordination Customer's monthl? peak
demand for the tv.elve months preceding the termination of the Service
Agreement, relative to the sum of'the monthl) peak demand during that
period o f all Reliability Coordination Customers and all Tariff ('ustomers
receiving Network Integration Transmission Service under the I'ariff. All
peak demand infbrmation shall be converted into Maximum I!nerg>
['ransfcr data an defined in Part ][, Section A, of Schedule 10 of this
Tariff L l'hc Transmission Prm, ider shall use the non-coincident peak
demand for each Reliability Coordination Customer muhiplied b ) t h e
number of'hours in a month to derive the Reliability Coordination
Customer's Maximum l-nergy Transfer value. The "1ransmission Provider
shall compute Maximum Energy Transfer values fbr its Tariff Customers
taking Network Integration Transmission Service during the preceding
month fi'om their non-coincident peak demand. ]'he Reliability
Coordination Customer shall pay the entire amount owed under this

Section 77 at the time the applicable Service Agreement is terminated.

Issued by: I Graham Ld',sards. Issuing Officer
Issued on: March 4.2(}08

I'ffecti,.c: June I. 2008

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FERC Electric laril1~ lhird Revised Volume No. ]

Original Sheet No. 850R

77.3.6 A s to a Reliability Coordination C u s t o m e r to v, hich Section 12t- o f
this l a r i f f a p p l i e s , the obligation to m a k e the pa>ments under this Section

is subordinate andjunior in all respects to the obligation o f the Reliability
Coordination Customer to pa', the principal and interest on its bonds.
77.4

l-ach Reliabilit', Coordinatkm ('ustomcr shall provide to the Transmission

Pro', ider the monthly peak demand required by the I ransmission Provider to calculate the
applicable charge as set forth in Schedule 31 o f this Tariff Such data shall be transmitted
electronically to the l'ransmission Provider no more than five (5) Business Da',s after the
end of each calendar month.
77.5

During March o f each calendar )'ear. the Transmission Provider shall

update the percentage cost allocations currcntl~ set forth in Table I and l'ablc 2 of
Schedule 31 o f this Tariff. "]'he revised percentage cost allocation values shall then bc
used to compute monthl.~ charges lbr Reliabilit', Coordination Service [br the next twelve
months as specified in Schedule 3 I. On or before April ] of each ',ear in which the
applicable Service Agreement is in effect, the Transmission Provider shall provide to the
Reliability Coordination Customer a copy oftbe applicable charge cost allocation for the
twelve month period beginning April I, and a reasonable explanation o|'its calculation.

issued by: [. Graham Fidv,ards, Issuing Officer
Issued on: March 4+2008

t.f'fi:clive: June I, 2008

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FER(" Electric 'tariff. Third Revised Volume No I

77.6

Original Sheet No. 830S

Notwithstanding any other provision o f this Part 1 o f Module F, all

amounts paid by the Transmission Provider as the result o f fines or penalties imposed b~,
or associated ~s ith a NERC or a Regional l'ntit,, enforcement action shall be recovered
pursuant to a Commission-appro,,ed Tariff charge, and the Reliabilit', Coordination
Customer shall pay its allocated share o f such costs, on the same basis as other costs
included in the charges set forth in Section 77 o f this "1 ariff.

78

ReliabiliB" Coordination Technical Committee
78.1

A Reliability Coordination Technical Committee is hereby established.

The Transmission Provider and each Reliability Coordination Customer shall be a voting
member of the Reliability Coordination l'echnical Committee.

78.2

The Reliability Coordination l'echnical Committee shall also coordinate

its efforts with the Joint Coordinating Committee formed 1o address matters relevant to
and arising under services perfi',rmcd under Part 111 o f this Module F.
78.3

A member's representative in the Reliability. Coordination "lechnical

Committee shall be a person o f reasonable competent', and with such authorit) as to
uphold the decisions made, to the extent such decisions do not require formal appro'~al
under governing state laws and regulations.

Issued b): I. Graham Edv, ards. Issuing Of'ricer
Issued on: March 4. 2008

Effective: June 1. 200g

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FI~RC Electric larifl; "third Revised Volume No. I
"/8.4

Original Sheet No 8501"

The Reliability Coordination Technical Committee shall meet at least

quarterly during the first year after the effective date o f Pan I of this Module F, and shall
meet periodically thereafter as the Reliability' Coordination Technical Committee shall.
by a majority vote ofthree-lbunhs of those entitled to vote, determine to be necessary, to
pertbrm its duties in a reliable and ctt~cient manner.
78.5

In cooperation v, ith the Transmission Provider, and consistent with the

requirements of this Tariffand all applicable reliability standards, the Reliability
Coordination Technical Committee shall:
a.

review procedures for the implementation of the operating and
technical requirements o f Part I of this Module F;

b.

review and comment upon operating practices and guides to ensure
the safe and reliable operation of their facilities consistent v, ilh
applicable NERC and Regional Entity standards:

c.

identify procedures tbr coordinating and integrating the operating
and technical requirements o f Part I o f Module F with those o f Parl
III o f this Module |-;

d.

participate in the development o f Business Practice Manuals for
the administration of Part I of this Module F on a reliable and
economically efficient basis; and

e.

address other matters rel~:rred to in, or necessary' tbr
implementation, administration or operation of, Part I of this
Module F.

Issued b) : T. Grahanl Ed~ards. Issuing C)fl~ccr
Issued on: Xlareh 4, 2008

Ef]~.'ctivc:

June I. 2(108

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FERC Electric l'ariff, Third Re',ised Volume No. 1

'78.6

Original Sheet No. 850U

Recommendations and other actions of the Reliability Coordination

"1echnical Committee shall be by a three-fourths majoril3, of those present and entitled Iv
'~ole under Ihe rules adopted by the Reliability Coordination Technical Committee to
govern its proceedings. Nothing herein shall prohibit the Reliability Coordination
l'echnical Committee from developing rules and procedures regarding prox,, voting.
and/or procedures to alloy, electronic meeting or voting.
78.7

All proceedings and decisions of the R~liability Coordination Technical

Committee shall be reduced to writing and signed by the Reliability. Coordination
l'echnical Committee representatives, but such proceedings and decisions shall not be
inconsistent ',~,ith and shall not serve to contradict an)' terms or conditions of the l'ariff in
effect at the lime of such procedures or decisions being made or developed.
78.8

Participation in the activities of the Reliabilit? Coordination l'echnical

Committee by the Transmission Provider or b ) t h e Reliability Coordination Customer
shall not constitute a waiver by that entity of'any of its rights under the Federal Power
Act to initiate a proceeding, make any other filing, or advance any position regarding an',
matter before the Commission.

Issued by: I. Graham Ed'c.ards. IssuingOfficer
Issued on: ~,lareh4. 2008

Effective: June I, 2008

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FER(" I'lcctric Tariff, "t'hirdRevised Volume No I

78.9

Original Sheet N,.x 850',,'

l h e I,'~eliability Coordination Technical Committee may coordinate its

activities v, ith the activities o f the Reliabilib Subcommittee o f the "Iransmission
Provider's stakeholder group, and may vote to suspend some or all of the meetings o f this
committee in order to attend and participate in the activities o f the Reliabilit~
Subcommittee if the Charter of the Reliabilit,, Subcommittee pro,,idcs for such
participation.

il.

I N T E R C O N N E C T E D O P E R A T I O N S AND C O N G E S T I O N M A N A G E M E N T
SERVICE
l"reamble

The Transmission Provider shall provide,

subject to the terms and conditions of this Part

II of Module F, specific congestion management scr'.'ices, including rcdispatch of generation
within the Energy and Operating Reserve Markets, for interconnected transmission providers.

issued by: 1. Graham Edwards. ls~,uing Officer
Issued on: March 4, 2008

[:ft~:ctiv¢: June T. 2L)08

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79

Original Sheet No. 850\%

Eligibili~'
"19.1

"1o be eligible for Interconnected Operations and Congestion Management

Service under Ibis Part, a Congestion Management Customer must: (i) be a NERC
Registered Transmission Provider providing reciprocal transmission ser',ice pursuant to
an open access transmission lariffor other applicable tariff using transmission facilities
that are ph',sicall) connected to the Iransmission S~,stern; and (it) register as a Market
Participant pursuant to the l'ariff. A Congestion Management Customer ma3 not be,
during the time service is provided under Ibis Part II, a signatory' to the IS(.) Agreement.
As a condition to obtaining service, the Congestion Management Customer must execute
an applicable Service Agreement, as set lbrlh in Section 85 and Attachment KK-2 of this
Tariff, and provide to the Transmission Provider the inlbrmation required by this Part.

Issued b) : T Graham t-Zd~ards. Issuing Officer
Issucd on: ',larch ,1, 2008

Etli..cli~ e: June I, 20()~

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FERC Electric Taritl~ third Revised Volume No. I

80

Original Sheet No, 850X

"l'ransfer of Information and I)ala

80A

l'he Transmission Provider and the Congestion Management Customer (or

the Congestion Management Customer's tariff'administrator or P,eliabilit} Coordinator as
appropriate) shall transtbr to each other the follo~ ing types of'data and intbrmation:
(a) Real-Time and Projected Operating Data (80. I. I):
(b) SCADA Data (80.1.2);
(e) I-MS Models (80.1.3); and
(d) Operations Planning Data (g0.l.4).
The lransmission Provider and the ('ongestion Management ('ustomer shall
provide to each other the data identified in items (a) through (d) above ',~ith respect to all
transmission owners for which the,.' administer transmission service on the effective date
el'this Part and thereafter, whether or not the) administer such transmission service as of
the eft'ectivc date. "lhc Transmission Provider and the Congestion Management
Customer shall cooperate to supply such data and information (to the extent such
infbrmation is the subject of'this Part) as tile Independent Market Monitor may request in
order to facilitate monitoring in accordance v, ith the Transmission Provider's
Commission-approved market monitoring plan.

Issued b.,,: l Graham Ed',,,ards, Issuing Officer
Issued on: March .1. 2008

t't'fectb.,z: .tune h 20(18

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FI'RC El~'ctric t'ariff, third Rc~,isud Volum,.: No, l

Original Sheet No. 850'Y

"tO ensure the accuracy of all crilical opcraling data, the "i'ransmission Provider and the
(_'on[zcstion Management Customer ~',ill dcsi,gnat¢ to each other, a contact person to be
available t~ cnt\-Ibur (24) hours each da',, seven (7) da\s per ~'.cck, and an alternate
contact to act in the absence or unavailabilit', of the primal, contact, to respond to an)
inquiries. With respect to each contact and alternate, the "['ransmission Provider and the
Congestion Management Customer shall pro'~ide to each other the name. telephone
number, e-mail address, and lax number. The l'ransmission Provider and the Congestion
Iklana,gcmcnl Customer ma', change a dcsi,g,naled contact l'rom time to limc b v notice: to
each other's designated rcprcscntali'~c. ] h e I ransmission Pro',ider and the Congestion
Iklana,g,cmcnl Customer shall transfer data to each other in a limel',' manner consistent
~.ilh e×istin,g defined formats or such other lbrmats to which the',' m% agree. ]fan'.
required data transfer tbrmat has not been agreed upon as o f the clTective date o f this
Part, or if the Transmission Provider or the Congestion Iklanagcmcnt Customer
determines that an agreed formal should b¢ revised, it shall gi',,c notice o f the need for an
agreed |ormat or revision to the other part',, and the "i"ransmissiun Pro',ider and the
Congestion Management Customer will jointly seek to complete development of'the
Ibrmat within thirty (30) days of such notice. Upon agreement, development will be
compleled as soon as practical.

80.1.! "l'hc Transmission Provider and the Congestion Mana,g,crnent
Customcr shall exchange two categories of operating data. real-lime
information and projected information, as l'ollov, s:

Issued by: 1' (}rallam Edwards. [ssuin,~ Officer
Issu,~d on: \larch ,1, 2008

t..ll~cti',c: +lun~ i. 2008

10080306-0053

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PDF

(Unofficial)

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Midv,,¢st ISO
FHRC Elcclric l'arilT, Third Revised Volume No I

a.

Original Sheet No 850Z

The real-lime operating mlbrmation consisting of':
i.

generation status of'the units, as telemetered or as
deri'vcd from the unit breaker, in each part)'s tariff"
or |bolprint;

if.

transmission line status, i.e., status of" switching
devices associated with each end of'the line;

iii.

balancing authority area demands;

iv.

selected real-time telemetered bus loads ~ here
available;

b.

v.

scheduled use of reservations;

vi.

critical facility limits; and

Projected operating infbrmation consisting of."
i.
if.

merit order block loading:
generating unit and transmission facilities
maintenance schedules;

iii.

the planned operational start-up or change dates for
an:,' permanentl:, added, removed or significantly
altered transmission segments; and

iv.

the planned start-up testing and operational start-up or
change dates tbr an:,' permanently added, removed or
significantl:,' altered generation units.

Issued b',: I , Graham lidwards, Issuing OIlic¢r
Issuc'd on: Xlarch 4, 2008

l~fl~cti~e: Jun~ I, 2008

~0080306-0053

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(Unofficial)

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Mid'.',~sl ISO
FER(" Electric tariff. ]hird Revised \ ulumc No 1

Original Sheet No 850X.01

80,1,2 The I'ransmission Provider and the Congestion Management
Customer shall transfer data as set tbrth below, consistent with NERC
requirements for the transfer of data by balancing authorities and

Reliability Coordinators:
i.

The "]'ransmission Provider and the Congestion
Management Customer shall transfer requested SCAI)A
Data ',ia ICCP or ISN;

ii.

The I ransmission Provider and the Congestion
Management Customer shall accommodate, as soon as
practical, the other parl)"s requests for additional existing
]CCP/ISN bulk transmission data points, after the request
has been submitted;

iii.

The I ransmission Provider and the Congestion
Management Customer shall respond, as soon as practical,
to the other party's requests tbr additional, unavailable
ICCP,']SN bulk transmission data points, hut in an,,' event
no more than two (2) v, eeks after the request has been
submitted, with an expected availability target dale fbr the
requested data;

iv.

The Transmission Provider and the Congestion
Management Customer shall comply with all governing
confidentiality agreements executed betv,'een them relating
to ICCP/ISN data; and

IssuL'db',: I. Graham Edv,ards. Issuing.()ffi~:er
Issuedon: ,~larch4,200~

['l'fe,:tiv,,:: June I. 2008

0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/2008

Midwest ISO
FERC Electric ] arit'T~Third Revised Volume No. I
v.

Original Sheet No. 85[)Z 02

All ICCP data transit'fred hetveeen the "1ransmission
Provider and the Congeslion Management Cuslomer shall
be transferred "via ISN (NERCNel), unless another transt~r
platlbrm is olhur',,, isc agreed upon.

80.1.3 The Congestion Management Customer and/he lransmission
Provider shall exchange EMS models once a year in the common
information model ( " C I M " ) lbrmat adopted by the NEKC Data Exchange
Working Group, or in an olherv,'ise agreed-upon [ormaL with monthly
updates to he provided as new data b,acomes available. This ~ earl',

lranslcr v, ill include the ISN data definition fries, identification or"
individual bus loads, seasonal equipment ratings and one-line drav, ings
that will be used to expedite the model conversion process, lhe monthl)
updates represent the incremental changes thal have occurred to the EMS
model since the last monthly update.
80.1.4 Upon the writlen request of either the Transmission Provider or the
Congestion Management Customer, the other part,,, shall provide the
in|brmation specit~ed in Sections 80.1.4. I through 80.1.4. I I of this Tariff.
Each request shall specify the intbrmalion sought and the frequenc,., upon
w'hich it shall be provided, and. with respect to Sections 80.1.4.6.80.1.4.7,
and 80.1.4.8, the reason why provision of the information is n e c e s ~ ' to
achieve the objectives of Part II of this Module F.

Issued by: I. Graham Ed~vards,Issuing Ot~cer
Issued on: March 4. 2008

I~ffectivc: Jun~:I. 2008

~0080306-0053

FERC

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(Unofficial)

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Midwest ISO
FIiI~.CElectric Tariff Third Re',iscd Volume No I

Original Sheet No 850Z 03

If the Transmission Provider or the Congestion Management Customer
receives a request under this Section, it shall provide the information
promptly to the extent the intbrmation is available.
80.1.4.1 - F l o w g a t e s :

i.

Flowgatc definitions including seasonal FI'C, TRM,
CBM, and appropriate muhipliers;

ii.

FIo',sgates to be added to OASIS Rcquest
Evaluation processes on demand, if needed
immediately fbr reliabilil} ;

iii.

last of Coordinated and Reciprocal Coordinated
Flo~

iv.

gates;

List of Flowgates to recognize ~',hen processing
transmission service (if different than list of
Coordinated and Reciprocal F/o~vgates);

v.

Operating Guides; and

vi.

Requirements under Section 81.1.7 ofthis Tariff

80.1.4.2 - T r a n s m i s s i o n S e r v i c e R e s e r v a t i o n s :

i.

Daily list of all transmission service requests,
hourly increment of new requests and status
changes on existing requests;

ii.

List of reservations to include and to exclude: and

iii.

Requirements under Sections 81.1.4 and 81.1.5 of"
this Tariff.

Issued by: 1 Graham Ed',sards, Issuing Officer
Issued on: Xlareh 4, 2008

Fffec0ve: June I. 2008

t0080306-0053

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(Unofficial)

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Midwest ISO
FER(" Electric Tariff, Third Revi~,edVolume No I

80.1.4.3

- AFC

Original Sheet No. 850Z.04

Data:

"lhe Transmission Provider and the Congestion Managernent
Customer eurrentl) meet and '.'.ill continue to meet a minirnum periodicity
lbr calculating and posting AFCs. l h e minimum periodicity depends on
the service being offered. The tbllowing AFC data will be provided:
i.

I lourly for the lirst seven (7) days posted at a
minimum, once per hour;

ii.

l)ail? tbr days eight (8) through thirD-one (31 )
posted at a minimum, once per da~; and

iii.

Monthly for months two (2) through thirt,,-six (36)
posted at a minimum, once per month.

80.1.4.4 - Load Foree,,st:

]'he Transmission Provider and the Congestion Management
Customer ",,,'ill provide the following load forecast information.
i.

Hourly for next sc~,en (7) da\s, daily for da', s three
(3) through thirty-one (31), and monthly for months
two (2) through thirty-six (36) submitted once a
day:

ii.

Identify whether the load fbrecast is for Balancing
Authority' Area or sub-Balancing Authority Area
(by company within the Balancing Authority Area)
[brecast;

issued by: I. Graham Fdv,ards. IssuingOfficer
Issued~>n: March 4. 2008

I'ffi.'cti',.u: June 1.20()8

0080306-0053

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Original Sheet No 850Z 05

Midv, csl ISO
FEll(" Elcclric Tariff, Third Revised Volume No I

iii.

Indicate whether this includes transmission s) stem
losses, and if it does, indicate v. hat the percent
losses are:

iv.

Identil}. non-conforming loads, as dctined b',
NER(?;

vii.

Indicate h(r~s, municipal entities, cooperatb.es and
other entit,, loads are treated; indicate v, hether the)
are included m the forecast; and, if so. indicate the
total load or net load after remo', ing other entity
generation: and

,,.
80.1.4.5 -

Requirements under Section 81.1.6. of this Tariff.
Generator Data:

i.

Unit ov, ner. bus location in modeF

ii.

Seasonal ratings, PMIN, PMAX, QMIN, QMAX:

iii.

Station auxiliaries to extent gross generation has
been reported;

iv.

v.
vi.

Regulated bus, target voltage and actual voltage;
Planned maintenance; and
Real-time output (MW & Mvar) with net generation
after being reduced for station auxiliaries preferred.
80.1.4.6 - Jointly-Owned

i.

Issued b): [" Graham I-dwards, Issuing Officer
Issued on: ".larch ,1, 2008

Units:

Deemed ownership shares;

|~t'l~:cU,,e: June I, 2008

t0080306-0053

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Midv, cst ISO
FERC Electric larifl; I'hird Re',ised Volume No I
ii.

Original Sheet No 850Z.06

Treatment as pseudo tie or dynamic/static
schedules;

iii.

Rules tbr sharing output between joint o,,,,ners o f
those unils lhat affect the operating seam bet~,,een
the I ransmission Provider and the Congestion
M a n a g e m e n t Custurner; and

iv.

Transmission arrangements between joint owners.

80.1.4.7 - Intermittent Generation:

i.

Accredited capacit) ;

ii.

Planned maintenance;

iii.

Whether aggregated generation or generation by
piece o f equipment:

i',.

~'hether all output is tagged; and

80.1.4.8 - Balancing Authority Area Net Interchange from
Reservations and Tags:

i.

A n y grandtathered agreements that do not appear in
OASIS; and

ii.

If tags and reservations can no longer be used to
develop balancing authority area or zone net
interchange, merit order block loading inlbrmation
w'ill be needed for all generators in the balancing
authority area/zone.

Issued b): l. Graham fldv, ards, Issuing Officer
Issued on: March 4. 2008

lille:eli',c: June I, 2008

~0080306-0053

FERC

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(Unofficial)

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Midwesl ISO
t:I!R(" I{leclric l'ariff, I'hird Rcxiscd Volume No. I

Original Sheet No. 850Z.07

80.1.4.9 - Dynamic Transfers:

i.

List of dynamic transl~rs;

ii.

Identification of each dynamic transfer as a
d) namie schedule or pseudo-tie, as defined b.,,
NERC; and

iii.

Requirements under Section 81.1 of this l'ariff.

80.1.4.10 - Controllable Devices:

i.

List of controllable devices that may include: phase
shiflers, I)C lines, and back-to-back AC/DC
con',criers; and

ii.

Operating practices of the controllable devices.

80.1.4.11 - G e n e r a t i u n a n d T r a n s m i s s i o n O u t a g e s :

i.

Generation Outages that are planned or forecast, as
soon as practicable after they are identitied,
including all data specified in Section 81.1 .l of this
Tariff;

ii.

Transmission Outages that are planned or forecast,
as soon as practicable after they are identified,
including all data specified in Section 81.1.3 of this
Tariff; and

iii.

Prompt notification o f all forced Outages of both
generation and transmission resources.

Issued b) : I. Graham Edwards, Issuing Offic,er
Issued on: March 4, 2008

Effccti',,e: June I, 2008

0080306-0053

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Midwest I ~O
FERC EIl:ctric "Tarifl~ lhird RcvisL:dVolume No. I

80.2

Original Sh~:,.:tNo, 850Z 08

l'he Transmission Provider and the Congestion Management Custorner

shall periodically confer regarding the need to transfer an', information other than that
identified tbr transfer in Section 80.1, and shall negotiate in good faith to make
agreements for the transfer of such additional information as is necessar,, to achieve the
objectives of this Part.
80.3

l h c Transmission Provider and the Congestion Management Customer

shall bear their o;,,n cost of pro,,iding intbrmation to each other 'xlrsuant to Sections 80A
and 80.2 of this Tariff

81

T T C / A T C / A F C Protocols
81.1

As oftbe effective date of this Part. the Transmission Provider and the

Congestion Management Customer shall use: tile N[",RC S',stcm Data Exchange ("SDX")
S',stem to transfer the status o f generators, Outages of all intcrconncctions and other
critical transmission [acilities, and peak load tbrccasts, v, hich has the capabiLib to house
daily data for the next seven (7) days. weekly data for the next month, and monthly data
for the next )'ear. The specific criteria for satisfying the requirements of this Section gl
shall be set forth in the "ITCIATCIAFC Protocol which shall be incorporated into and
made a part o f t b e Service Agreement executed by the Congestion Management
Customer and the Transmission Provider pursuant to Section 85 and Attachment KK-2 of
this Tariff.

Issued by: l" Graham I-dssards,IssuingOtliccr
Issuedon: ~.larch4, 2008

Et'[~cti',~: JuneL 2(708

0080306-0053

FERC

PDF

(Unofficial)

03/06/2008

Midwesl ISO
FHRC lilectric ] arilT,Third Re'.,isedVolume No. I

Original Sheet No 1150709

81,1.1 rbe "rransmission Provider and the Congestion Management
Customer shall provide each other with projected status of generation
availability over the next tv,,clve (12) months. I f information is available,
the "[ ransmission Provider and the Congestion Management Customer
ma} provide more than l'a.elve (12) months of infbrmation regarding the
projected status o f generation availability, rbe Transmission Provider and
the Congestion Management Customer '.',ill update this data no less lhan
once daily lbr the full posling horizon and more ofien as required by
system conditions, rh¢ data '.','ill include complete generation
maintenance schedules and the most current generator availability data.
such that each part) is aware oflhe "'return dale" o f each generator subject
to a scheduled or lbrced outage.
81.1.2 As necessary to permit the Transnfission Provider and the
Congestion Management Customer to develop a reasonably accurate
dispatch tbr the calculation o f r l C and A rC/AFC values under any
modeled condition, they shall provide each other with a t>pical generation
merit order or the generation participation factors of all units on an
affected balancing authority area basis. The generation merit order ',,.ill be
updated as required by changes in the status of the unit; however, a new
generation merit order need not be provided more often than prior to each
peak load season.

Issued b.,,: I GrahamF.dv,ards, Issuing Officer
Issuedon: March 4, 2008

[il'fecfivc: Jun,¢ I, 2008

0080306-0053

FERC PDF

(Unofficial)

03/06/2008

Xlidwcst I SO
FLR( Electric larifl~ third Rcvis~:d Volume No. I

Original Sheet No 850Z.10

81.1.3 The Transmission Provider and the Congestion Management
Customer shall provide each other with the projected status of
transmission outage schedules over the next twelve (12) months or more it"
available. This data shall b¢ updated no less than once daily fbr the fidl
posting horizon and more often as required by system conditions. The
data will include current, accurate and complete transmission facilit,,
maintenance schedules, including the "'outage date" and "return date" e r a
transmission facility from a scheduled or forced outage.
81.1.4 The ]'ransmission Provider and the Congestion Management
Customer shall make available to each other their interchange schedules,
as required to permit accurate calculation o F T I ' C and ATC/AFC values.
Due to the high volume o f this data, the Transmission Provider and the

Congestion Management Customer shall either post this data to an FTP
site for download or shall request NERC to modify the IDC to allow fbr
selected interrogation by each other.
81.1.5 The Transmission Provider and the Congestion Management
Customer shall coordinate transmission service requests as follows:

Issut:d b'. : l'. Graham Edwards, I,~suing Officer
Issued on: klarch 4, 2008

I'tfecti,.~:: Jul;¢ t. 2~1g

~0080306-0053

FERC

PDF

(Unofficial)

03/06/2008

Mid~est ISO
FERC Electric "l'arit]~third Revised Volume N~ I

Original Sheet No 850Z.II

81.1.5.1 l'he Transmission Provider and the Congestion
Management Customer shall make available to each other, on an

FfP site. all transmission service request information available tbr
inlcgralion inlo their AI'('/AFC calculation process, lhe
Transmission Provider shall provide transmission service request
information from its OASIS Node. l'he Congestion Management
Customer shall provide transmission serv ice request information
from the Congestion Management Customer OASIS Node.
81.1.5.2 The l'ransmission Provider and the Congestion
Management Customer shall develop practices for modeling their
transmission service requests, including external third part),
requests. ]"he Transmission Provider and the Congestion
Management Customer shall provide each other with the
procedures developed and implemented to model in/re-part)
requests under the Congestion Management (_'ustomer's
transmission tariffand other designated tariffs thal may be used to
provide transmission service.

Issuedh>: T Grahaml'dwards. IssuingOffic~:r
Issm..don: March4. 2008

Effecti',,t:: June I, 2008

0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/2008

M idv, L.'st ]SO
FI'RC Electric tariff, Third l,[c'~.isgd Volume No. I

Original Shout No. 850Z.I 2

81.1.5.3 Transactions are not included in A I'C/AFC detcrminalkms
if'the impacts fi'om the transmission service request are alrcad)

accounted in a base case model or some other component o f the
ATCiAFC calculation. The I ransmission Provider and the
Congestion Management Customer shall create and maintain a list.
on an FTP site, of'transmission service requests on their OASIS
Node lhal are not included in their own A I'C/AFC determination
process, so that the transmission service request is excluded in
each other's anal) sis.
8 I, 1.6 The Transmission Pro','ider and the Congestion Management
Customer shall transl~.r peak load dala for each period (e.g., daily, v,'eekly,
and monthly). Because peak load ',.alucs rnay only apply to one (I) hour
of the period, additional assumptions rnust be made v, ilh resp,,.'ct to load
level when not at peak load conditions. For the next seven (7) da,,
horizon, the Transmission Provider and the Congestion Management
Customer shall either supply hourly' load fbrccasls or they shall supply'
daily peak load forecasts with a load profile.

Issued by: J', Graham t~d',',ards, Issuing ()fl~cer
Jssucdon: %larch4,2008

Effective: June I, 2008

0080306-0053 FERC PDF

(Unofficial) 03/06/2008

Mid'.,,cst ISO
I.I'RC Electric larifl: l'hird Revised Volume No. I

Original Sh¢,.'t Xo. 850Z. 13

81.I.7 t o determine ifa transmission service reservation (or interchange
schedule) will impact Flo~,,,gatesto an extent greater than the (firm or
non-firm) A]:C and to assure that the l'ransmission Provider and the
Congestion Management Customer respect each other's Flov.gates, the
l'ransmission Provider and the Congestion Management Customer will
transfer Firm and Non-firm AFC tbr all Coordinated Flov, gates. The
Transmission Provider and the Congestion Management Customer will
continue to accept or reject transmission service ruquests based upon
projected Ioadings on their own Flowgates as ',','ell as the Ioadings on the
other party's Flov, gates so as not to exceed the posted AFC.
81.1.8 The Transmission Provider and the Congestion Management
Customer ,,,,ill transfer (seasonal, normal and emergenc.,) Fhw, gate
Ratings as well as all limiting conditions (thermal, ',ohage, or stabilit?).
"The Transmission Provider and the Congestion Management Customer
',,,'ill update this information in a timel> manner as required b.', changes on
the transmission system.
81.1.9 In accordance with Attachment l.l. of this Tariff] F[o'~,,gates that
have a response factor equal to or greater than the distribution factor cutoffmust be included in the evaluating party's model to the extent
inclusion is practical. ]'he Transmission Provider and the Congestion
Management Customer shall use the response factor cut-off that the
owning/operating party uses for its Flowgate in its AFC detemfination
ellbrts.

Issued b): I. Graham Edv, ards, l:.,suing Officer
Issuctl o n : March 4, 200g

[£ff¢cti'.e: Jun,~ I, 2008

0080306-0053

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Midv, est I SO
FERC Electric l a n t l , Ihird Revised \ ohmic No I

Original Sheel x;o. 850Z. 14

~1.1.10 l'he Transmission Provider and the Congestion Management
Customer will ensure that ;nil significant system changes are incorporated
in their TTC/ATC/AI"C calculation models. Although this inlormation
and additkmal, detailed data are included in the MMWG cases, this data
transfer mechanism v, ill address the major changes that should be included
in the "Iq'C/AI'C/AFC calculation models in a more timel,, manner. This
data transfer v. ill occur no less often than prior to each peak load season.
In addition, the Transmission Provider and the Congestion Management
Customer agree to translbr T'IC/AI'C/AFC calculation models o f their
transmission systems as soon as mechanisms can be established to
t=acilitate this transfer.
81.1.11 Follov, ing standardization of'I'I'C,'AI'C/AFC calculations
pursuant to Commission order and action b v N[!RC and NAESB, the
Transmission Pro',ider and the Congestion Management Customer shall
confer to determine ~ hether the protocols continue to be necessary, and if

so, what revisions it) the protocols or this Part ma? be required Io comply
~,,ith the current standards and practices, l'he Transmission Provider and
the Congestion Management Customer shall cooperate in good faith to
implement such revisions as quickly as possible.

Issued b~: T. Graham Ed~ards, Issuing Officer
Issued on: b.larch 4, 2008

E:ffective June I, 2008

0080306-0053 FERC PDF

(Unofficial) 03/06/2008

b.tidwest IS()
FER(" Electric rarift; third Revised Volume No. I

82

(,)riginalSheet No 850Z.15

Reciprocal Coordination of Flowgates
82.1

In order to coordinate congestion management proactively, the

Transmission Provider and tile Congestion Management Customer agree to respect each
other's determinations of AFC/A'IC and curtailment priorities Ibr real-time operations
applicable to their Coordinated Flowgates (C}:s). Additionallb. the "I ransmission
Provider and the Congestion Management Customer agree to respect the allocations
defined b,, the reciprocal allocation process set forth in the Congestion Management
Process (CMP), v, hich is set forth in Attachment I,L to this l'ariff.
82.2

The process and timing for exchanging ATC.,'AFC calculations and Firm

Flow calculations/allocations with respect to all RCFs are set lbrth in the CMP.
82.3

The Transmission Provider's and the Congestion Management Customer's

capabilities and real time actions shall be governed by and in accordance s', ith the
coordination process for RCFs, as set forth in the CMP.
82.4

The "l"ransmission Provider will utilize its Unit Dispatch S)stem

(t.:DS)

and Securit?,'-Constrained Unit Commitment (SCUC) in effect at the time to manage the
portion of the flows on an RCF allocated to the Transmission Provider. The Congestion
Management Customer's Reliability Coordinator will utilize NERC TI,R process to
manage the portion of the flows on an RCF allocated to the Congestion Management
Customer.

Issuedby: T GrahamEd',vards,lssuingOfficc:r
Issuedon: klarch 4. 2008

Effective J.,me1,2()0g

0080306-0053

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M id',,,est ISO
FERC Electric "l'arifl~ third Revised Volume No. I

82.5

Original Sheet No 850Z.16

"['o the extent that the Congestion M a n a g e m e n t C u s t o m e r is an o w n e r o f

rights to transmission capacity on tacilities comprising the North Dakota Export flowgate
{ " N D E X " ) , and one or rnore other owners ot'such rights are either l'ransmission Owners
or Market Coordinaliun Customers under this l'arit'f, the l'ransrnission Provider and the
Congestion Management Customer ,,',ill manage congestion on the NDEX flowgate
consistent ',',ith existing agreements among the owners of'such rights rather than as an
RCI. under Attachment I,L of'this Tarifl~

83

Generation Redispaleh and Compensation
83.1

"['he Congestion Management Customer's Reliabilit) Coordinator v, ill use

the NI'RC "]LR procedures to mitigate congestion on the Congestion Management
Customer's "1ransmission System. As a condition o f service under this Part, the
Congestion Management Customer shall redispatch generation under its control, as set
tbrth in Section 83.2 through Section 83.6 of this Tariff, for the purpose o f relieving
actual or contingency overloads on Designated Flov, gates.

Issued by: l" Graham Edwards. issuing Officer
Issued on: \larch 4, 2008

l.~tlkcli,,e: June I, 200g

0080306-0053

FERC

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03/06/2008

Midwcsl ISO
FERC l!Ict.:tri¢ l'arifl. "third Revist:dVolumeXo I

g3.2

Original Shcct No. 850Z. 17

Upon each other's request, the Transmission Provider and the Congestion

Management Customer shall contk:r to idcnti[~,: (i) transmission operating constraints
that could result in TI.R or other emergency procedures in order to alleviate the
transmission constraints, the need for ~,.hich could bc reduced or eliminated by the
redispatch of generation controlled by the Congestion Management Customer. and (ii) the
generation units on the Congestion Management Custonler's system, the redispatch of
v, hich '~,,ould alleviate the identified transmission constraints. In the event that the
Transmission Provider and the Congestion Management Customer identify,' such
additional transmission constraints and generation units, the applicable Service
Agreement may be amended to include such additional transmission constraints and
generating units. Agreemenl to such additional transmission operating constraints or
generation units shall not be unreasonahl~ v, ilhhcld.
83.3

The following redispatch procedures shall apply to generation redispatch

arising under this Part II:
83,3.1 Redispalch procedures (operation procedures) Ibr each flowgate
shall be developed and agreed upon in writing b) the Transmission
Provider and the Congestion Management Customer prior to providing
redispatch service. Implementation of the operating procedures shall be
coordinated with the Congestion Management Customer.

Issu~:db): !Graharn I!d',,,ards.Issuing()flio:r
[ssucd on: March4.20(),~

Ktl~:¢ti'.:: JuneI, 200g

0080306-0053

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Mid;,,est ISO
FERC Electric Tarit1~ I hird Revised Volume No I

Original Sheet No 850Z.18

83.3.2 IfTI,R is called on a transmission flowgatc subjccl to this Part,
then the Transmission Provider may request that the Congestion
Management Customer redispatch one or more of the units identified in
the applicable Service Agreement or pursuant to Section 83.2 bereofto
alleviate the l'ransmission Provider's TI,R assigned impacts on the
transmission flo',~,gate.
83.3.3 Upon such request, the Congestion Management Customer x,.ill
redispatch, under the direction of the Transmission Provider, one or more
of the units identified in the applicable Service Agreement or pursuant to
Section 83.2. In no event shall the Congestion Management Customer be
required to redispatch or cycle the output of an) unit if such rcdispatch or
cycling: (i) may impair the safe and reliable operation of the Congestion
Management Customer units; (ii) is inconsistent with Good Utility
Practice; or (iii) is contrary to any NERC requirement, or any legal or
regulatoD rule. standard or prohibition.

Issued by: I Graham Edwards, Issuing Off)oct
Issucd on: March 4, 2008

Hl~.'ctivc: June l, 2008

0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

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FERC El¢~,:tri¢:"l'arift~ lhird Revb:,edVolume No I

Original Sheet No. 850Z. 19

83.3.4 The Congestion Management Customer ',,,ill not implement a
redispatch request under this Section 83.3, unless and until the
Transmisskm Pro', ider verifies the availability and deliverability into the
Congestkm Management Customer's system of replacement p o ~ e r from
the Energy and Operating Reserve Markets, if such po;,~er is required by
the Congestion ManagEment Customer. If the Transmission Provider and
the Congestion Management Customer do not concur on the availability
and deliverabiliD ofreplacemcm pmser, and that the purchase o f such
power as described in Section 83.4 of this l a r i ff can be: completed ,,s ithout
creating adverse conditions elsewhere on the s', stems of either party, the
Congestkm Management Customer ,a ill not implement the redispatch
request.
B3.3.5 If initiating a redispatch request involves a time commitment for
the Congestion Management Customer's generators such as minimum run
times, minimum down times and/or a fuel delivery' commitment period.
this will be provided in the response to the request for redispateh and ~sill
be factored into the decision to proceed with the redispateh request.

Issued b) : t" Graham Edwards, Issuing Officer
Issued on: \tarch 4, 2008

I!ff¢¢tiv¢: June I, 2008

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Original Sheet No. 850Z.20

83.3.6 I f there is mutual agreement between the Transmission Provider
and the Congestion Management Customer to implement a redispalch
request, it ~,ill be implemented at a starl lime that may differ from the
beginning of the hour. Like~,ise. the Transmission Provider and the
Congestion Management Customer each retain the right to discontinue a
redispatch request in the event the redispaleh is no longer needed or the
generators being used for redispalch are needed for other purposes, l'he
redispateh '.,,ill be discontinued at a mutually agreed upon stop time v, hieh
ma'. differ from the end of the hour.
83.3.7 "lhe Transmission Provider and the Congestion Management
Customer shall operate their s'.slems in good faith and, consistent '~, ilh
Good Utility Practice, to avoid dispatching generation or taking other
actions lbr the sole purpose o f causing or increasing congestion on
flowgates thal are subject to this Parl II of Module F.

Issued b,',' l', Graham l-dv,ards, Issuing ()t'ficcr
Issued on: ".larch 4. 200S

Efli.,elive June 1,200g

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X|id~cst 1 5 0
FERC t-lectric Tarif't~Third Revised Volume No. I

83.4

Original Sheet No. 85OZ21

The Congestion Management Customer and the l'ransrnission Provider

shall be compensated as follows for redispatch service.
83.4.1 During the period of time that the Congestion ,Management
Customer reduces the output of its units in response to a request from the
Transmission Provider in accordance with Section 83.3. and does not
simultaneously increasc the output ofone or more Congestion
Management Customer units on the opposite side of the constraint to equal
or exceed the decrease in output of the decremented units, the Congestion
Management Customer shall purchase from the Midwest IS() Real:lime
lincrgy and Operating Reserve Market at the Congfstion Management
Customer-Transmission Provider interlace, a quantit', ofencrg)equal to
the megawatl hour quantity of the net reduction in output for the duration
of the net reduction in output. 1"he price lbr such purchase shall be the
Lo~ational Marginal Price in ¢ffi:ct over such time at the Congestion
Management Customer-Transmission Provider interfhee node. The
l'ransmission Provider and the Congestion Management Customer shall
develop an Operating Procedure for the implementation ofredispatch
requests under this Agreement. I f the Operating Procedure is fbllowed for
a redispatch request, the Congestion Management Customer shall not be
required to pay any Revenue Sufficiency Guarantee charges that v, ould
otherwise be associated with purchases under this Section 83.4. I to
comply with that redispatch request.

Issuedby: [' GrahamEdv,ards.IssuingOfficer
Issucdon: March4.2008

El1~,.:tive: ~un¢ I. 2(7'08

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FIiR(" I'lectric tariff, Ihird Revised Volume No. 1

Original Sh~'et No 850Z.22

83.4.2 For each occasion that the Congestion Management Customer
increases the output of its units in response to a request from the
l'ransmisskm Provider in accordance with Section 83.3, and does not
simultaneously decrease the output of+one or more Congestion
Management Customer units on the opposite side of the constraint to
match at least the increased output of the incremented units, the
l'ransmission Provider shall arrange, for and on behalf of the Midwest IS()
Market Participants, the deliver} of a quantity ofcnergy ti'om the
Congestion Management Customer equal to the megawatt hour quantity of
the net increase in output for the duration o|'the net increase in o u t p u t .
The price for such delivery shall be the I.MI' at the Congestion
Management Customer-Transmission Pro', ider interface node

the time

at

of each occasion. If the Op,,zrating Procedure relkrred to in the preceding
Section 83.4. I is [bllov, ed lbr a rcdispatch request, the Congestion
Management Customer shall not be required to pay any Revenue
Sufficient) Guarantee charges that v,ould otherwise be associated v, ith
purchases under this Section 83.4.2 to compb with that redispatch request.

]ssm:db',: l" Grahaml!d~.~.ards, lssumgOfficer
Issued ~m: ",,larch ,l, 2008

Lffi:cti;e

June 1,2008

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F|qRC Electric larifl, l'hird Rc~,iscd Volume No. 1

Original Sheet No 851)Z.23

83.4.3 For each occasion that the Congestion M a n a g e m e n t
Customer increases the output o f its units in response to a request
from the "l'ransmission Provider in accordance v. ith Section 83.3 o f
this 'larifE and simultaneously decreases the output of'one or more

Congestkm Managemcnt Customer units on the opposite side of
the constraint to match the increased output of the incremented
units, no purchase from the Real- ['ime l!ncrgy and Operating
Reserve Market is required,
83.4.4 In addition, the Transmission Provider shall be obligated to
pax and shall pa', to the Congestion M a n a g e m e n t ( u s t o m e r , b,,
and on behalf o f the Midwest ISO Market Participants. in
accordance with the tbllov, ing:

Issued b.',: 'l Graham Ed'.'*ards, Issuing ()tlicer
Issued on: Mari:h 4. 2008

['fleetly,,:: June L 2~)~)B

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FERC Electric larift, l h i r d Revised Volume No. I

Original Sheet No 850Z.24

83.4.4.1 When the Congestion Management Customer
decreases the output of" its units in response to a request
From lhe l'ransmission Provider in accordance with Section
83.3 of this l'arifl'and there is not an offsetting and equal
increase in the output o f Congestion Management
Customer units on the opposite side of the constraint as
described in Section 83.4. I, the I ransrnission Provider
shall pa~, to the Congestion Managernent Customer an
amount equal to the amount thai the Congestion
Management Customer pays to the Iransrnission Provider
For the energ', purchases described in Section 83.4.1 o f this
l'ariff, plus an',' transmission and transmission related
charges billed to the Congestion Management Customer to
effect the rcdispatch request (including an adjustment to
rellect increased l'ransmission Provider energy market
resettlement charges totaling $200.00 or more in an).'
month, related to previous redispatch events), minus the
"Change in Total System Cost".

Issued bx: I. Graham Ed;~.ards,Issuing Officer
Issued on: March 4, 2008

l.llk:ctivc: June I, 2(X)8

3080306-0053 FERC PDF

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Midv.cst IS()
FER(" |'leclric l'arift, l'hird Revised Volume No. 1

Original Sheet No 850Z.25

If'the amount the Congestion Management Customer pays
to the Transmission Provider tbr energ', purchases
described in Scction 83.4. I o f this Tariff is less than the
"'Change in l o t a l System Cost," there ,,,,ill be no
l'ransmission Provider payment to the Congestion
Management Customer.
83.4.4.2 VJhen the Congestion Management (.'ustorner
increases the output of its unils in response to a request
from the 1 ransmission Provider in accordance v, ith Section
83.3 o f this Tariff and there is not an offsetting and equal
decrease in the output of Congestion Management
Customer units on the opposite side of the constraint as
described in Section 83.4.2, the "1ransrnission Provider
shall pay to Congestion M~magement Customer an amount
equal to 110% of the "Change in Total System Cost," plus
the Congestion Management Customer's applicable startup costs and the cost for minimum generation output, plus
any transmission and transmission related

Issuedby: l. Gr~dlaml!dwards, lssuingOfficer
Issued on: March.1, 2008

Eft~:ctive: June 1,2008

0080306-0053 FERC PDF

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Mid~est ISO
FI'RC I-I,:~:tri~:I arit'f. Third Revis~.'dVolume No. I

Original Sheet No. 850Z,26

charges billed to the Congestion Management Customer to
effect the redispatch request (including an adjustment to
reflect increased Transmission Provider energy market
resettlement charges totaling $200.00 or more in an)'
month, related to previous redispatch events), minus the
amount the Transmission Provider pays to the Congestion
Management Customer for energy deliveries arrangi.'d tbr
and on behalf of the Mid,,,,est IS() Market Participants. as
described in Section 83.4.2. 1t"110% of'the "'Change in
l'ota] System Cost" is less than the amount the
"[ ransrnission Provider pa~,s to th~ Congestion Management
Customer for cnerg~ deliveries arranged for and on behalf
of the Mid~,.est IS() Market Participants ~ls described in
Section 83.4.2. the I ransmission Provider v, ill pay the
Congestion Management Customer only fbr its applicable
start-up costs and cost for minimum generation output.

Issued b~: 1 Graham [!d~ards, Issuin~ OFfic~:r
Issued on: ~,larch4, 2008

Et't~:cfive: June t, 200~,

3080306-0053 FERC PDF

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\lidwest I SO
FERC Electric I aM'f, third Revised Volume No I

83.4.4.3

Original Sheet No 850Z.27

When the Congestion Management Customer

increases the output of its units in response to a request
from the Iransmission Provider in accordance v, ith Section
83.3 o f this Tariff and there is an offsetting and equal
decrease in the output of Congestion Management

Customer units on the opposite side or'the constraint as
described in Section g3.4.3.1he "l ransmission Provider
shall pay 110% of the Congestion Management Customer's
"Change in l'otal S)stem Cost" plus an) applicable start-up
costs and the cost tbr minimum generation output.
83.5

In addition to the redispatch procedures set fbrth in this section/br the

redispateh o f the Congestion Management Customer's generation, the Congestion
Management Customer may request a shado,,~ price that represents an estimate o f the
redispatch cost o f the Transmission Providcr's generating resources to mitigate the
Congestion Management Customer's assigned TI,R requirements. If the Congestkm
Management Customer requests the Transmission Provider to perform a Manaa~
Redispatch o f the Transmission Provider's resources, the Congestion Management
Customer shall pay the Transmission Provider for and on behalf of the Midwest ISO
Market Participants in an amount equal the Manual Redispatch Energy volume multiplied
b) such shadow price.

Issued b}: "l'+Graham Edwards, Issuing Officer
Issued on: \tarch 4. 2008

F.ffccfi,,e: June I. 2008

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83.6

Original Sheet N o 850Z.28

The amounts paid by the Transmission Provider to the Congestion

Management Customer lbr redispalch during any hour under this Part v. ill b¢ funded
fi'om congestion charges collected as part of'the real-time settlement, l'o the extent that
congestion charges collected as part of the real-time settlement are not sufficient to fund
the payment to the Congestion Management Customer. the remaining payment shall be
funded prc~ r~l{a by Market Participants on a load ratio share basis, where load ratio share
is equal to the sum ot~ (i) v, ithdra'.va]s at Commercial Nodes, excluding ~ ilhdra',~.als
associated ~,.ith Carved-Out GFAs and (ii) Exports. The amounts paid to the
lransmission Provider from the Congestion Management Customer lbr redispatch during
any hour under this Part '.,,'ill be added to the congestion charges collected as part ofthe
real-time settlement and distributed to Market Participants on a load ratio share basis,
,.,.here load ratio share is equal to the sum o f (i) "~,ithdrav,'als at Commercial Nodes,

excluding ~,,ithdrawals associated with Carved-Out GFAs and (ii) Exports.

Issued b~,: ] Graham Edv, ards, IssuingOfficcr
b:sut:d on: Mar~.-h 4, 2008

[-l'I~:liv~: Jun,e t, 2(~3~

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Midv, est ISO

Original Sheet No 850Z.29

FERC Elc~tric lariff l'hlrd Rc',i~,ed Volume NI~. I

83.7

The billing and pa'.ment terFns for this Part shall be as set lbrth in Section

7.20 of this Tariff
83.7.1 When applicable, the Transmission Provider shall pa', the
Congestion Management Cuslorner all sums due Ibr each redispatch
request, determined in accordance with Section 83.3 and Section 83.4
abow.'. Within twelve (12) calendar da)s o f each redispatch e',cnt, the
('ongeslion Management Customer shall provide an invoice sho,,,, ing the
hours, and the costs incurred by Congestion Management Customer during
each hour, and an) other costs (including the l'ransFnission Providcr's
encrg) market and transmission charges described in Sections 83.4.4. I and
83.4.4.2) to compl', with a redispatch request under this Part. Failure to
provide the invoice ',~ ithin the twelve day period v. ill not excuse, but ma.',
dela), payments duc to the Congestion Management Customer until the
next scheduled settlement period.

Issued b) : l" GrahamtZdwards,Issuing ()Nicer

Issuedon: %tarch4, 2008

[.~('t~ctive: June l, 2008

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Mid',,,¢sl IS()
FERC El¢¢lric; l'arlff. I bird Revised \ olume No. I

(.)ri~inal Sheet No. 8.~0Z.30

Purchases ofenerg.v by die Con,~'estion Manag.emcnt Customer from the
Transmission Provider under Section 83.4.1 of this Pan and Markel
Participant charges normall~ billed to the Congestion Management
Customer, ",sill be netted againsl sums o~,ing to the Congestion
Managemen! Customer tbr redispatch ser,,ice under this Part. The
Transmission Provider will invoice or pa', the Congeslion ~,lanagemcnt
Customer the net arnount o~ed or credited tor all energ', purchases and

other Congestion Management Customer Market Parlk:ipant charges,
pursuanl to the terms and conditions of Section 7.20 or'this Tariff.

Issued by: 1" Graham I!dwards, Issuing OMcer
Issued Lm: Nlarch 4. 2008

I.flkctive: June I, 2008

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Y',,Iid ,,,,cst IS()
FERC Electric: l'aril1~ ]hird Revised Volume Nt~. I

Original Sheet No 850Z.31

83.7.2 All net settlements o',~.ing to the Congestion Management
Customer shall be due and payable by the Transmission Provider pursuant to the
terms and conditions o f the "l'arifl~ v.'hethcr or not a Party disputes all or an','

portion or'the amount o~ ing to the Congestion Management Customer fbr
rcdispatch service under this Part. Payment or acceptance of+disputed amounts
shall not be a w a i v e r o f a party's right to challenge the correctness o f that amount.
or to pursue dispute resolution process o f the l ' a r i f f including Comrnission rc',.iev,

of the correctness of such amounts. Net settlements ox~ing to the Transmission
Pro', idcr shall be due and payable pursuant to the terms and conditions of Section
7.20 of this Tariff.
83.7.3 As to a Congestion Management Customer to "~,hich 5cction 121!
of this Tariffis applicable, the obligation to make the payments under this
Section is subordinate and junior in all respects to the obligation of the
Congestion Management Customer to pay the principal and interest on its
bonds.

84

Coordinated Operations and Planning
84.1

The Transmission Provider and the Congestion Management

Customer acknowledge that voltage control and reactive power coordination are
essential to maintain reliabilit),. "rhcrelbre, the Transmission Provider and the
Congestion Management Customer shall establish procedures ("Voltage and
Reactive Power Coordination Procedures") by which their respective Reliability
Coordinators shall conduct such coordination.

Issued b~,: I . Grahan't Edv, ards, Issuing ()t'l~cer
Issued on: \larch 4, 2008

F.~,.:tiv¢: Jur,e I, 2{~{~

3080306-0053 FERC PDF

(Unofficial) 03/06/2008

Midv.est ISO
t:ERC Electric "l'atiff. l h i r d Ri:,,ised Volume No. t

84.2

OrJ~ina~ Sheet No. 850Z.32

The Transmisskm Provider and the Congestion Management

Customer will perlorm regional transmission and generation outage coordination
in order to identify proposed transmission and generation maintenance that would
create unacceptable reliability-related s',stem conditions and ~ ill v, ork with the
fhcility o~sners to provide remedial steps to be taken in advance of such proposed
maintenance.
84.3

"Theobjectives of the planning coordination process are to make

certain that appropriate and adequate reviews of transmission planning ['unctions
are pertbrmed between the Transmission Provider and the CorLgestion
Management Customer on a collaborative basis to ensure comparabilit}.
efficiency and timeliness. The l'ransmission Provider and the Congestion
Management Customer shall coordinate their planning processes b.,, exchanging
planning information required under this Part and through joint cooperation
betv~een their respective Planning Authorities.
84.4

"lhe'Iransmission Provider and the Congestion Management

Customer shall make transmission capacity available within their transmission
systems for generation reserve sharing. Subject to any applicable Commission
rules, regulations or orders, the Transmission Provider and the Congestkm
Management Customer shall reserve the required TRM, or its equivalent, for its
generation reserve sharing pool requirements. The part)' responsible for making
transmission capacity available for the reserve sharing obligation shall bear the
costs of any redispatch required to make the transmission capacity a,,ailablc.

Issued by: "['. Graham Edwards, Issuing Officer
Issued on: March 4, 2008

Ell¢cti~¢: June I. 2008

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Original Sheet No, 850Z 33

Mid;',es! IS(9

FERC I{lectri¢Iariff, l-hlrd Revised Volume No I

85

Sen'ice Agreement
85.1

The Transmission Provider shall offer a standard Ibrm Ser~,icc Agreement

lbr Interconnected Operations and Congestion Management Services to the entity eligible
to receive the Interconnected Operations and Congestion Management Service. Executed
Service Agreernents that contain the intbrmation required under this Part shall be liled
with the Commission in compliance ~aith applicable Commission regulations. The
standard lbrm ol'Service Agreement for Interconnected Operations and Congestion
Management Services is provided in Attachment KK-2 to this Tariff
85.2

The "l'ransmisskm Provider and the Congestion Management Customer

shall cooperate in good [aith in making an), filings before the Commission that ma> be
required to implement the terms of this Part or an),' applicable Service Agreement or to
facilitate their eftbctive dates. Whenever practicable, such 111ingsshall be made
simultaneously with each other.
86

Records
86.1

"[he l'ransmission Provider and the Congestion Management Customer

shall keep complete and accurate records relating to the pertbrmancc of their respective
obligations, as well as any calculations necessary in the performance of such obligations,
under this Part and shall maintain such data as may be necessary' for the purpose of
ascertaining that their ~rfbrmance, or calculations in support of such perlbrmance,
conforms to the standards set |brth in this Part, including, but not limited to, data
supporting the calculation of'I'l'C, TRM, ATC/AFC, and RCF allocations.

Issuedby: I' GrahamEdwards,Issuing()flic~:r
Issued,an: \larch 4, 2008

l'ffcctiv~:: JuneL 200g

3080306-0053 FERC PDF

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Midwest IS()
FI'~RC Llet:lri¢ I'arilg, third Revised Volume No. I

86.2

Original Sheet No. 850Z.34

The Transmission Provider and the Congestion Management Customer

shall maintain the complete and accurate records required by Section 86.1 lor a period of
one -,ear from the end of the fiscal year during "e,hich the obligations were performed.
Within that one ,.'ear period, either the Transmission Provider or the (2ongestioo
Management Customer ma~, request in writing copies of the records of the other party to
the exlent reasonably necessary to verif} thal the pertbrmancc, or calculations in support
of such pertbrmance, contbrms to this Part. The costs of the data review, including costs
related to retrieving, compiling, reproducing and analyzing an', data requested pursuant
to this provision shall be borne by the party making the request.
86.3

Any access to the Transmission Provider's books and records shall be

subject to applicable confidentiality and CEll requirements and procedures, as may' be
provided in the Tariff or Commission rules, regulations or orders.
87

Revenue Distribution.

87.1

Nothing in this Part II shall be interpreted to modil~,' an', prior agreement

betv,'een the Transmission Provider and the "1"ransmission O',,, ners regarding revenue
distribution.

Issued b.,,: T. Graham l!dv, ards, Issuing Officer
Issued on: March 4, 2008

Ftl~:cti',e: June I, 2008

~0080306-0053

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FER(" Electric Taritl~ third Revised Volume No I
87.2

Original Sheet No 850Z.35

For an.'.' charges not insoiced pursuant to Section 83.7 of this l'ariff the

Congestion Management Customer shall render invoices to the "1ransmission l'rovider lbr
amounts due in accordance with the Congestion Management Customer Customer's
customary billing practices and pa',mcnt shall be due in accordance v, ith the Congestion
Management Customer Customer's customary payment requirements. All payments
shall be made in immediately available liands pa',ablc to the Congestion Management
Customer b) xs ire transtcr pursuant to instructions set out h) the Iransmission Provider
and the ('ongestion Management Customer from time to time. Interest on an.', amounts
not paid when due shall be calculated in accordance with the methodolog} specified for
interest on refunds in the Commission's regulations at 18 C.I:.R. § 35.19a(a)(2)(iii).
88

Effective Date and Term
88.1

l'he initial term of the Interconnected Operations and Congestion

Management Service shall be for a period of three (3) years alier tile effective date o f the
Service Agreement executed pursuant to Section 85 and Attachment KK-2 o f this Tariff.
l'he Service Agreement shall automatically renc~ thereaIter for successive one (I) year
terms unless v, ritten notice o f termination is provided not less than one )'ear prior to the
end o f the initial or any subsequent term. The Service Agreement shall also terminate
and cease to be effective upon the mutual agreement by the parlies to terminate the
Service Agreement or upon Commission order terminating the Service Agreement. "l'he
effective date of the Service Agreement shall be the date set forth therein or any other
date as may be established by the Commission.

Issued b) I. Graham Edv.ards, Issuing Officer
Issued on: Mardl .I.2008

Eft~.'cti',e: June I, 2008

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FERC Electric Iarifl] third Rcvis,ed \'tllunle No l

88.2

Ori~.in~[ Sheet No. 850Z 36

A Congestion Management Customer to v. hich Section 121.:of this Tariff

applies ma? terminate its Service Agreement executed pursuant to Section 85 and
Attachment KK-2 of this Tariff'at an.', time during the initial term or any extension
thereof ~ith less than the required onc-~ear notice, in the event that the statutes
governing such Congestion Management Customer. or any provisions of this Part II of
Module F, or the provisions of the Transmission Provider's Tariff incorporated b:~
refercnce in this Part II Module f. arc changed or modified, in a manner that causes a
conflict ~ ith state lay,, regulations, or rate schedules and the re',ie~,, process described in
Section 12E of this 1 ariff is unable to resolve such c(mllict.

88.3

Upon ~rittcn notice to the l'ransmission Provider that Congestion

Managerncnt Customer is exercising its right to terminate its Service Agreement under
Section 88.2 of this Tariff, the Transmission Provider and the Congestion Management
Customer ~,.ill work in good thith to make all required arrangements to resume as soon as
possible, but not to exceed thirty (30) days from such v,'ritten notice, all normal operating
conditions and provide transmission service on their respective systems without regard to
the requirements o f this Part II.

Issued b',: T. Graimm Edv.ards, Issuing Officer
Issued on: Xlllrch 4, 2008

t-ftccti',,e: June I, 2008

20080306-0053 FERC PDF

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i:ERC I-le~:tricl'arifl\ third Revised Volume No. I

III.

MARKET COORDINATION

Original Sheet No. 85()Z,37

SERVICE

Preamble
The "1ransmission Provider will provide Market Coordination Service to integrate into the
Energy and Operating Reserve Markets the resources and loads interconnected to transmission
f~cilities that are not included in the Transmission System, as set forth in this Part.

89 Eligibility
89.1

Market Coordination Customers eligible for service under this Part III

must be transmission providers providing transmission service on lhcilities that are: (i)

interconnected with the facilhies of a Transmission Owner; (ii) interconnected with the
fhcilities of another Market Coordination Customer taking service pursuant to this Part
111;or (iii) interconnected with the facilities of a Congestion Management Customer
taking service under Part l[ of this Module F that offers transmission service pursuant to
terms and conditions that arc consistent ~ith or superior to the terms and conditions set
forth in Attachment M M o f this Tariff.

Issued by: l, Graham Edwards, Issuing Officer
Issued ~n: March 4, 200t~

Effccti'.,c: June I, 2008

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FERC Electric I arifl, third Rc'.ised Volume No I

89.2

Original Sheet No 850Z.38

A Market Coordination Customer taking service under this Part III must

also take the Reliability Coordination Service under Part I of Module F of this Tariff.
89.3

A Transmission Owner shall not bc eligible fbr service under this Pan 111

until it has v~ithdrawn frorn the IS() Agreement pursuant to Commission approval, if
applicable, and has paid its ',,,ithdrav, al obligation under the ISO Agreement. Nothing in
this Part II1 of Module F shall be interpreted as an alteration of. or a limitation on, or to
othcrv, isc af'lect, the right of the Transrnission Pro', idcr or the right o f a Transmissitm
Owner to make filings pursuant to Sections 205 and 206 o f the Federal Power Act.
90

Nature of Market Coordination Service

90.1

Market Coordination Customer Facilities

90.1.1 The Transmission Providcr shall not provide any transmission
service on Market Coordination Customer rransmission l.acilities. All
forms of'transmission service on Market Coordination Customer
Transmission Facilities shall be provided by the Market Coordination

Customer pursuant to its tariff consistent with the specific terms of this
Part 111 o f Module F and the Market Coordination Customer's obligations
thereunder.

Issm.,d h) : T (iraham I'd~ards, Is~,uingofficer
Issucd on: March 4, 2008

Effective: June I, 2008

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Original Sheet No 850Z.39

90.1.2 The Market Coordination Customer shall determine, and provide
to the Transmission Provider. a list of the facilities to be included as its
Market Coordination Customer l'ransmission Facilities, v, hicb shall be
facilities used lbr the transmission of electric energy in interstate
commerce, and facilities for which the "1ransmission Pro',ider has
responsibility for Reliability Coordination Service under Part I of Module
F o f this ]'ariff.
90.1.3 On an annual basis, the Market Coordination Customer shall
reviev, the determination of facilities to be included as Market
Coordination Customer Transmission Facilities in Section 90.1.2, and
shall notil~.' the Transmission Provider o f an,', facilities to be added to or
removed from the list of Market Coordination Customer l'ransmission
Facilities.

Issued b',: I Grahaln I'd',,.ards. Issuing Officer
Issued on: ",larch 4. 2008

l:ffi:clivc: June I. 2(108

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FERC Electric lariff, Third Revised ~. olume No I

90.2

Original Sheet No. 850Z.4O

Market Coordination Service

The I ransmission Provider will provide the Ibllowing Market Coordination
Service on the terms and conditions set Ibrlh in this l'arifl':
90.2.1 The l'ransmission Provider ssill integrale the resources and loads
in the Customer Zone ~sith the l!nergy and Operating Reserve Markets b',
including the Market Coordination Customer Transmission Facilities and
loads and resources in the Customer Zone in the Net',sork Mode] and the
Commercial Model. All resources and loads in the Custon-ler Zone must
be registered to participate in the t-nergy and Operating Reserve Markets,
including resources and loads in or outside the Customer Zone that are
Pseudo Tied into the Midwest ISO Balancing Authorit) Area, hut
excluding loads and resources in the Customer Zone thai are Pseudo Tied
out of the Mid',~.est ISO Balancing Authority Area, and each of such
registered resources and loads must he represented b', a Market
Participant.
90.2.2 The Transmission Provider ,,,,ill manage transmission congestion in
the Transmission Provider Region using Security Constrained lieonomic
Dispatch that includes redispatehing Generation Resources, as set forth in
Module C of this Tariff.

Issuedby: [" Graham['dv, ards, tssuinBOfficer
Issued or): March 4, 2008

Et~:~:~ive: June 1,200B

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Original Sheel "-~o. 850Z 41

Ifa Market Coordination Customer holds rights, other than transmission
tariff service entitlements, to transmission capacity across the North
Dakota l!xpon llo,,,,gate ("NI)I!X'). as established and documented
through l.liRC-filed documents, or through existing contracts, operating
agreernents, and operating guides that are specified in the Service
Agrc(:menl executed b) the l'ransrnission Provider and the Market
Coordination Customer pursuant to Section 96 of the "]'aril]: the
Transmission Provider ',',ill implement SCED on the NDEX llo'.~gate
consistent with existing agreements among the holders of such rights,
rather than as an RCF under Attachment [.,[,. The Market Coordination
Customer shall designate in its Service Agreernent KK-3, and from time to
time update as required, the NDI'X capacity available Ibr use b) the
Transmission Provider for the dispatch of the loads and resources in its
Customer Zone. The Market Coordination Customer shall make avai}able
on a non-discriminatory basis to its transmission customers, to other
Market Coordination Customers. and to Transmission Customers of the
Transmission Provider, an)' remaining rights it may hold across the NI)I{X
llov, gatc in excess of the agreed-upon use set forth in the Attachment KK3 Service Agreement. In addition, the Transmission Provider and each
Market Coordination Customer '.','ill honor each other's rights when
evaluating requests for long term transmission service under their
respective tariffs.

Issued b): T. Graham Edwards, Issuing Ot]icer
Issued on: March 4, 2008

F.fl~cli~ e: June 1, 2008

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FERC l:leclric I arit], Third RevisedVolumL:No. I

Original ,'sheetNl~ 850Z.42

90.2.3 Market Participants that arc customers tinder the Market
Coordination Customer's tariff'are eligible to receive ARR Entitlements
on the terms and conditions established in this "]'ariff~ provided that:
(I) they are taking net~ork integration transmission scrvice and/or firm
poinl-lo-rx)inl ser',icc that is comparable to Net',~ork Integration
Transmission Service and/or Firm Point-to-Point Transmission Service
under Module 13 of the fariff; (2) the',' have entered into a long-term
agreement for firm transmission service on the Market Coordination
('ustomer's transmission s',slem; (3) they timely submit the necessar',
infbrmation to the l'ransmission Provider: and (4) they timel? meet the
other applicable requirements of the Tariff and Business Practices
Manuals. Subject to compliance with the foregoing conditions, iflhe
transmission planning and expansion process of the Market Coordination
Customer's tariff contains a provision for customer participation in the
transmission planning process and also includes a transmission expansion
process that demonstrates a mutual obligation to the Market Coordination
Customer and the Transmission Provider to maintain simultaneous
fi:asibility across the Combined Systems by' expanding their respective
transmission systems to serve Net~ork Load, then beginning the first full
allocation year of'the Market Coordination Customer's participation in the
Energ~ and Operating Reserve Markets. and in every full allocation )'ear
of its participation thereafter, customers under the

rssucd by: T Graham [-dwards, Issuing Officer
Issued on: March 4, 2008

El'fee(ire: June 1, 2008

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FERC Electric luritl~ Ihird Revised Volume No I

Original Sheet No 850Z.43

Market Coordination Customer's tariffshall also be eligible to participate
in Stage IA of the Annual ARR Allocation process. When a Market
Coordinatkm Customer first participates in the Energy and Operating
Reserve Market during, rather than from the start oI~ an allocation year its
customers shall be eligible to participate in a partial-)ear alk~ation o f
F I R s lbr the remainder o f such allocation 5ear. During the Annual ARR
Registration. the customers o f the Market Coordination Customer must
register their existing rights by providing int~.mnation requested b', the
Transmission Provider. A Market Participant serving bundled retail load
in the Customer Zone of a Market Coordination Customer pursuant to a
state approved retail electric tariffthat imposes an obligation to serve
under state lay, shall be deemed to have satisfied the requirements for
eligibility to recei'~e ARR Entitlements under this Section 90.2.3.

Issued b.', I Graham hd,.sards. Isst, ing Officer
lssu~.+d oil: March 4, 2008

i!t't~ctive: Jul;¢ 1.2008

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FER(" l!lec(ric Iarifl~ third Revised x, olume No. I

Original Sheet No. 850Z 44

90.2.4 To enable the integration ot'rcsources and loads into the dispatch
of the Energy and Operating Reserves Markets. the follou, ing
requirements shall apply to preexisting agreements to ~shich a Market
Coordination Customer taking service under this Part is a party if such
preexisting agreements appl) to loads or resources that are or ~ ill be
registered to participate in the Energ) and Operating Reserves Markets:
90.'2.4.1 As a precondition lbr receiving service under this Part Ilk
a Market Coordination Customer that is a part) to a Carved-Out
GFA listed in Attachment P o f the "1aril'f: to ',',hich the onl', other
parties are another Market Coordination Customer or a
Transmission Owner. will be required, fbr the period of til'ne
during ',',hich the Market Coordination Customer takes service
under Part 111 o f Module F, to convert such Carved-Out GFA to
Option A or Option C treatment, in accordance ;,,ith the
requirements o f Module C of the Tariff, or permanently convert
such Carved-Out GFA to service under the terms of'this l'arifl"
and/or its tarif'E Any Market Coordination Customer that is a puffy
to an Option B GFA with a Transmission O'~,ner. as listed in
Attachment P of this Tariff, shall be eligible to receive service
under this Pan 111.

Issued by: T Graham lid'.,.ards. Issuing Officer
Issued on: March 4. 2008

Etl~ctive: June I, 20U8

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FER(" [ilcctric latiff, 7bird Re:vised x,olume No. I

Original Sh,:¢t No. 85tJZ.45

90.2.4.2 As a precondition lor receiving ser~,ic¢ under this Part Ill,

a Market Coordination Customer shall provide to the l'ransrnission
Provider detailed information about ever) agreement that obligates
the Market Coordination Customer to provide transmission service
on Market Coordination Customer Transmission Facilities
(including as a component of"bundled" service) to the extent such
an agreement is not included in Attachment P of this l'arifl: l'he
inlbrmation that the Market Coordination Customer is required to
provide under this S,ection 90.2.4.2 shall be in the template adopted
b) the Commission in the "1ransmission Provider's GFA
proceeding in Docket No. ER04-691. "lhe Transmission Provider
shall intbrm the Market Coordination Customer within sixty (60)
days after receiving the infbrmation required whether the
agreement has been correctly identilied by the Market

Coordination Customer. l h e Market Coordination Customer shall
have the right to appeal the I ransmission Provider's determination
made under this Section 90.2.4.2 directly to the Commission under
Section 206 of the Federal Power Act.

Issued b>: T Graham £d~ards, Issuing Otlieer
Issued on: March 4. 2008

Effective: June I, 2008

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FERC l'leclric l'ariff, Third Revised Volume No I

Original Sheet No. 850Z 46

90.2.4.3 The Market Coordination Customer and the affected
parties to each preexisting agreement identified in Section 90.2.4.2
shall select the appropriate treatment to be accorded each such
agreement under the l"arifl"
(i)

preexisting agreements subject to a just and reasonable

standard of review ma~ choose:
a. Option A or Option C treatment under the l'ariff; or
b. I:ull conversion to transmission service under the Tariff
and/or the open access transmission tariff'of the Market
Coordination Customer.
(ii)

preexisting agreements shall be identified as Carved-Out

GFAs under Section 38.8.4 o f the Tariff, to the extent that:
a. They are subject to the public interest standard of
review;
b. They are silent on the applicable standard ofreviev,; or
c. The) provide tbr transmission service b)' an entity that
is not a public utility.

Issued b): I. Graham Ed~ards, Issuing Officer
Issued on: March 4, 200g

I ffecli',e: June 1, 2008

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~.1id',,.cst 150
Ft~RC t!lcctric tariff, lhird RevisedVolu[r~eNo I

Original Sh,..'etNo. 850Z 47

90.2.4.4 Parties to preexisting agreements identil]cd in Section
90.2.4.3 (ii) may voluntarily choose Option A or Option C
treatment under the "1aritt~ or full.,, convert to transmission service
under the Tarill"and/or open access transmission tariFf o f the
Market Coordination Customer. Parties that convert to
transmission service under an applicable t a r i f f o r this T a r i f f cannot

revert to carved-out status.
90.2.4,5 If the parties to a preexisting agreement other~visc
eligible for Carved-Out GFA treatment under Section ~0.2.4.3
(ii)do not voluntarily select Option A or Options C treatment, or
conversion to service under the Tariffand/or under the Market
Coordination Customer's tarifl~ then. subject to the Balancing
Authority requirements imposed b) Section 90.2.5.3. each such
preexisting agreement shall be treated as a Carved-Out GFA,
provided, that, not~,~,ithstanding any other provision of the "l"ariff.
in case o f a n y insulliciency of the revenue needed to cover the
Costs of Congestion relating to such preexisting agreements, the
revenue shortfall shall be funded through assessments on all load
in the relevant Customer Zone that is not served under a
preexisting agreement subject to this Section 90.2.4.5.

Issued b.~: I Graham L-:dv,ards, Issuing Otl'~:er
Issuedon: March 4. 2008

Eflkcli',,¢: Jun~ t. 200?,

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FERC Eleclric Tariff, l'hird Revised Volume No. I

Orit~inal Sllcei No. 8501.40

90.2.5 The lbllo',~.ing balancing authority requirements shall appl)to
Market Coordination Customers:
90.2.5.1 It'the Market Coordination Customer is a balancing
authority, prior to obtaining service under this Part, the Market
Coordination Customer shall sign the Balancing Authorit)
Agreement, and shall be bound b) the terms and conditions of'that
agreement lbr the term or'the applicable Service Agree:men( and
an),' renev~al term thereol~ in order to permit the Transmission
Provider to perlbrm those Balancing Authorit,,, functions required
to sat'el,, and reliably operate and administer the I'nerg.', and
Operating Reserve Markets in the Market Coordination
Customer's Balancing Authority Area.

Issu~.'db) : 1'. Graham Edwards. Issuing ()filter
Issued on: ('.larch 4, 2008

Effecti'.,~: June ], 2008

3080306-0053 FERC PDF

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Mid;,,est ISO
FERC Electric "rariff, Ihird Revised Volume No. I

Original Sheet No 850Z.49

90.2.5.2 If the Market Coordination Customer is not a balancing
autborit), and the balancing authority from whom the Market
Coordination Customer receives balancing authority scr,,,ices is nol
a Transmission ()~ ner or a Market Coordination Customer
receiving services under this Part, the Market Coordination
Customer shall take such measures, and install such metering and
other equipment, It) alloy, the Transmission Provider to perform all
necessary balancing authority functions fbr the Market
Coordination Customer.

Issued by: I. (.;raham Edv, ard~,, Issuing Officer

Issued on: March 4, 2008

Eff~cti',e: June 1, 2008

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FERC Elcctric I ariff, lhird Revised Volume No. I

Original Sheet No, 850Z.50

90.2.5.3 l'he Marke( Coordination C'ustomcr shall amend, or
exercise its rights under its transmission tariff or other applicable
agreements to require that for the period of time during which the
Market Coordination Customer is taking service under this Part [I[:
(i) its transmission customers with load or resources in its
Customer Zone or located in its Balancing Authority Area, or in its
Balancing Authoril? Area, shall appl) to the l'ransmission
Provider to become Market l>articipanls and submit to the
Transmission Provider infbrmalion it requires to register their
loads and resources as required b) this "I arif'f: or (ii) that such
transmission customers either become balancing authorities or
make other arrangements for the provision o f such services b:, a
NERC certified Balancing Authori b .
90.2.5.4 To the extent required b', NIZ~RC or Regional Enlit)
standards, the Transmission Provider ~ill enter into such
emergent) assistance or similar agreements with balancing
authorities thal adjoin the Market Coordination Customer
"l"ransmission Facilities, for such period of'time as the
Transmission Provider continues to perlbrm the balancing
authority functions for the Market Coordination Customer under
this Section.

Issued b}: 1". (3raham l~dwards, issuing Officer
Issued on: ~.larch 4. 2008

I-fl"ccli~¢:

June I. 3008

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FERC Electric Tariff, Third Revised Volume No. I

Original Sheet No. 850Z.51

90.2.5.5 If the Market Coordination Customer terminates service
under this Part for an) reason other than to become a Transmission
O w n e r under the ISO Agreement, the Market Coordination
Custorncr must make all necessary arrangements to resume all
balancing authority obligations [br its balancing authori b area, or

to have a NI!RC certified Balancing Authority. assume those
obligations, h) the date upon v, hich service under this Part ,,',ill
end. I f the Market Coordination Customer has not made such
arrangements b,, the date service under this Part 111 is to be
terminated, such service, including the provision of Balancing
Authorit> services by the l'ransmission Provider, shall continue
until the Market Coordination Customer has completed ¢.uch
arrangements.
90.2.6 The Transmission Provider ~,ill act as the Reliability Coordinator
for the Market Coordination Customer Transmission Facilities in
accordance with the responsibilities specified in Part I of this Module F
(but excluding Section 76 of this Tariff). For Market Coordination
Customers taking service under Part l of Module F, the congestion
management process described in Section 76 of the "l"ariffis replaced in its
entirety by the terms and conditions for congestion management set tbrth
in this Part.

Issued by: ] Graham I'd~ards, Issuing Otl~cer

Issuedi')n: March4, 2008

Effective: June I, 2008

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FERC Electric Tariff. l'hird Revised Volume No. I

Original Sheet Nt~ 850Z 52

90.2.7 The Transmission Provider ',,.ill facilitate the coordination of
transmission planning tbr the Combined S', stems by providing the Market
Coordination Customer with transmission planning intbrmation relevant to
transmission service over the Combined Systems, including the Midwest
ISO Plan, on request, and by conducting joint planning meetings and other
requirements necessary to satisl~.' any state or federal regulator,,
requirements applicable to the planning process, lt'the Market
Coordination Customer is a member of a regional planning group, the
Transmission Provider v, ill coordinate planning activities as described in
this section with that regional planning group.
90.2.7.1 Nothing in this Part shall be construed to either permit or
require the Market Coordination Customer to participate in the
Midwest ISO Regional t-xpansion Criteria and Benefits ("RbCB"
process, or to have the Market Coordination Customcr's
transmission lacility expansions included in the RECB allocations
or to permit or require the l'ransmission Provider to allocate any
costs of the Transmission System to the Market Coordination
Customer via the RI(CB process.

Issued b,',: I. Graham l'dwards, Issuing Officer
Issued on: March 4, 2008

[!ffccti~ c: June l, 2008

2 0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

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Mid,.,.est I.'SO

I-ERe"l-l¢ctric Tariff\ "third Rc,.isL:dVolumeNo I

90.2.8 t he "l'ransmission Provider and each Market Coordination
Customer shall coordinate System Impact Studies, Facilities Studies and
generator interconnection studies conducted bv the Transmission Provider
v, ith those conducted b> each Market Coordination Customer (or
conducted, on the Market Coordination Custorner's behalf, by an
independent transmission servicc coordinator or tariffadministrator) lbr
transmission service requests and generation interconncction requests over
the Combined Systems:
90.2.9 The Transmission Provider shall coordinate the calculation o f
AT('IAI:CfI'TC pursuant to the mutuall', agreed-upon methodology
indicated in the Ser~,ice Agreement executed b) the Market Coordination
Customer pursuant to Section 96 and Attachment KK-3 of'this "l'arif~ The
ATC/AFCITTC methodology ',,,ill be posted on the Midwest ISO OASIS.
90.2.10 "lhe Transmission Provider and each Market Coordination
Customer will review system impact sludies and facilities studies
conducted b) the Market Coordination Customer (or conducted on the
Market Coordination Customer's behalf b3, an independent transmission
service coordinator or tariffadministrator) for tariffservice that would
result in a candidate request lbr an FTR or ARR, to determine whether of
such service is simultaneously feasible, as provided in the Tariff.

Issued by: l' Graham [-dwards, Issuing Officer
Issued on: ~,larch 4, 2008

E|+f~cti',e: June I, 2008

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FERC I'lcclric larill, Ihird Re',iscd

90.3

Original ~,hcet No SSOZ,54

Volume No I

Optional Tariff Administration And Related Services

Nothing in this Part III shall be interpreted to preclude the Transmission Pro',ider
and the Market Coordination Customer from entering into an agreement to provide
optional tariffadrninistration and related services.
90.4

Transmission Provider Discretion

lhe Transmission Provider shall have reasonable discretion in accordance with
Good Ulilil) Practice as to the manner in ',,,hich it provides all services available under
lhis Part IlL provided thal the "I ransmission Provider shall act in compliance ;',ilh the
provisions o f this Part. the Funds Trust Agreement, applicable NI£RC and Regional
Enlit) standards, and the applicable tariffs governing the I ransrnission S,.slcm and the
Market Coordination Customer l'ransmission Facilities.

Issued by: ]'. Graham Ed~ards. Issuing ()fficcr
Issued ,an: March ,I, 2008

Ef'|'ccliw:: June I, 2008

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Mid~ esl IS()
FEP,C fde~:t~icTarifl] Third Re',ised Volume No. I

91

Original Sheet No. 850Z 55

Market Coordination Customer Obligations

91.1

l'he Market Coordination Customer shall: (i) execute the separate Service

Agreements tbr the Market Coordination Service under this Part Ill, as set forth in
Section 96 and Attachment KK-3 of this "l'arift: and tbr the Reliability Coordination
Service under ["art 1 of Module F, as set forth in Section 74 and Attachment KK-I of this
l'ariff; (ii) become a registered Market Participant pursuant to the Tariff belbre receiving
Market Coordination Service under this Part 1o the extent that the Market Coordination
Customer has a direct ownership or contractual interest in the resources specified under
Section 90.2. I and/or the Market Coordination Customer is a load serving entit) under
the Market Coordination Customer's tariff: (iii) ensure that any other resources and loads
in the Customer Zone, excluding resources or loads in the Customer Zone Pseudo Tied
out o f the Midv~est IS() Balancing Authority Area. are notified that the)' must be
represented by a Market Participant; (iv) comply with all requirements, including all time
limitations, lot integrating the loads and resources in the ('ustomer Zone, including loads
and resources in the Customer Zone Pseudo Tied into the Midwest IS{.) Balancing
Authority Area with the operation of the linerg~, and Operating Reserve Markets, as set
forth in the "Fariffand the related Business Practices Manuals.

Issued b~,: I. (]raham t'Zdv.ards,Issuing Officer
Issued on: March .l, 2008

Efl~.'cti,.e: June I, 2008

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Midwest ISO

Original Sheet No. 850Z 56

F|~R(" I!leetric I aritl, t'hird Revi~ed Volume N o I

91.2

I h e Market Coordination Customer shall calculate the components of

available transmission capabilit3, and available flow',gate capability tot its transmission
lacilities in accordance with NERC and Regional Entit'. requirements binding on the
Markct Coordination Customer by `',a) of contract, or provided on the Market
Coordination Customer's behalf by an independent transmission service coordinator or
tari ff administratnr.
91.3

A Market Coordination Customer taking service under this Part shall offer

to provide the equivalent of Other AncillaL', Services to transmission customers taking
scr',ice under the Market Coordination Customer's tariff. All such services ',',ill be
provided and offered under rates, terms and conditions that are consistent with
Commission regulations and orders, to the extent applicable, l'he Market Coordination
Customer shall not be required to continue to provide and offer these services if the
Commission no longer requires a utilit', operating as a balancing authority to offer them.
All Market Participants. including Market Participants representing loads and/or
resources in a Customer Zone, shall have a Regulating Reserve obligation as specified
under Section II1 of Schcdule 3 of this Tariff; a Spinning Reservc obligation as specified
under Section 111 of Schedule 5 of this l'ariff, and a Supplemental Reserve obligation as
specified under Section III of Schedule 6 of this Tariff. Market Participants may satis~'
these obligations as specified under Schedules 3, 5 and 6 of this Tariff. A Market
Coordination Customer providing Regulating Reserve, Spinning Reserve and
Supplemental Reserve to its transmission customers in its Customer Zone under
Schedules 3, 5, and 6 of its tariffshall obtain such services from the Midwest ISO Energ)
and Operating Reserve Market.

Issued b~: T Grah;lm l?d~ards, Issuing ()filter
Issued on: March 4. 2008

El'fcctiv~: June I, 2()08

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FER(" I-Icctric Iarift. lhird Revised Volume No I

91.4

Original Sheet No 850Z 57

As a condition ot'receiving any ser~,ices under this Part, the Market

Coordination Customer shall revise its tariff to include the pro Jorma Market Integration
l'ransmission Service tariff provisions, as set tbrlh as Attachment MM of this Tariff.
91.5

l'he Market Coordination Customer shall provide the Transmission

Provider, as required by and in the time limitations contained in the l'arill"and Business
Practices Manuals, v, ith all such intbrmation as is reasonably necessary fbr the
l'ransmission Provider to provide the services under this Part. Such intbrmation, if
deemed to be C['II or confidential shall be so designated by the Market Coordination
Customer and ',,,.ill be treated as such b ) t h e Transmission Provider in accordance vdth
the Tariff and applicable Commission regulations. l h e information required by the
I ransmission Provider includes, but is not limited to, the tbllov, ing:
91.5.1 transmission planning inlbrmation tbr transmission lhcilities that

has an impact on transmission service over the Combined Systems:
91.5.2 notice of granting any application for nelxvork integration
transmission service under the Market Coordination Customer's
transmission tariff and the lime of receipt of said application(s):
91.5.3 notice of granting any applications for firm point-to-point
transmission service under the Market Coordination Customer's tariff and
the time of receipt of said application(s);

Issued b',: I Graham Edv, ards+ Issuing Officer
Issued on: March .l, 2008

Et]i:ctive: June I, 2008

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83/86/2888

Mid',,,est ISO
FFRC Electri,: larifl" lhird Revised \'t~lume No. 1

91.5.4

Original Sheet No. 850Z.58

notice of granting an',' applications for network resource

interconnection ser.,ice under the Market Coordination Customer's tariff
and the time of receipt of said application(s);
91.5.5

all resources and loads that are required to bc modeled in the

Network Model and the Commercial Models: and
91.5.6

an',' additional information reasonabl', rcquired b.', the

"1ransmission Provider to provide services to all Market Coordination
Customers pursuant to this Part.
91.6

All transmission service priorities and curtailments shall be governed by

the "lariff, the Market Coordination Customer's tarifl~ and applicable NERC/NAI{SII
requirements.

Issued b',: 1. Graham Edwards, Issuing Officer
Issued on: M~rch 4, 2(X)8

[-.flccti',,c: June l. 2[X}8

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M id,,~,est iS()

FERC Electric l'ariff. Third Revised Volume No. I

91.'7,

Upon termination of ser,.ice under this Part. for any reason other than to

become a signatory to the ISO Agreement: (i) the Market Coordination Customer shall
provide to transmission customers of other Market Coordination Customers taking
service under this Part at the time the notice of termination is served such firm
transmission service (under the rates, terms and conditions of the terminating Market
Coordination Customer's tariff) in the torm of Market Integration Transmission Service
or such other firm transmission service as the other transmission customers m a ) request
to effect the Security Constrained £conomic Dispatch tbr those customers: (it) the Market
Coordination Customer shall grant firm service to any designated Nctv, ork Resources on
the Market Coordination Customer Transmission Facilities supplying designated
Netv, ork I.oad on the Transmission System for the duration of the reservation of service
under the Market Coordination Customer's tariff, including rollover rights when the term
of the supply contract qualifies for such ser,,ice tinder the terms and conditions of the
Market Coordination Customer's transmission tariff.); and, (iii) the Transmission
Provider shall grant firm service to an)' designated Network Resources on the
"I ransmission System supplying designated Network Load on a Market Coordinator
Customer Transmission System for the duration o f the reservation o f service under the
Tariff: (The Transmission Provider shall grant long-term firm service and rolk)ver rights
when the term of the contract qualifies for such service under the terms and conditions o f
its Tariff.)

Issued b}: '[, Graham Ed~ards, Issuing ()ffleer
Issuedon: March4, 2008

Efl~:ctive: June I, 2008

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91.7.1

Original Sheet No 850Z.60

Provided. hov, evcr, that the obligations set [brth in subparts (i),

(it) and (iii) of section 91.7 shall be subject to available transmission
capacity on the transmission systems of the Market Coordinator Customer
and the Transmission Provider, and that neither the Market Coordination
Customer nor the Transmission Provider shall have an obligation to build
or expand their respective transmission lacilities at the time service is
terminated under this Section to implement the ser'.ice required b) Section
91,7 (i), (it) and (iii) of this Tariff; except as provided in this Tariffand the
transmission tariffofthe Market Coordination Customer.

92

Congestion Management
92.1

The "1ransmission Provider will employ the Security Constrained

Economic Dispatch of the resources within the Midwest IS() Balancing Authority Area.
including the resources in each Customer Zone, as described in Module C of this l'arift~
as a congestion management mechanism to reduce or eliminate congestion on the
Combined Systems.

Issued b~ : l Graham Edwards, Issuing Officer
Issued on: M a r c h 4 , 2 0 0 8

[.:ff~ctive: June I, 2008

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92.2

Original Sheet No. 850Z.61

The "1ransmission Provider shall model and identif.v flo',~.s over the Market

Coordination Customer Transmission Facilities in order to monitor congestion on the
Market Coordination Customer Transmission Facilities caused by t'/o~ s ti'om the
Combined Systems, from transmission customers under the Market Coordination
Customer's tariff and the transmission systems ol" Reciprocal Entities.
92.3

In order to coordinate third-party transmission providers' use of

curtailment procedures and generation redispatch tbr the relief of'transmission congestion

on third-party transmission fhcilities (including operating entities taking onl.', the
Reliability Coordination Service under Part I of'this Module F) u, ith the Transmission
Provider's use of economic redispatch fbr the relief'of transmission congestion on the
Combined Systems and the congestion management procedures oi' Reciprocal Entities,
the Transmission Provider will offer the Congestion Management Services under Part II
of'this Module F, containing the procedures set forth in Attachment [.I. o f this Tariff'.
92.4

In the application of'existing or future congestion management

agreements bel,,,,een the Transmission Provider and third parl) transmission
providers using the CMP methodolog), the flo',',s o f Market Coordination
Customers taking service pursuant to this Part shall be included with the market
flows of the Transmission Provider to calculate impacts on Coordinated
Flowgates and Reciprocal Coordinated l.'lo~,,gates.

Is~uedb}: l',(~rahaml'dwards, lssuingOtlicer
Issued on: March ,1, 2008

L.~ff¢cfi~,,~:Jul'~e 1,200g

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92.5

Original Sheet No. 850Z 62

The Market Coordination Customer ma~ designate an independent

transmission ser'Hce coordinator or tariff'administrator as the manager for studies
regarding the Ibr~ard cot~rdination process for the Market Coordination
Customer's l:lowgates. If no such designation is made. the Transmission Provider
•,,,ill managc the sludies for the Market Coordination Customer's FIo'~sgales.

93

Transmission Service Arrangements
93.1

Transmission Service by Transmission P r o v i d e r

l h e "l'ransmission Provider shall provide Market Integration Transmission Service to
Market Coordination Customers to effectuate Market Coordination Service under Part I11
of Module F. Market Integration Transmission Service shall not be available lbr an?
other purpose or to entities that arc not Market Coordination Customers or Market
Participants. The terms and conditions of service applicable to Point-to-Point
Transmission Service and Network Integration "Transmission Service provided under
Module B of this "lariff shall not apply to Markct Integration Transmission Service. The
lbllo~s ing terms and conditions shall appl', to Market Integration Transmission Service:
93.1. I "1he Transm ission Provider shall provide Market Integration
Transmission Service only on the facilities that comprise the Transmission
System.
93.1.2 Market Integration Transmission Service shall be a firm hourly
transmission Service.

Issued by: T Graham Edx~ards. Issuing Officer
Issued on: March 4, 2008

Efl~:clive: June I, 2008

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93.1.3 The Transmission Provider shall not require an application i~br
service to provide Market Integration l'ransmission Service. No separate
scrvice agreement shall bc required to provide Market Integration
"['ransmission Service to an)' Market Coordination Customer thal has
executed a S~:rvice Agreement pursuant to Attachment KK-3 of this Tariff:
93.1.4 Market Integration Transrnission Service shall bc provided on an
"'as-a',ailablc'" basis, as determined b) the Securit'. Constrained liconomic
Dispatch f o r this reason, no reser',ation, tag, or schedule shall bc required
to obtain Market Integration Transmission Service, and the l'ransmission
Provider shall not bc required to post or decrement Available Transfer
Capability or Available Flowgate Capability associated with Market
Integration Transmission Service on its OASIS.
93.1,5 Market Integration Transmission Service shall bc offered b ) t h e
Transmission Provider to cl'l'¢cluatc transactions in the Energy and
Operating Reserve Market. Market Integration Transmission Scr',icc shall
not be eligible for annual Auction Revenue Rights or Financial
Fransmission Rights.

Issued b): T. Graham Edwards, Issuing Officer
Issued on: klarch 4, 2008

Effective: June 1, 2008

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Ori~,inal Sheet No 850Z 64

93.1.6 The rates, charges and additional terms and conditions applicable
to the Transmission Pro',idcr's Market Integration Transmission Ser',ice are set
Ibrth in Schedule 32 o f this Tariff.
93.1.7 The Transmission Provider undertakes no obligation under this
Tariff to plan or construct its Transmission S',stem in order to have sufficient
capacity Ibr Market Integration 'I ransmission Service.
93.2

Transmission Service

by .Market Coordination Customer

93.2.1 The Market Coordination Customer shall provide transmission
service under its tariff to permit the Transmission Provider to provide
service under this Part III of this Module F to the Market Coordination
Customer and other Market Coordination Customers. To that effect, the
Market (.'oordination Customer shall adopt in its tarifflcrrns and
conditions that are consistent with or superior to the pro forma provisions
set forth in Attachment M M o f this '1"ariff and shall comply v, ith all other
rcquircntents set forth in Parl III o f this Module F.
93.2,2 A Market Participant that is located in a ('ustomer Zone of a
Market Coordination Customer shall comply with the transmission service
provisions that are established by Market Coordination Customers
pursuant to Section 93.2. ] of this Tariff.

Issued b',: 1. Graham Ed~.,.ards, Fs:-,uing Officer
Issuc.'d on: klar,,:h 4, 2008

EflEcdvc

June l, 2008

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93.3

Original Y,heel No. 850Z 6~

Designating Nelwork Resources
93.3.1 Network Load taking transmission service from the Transmission
Provider may designate resources v.hich are connected to the transmission
system o f a Market Coordination Customer. or network load taking
net~ork transmission service from a Market Coordination Customer may
designate

a

network resource connected to the l'ransmission Providcr's

"1ransmission System. Resources not connected to the I ransmission
System must satisfy, the requirements o f Section 30.6 of the laritTto
become designated Network Resources under the Transmission Providers
Tariff
93.3.2 A resource connected to the transmission system of a Market
Coordination Customer v, ill be deemed to have complied with the
requirements of Section 30.6 of this Tariff il:. (i) the Market Coordination
Customer's tariff requires such resources to meet the requirements set
lbrth in Section 69 of the Transmission Provider's l'ariffand the
Transmission Provider determines thal the resource has met the
requirements set lbrth in Section 69 of this "Fariff~ and (ii) the
Transmission Provider determines that the terms and conditions for
designating and remo'dng netv,'ork resources, as defined in the Market
Coordination Customer's transmission tariff'and business practices,
including the requirements set forth in this Section 93.3.2, are comparable
to the terms and conditions applicable to designating and removing
Network Resources under the l'ransmission Provider's Tariff.

Issued b): T. Graham lid',~ards, Issuing Officer
Issued on: March 4, 2008

Ellk:cli',,,2: June I, 2008

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93.4

Original Sheet No. 850Z 66

Reciprocity
It is a continuing condition of service under this Part that: (i) the Market

Coordination Customer and any of its po',~,cr marketing a|filiates shall bc entitled to all
forms of'l'ransmisskm Service available under the l'arifL and (ii) all Market Parlicipants
and Eligible Customers under this Tariff; all Market Coordination Customers taking
Market Coordination Service under this l-'arl, and all Transmission Customers shall be
entitled to all forms nftransmission service available under the Market Coordination
Customer's taril1~ Failure of this conditkm to be fulfilled shall result in either the
immediate termination or suspension o f service under this Part. or default under this
Taril'|~ whiche,.er is applicable. Nothing in Section 6 of the Tariff shall be interpreted to
modif) or diminish the obligations of Market Coordination Customers set lorlh in this
Section 93.4 and/or Attachment M M of the Taril1:

Issued b): T (iraham I'd~ards, Issuing Ot~cer
Issued on: March 4, 2008

Fffectivc: June I, 2008

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93.5

Original Sheet No. 850Z.67

Single Customer Zone

l v.o or more Market Coordination Customers taking service under this Part
','~hose Market Coordination Customer Transmission S) stems are interconnected may
enter into a transmission service and revenue sharing agreement and request thal their
individual zones be combined into a single Customer Zone. The Fransmission Provider
•o, ill analyze the proposed Customer Zone and if the proposed rate zone does not result in
financial or operating detriment Io other Market Coordination Customers taking service
under this Par~, or to other Market Participants or Transmission Owners. the
Transmission Provider ~ill enter into a supplemental Service Agreemenl ~sith the Market
Coordination Customers lbr this purpose. For the purposes oftransmisskm ser',ice
pricing, resources and load connected directly to the Market Coordination Customer's
transmission lacililies shall be considered to be in only that Customer Zone.

Issued b): T. Graham Edwards, Issuing Officer
Issued on: March 4, 2008

Effective: June ], 2008

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Midv, est IS()

FER(" El¢i:tric "l arifl~ Third Re', ised Volume No. l

94

(?umpensalion for Sen, ices
94.1

The "1ransmission Provider shall bill the Market Coordination Customer

and the Market Coordination Customer shall pay the Transmission Provider for services
provided under Part I11 of this Module F in accordance with this Section 94 and the
billing and payment terms set forth in Article 7 of the Tariff. All Market Participants
shall be billed for, and shall pay' tbr services provided under this Tariff pursuant to the
billing and payment terms set forth in Article 7 of the Tariff, as such terms may he
modified from time to time by an order of the Commission.
94.2

Market Coordination Customers taking Market Coordination %er',ice shall

pay' all applicable charges that ma) be required by Modules A. C, D, [i and F, including
,.~ithout limitation charges required under (i) Schedtdc 16 of this Tariff'lbr financial
transmission rights. (it) Schedule 17 of the Tariff'lot energy market transactions, and (iii)
Schedule 32 of this "l'ariff" for Market Integration l'ransmission Service required b) the
Market Coordination Customer to integrate the resources and loads of its transmission
customers. Charges for Reliability Coordination Service under Part I of this Module F
taken in conjunction with the services provided under this Part shall be paid as set tbrlh in
Part I of this Module F.

issued b) [ Graham E d ~ d s .
Issu~.'d on: March 4, 2008

Issuing Otlicer

l-:|'tecti~e: Jun~ I. 2008

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FERC Elcclric l'ariff third Revised Volume No. I

94.3

Original Shccl No 850Z.09

Upon temlination of the applicable Service Agreement. if the Market

Coordination Customer does not become a Transrnission Owner, the Market
Coordination Customer shall be responsible for pa'.mcnt of: (a) an allocated share of the
remaining book value of all Incremental Reliabilit.,, Coordination Assets, and (b) an
allocated share ol'the remaining book ~,alu¢ of all incremental capital assets associated
v~ith the provision of Market Coordination Ser',ice ("Incremental l!nerg.v Market Assets")
and [br certain l~nancing costs associated with the Incremental l'nerg,, Market Assets as
set Ibrth in Section 94.3. I to 94.3.3 of this larifl~ l:or the purposes o f this Section 94.4 of
this Tariff the calculation o f the value for Incremental Rcli~,bility Coordination Assets
shall be as described in Section 77.3.1 to Section 77.3.3 of this Tariff.
94.3.1 l'he calculation of the ~,alue Ibr Incremental Imergv Market Assets
shall be the sum of: (a) the remaining book value of all capital assets
associated with the pro,,'ision of'Market Coordination Service that v, erc
placed into service on or after December 3 I, 2007; and (b) the balance o f
all v, ork in progress on assets associated v.ilh the provision o[" Market
Coordination Service as of the date o f termination.

Issued b): 1. Graham f!d~ard~,, [ssuin~ Of'ricer
Issuedon: March 4, 2008

I{ffccfi',e: June I, 2008

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I:ERC Elct:tric 3 ariff, t'hird Re',iscd \ olumc No. I

Original Sheet No. 850Z 70

94.3.2 In addition to payment owed lbr an allocated share of Incremental
Reliabilit) Coordination Assets and Incremental l'nergy Market Assets,
the Market Coordination Customer shall be responsible fbr payment of an
allocated share or'the remaining interest expense over the life of any
outstanding debt issued subsequent to December 3 I, 2007 used to finance
the development or acquisition of capital assets associated ~,.ith the
provision of Reliability Coordination ,~ervice and Market (_'ot~rdination
Service that were placed into service on or after December 3 I, 2007, l'he
Market Coordination Customer shall also be responsiblu for pa) ment of an
allocated share of'any remaining payments associated ~',ith lease
obligations incurred after December 3 l, 2007 used to finance the
development or acquisition of assets associated ',~.ith the provision of
Rcliabilitv Coordination Service and Market Coordination Service thai
were placed into service on or after December 3 ], 2007.

Issued b',: l'. (]raham Edv, ards. Issuing Officer
Issued on: Xtarch 4. 2008

I~fl~:cti~e: June I, 2008

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FI'RC 1 lectric lariff, l'hird Revised Volun'tc No. I

Original Sheet No. 850Z 71

94.3.3 In computing the financial obligations outstanding as o f the date o f
termination, the lump sum amount o',,,ed under this Section 94.3 that is
associated with remaining interest pa>rnents over the lil~ o f the
outstanding debt that is associated ,,~ith the provision o f Reliahilit',
Coordination Service and Market Coordination Service shall be
discounted to a net present value amount ",~ith the discount rate used equal
to the expected interest rate to be earned on funds held in the investment
account o f the ['ransmission Provider.
9,.I.3.4 [ h e Market Coordination Customer shall also be responsible for
payment o f an allocated share o f the accrued current liabilities on the
balance sheet o f the Transmission Provider as o f the dale ofterrnination o f
the S e r v i c e A g r e e m e n t .

Issuedb,,: "[ GrahamEd'.,.ards,lssuing Officer
Issued on: March 4, 2008

Ef'fecti,,c: ,rune 1.2008

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FER(" Electric Tariff, Third Revised Volume No. I

(.)riginal Sheet N,a 850Z.72

94.3.5 The Market Coordination Customer shall pay a load ratio share of
thesc incremental financial obligations. "lhe load ratio share shall bc
calculated as the Market Coordination Customer's monthly peak demand
for the tweh'e months preceding the termination of+the Service
Agreement, relative to the sum of the monthl,, peak demand during that
period of all Market Coordination Customers and all TariffCustomcrs
recei',ing Network Integration Transmission Service under the "lariff. All
peak demand inlbrmation shall be converted into Maximum l£nerg)
"rransf;ar data as defined in Part 11, Section A. of Schedule 10 of this
l'arill: The Transmission Provider shall use the non-coincident peak
demand fi~r each Market Coordination Customer multiplied by the number
of hours in a month to derive the Market Coordination Customer's
Maximum l-nergy Transfer value, l'he Transmission Provider shall
compute Maximum Energy f'ransfer values for its Tariff Customers taking
Network Integration Transmission Service during the preceding month
ti'om their non-coincident peak demand, l'he Market Coordination
Customer shall pay the entire amount owed under this Section 94 at the
time the applicable Service Agreement is terminated.

Issued b',: T. Graham Edwards, Issuing Oflicer
Issued on: March 4, 2008

l-ZtI~:ti,.~: June I, 2008

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(.)ri~inal Sheet No. 850Z 73

94.3.6 As to a Market Coordination Customer to v, hich Section 121! of
this l'ariffapplics, the obligation to make the payments under this Section
is subordinate and junior in all respects to the obligation of the Market
Coordination Customer to pay the principal and interest on its bonds.

95

Joint Coordinating Committee
95.1

A Joint Ctx~rdinating Committee is hereb.v established, l'he "1ransmission

Provide and each Market Coordination Customer taking service under this Part II1 of
Module F shall be a voting member o f the Joint Coordinating Committee.
95.2

The Transmission Provider and each Market Coordination Customer

taking service pursuant to this Part III of Module F shall appoint one representative to the
Joint Coordinating Committee and each part,, shall pa? the expenses of its rcpresentati'~e
to the Joint Coordinating Committee.
95.3

A member's Joint Coordinating Committee representative shall be a

person o f reasonable competency and with such authority as to uphold the decisions
made to the c.xtent such decisions do not require formal approval under governing state
la,,vs and regulations.

Issued b'.: I. Graham Ed',~,ards.ls~,uingOfficer
Issued on: ~.|~lrch4, 2008

Effccti',c: June I. 2008

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95.4

Original Sh,:,,uNo 850Z.74

The Joint Coordinating Committee shall meet at least quarterl,, during the

first >ear after the effective date o/'this Part, and shall meet periodicall', thereafter as the
Joint Coordinating Committee shall, b) a majority vote ofthree-lburths of those entitled
Ua ,.ore. determine to be necessa~ to administer its duties under this Part in a reliable and
efficient manner.
95.5

In cooperation v.ilh the l'ransmission Provider, and consistent v. ith the

requirements of the Tarill'and all applicable reliabilit) standards, the Joint Coordinating
Committee shall:
95.5.1 review procedures for the implementation of the operating and technical
requirements of'this Part:
95.5.2 identity,' procedures for coordinating and integrating the operating and
technical requirements of this Part 'Mth those of Part 1 of Module F;
95.5.3 periodically meet v, ith and incorporate suggestions from the Reliabilit)
Coordinating Technical Committee created under Part I of Module F;
95.5.4 participate in the development o f Business Practices Manuals tbr the
administration o f this Part on a reliable and economicall> efficient basis; and
95.5.5 address any other matters refi:rred to herein or necessar? tbr
implementation, administration or operation o f this Part.

Issued b) : T Graham Edv, ards, Issuing ()flic~r
Issued on: March 4, 2008

Effective: June I. 20()~

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}:ERC tJectric lariff~ third Revised Volume No I
95.6

Original Sheet No 850Z.75

']'he Joint Coordinating Committee shall create and direct such

subcommittees, task ibrces or ",vork groups as it deems appropriate to address technical or
other operating issues.
95.7

Recommendations and other actions tile .Ioint Coordinating Committee

shall be b~ a lhrec-lburths majority of those present and entitled to vote under the rules
adopted by the Joint Coordinating Committee to govern its proceedings. Nothing herein
shall prohibit the Joint Coordinating Committee l?om developing rules and procedures
regarding proxy voting, and procedures to allow electronic rnceting or voting.
95.8

All proceedings and decisions of the Joint Coordinating Committee shall

be reduced to writing and approved by the Joint Coordinating Committee representatives,
but shall not be inconsistent with and shall not serve to contradict an',' terms or conditions
of this Part in effect at the time of such procedures or decisions being made or de,,eloped.
95.9

Market Coordination Customers taking service under this Part shall be

eligible to participate in the Transmission Provider's stakeholder process as members of
the Coordinating Members segment.
95.111 Participation in the activities of the Joint Coordinating Committee by the
Transmission Provider or by the Market Coordination Customer shall not constitute a
v.'aivcr by that party of any of its rights under the Federal Pov.er Act to initiate a
proceeding, make any other filing, or advance any position regarding any matter betbre
the Commission.

Issued by: I. Graham Edv,ards, IssuingOllicer
Issued on: Nlarch 4, 2008

Effective: June I. 2t)t~8

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96

Original Sheet No. 850Z.76

Sen'ice Agreement
96.1

The l'ransmission Provider shall offer a standard form Service Agreement

for Market Coordination Service to the entit', eligible to receive service under Part I11 of
this Module F. Executed Service Agreements entered into pursuant to this Section 96
shall be filed x~,ith the Commission in compliance with applicable Commission
regulations. "lhe standard form of Service Agreement lor Market Coordination Services
is provided in Attachment KK-3 to this Tariff.
96.2

If the Commission determines that regulator> filings are required to

implement the Nervice Agreement executed pursuant to this Section 96. the "1ransmission
Provider and the Market Coordination Customer shall cooperate with each other as
necessary and appropriate to tacilitate any such required Commission filings,
97

Term
97.1

The initial term of Market Coordination Service shall be for a period of

three (3) years after the ef[ketive date o f t b e Service Agreement executed pursuant to
Section 96 and Attachment KK-3 of this Tariff. The Service Agreement shall
automatically renew thereafter lbr successive one-year terms unless written notice of
termination is provided not less than one year prior to the end of the initial term or a
subsequent term. The effective date o f t b e Service Agreement shall be the date set forth
therein or any other date as may be established by the Commission.

Issued by: 1. (;raham Edwards, Issuing Officer
Issued ,an: March 4, 2008

Etl~:ctive: June I. 2008

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97.2

(.)rlginal Sheet No 850Z.77

A Market Coordination Customer to ~.shich Section 121i o f this Tariff"

applies ma'. terminate its Service Agreement executed pursuant to Section 96 and
Attachment KK-3 oFthis "l'arifl"at any time during the initial term or any extcnsk)n
thereof with less than the required on¢-',ear notice, in the event that the statutes
governing such Market Coordination Customer. or an)' provisions of this Part III oF
Module F, or the provisions o f the l"ransmission Provider's Tariff'incorporated by
relhrence in this Part III of Module F are changed or modified, in a manner that causes a
conllict ~.~,ith state law. regulations, or rate schedules and the review.,, process described in
Section 12E ot'this Taritl" is unable to resolve such ¢onllict.
97.3

Upon written notice to the Transmission Provider that the Market

Coordination Customer is exercising its right to terminate its %ervice Agreement pursuant
to Section 97.2 of this Tarit't. the l'ransmission Provider and the Market Coordination

Customer will v, ork in good faith to make all required arrangements to adjust the
commercial and net',~ork models used b~, the Transmission Pro',.ider to pro',ider service
undur this Part 111,and to arrange for a transfer or'the balancing authorit', rcslx~nsibilitics
to another balancing authority or to the Market Coordination Customer, in order to permit
the Market Coordination Customer to terminate service under this Part I[I on the earliest
possible date.
97.4

Upon termination o f service under this Part, the Market Coordination

Customer and the Transmission Provider shall each remain responsible tor their
respective financial obligations, ifany, incurred under this Part prior to termination until
completion ofan~, such obligation.

Issued b',: I. Grahanl Ed,aards.Issuing Ofticer
)ssucdon: March4,2008

Effective: June I, 2001~

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Original S;hectNo. I050Z 53

SCIIEDULE 31
Reliability Coordination Sen'ice Cost Recoven' Adder
Definitions:
Maximum Ener~' Transfer for Reliability Coordination Sen'ice - the rcsuh of multiplying the
Reliability Coordination Customer Monthl.', Peak ~br tile month by the number of hours in the
month.

Reliability Coordination Customer Monthly Peak--the non-coincident monthly peak load of the
Reliabilit> C~×~rdination Customer. The non-coincident monthly peak load of the Reliability
Coordination Customer shall include all xsholesale and retail load within the Balancing Authorit~
Area o f the Reliability, Coordination Customer, or that is interconnected v, ith and taking service
over the transmission l~a~:ilities of the Reliabi]it', Coordination Customer, but shall not include load
that pays for Reliabilit,, Coordination Ser',ice separately under Part ] of Module F, or pa~s for
reliabilit,, coordination service li'om another Reliability, Coordinator other than the Transmission
Provider.

1.

GFNERAL
"lhe Transmission Provider ',',ill recover its costs to provide Reliability C'(~ordination Service

pursuant to the terms of this Schedule 31 from Reliabili~' Coordination Customers that execute the

applicable Service Agreement as set tbrth in Section 74 and Attachment KK-I to the Tariff. The
costs recovered pursuant to the terms ofthis Schedule 31 are exclusive of those costs recovered
pursuant to Schedules I. 10, 10-A, 10-B, 10-C, 16, 16-A, 17 or 17-A ofthis'l'arifl: Part II ofthis
Schedule 31 presents the cost recovery formula and charges applicable to all Reliability
Coordination Customers.

Issued b',: T Graham E,.lwards,Issuing Officer
Issuedon: Mar~:h.l, 2008

Effecti',e: June I. 2008

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Midwest ISO
FI(R(" Electric tariff, I hkrd Revised Volume No. I

Original Sheet No. 1050Z 54

l'he cost recovery fi~rmula and charges in Part II of this Schedule applicable to the
Maximunt Energy "lransfcr tbr Reliability Coordination Service shall be billed to and recovered
from Reliability Coordination Customers based on the physical location of the Reliabilit>
Coordination Customer's load as described in Part 11, Section B ot'this Schedule 31.
I[.

REI,IABILITY COORDINATION SERVICE COST RECOVERY ADDER
The charges applicable it) each Reliability Coordination Customer shall be the product of

the monthly rate for service tinder this Schedule 3 [ and the Maximum Energ~ Iransfer fbr
Reliability Coordination Service.
Each monthl', charge shall bc calculated based on budgeted costs and fbrecasted
Maximum I'nergy l'ransfer for ReJiability Coordination Service and ~ill be trued up in the
following month's calculation to reflect actual costs and actual Maximum Energy Transfer fi)r
Reliability Coordination Service.

I:,sued b',: I. Graham I!dt~,ards, Issuing Officer
Issued on: March 4, 2008

Effective: June l, 2008

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Midwest ISO
FERC Electric laritI~ third Revised Volume No.

Original Sheet No 1050Z 55
I

Determination of the Monthly Charge
The monthly charge for Reliability Coordination Service shall be based on a subset of the
costs recovered under Schedule 10 off'the Tariff. lhe subset of costs shall be those associated
with the perlbrmance of the Reliability Coordination Service as set lbrth in Part I of Module F.
For budgeting and cost recovery purposes the Transmission Provider shall allocate a portion of"
its Schedule I[)-related operating costs to the reliability cc×~rdination functions based on an
anal)sis of the lhnetions performed b) each department and b) each employee. Allocation of
capital-related costs, including depreciation expense, interest expense and amortization of
deferred regulator)' assets, shall be based on the purpose and use off'each asset. The end result of"
the cost allocation process shall be a set of'financial records ffbr each cost recover>' category
maintained in accordance with the FERC Unitbrm System off'Accounts.
The recording of salaries and benefits to the financial accounting books and records of
the "1ransmission Provider is based on time sheet entries. All other operating expenses are then
either directly recorded to the appropriate set of financial records or allocated to the appropriate
set off"financial records using salary-based labor allocation ff'aetors other appropriate allocation
factors. All capital-related costs are either directly recorded to the appropriate set of financial
records or allocated to the appropriate set off"financial records using salary-based labor allocation
factors or other appropriate allocation ffactors.

Issued by: r Graham }!d~ards, issuing Officer
Issued on: March 4. 2008

Effective: June I. 2008

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Midwest IS()
FI!R(7 l!lectric I arifl; Third Revised Volume No I

Original Sheet No 1050Z.50

The cost allocation process described above shall bc used b~ the Transmission Provider
to first allocate costs to Schedule 10 and then to the Reliabilit', Coordination Service functions
that are a subset of its Schedule 10-related services, l'he categories of'services provided under
Schedule 10 or'the Tariffarc:

I. Reliabilit3, Coordination

ensuring the reliable operation of the bulk pos'.er system in

accordance ',',ilh NI£RC Standards and other requirements, including:
a. Operations Planning

de,,elopment ol'opcrational plans to respond to system

conditions and potential contingent', situations
b. Maintenance Coordination - re,.'ie',~ins and approving or denying requests lot
scheduled transmission line outages, and coordinating generating unit outages
2.

Tariff Administration .. revie~ing and approving or den~ ins requests tbr "l ransmission

Service.
3. Scheduling - reviewing and approving or den)ins schedules for use ol'confirmed
transmission reservations.
4. Billing & Settlements • computation of'charges, invoicing, and revenue distribution
5. Transmission Planning

including all studies associated ',~,ith requests lbr long term firm

transmission service, requests for generation interconnection service, and development of
the Midwest ISO Transmission Expansion Plan ("M'I'EP") document approved by the
board of directors.

Issuedb): I (irahan'.l-;d,.,.ards, lssuingOflicer
Issued on: March 4,200~

I~tI~cti,.e: June 1,2(108

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Mid',,.est ISO
FERC Electric Tariff. third I'~.cvised\ ulume No I

Original Sheet No. 1050Z 57

The costs to be recovered from Reliabilily Coordination Customers under this Schedule
31 are those associated ~,,ith the performance o f the Reliabilit} Coordination Service as set lbrth
in Part I o f Module F.
The allocation of costs into subcategories of Schedule I O-related service is performed
separatel} tbr: ( I ) Operating Expenscs, and (2) Fixed Cost Recover>. Opcrating Expenses
include all costs sho,,,.n on the Schedule 10 income statement of the "1ransmission I'rovidcr
except the follo'~s ing: (a) FERC Fees. (b) depreciation, (c) amortization, and (d) othcr
income/(expense), Fixed Cost Recovery includes the costs sho',~,n on the Schedule 10 income
statement of the Transmission Provider that are associated v~ith: (a) depreciation, (b)
amortization, and (c) other income/(expense). I'he fixed costs recovered under this Schedule 3 1
exclude certain depreciation and amortization expenses as described in more detail belo'.s.

Operating Expense Recovery
"lhe Transmission Provider shall allocate Operating Expenses to the appropriate
subcategories of Schedule I 0-related services based on a department-by-department review of
the costs incurred b', each department. All indirect costs are allocated based on the ratio of direct
labor costs allocated m ReliubiliIy C(~ordinmion Service functions divided by the total of all
direct labor costs to be recovered under Schedule I 0 of the larifl:

Issued bY: ]'. Graham Ld~ards. ]sslfin~ Officer

Issued on: M~lrch,1, 2008

l~tl~:cIi~ e: .lu.c h 2008

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Original Sheet N o 1050Z,58

Midwest ISO
FER(" Electric farit'f, "third Revised Volume No. I

l'he initial cost of'the Schedule 10-relatcd Reliability Coordination functions as a percent
of the total budgeted Schedule 10 operating costs based on budget data |br 2007 is summarized
in Table I belov,. The initial cost allocation percentages for Operating Expenses to bc recovered
under Schedule 31 shall remain in effect until April I. 2008. During March 2008, the
Transmission Provider shall update the cost of service stud.', based on actual costs incurred
during 2007 and budgeted costs for 2008. The updated cost alk)cation percentages shall remain
in effect until April I, 2009. The process of updating the Schedule 10 Operating Expense
Allocation Factor shall be repeated annuall',.

Table 1
Reliabilit', Coordination Service

Schedule 10 Operating l-xpense Allocation Factor

m

Schedule 10 Service Category
Reliability Coordination
Operations Planning
Maintenance Coordination
Total - Reliability
Coordination Ser~ ice

Issued b) : ! (.;raham E(h~ards, Issuing r.)t]icer
Issued on: March 4, 2008

_

Percent of
Schedule 10
Operating
Costs
40.3%
1.7%
9.4%

51.4%

t!ft~.cli~c: June I. 2008

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ISO
FERC Electric Tariff, Ihird Revised VolumeNo 1
Midv, est

Original SheetNo. 1050Z 59

Fixed Cost Recove n '
Fixed Cost Recovery' [br the purposes of Schedule 31 shall include: (a) certain

depreciation as set forth in this Schedule 31; (b) certain amortization expenses as set Ibrth in this
Schedule 31 ; and (c) certain interest expense recorded as other incomel(expens¢) as set forth in
this Schedule 3 I.
For the purposes o f this Schedule 31, the depreciation expense shall be Schedule I0
depreciation expense net o f depreciation associated with the initial capital costs to develop the
Integrated Control Center S,,stern placed into service on February I. 2002 and depreciated over
se',,en (7) ,,ears. During 2007 and 2008 a proxy value lbr the depreciation expense net o f
deprecialion associated with the initial capital costs to develop the Integrated Control Center
System placed into service on February I, 2002 shall be used. The initial proxy value lbr total
Schedule ]0 deprecation net of the initial capital costs to develop the Integrated Control Center
System is $I 2.405,84 I.

Issued by: T Graham l'd~ards, Issuing Officer
Issued on: ~.la,~h4, 2008

Elllzctive: June I. 2008

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(Unofficial) 03/06/2008

Midv, est ISO
FERC Electric larifl] Third Revised Volume No. I

Original Sheet No. 1050Z 60

I h e initial cost allocation percentages/br lqxcd Cost Recovers' shov.n in "/'able 2 s/tall
remain in effect until April I, 2008. During March of 2008. the l'ransmission Provider shall
update the proxy value in the preceding paragraph to rctlect an', changes to (a) the capital
expenditures lbrccasted to have been incurred during 2007, (b) the forecast of capital
expenditures scheduled to occur in 2008, and (c) the forecast of capital expenditures scheduled to
occur in 2009. The initial cost allocation percentages in Fable 2 shall rcmain in efl~.-ct until
April I, 2009. The process of updating the Schedule 10 Fixed Cost Allocation Factor shall be
repeated annually thereafter.

"l'ablc 2
Reliability Coordination Servicc

-.

Service Category
Reliability, Coordination
Operations
Maintenance

Plannin~
Coordination

Total Reliability
Coordination Service

Issued b~,: I'. Graham Edwards, Issuing Officer
Issued on: March 4, 2008

.

Schedule 10 Fixed Cost Allocation Factor

Percent of 2009
Schedule 10
Depreciation
26.1%
3.3%
3.0%

I

_

32.4%

Ell~.'cti',c: June I, 2008

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,Midwest ISO
FER(" Electric larifl" 'lhird Revised ~,olumc No. I

OriginaIShectNo 1050Z61

For the purposes of this Schedule 31 the recovery of amortization expenses shall exclude
those associated v, ith: (a) pre-operating expenses for Da) One development, (b) pre-operating
expenses tbr l)ay l'wo development, (c) deferral ofS25 million tbr future recove D' under
settlement agreement ~s ith Transmission Ox~ ncrs, and (d) all GridAmerica and Alliance RTO
costs paid to GridAmerica, Amcrcn. and Illinois Power (sec Footnote No. 4 to the audited
financial statements of the lransmission provider tbr period ending 12/31/2006).
Interest expense and interest income allocated to Schedule I0 shall be allocated to the
appropriate subcategories in Table 2 based on the depreciation allocation factor for each
subcategoD in l'ablc 2. For the purposes of this Schedule 31. interest expense shall be that
associated existing debt. including the senior, unsecured notes issued by the l'ransmission
Provider. that is allocated to Schedule I0 for cost recover3, purposes as delineated in the Tariff.
Interest expenses shall also include that expense associated with the issuance of an', new debt to
finance incremental capital improvements that are to bc recovered under Schedule 10.

Issued by: T, GrahaJn Edv.aJ'ds, Issuing Officer
Issued 'cars (thirty-six (36)
calendar months) from the tirst time that the first Market Coordination Customer takes
service under Part Ill of Module F of this l'arill; but shall not exceed 4 years from the
effective date established by the Commission for service under Part 1[I o f Module F. The
charges applicable during the Market Integration l'ransition Period arc set fi)rth in Part A
o f this Schedule. Part B of'this Schedule ~ill be used fbr an> period subsequent to the
Market Integration Transition Period.

Issued b',: [ Graham Ed~ards, Issuing. Officer
Issued on: March .t 2008

I'ffL'cliv¢: June I, 2008

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Mid'.', est IS()

Original She,:t No 1050Z 68

FI'R(" Electric l'ur~ff,Third Revised Volume No. I

(2) The charges for Market Integration Transmission Service taken during the Market
Integration Transition Period shall be determined as [bllows:
Market Integration Transmission Service charge tbr each ",'ear during the Market
Integration I ransition Period shall bc equal to charges assessed to the Market
Coordination Customer during the calendar >,ear prior to the effective date o f the Service
Agreement executed by the Market Coordination Customer pursuant to Section 96 and
Attachment KK-3 of this Tarilt: l'he charge shall include all applicable charges lot
transmission service incurred during such calendar >ear to the lnterli~ce that

represented

the Market Coordination Customer.
(3) The Market Coordination Customer shall compensate the Transmission Provider each
month for Market Integration "Iransmission Service. The monthb, charge shall be onetwelfth of the total charge calculated in Part A (2).

Issued by: 1. Graham Ldv,ards, Issuing Otlicer
/ssued on: March 4, 2008

Etl;:,.:ti'.e: June 1,2008

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Midw~:st ISO
FERC Iilectric I ariff, "third Revised Volume No. I

B.

Original SheetNo 1050Z.69

M A R K E T I N T E G R A T I O N "I'RA~'SMISSIO~' S E R V I C E C H A R G E S A F T E R "I'llE
TRANSITION PERIOD
Part B of this Schedule shall apply to Market Integration Transmission Service taken

after the end o f the Market Integration Transition Period b) each Market Coordination Customer.
All eflectivc rates under Pan B shall he posted on the Transmission Pro\ider's OASIS.
"lhe rate is calculated using the [brmula included in Attachment O, pages I and 2. ]'he rate will
be recalculated each June I based on the prior fbll calendar or fiscal year.
(I) Single System - Wide Rate: The Market Coordination Customer shall pay the applicable
single system rate lor Market Integration Transmission Service
(2) Discounts: [ h r e e principal requirements apply to discounts lbr transmission service as
follows: (I) an', offer o r a discount made by the Transmission Provider must he announced
to all Market Coordination Customers solel) by posting on the OASIS, (2) any customerinitiated requests lbr discounts (including requests tbr use by one's ,,,.holesale merchant or an
affiliate's use) must occur solely by posting on the OASIS, and (3) once a discount is
negotiated, details must be immediately posted on the OASIS. For an', discount agreed upon
for Market Integration Transmission Service, thc "rransmission Provider must offer the same
discounted transmission service rate tbr the sarne tirne period to all Market Coordination
Customers.

Issuedb) : l ~.Grahamlld~ards, IssuingOfficer
Issuedon: March4, 200~

I~tTectise: June I, "008

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5.lid'~,est IS()
FHRC £1ectric [ arifl] third R,~vis~dVolume No. I

OriginaIShcctNo 1050Z70

(3) Average Iiourly Market Integratiun Transmission Sen'ice Demand: "lhe average
demand by a Market Coordination Customer is calculated by summing the positi'~e houri)
demand over the previous calendar year from the Transmission System to the Market
Coordination Customer's transmission system and dividing b)' the number o f hours in a year.
The Transmission Provider shall determine the Amount of service tbr Market Integration
Fransmission Service taken by each Market Coordination Customer and calculate the
applicable charge for Market Integration l'ransmission Service as tblluws:

a. The Transmission Provider shall calculate a momhl) charge tbr Market Integration
Transmission Service for each Market Coordination Customer by applying the
applicable Single - System Wide Rate to the Average Hourly Market Integration
Transmission Service Demand.
(i)

The Average tlourly Market Integration Transmission Demand is
adjusted [br pre-arranged transmission service under this Tariffto the
Market Coordination Customer transmission system.

Issued b>: T. Graham l-d,.v~ds. Issuing ()fficcr
Jsstwd on: >,~arch4, 2~8

H1ectivc: June i. 2[)[)~

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M id'.~.est ISO
Ft'RC Electric Iariff. Third Revised Volume No. I

third Rc'..ised S,hect Nt~ 1207
Superseding Second Re',ised Sheet No. 1207

POLICY INTENT:
This Credit Policy describes requirements lbr: (I) the establishment and maintenance of
credit by Market Participants, Transmission Customers. and Applicants pursuant to one or
more Credit and Securit) Agreement(s). and (2) forms of security that will be deemed
acceptable (hereinafter the "'Financial Security") in the event the Applicant and/or Tariff
Customer does not satisfy the linancial requirements to establish Unsecured Credit to cover
its Total Potential l-xposure.
I'his policy also sets forth: (i) the basis for establishing the individual Total Credit Limit that
will be imposed on an Applicant and/or "lariffCustomer in order to minimize the possibilit:,
of failure of p.'t',mcnt fbr services rendered pursuant to the Agreements and (i i) various
obligations and requirements the violation ol'``~.hich ",``'illresult in a Default pursuant to this
policy, this Tariff'and the Agreements.
l h e Transmission Provider shall administer and implement the terms of'this Credit Policy.
APPLICABILITY:
This policy applies to all Applicants and tariff'Customer who take Transmission Service
under this Tarift~ utilize se~ices or participate in the [:~ncrg', Markets, hold FIRs, or
otherv, isc participate in Market Activities under Module C of this "lariff. This policy also
applies to Reliability Coordination Customers. Congestion Management Customers and
Energy Market Coordination that take service under Module F of this Tariff.
NOTICE:
All "~.ritten notifications by the Transmission Provider under this policy shall be in
accordance with Section 7.15 of this Fariff. Notilications to Applicants and/or Tariff
Customer ,,,,ill be sent to their credit contact.

Issued b,',: I. Graham Ed~ards. Issuing Officer
Issued on: March 4. 2008

I!fleclive: June I. 2008

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Midv,'est ISO
FERC Electric Tariff'."Ihird Revised Volume No. I
IV.

Third Revised Sheet No 1231
Superseding Secmld Revised Sheet No 1231

Potential Exposure to Non-Payment and Total Potential Exposure
Potential exposure to non-payment is calculated separately lbr each category o f Markets
and Services. "Fhc information in Section IV o f this Credit Policy addresses the
calculation and use o f the value for Total Potential Exposure b', Participant, Reliability
Coordination Customers. Congestion Management Customer or Energ) Market
C'oordination Customer.
A. Total I'otential Exposure
'/:or credit purposes, a Tariff Customer's Total Potential Exposure shall be the sum of
the charges and credits lbr the following service categories as calculated per the
lormulas in Section IV of this Credit Policy:
I.

Real-l-ime Energ', Market

•

2.

3.

4.

5.

6.

7.

Including all charge types associated v, ith Congestion Management
Service under Part 11 of Module F
• Including all charge t)pcs associated ,,~,,ith Encrg) Market Coordination
Service under Part III o f Module F
Day-Ahead Energy Market
• Including all charge types associated with Congestion Managerncnt
Service under Part 111 of Module F
Virtual l'ransactions
• Including all charge types associated with Energy Market Coordination
Service under Part I11 of Module F
FTR Auction activity
• Including all charge types associated with Energy Market Coordination
Service under Part I11 of Module F
FTR portlolio
• Including all charge types associated with Energy Market Coordination
Service under Part I11 of Module F
Congestion and losses
• Including all charge types associated with Energy Market Coordination
Service under Part I11 of Module F
Transmission Service
• Including Schedule 31 charges associated with Reliability Coordination
Service under Part I of Module F

Issued b): r.- Graham t d;~.ards.Issuing Officer
Issued on: March 4, 2008

t!ffcctive: June 1,2008

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Midwest ISO
FERC Electric l'aritT, l h i r d Revised Volume No. I

Original Sheet No. 1231.01

In general, the calculation of potential exposure to non-pa',ment v, ithin each service
categor;, is based on three exposure components:
I. Invoiced but not paid;
2. Measured but not invoiced, where measured means the settlement s',stems of
the Midwest ISO have computed the charges and credits tbr all transactions
tbr a given Operating Day; and
3. [.~stimated for future operating days based on known and/or potential activity.
In the e',ent a Market Participant's Iotal Potential Exposure exceeds its Total Credit
Limit as of the close of business on three (3) consecutive da) s, then tbr the next ten
(I 0) days the Market Participant's l'otal Potential Exposure shall be equal to the sum
ol- (i) the amount calculated per the formulas in this ~,cction IV; plus (it) a factor of
up to ten (10) times the average amount of'the excess exposure over the three (3)
consecutive days, if the l'ransmission Provider determines, after consultation x~,ith the
Market Participant, that such additional collateral is necessary to reflect tile potential
exposure associated v, ith the Market Participant's expected market activit',.

Issued b).: ] Gr;lham Ed~ards. Issuin~ Officer
Issued ~n: March 4, 2008

liffi:~tivc: June I, 2008

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Midv,est IS()
FERC Electric l'ariff. Third Revised \olun'te No. I

Fourth Revised Sheet No. 1232E
Superseding Third Revised Sheet No 1232E

L - the set of all Congestion and I.osses Charge Types that ha',e been settled

and/or calculated, but not )et invoiced.
CLEE (Congestion and Losses Estimated tixposure):

("l.f-f- will be the greater ~/2
(I) The seven da) rolling average of dail.', Congestion and l.osses
Charges/Credits from previously approved initial Settlements times six
(6).
OR
(2) The three hundred sixty five (365) day rolling average of daily
Congestion and l.osses Charges/Credits from previousl:, approved $7
Settlements times six (6).
7) T r a n s m i s s i o n S e r v i c e Potential E x p o s u r e

Transmission Service Potential Exposure is calculated per the fornmla belo;',:

Z'I'II-i ZTMI!
Modif> formula abo'~e to include t',',o new exposurc charge types for Rcliability
Coordination Service (see next sheet).

Issued b>: 1".Graham I.d;vards, Issuing Officer
Issued on: [",larch4, 2008

t!ffecti,,e: June 1. 2008

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Second Revised Sheet No. 1232F
Superseding First Revised Sheet No. 1232F

ISO
FI'RC [:[ectric Tariff, lhird Re',,ised Volume No I
',,lid ;~, est

Where:

"lie (Transmission Invoiced l£xposure) = all transmission service charges
associated with confirmed Transmission Service rescn,'ations from the number of
days in the previous month v, hich have been calculated or inw.ficed but not yet
paid.
TMI" (Transmission Measured Exposure) = all transmission service charges
associated v, ith contirmed Transmission Service reservations Ibr:

A.

1"he number of days of the current rnonth which when added to the
number of days in the previous month equals 50 Calendar l)ays if
the TIE has not been paid.
OR

13.

l'he number o f d a ) s in the current month plus the required number
of days in the subsequent month to equal 50 Calendar Days if the
111- has been paid.

RCIE (Reliability Coordination Invoiced l-xposure) - all Schedule 31 charges
associated with Reliability Coordination Service under Part I of Module F that
have been measured but not yet paid.
RCEI: (Reliability Coordination Estimated ExlxJsure) : all Schedule 31 charges
associated with Reliability Coordination Service under Part l of Module F that
have been measured but not yet paid.

Issued b): I . Graham Ed~ards, Issuing Officer
Issued on: March 4, 2008

EFte~:ti,,e: June I, 2008

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Midwes! ISO
FI~R("HlcclricTariff. Third Revised Volume No. ]

Original Sheel No. 1935

A T T A C H M E N T KK-I
Form of Service Agreement for Reliabilit?,.'Coordination Service
1.0

This Service Agreement. dated as of the d a ' .
o f _ ..
,
is entered into, b)
and bet'.,,cen the Midv.est ISO ("Transmission Pro~,ider") and
.. ("Reliabilit', Coordination Customer"),
(also hereafter rel~:rred to as Part? or Parties as the context requires).

2.0

I he Reliability Coordination Customer has been determined by the Transmission
Provider to be eligible for Reliability Coordination Ser',ice as set lbrth in Part I of
Module F of the Tariff, and the "lrransmission I'rovider agrees to provide set', ice ul'x',n the
request of an authorized representative of the Reliability Coordination Customer.

3.0

l'he P,eliability Coordination Customer: (i) agrees to supply information as set forth in
Section 73 of this Tariff, and such other inlbrmation, data. and specifications reasonabl?
necessaD, in accordance v, ith Good Ltility Practice, to permit the Transmission Provider
to provide the requested service: (ii) agrees to perform the obligations required of
Reliability Coordination Customers set forth in the Tariff; and, (iii) agrees to take and
pay tbr the requested service in accordance v.ith the provisions of the l'arifl'and this
Service Agreement.

4.0

Service under this Service Agreement shall commence on the later of: ( I ) the requested
service commencement date, (2) the date on which all required technical data has been
received and entered into the Transmission Provider models, or (3) any other date that
may be established by the Commission. Service under this Service Agreement shall
terminate upon receipt of written notification as required by the Tariff, or on a date
mutuall) agreed upon by the Parties, or as other,.~ ise pro~,ided under the Tariffor
Commission regulations.

5.0

Any notice required or authorized b) this Service Agreement ("Notice") or request made
b,, a Part,. regarding this Service Agreement shall be in writing. Notice shall be
personally delivered, transmitted by facsimile (with receipt verbally or electronicall)
confirmed), emailed, delivered by overnight courier or mailed, postage prepaid, to the
other Party at the address designated below. A Party may change its designated address
upon Notice to the other Party. If the Reliability Coordination Customer has designated a
Contract Manager to receive Notice, the contact information for that person or entity shall
also be inserted here:

[ssu~d b? : "['. Graham Kd~ards, Issuing Ollic~r
Issued on: Nl~irch.I.2008

Ktli.'cli~.': June h 2008

0080306-0053 FERC PDF

(Unofficial) 03/06/2008

Original Sheet No 1936

Midx~est ISO
FERC Electric laritt~ I'hird Revised Volume No. I

l'ransmission l'rovider

Keliabilit~, Coordination

Customer
Title:
Address:

5.1

General Counsel
701 City Center [)rive
Carmel, IN 46032
Fax: 317-249-5912
Email(d.
Contract Manager:

.

m

l h e Reliability Coordination Customer's designated Contract Manager shall have
the follm~,ing responsibilities, as mutually agreed to b', the Parties:

6.0

l h e "Fariffis incorporated herein and made a part hereol:

7.0

Description of Reliability Coordination Customer Transmission Facilities that arc within
the NERC definition of Bulk Electric System and that "MII be monitored by the
Transmission Provider:
lAttach a separate sheet listing all facilities to be covered by this Service Agreement I

m

.

.

_

Issued b): ] (iraham [!dwards, Issuing Officer

Issued on: X1arch4, 2008

m

lif]~:cli,,e: June 1, 2008

0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/2008

Midv, est ISO
FERC Electric "tariff third Revised Volume No. I

8.0

The Reliability Coordination Customer has determined that the follov, ing Reliability
Coordination Customer I'ransmission Facilities are subject to the follo',,,ing contractual
commitments that ma> limit the Reliability Coordination Customer's ability to
recontigure its Reliability Coordination Customer Transmission Facilities ",,,hen directed
to do so b,', the "Iransmission l'rovider: ]Describe the transmission lacilit',' and the nature
or'contractual limitation]

m

9.0

Original Sheet No. 1937

_

.

The fbllo',,, ing contractual commitments, laws or environmental restrictions ma}' limit the
Reliability ('oordination Customer's abiliD, to redispatch generation ,,',hen directed to do
so by the Transmission Provider: IDescribc the facility and the naturc ofthe limitation
knov,'n to the Reliability Coordination CustomcrJ

10.0 Representations and Warranties. Fach Part} represents and ',~,arrants to the other that, as of
the date it executes this Service Agreement:
I 0. I

The Part',' is duly organized, validly existing and in good standing under the laws
of the jurisdiction where organized;

10.2

The execution and delivery by the Party of this Service Agreement and the
pertbrmance of its obligations hereunder have been duly and validly authorized
by all requisite action on the part of the Party and do not conflict, based on
present knowledge and information, with any applicable law or with any other
agreement binding upon the Party; this Service Agreement has been duly
executed and delivered by the Party, and, upon receipt of any necessary regulator)'
approvals, this Service Agreement constitutes the legal, valid and binding
obligation of the Party enforceable against it in accordance with its terms except
insofar as the enlbrceability thereof may be limited by applicable bankruptcy,
insolvency, reorganization, fraudulent conveyance, moratorium or other similar
laws affecting the enfbrcement of'creditor's rights generally and by general
principles of equity regardless of whether such principles are considered in a
proceeding at law or in equity;

Issued b) : r. Graham Ed~ards. Issuing Ofticer
Issued on: ,March 4. 2008

Effective: June I. 20(}8

0080306-0053

FERC

PDF

(Unofficial)

03/06/2008

Midwest ISO
FEP, C l-lcctric Tariff. Third Rc,,ised Volume No I

Original Sheet No 1938

10.3

"l here are no actions at lay,. suits in equity, proceedings or claims pending or, to
the knowledge of the Part)', threatened against the Party before or by any fi:deral.
state, foreign or local court, tribunal or governmental agency or authoriLv that
might matcrially delay, prevent or hinder the performance by the Party of its
obligations hereunder; and

10.4

It is in compliance with all NERC and Regional Entit~ standards applicable to its
operations and facilities.

II.

~nmcnt.
Neither Part). may assign this Servicc Agreement or its rights hereunder
v, ithout the prior written consent of the other Party. ,.,.hich consent shall not be
unreasonably withheld, except in the case of a merger, consolidation, sale. or spin-offof
substantially all of'a Part)'s assets. Notwithstanding anything to the central' herein, the
following conditions shall apply to assignment orthis Service Agreement b). the
Reliabilit', Coordination Customer" (I) assignment may he made to only another eligible
F',cliabilit). Coordination Customer: (2) if any change is requested b) the assignee, it may
be approved by the Transmission Provider only if such change does not impair reliabilit) ;
and (3) the assignee must agree to be subject to and hound by all applicable terms and
conditions of the Ser','ice Agreement and the Tariff'..

12.

"l'hird Parh Beneticiaries. There are no intended third-party beneficiaries of this Service
Agreement. Nothing in this Service Agreement shall be construed to create an'. duty to.
any standard of care with reference to. or any liability to, any person not a Part) to this
Service Agreement.

13.

Entire Agreement. ]'his Service Agreement, v, hich incorporates the Tarifl~ constitutes
the entire understanding and agreement of'the I:'artics. and supersedes any and al~
previous communications, rcpresentations, understandings, and agrccments (oral or
~ ritten) bet~,,ccn the Parties v,'ith respect to the subjcct matter hereof. The headings used
in this Scrvicc Agreement arc for purposes of convenience only and shall not be
construcd to affect the meaning or construction of any of the provisions hereof.

14.

No Joint Venture. Nothing contained in this Service Agreement shall be construed to
imply the existence of a joint venture, principal and agent relationship, or employment
relationship betv, een the Parties, and no Party shall have an? right, pov, er or authority to
create any obligation, express or implied, on bchalfofthe other Party without the express
written consent of the other.

Issued by: I . Graham Ed;'.ards, Issuing Officer
Issued on: March 4. 2008

Eflk:cti'.c: Junt: l. 2008

~0080306-0053

FERC

PDF

(Unofficial)

03/06/2008

Midv,'est IS()
I:FRC Electric l'arift~ Third Revised Volume No. I

Original Sheet No. 1939

15.

Governing l.a~,,. This Service Agreement, to the extent not subject to the jurisdiction of"
the FERC, shall be governed by and construed in accordance ',~,ith applicable State laws.

16.

.Additional l'erms. If the Reliability Coordination Customer is the United States of
America or an agency thereol~ the terms and conditions tbund in Section 12B of the
Tariff applicable to participation b', the United State of America shall be incorporated in
this Set', ice Agreement and shall become a part hereof by this reference. If the Reliabilit,,
Coordination Customer is a public-power entity, the terms and conditions lbund in
Section 12E of the Tariff applicable to participation by public power entities shall bc
incorporated in this Service Agreement and shall become a part hereof b ) t h i s reference.

17.

No Waiver of Jurisdictional Immunity. If the Reliability Coordination Customer is not
subject to the jurisdiction of the FERC as a "public utility" under the Federal Po,.,,er Act,
the Reliability Coordination Customer shall not be required to take any action or
participate in any filing or appeal that would confer FI!RC jurisdiction over the
Reliability Coordination Customer. Nothing in this Service Agreement waives an',"
objection to, or otherwise constitutes a consent to, the jurisdiction by FERC over the
Reliability Coordination Customer or its transmission service, facilities and rates.

IN WITNI'SS \VI It!RI'OF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.
I ransmission Provider

By:
Name: "
'l itle:
Date:

Issued b) ]. Graham I dv.ards. Issuing Officer
Issued on: ".larch 4. 2008

Reliability Coordination Customer
B) :
Name:
Title:
Date:

l.:tt~eti'.,e: June 1. 2008

~0080306-0053

FERC

PDF

(Unofficial)

03/06/2008

Mid',vcs! ISO
FERC [~leclric tariff, lhird Revised Volume No. I

Original Shcel N o 1940

A T T A C I I M E N T KK-2

Form of Service Agreement Interconnected Operations and Congestion Management
Service
1.0

This Service Agreement, dated as of the ..... da.~ of
. ...... is entered into. by
and betv~ccn the Midwest ISO ("Transmission Pro',ider") and
CCongestion Management Customer"), (also hereafter
referred to as Party or Parties as the context requires).

2.0

l h e Congestion Management Customer has been deterrnined by the Transmission
Provider to be eligible l'or Services as set forth in Part II of Module F of the Tariff and the
l'ransmission Provider agrees to provide service upon the request of an authorized
representative of the Congestion Management Customer.

3.0

l'he Congestion Management Customer agrees : (i) to suppl) information as set lbrth in
Section 80 of the 1 arit'f: and such other information, dam, and specifications as the
Transmission Provider deems reasonabl} necessary in accordance v, ith Good L'tilit)
Practice in order to provide the requested service: (ii) to perform the obligations required
of Congestion Management Customers under the l'arifl, and (iii) to take and pa) fbr the
requested service in accordance with the provisions of the Tariff.

4.0

Service under this Service Agreement shall commence on the later of: (I) the requested
service commencement date, (2) the date on which all required technical data has been
received and entered into the Transmission Provider models, or (3) any other date that
may be established by the Commission. Service under this Service Agreement shall
terminate upon receipt of written notification as required by the Tariff. or on a date
mutually agreed upon by thc Parlies. or as otherwise provided under the Tariffor
Commission regulations.

5.0

Any notice required or authorized by this Service Agreement ("Notice") or request made
by a Part.', regarding this Service Agreement shall be in ',~,riting. Notice shall be
personally dcliw:red, transmitted by facsimile (with receipt verbally or electronically
contirmed), emailed, delivered by overnight courier or mailed, postage prepaid, to the
other Party at the address designated below. A Party may change its designated address
upon Notice to the other Party. If the Congestion Management Customer has designated
a Contract Manager to receive Notice, the contact information ['or that person or entity
shall also be inserted here:

Issued b>: T Graham I'd~ards, Issuing Officer
Issued on: ~.larch .l. 2008

Efl~¢tivc: Jura: I, 2008

0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/2008

Original Sheet No 1941

Midv,esl ISO
F[iRC I'leclric "l'arifl]Third Revised Volume No. I

C'ongeslion Management
Customer

Transmission Provider

]itle:
Address:

General Counsel
701 City Center Drive
Carmel, [N 46032
Fax: 317-249-5912
l!mailk~'
Contract Manager:

___

6.0

l h e Tariff is incorporated herein and made a part hereof.

7.0

Description of the Congestion Management Customer's transmission facilities that are
',',ilhin the NERC delinilion of Bulk Electric System, and all Flov.,gates that are
Coordinated Flov, gates, and Reciprocal Coordinated Flowgales under the Congestion
.Management Customer's control:
[Attach a separate sheet listing all fhcilities and Flowgates to be covered by this Ser,,ice

8.0

The Transmission Provider and the Congestion Management Customer have determined
that the initial list o f Designated Flov, gates, as defined in Section 83.2 of the I'arifl~ shall
bc the (bllo'.~ ing:

Issued b', : ]. Graham Ldwards, Issuing Officer
Issued on: March .l, 2008

l.Ztf~cti;e: June I, 200~

2 0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/2008

Midv, est IS,()
FERC Electric TarilL l h i r d I,tevised Volume No. I

9.0

Original Sheet No. 1942

The Transmission Provider and the Congestion Management Customer have determined
that the initial list of generators that arc capable of relieving congestion, as defined in
Section 83.2 of the Tariff; shall be the tbllowing:

10.0 Representations and Warranties. Each Part) represents and ,,',arrants to the other that, as
of the date it executes this Service Agreement:
10. I

The Party is duly organizcd, validl) existing and in good standing under the lav, s
of the jurisdiction v. here organized;

10.2

The execution and deliveu by the Party of this Service Agreement and the
perfbrmance of its obligations hereunder have been duly and validly authorized
b) all requisite action on the part of the Part',' and do not, based on present
knowledge and information, conllict with any applicable law or v, ith any other
agreement binding upon the Party" this Service Agreement has been duly
executed and delivered by the Party, and, upon receipt of any necessar) regulator3.,
approvals, this Service Agreement constitutes the legal, valid and binding
obligation of the Part), enfbrceable against it in accordance v.itb its t e r m s except
insothr as the enforceability thereof may be limited by applicable bankruptc',,
insolvency, reorganization, fraudulent conveyance, moratorium or othcr similar
laws affecting the enforcement of creditor's rights generally and by general
principles ofequity regardless or'whether such principles are considered in a
proceeding at law or in equity; and

10.3

I'here are no actions at law, suits in equity, proceedings or claims pending or, to
the knowledge of the Party. threatened against the Parly before or by an)' federal,
state, foreign or local court, tribunal or governmental agency or authority that
might materially delay, prevent or hinder the perlbrmance by the Part,', of its
obligations hereunder; and

10.4

It is in compliance with all NF.RC and Regional Entity standards applicable to its
operations and facilities.

Issued b~,: l" Graham I:.d;,.ards, Issuing Officer
Issued t)n; 5,1arch 4. 2008

Effi:cti'~e: June I. 2008

0080306-0053

FERC

PDF

(Unofficial)

03/06/2008

Midwest IS()
FI-RC"Electric laritI~ third Revised Volunlc No, I

Original Sheet No 1943

II.

:~ss.sjg_nment. Neither Party may assign this Service Agreement or its rights hereunder
without the prior writlen consent of the other Party, v, hich consent shall not be
unreasonably withheld, except in the case of a merger, consolidation, sale, or spin-offof
substantiall,, all of a Party's assets. Notwithstanding anything to the contrary herein, the
lbllo~', ing conditions shall appl', to assignment of this Service Agreement by the
Congestion Management Customer: ( I ) assignment may be made to only another eligible
Congestion Management Customer: (2) if an,', change is requested by the assignee, it may
be approved by the Transmission Provider only if such change does not impair reliability;
and (3) the assignee must agree to be subject to and bound by all applicable terms and
conditions of the Service Agreement and the Tariff.

12.

Third Part'/Beneliciaries. There are no intended third-party bcneticiaries of this Service
Agreement. Nothing in this Service Agreement shall be construed to create any dut', to,
any standard of care with reference to, or any liability to, an)' person not a Party to this
Service Agreement.

13.

I_~ntire Agreemenl.. This Service Agreement, which incorporates the Tariff. constitutes
the entire understanding and agreement of the Parties, and supersedes an',' and all
previous communications, representations, understandings, and agreements (oral or
v, ritten) bet'~een the Parties v, ith respect to the subject matter hereof The headings used
in this Service Agreement arc lbr purposes of convenience onl) and shall not bc
construed to at'ti:ct the meaning or construction ot'anx of the provisions hereof.

14.

No Joint Venture. Nothing contained in this Service Agreement shall be construed to
imply the existence of a joint venture, principal and agent relationship, or employment
relationship between the Parties, and no Party shall have any right, power or authorit~ to
create any obligation, express or implied, on behalf of the other Party without the express
~ riuen consent of the other.

15.

Governing I,aw. "|'his Service Agreement, to the extent not subject to the jurisdictkm of
the FERC, shall be governed by and construed in accordance with applicable State laws.

16.

Additional Terms. If the Congestion Management Customer is the United States of
America or an agency thereof, the terms and conditions tbund in Section 12B of the
"l'ariffshall be incorporated in this Service Agreement and shall become a pan hereof by
this reference. If the Congestion Management Customer is a public-power entity, the
terms and conditions found in Section 12E ofthe Tariffapplicable to participation by
public power entities shall be incorporated in this Service Agreement and shall become a
part hereof by this reterence.

Issued by: T Graham l.'dv,ards, IssuingOfficer
Issued on: March 4, 2008

Kflectivc: June I, 200~

2 0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/2008

Original Sheet No. 1944

Midv, c..stIS(.)
FERC l'lectric Tariff, |bird Re',,ised Volume No. I

17.

No Waiver o f Jurisdictional lmmunit'~'. If the Congestion Management Customer is not
subject to the jurisdiction o f the FERC as a "public utility" under the Federal Pov,'er Act.
the Congestion Management Customer shall not be required to take an.'.' action or
participate in an: filing or appeal that ~,.ould confer FERC .jurisdiction over the
Congestion Management Custm'ner. Nothing in this Service Agreement ~'.ai','es an)
objection to, or otherwise constitutes a consent to. the iurisdiction b2 I.I'RC over the
CongestJon Management Customer or its transmission service, facilities and rates.

IN Wl I'NESS WIIEREOF. the Parties have caused this Service Agreement to be
executed b) their respective authorized officials.

I ransmission Provider

B):

. . . .

Name:
l'itle:
Date:

Issued b) : T Graham Edwards, Issuing Officer
Issuedon: March 4. 2008

Congestion Management
Customer
13) :

Date:

Etlecti~ e: June I, 2008

~0080306-0053

FERC

PDF

(Unofficial)

03/06/2008

Midwest ISO
FERC Electric tariff, third Revised Volume No. I

OriginaISh¢ctNo 1945

AI~FACIIMENT KK-3
Form of Service Agreement for Market Coordination Service
1.0

"lhis Service Agreement, dated as of the d a )
of
, ..
is entered into, by
and bctv, een the Midv~est ISO ('"l ransmission Pr~wider") and
("Market Coordinatkm Customer"), (also hereafter
referred to as Party or Parties as the context requires).

2.0

The Market Coordination Customer has been determined by the Transmission Provider to
be eligible for Market Coordination Service as set [brth in Part II1 of Module F of the
Tariff. and the l'ransmission Provider agrees to provide the services upon the request of
an authorized representative of the Market Coordination Customer.

3.0

l h e Market Coordination Customer agrees: (i) to supply intbrmation as set [brth in
Section 91 of the Tariff: and such other inlbrmation, data, and specilications as the
Transmission Pro',ider deems reasonably necessaD' in accordance v,,ith Good Utility
Practice in order to provide the requested service; (ii) to perform the obligations required
of Market Coordination Customers under the Tariff; and, (iii) to take and pa) for the
requested service in accordance v, ith the provisions of the Tarit'E

4.0

Service under this Service Agreement shall commence on the later o f (1) the requested
service commencement date, or (2) the date on which all required transmission |acilitics.
loads and resources for which the Market Coordination Customer is responsible have
been received and entered into the "1ransmission Provider's Network Model and the
Transmission Provider's Comrnercial Model. or (3) an)' other date that may be
established by the Commission. Service under this agreement shall terminate upon
receipt of written notification as required by the Tariff, or on a date mutually agreed upon
by the Parties, or as otherwise ma', be pro,,ided under the Tariff or Commission
regulations.

5.0

Any notice required or authorized by this Service Agreement ("Notice") or request made
by a Party regarding this Service Agreement shall be in writing. Notice shall be
personally delivered, transmitted by facsimile (with receipt verbally or electronically
confirmed), emailed, delivered by overnight courier or mailed, postage prepaid, to the
other Party at the address designated below. A Party ma> change its designated address
upon Notice to the other Party. If the Market Coordination Customer has designated a
Contract Manager to receive Notice, the contact inlbrmation lbr that person or entity shall
also be inserted here:

Issued b>: l Graham t~dv,ards, Issuing Officer
Issued on: March 4, 2008

Effective: June I, 200~

3080306-0053 FERC PDF

(Unofficial) 03/06/2008

Original Sheet No 1(;46

,Midv, est IS()
FERC ['lectric Tariff, Third Re',ised Volume No. I

Transmission F'rovidcr

Market Co()rdination

Customer
Titlc:
Address:

General Counsel
701 City Center I)rivc
Carmel. IN 46032
Fax: 317-249-5912
Email"~

Contract Manager:

6.0

l'he l'aril'f is incorporated herein and made a part hereof.

7.0

Description of the Market Coordination Customer l'ransmission Facilities:
IOn the attached sheet list all facilities to be covered by this Service Agreement and
identify which services are being clected for each facilitv.]

8.0

l h e AIC/AI:C/'I'IC methodology to be used to coordinate transmission service bctv, ecn
the "I ariff and the Market Coordination Customer's transrnission lariff shall be as set forth
in Attachment A to this Service Agreement.

9.0

Representations and Warranties. Each Party represents and ~,arrants to the other that, as
of the date it executes this Service Agreement:
9.1

l'he Party is duly organized, validly existing and in good standing under the laws
of the jurisdiction where organized;

9.2

l'he execution and delivery by the Party of this Service Agreement and the
performance of its obligations hereunder have been dull, and validly authorized
by all requisite action on the part of the Party and do not conflict, based on
present knowledge and inlbrmation, v, ith any applicable law or with any other
agreement binding upon the Party; this Service Agreement has been duly
executed and delivered by the Party, and, upon receipt of any necessary regulatory.
approvals, this Service Agreement constitutes the legal, valid and binding
obligation of the Party enforceable against it in accordance with its terms except
insofar as the enforceabili b, thereof may be limited by applicable bankruptcy,
insolvency, reorganization, fraudulent conveyance, moratorium or other similar
laws affecting the enforcement of creditor's rights generally and by general
principles of equity regardless of whether such principles are considered in a
proceeding at law or in equity;

Issued b): I Graham I!dv,'ards. Issuing Officer
Issued 'an: March 4, 200~

Ella:eli',c: June I. 2008

20080306-0053

FERC

PDF

(Unofficial)

03/06/2008

Midwest IS()
FERC I-lectric Tariff. l'hird Revised Volume No I

Original Sheet No. 1947

9.3

l'here are no actions at law, suits in equit,,, proceedings or claims pending or, to
the knowledge of the Party, threatened against the Party before or by any federal,
state, tbreign or local court, tribunal or governmental agency or authority that
might materially delay, prevent or hinder the performance by the Part,,' of its
obligations hereunder: and

9.4

It is in compliance with all NEP, C and Regional Entity standards applicable to its
operations and lhcilities.

10.

~nment.
Neither Part+,, ma) assign this Service Agreement or its rights hereunder
~ithout the prior ~ rit~en consent of the other Party, v, hich consent shall not be
unreasonably v~ithheld, except in the case of a merger, consolidation, sale, or spin-off of
substantially all of a Party's assets. Notwithstanding anything to the contrar2,' herein, the
follo~ ing conditions shall apply to assignment of this Service Agreement by the Market
Coordination Customer: (I) assignment ma3 be made to only another eligible Market
Coordination Customer; (2) if any change is requested b) the assignee, it ma? be
approved b ) t h e "lransmission Provider only if such change does not impair reliability;
and (3) the assignee must agree to be subject to and bound b) all applicable terms and
conditions oftbe Service Agreement and the l'ariff'..

II.

"Ihird Party Beneficiaries. There are no intended third-party beneficiaries of this Service
Agreement. Nothing in this Service Agreement shall be construed to create an', duty to,
an~. standard of care with reference to. or an,,. li.',bility to, an,', person not a Party to this
Service Agreement.

12.

Entire Agreement. This Service Agreement, v, hich incorporates the Tariff; constitutes
the entire understanding and agreement of the Parties. and supersedes an~ and all
previous communications, representations, understandings, and agreements (oral or
v, ritten) betv, een the Parties with respect to the subject matter hereof The headings used
in this Service Agreement are tbr purposes of convenience only and shall not be
construed to affect the meaning or construction ofan.~ of the provisions hereof.

13.

No Joint Venture. Nothing contained in this Service Agreement shall be construed to
imply the existence of a joint venture, principal and agent relationship, or employment
relationship between the Parties, and no Pan)' shall have any right, power or authority to
create any obligation, express or implied, on behalf of the other Part), without the express
v, ritten consent o f the other.

Issued b): 1. Graham Ed'.'.ilrds, Issuing Of'ricer
Issued on: Xlarch 4, 2008

Effccti,,c: June I, 2008

20080306-0053

FERC

PDF

(Unofficial)

03/06/2008

ISO
FERC Electric I arit't] Third Revised Volume No. I

Y',,1id'.'. c st

Origina~ Sheet No. 1948

14.

Governing l,aw. This Service Agreement, to the extent not subject to the jurisdiction of
the FI-RC, shall be governed by and construed in accordance with applicable State laws.

15.

Additional Terms. If the Market Coordination ('usttmlcr is the United States of America
or an agency thereof thc terms and conditions tbund in Section 12B of the "lariffshall be
incorporated in this Service Agreement and shall become a part hereof by this reference.
If the Market Coordination Customer is a public-pov.er cntit',, the terms and conditions
found in Section 12E of the Tariffapplicable to participation b', public pov.er entities
shall be incorporated in this Service Agreement and shall become a part hereof b', this
reference.

16.

No Waiver of Jurisdictional lmmunit,,,. If the Market Coordination Customer is not
subject to the jurisdiction oftbe FI'II~,Cas a "public utility" under the Federal Power Act.
the Market Coordination Customer shall not be required to take an), action or participate
in an}' filing or appeal that v, ould confer FERC jurisdiction over the Market Coordination
Customer. Nothing in this Service Agreement v,'aives an), objection to, or otherv, ise
constitutes a consent to. the jurisdiction b) FERC over the Market Coordination
Customer or its transmisskm service, facilities and rates.

17.

"lax-l-xempt Financing. If the Market Coordination Custorner is an entity to v.hich
Section 12E of the Tariff'applies and has financed its generation and transmission
facilities, and may in the future finance upgrades, improvements and additions to its
gcncrati~m and transmission facilities, with the proceeds of debt, the interest on which is
excluded from gross income for Federal and State income tax purposes, then as a
condition to this Service Agreement becoming eflizctive, the Market Coordination
Customer shall obtain and deliver to the "lransmission Provider an opinion of a nationally
recognized bond counsel, or a ruling of the Internal Revenue Service ('qRS") that the
obligations of performance, as set forth in Module F of the Tariff, as of the date of such
opinion or ruling, v.ould not adversely affect such exclusion from gross income or
otberv,'ise impair the tax exempt status of such debt. Notwithstanding any other provision
of this Service Agreement or the Tariff, the Market Coordination Customer shall not be
required to perform or receive performance under this Service Agreement or Module F of
the Tariffif, in a subsequent opinion of a nationally recognized bond counsel or a ruling
of the IRS. it is determined that such performance or receipt of performance would
adversely affect the exclusion from gross income for Federal or State income tax
purposes of interest paid or to be paid on any debt issued or to be issued by or for the
benefit of the Market Coordination Customer. In such circumstances the parties to this
Service Agreement may initiate the procedures set forth in Section 12E of the Tariff, or
the Transmission Provider may immediately terminate this Service Agreement, or the
Market Coordination Customer may immediately terminate this Service Agreement,
subject to the requirements of Sections 94.3 to 94.3.5, Section 97.2 and Section 97.3 of
the Tariff:

Issued b~ : T. Graham l'dwards, ]ssuin~ Omcer
Issued on: March 4, 2008

I'ffcctiw.': June l, 2008

20080306-0053

FERC

PDF

(Unofficial)

03/06/2008

Original Sheet No 194'-)

Midwest ISt)
FERC Electric Tariff', l h i r d Revised Volume No I

18.

Bond Covenant and Financing Agreement Obligations. Nothing in Module F of the
Tariff or this Service Agreement, nor anything arising ti'om the Market Coordination
Customer's obligations and perlbrmance thereunder, shall affect or require the Market
Coordination Customer to which Section 12E of the Tariff applies to take or refrain li'om
taking any action that would affect the rights and obligations or enlbrceability of the
Market Coordination Customer's bond resolutions and financing agreements. The
Market Coordination Customer shall determine, in accordance with advice and opinions
from a nationally recognized bond counsel, what actions, conduct and pcrlbrmance it is
permitted to or must take under its bond resolutions and financing agreements. If, at any
time, the Market Coordination Customer's perlbrmance or receipt of perlbrmance under
this Scrvice Agreement or Module F of the Tariff would impair or adversely affect the
rights, obligations or enlbrceability of the Market Coordination Customer's bond
resolutions and financing agreements, then the Market Coordination Customer shall
immediately notify the Transmission Provider of this fact and the parties to this Service
Agreement may initiate the procedures set lbrth in Section 12 E of the Tariff~ or the
Transmisskm Provider may immediatel> terminate this Service Agreement, or the Market
Coordination Customer may immediately terminate this Service Agreement. subject to
thc requirements of Sections 94.3 to 94.3.5, Section 97.2 and Section 97.3 of the Tariff.

19.

Transition Period Charges. Based upon the Market Coordination Customer's historic
usage of the Transmission System during the tv, elve months period preceding the
effective date of Part 111 of Module F of the Tariff, the charge lbr Market Integration
"1ransmission Service as set forth in Schedule 32 shall be $
per month for the
remainder of the Transition Period.

IN WITNESS Wl IEREOF, the Parties have caused this Service Agreement to be
executed by' their respective authorized officials.
Market Coordination
Customer

"lransmission Provider

By:
Name:
Title:
Date:

Issued b'.: 1". Graham l'dwards, Issuing Officer
Issued on: March 4, 2008

By:
Name:
Title:
Date:

I'ffecti'.,e: June 1, 2008

~0080306-0053

FERC

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O r i g i n a I S h c c l N o 1950

Midwest ISO
FERr._" I'lcctric l'ariff. "lhird Rc'.,ised Volume No I

Congeslion
Managemen!
Process

(CMI')

MASTER

Baseline
Version 1.1
November 30, 2007

Issued b) : I C;raham l-.dw~irds, Issuing Ofli¢cr
Issued on: March .I. 2008

['ffcclivc: June I, 2008

20080306-0053

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(Unofficial)

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Midwest IS()
FI~RC Electric Iitril]~ Third Rc',iscd k. olume No, I

Original 'Sheet No 1951

Executive Summary

This ('ongestum Management l'rocess document provides significant detail in the areas o f
Market Flow ('alczdation. These addttional details are the result o f discussions between multq;le
()peratmg Entities.
As Operating Enttties expand attd intplement their re.spective markets, one o f the primary seams
issues that must be resolved is ho~ dill, rent congestion management methodologies (marketbased and traditional) will interact to ensure that parallel[lows and impacts are recognized and
controlled in a manner that con.~%'tentlv ensures .sTstem re/iabi[tt)'. "['hisproposed solution will
greatly enhance current Interchange Distribution ('alculator (ID(') granularity b) utilizing
existinG real-time applications to monitor and react to FIowgates external to an Operating
Entity's [botprint
In brief the proce~s inch+des the [ollowing concepts
•

Partictpating Operating Entittes will agree to observe limits on an extensive list q/
coordinated external 1.7owgate.~.

•

Ltke all Control Areas t'C'A/. Market-Based Operating Enttties will have l"irm Market
t"lows upon those FIowgates.

•

Market-Based Operating Entities ~ill determine Firm Market Fhms and convtram their
operattons to lhnit Firm Market FIo~*s on the f'oordmated t"[owgate.g to no more than the
calculated t'Trm Flow Ltmit estahhshed tn the analysis.

•

bt real-time. Market-Based Operating Entitie.g will calculate and monttor one-hour
ahead preyected and actual flows

•

Market-Based Operating Entities will post to the ID(" the actual and the one-hour ahead
projeeted market flow, consisting o[the Firm Market Flow and the additional Non-Firm
Market Flow, fi;r both internal and external C'oordinated FIowgates.

Issued h',: I. Graham l-Zd~,ards. Issuing Officer
Issued on: klarch 4, 2(X)8

l-:fl~.'cli',c: June I. 200g

0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/2008

Mid'.', est IS()
FERC Electric larifl~ Third Revised Volume No. I

Original Sheet No. 1952

•

Market-Based Operating Enttties wtllprovide to the IDC detailed r~Tn'esent~aion ~(their
marginal units, so that the ID(" can continue to ef~,ettvelv compute the t~ff~'ctso f all
tagged transacttons regardless ~[ the size ~(the market area. These tagged transacttons
will include transactions into the market, transactions out o/the market, transactions
through the market, atul tagged grandfathered transactions ~ ithin the market

•

When there is a ~}'~msntisston Loading RelitJ{TLRI 3a request or htgher called on a
C'oordinated FIowgate, and the Market-Ba~ed Operating Enti O"'s actual, one-hour ahead
prolected Market l'7ows exceed the Firm ]"low Limit.s, Market-Based Oper~zting Entities
~vill redi.v)atch in order to provhte the reqttlred megawatt (MW) relA~f, per the ID("
congestion management report.

•

When there is a ILR 5a or 5b, all 7)'ansmission Providers will curtail or redi,~putch their
respective .wstems to provide their shares ~[']~2,twork and Nattve Load (N,VL) re~htctions
as directed by the II)C',

•

Because the 119(" will have the real-time'one-hour aheadprc?jectedflows throughout the
Market-Based Operatmg Enti O, ".s s)wtem (as repre.wnted by the Impacts upott variaus
( "oordinated l"lowgate.s7, the qffecttveness ~/the If)(" will be greatly enhanced

•

The above processes refi~r to the "('ongestion Managemettt "portum o f the paper, which
will be implemented by Market-Based OperathTg Fntities

•

Additional entities may choose to enter into similar Reciprocal ('oordinalion Agreements
that describe how Available Tran.~Jer Capability (AlL')/Available Howgate Capabih O,
(.4FC), Firm 1"7ows, and outage maintenance will be coordinated on afterward basis.

•

"1hecomplete process will allow participating Operating Entities to address the
reliability aspects o f congestion management seams issues between all parties whether
the seams arc between market to non-market operations or market-to-market operations,

Issued b~: r. Graham Edwards, Issuing Ol~cer
Issued on: March 4, 2008

Effi:cti~c: June I, 2008

~0080306-0053

FERC

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(Unofficial)

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Midwest ISO
FI'I>-,C Electric ['ariff, t h i r d Rc',,iscd ;'olumc No. I

Original Sheet lNo 1~)53

Chanl~eSummao'

Generate baseline Congestion Management Process (CMP) document based on CMP
documents executed by:
•
•
•
•
•

Manitoba llydro and the Midv.est IS()
MAPPCOR and the Midv, est IS()
The Midv, cst IS() and PJM
The Midv.est ISO, PJM and TVA
The Midv.est ISO and SPP

"lhe document also includes subsequent changes agreed upon by a majorit) of the Congestion
Management Process Council (CMPC). For items v, hich are specific to a limited number of
agreements, the ('MP members have used an approach of documenting these unique items in
separate appendices rather than in the base document. The CMPC members reserve all rights
~ith respect to the dillS:rent options identified in the appendices attached hereto without an~
obligation to adopt or support such options. l h c CMPC rnembers reserve the right to oppose
any position taken by another CMPCmember in a FERC filing or otherv, ise with respect to
the choice of options listed in the appendices. Nothing contained herein shall be construed to
indicate the support or agreement by the CMPC members to an option presented in the
appendices.
Revision 1.1 (November 30, 2007)
leer I:ERC Order ER07-1417-000, in the "'For'.sard Coordination Processes" section 6.6
added the word "'outage'" between "unit" and "scheduling" in the fbllo',ving sentence,
"'Market-Based Operating Entities will use the Flowgatc limit to restrict unit outage
scheduling tbr a Coordinated Flov.'gate t h e n maintenance outage coordination indicates
possible congestion and there is recent TI,R activity on a Flov, gate."

Issued b,',: ]. Graham Edwards, ]ssuing ()t'ficcr
Issued on: ,",larch 4, 2(X)8

t-lt'f~ctivc: June I. 2008

~0080306-0053

FERC

PDF

(Unofficial)

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Mid',',cst IS()
FER(" Elcclric l'arifl~ third Rc',isud Volume No. I

Original 5hecl No. 195.1

]'able of Contents
Sheet No.
S E C T I O N 1 - I N T R O D U C T I O N ..........................................................................................
1.1

1.2

P r o b l e m D e f i n i t i o n ......................................................................................................
I.l.I
The Nature o f Energy Flows .....................................................................
1.1.2
Granularity in the II)C ..............................................................................
I. 1.3
Reduced Data and Granularit? Coarseness ...............................................
I.I.4
Accounting for Loop Flows ......................................................................
1,1.5
Conclusion ................................................................................................

1950

1950
1950
1950
1950
1950
1950

Process Scope a n d L i m i t a t i o n s ..................................................................................
1.2.1

V i s i o n Statement .......................................................................................

1.2.2

Process Scope ............................................................................................

1950
1950
1950

i.3

G o a l s a n d M e t r i c s .......................................................................................................

1950

1.4

Assumptions

1950

................................................................................................................

S E C T I O N 2 - P R O C E S S O V E R V I E W ................................................................................

1951

2.1

S u m m a r y o f Process ...................................................................................................

1951

S E C T I O N 3 - I M P A C ' F E D F L O W G A T E D E T E R M I N A T I O N ........................................

1953

3.1

1953

3.2

F l o w g a t e s .....................................................................................................................
C o o r d i n a t e d F l o w g a t e s ...............................................................................................
3.2.1
Flowgate Studies .......................................................................................
3.2.2
Disputed Flowgates ...................................................................................
3.2.3
Third Party Request lqowgate Additions ..................................................
3.2.4
Frequency o f Coordinated Flowgate Determination .................................
3.2.5
Dynamic Creation o f Coordinated Flowgates ...........................................

Issued b.',: r Graham Eds~ards, Issuing Officer
Issued oil: March 4, 2008

1953
1954
1956
1956
1957
1957

Effectisc: June I. 2008

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Midwest ISO
FEI~,C Electric I ariff', Third lZ.~vised Volume No I

OriginaISheelNo 1955

SECTION 4 - MARKET-BASEl) OPERATING ENTITY FLOW CALCULATIONS:
M A R K E T F L O W , F I R M M A R K E T F L O W , A N D N O N - F I R M M A R K E T F I , O W ...... 1958
4.1

M a r k e t Flow Determination ......................................................................................

1959

4.2

F i r m Flow D e t e r m i n a t i o n ...........................................................................................

1964

4.3

D e t e r m i n i n g the F i r m Flow Limit .............................................................................

1964

4.4

F i r m M a r k e t Flow Calculation Rules .......................................................................

1965

SECTION 5 - MARKET-BASED OPERATING ENTrrY CONGESTION
M A N A G E M E N T ....................................................................................................................

1967

5.1

Calculating M a r k e t Flows ..........................................................................................

1967

5.2

Q u a n t i f y and P r o v i d e Data for M a r k e t Flow. ..........................................................

1967

5.3

Day-Ahead O p e r a t i o n s Process .................................................................................

1968

5.4

Real-time O p e r a t i o n s Process - O p e r a t i n g EntiW Capabilities .............................

1968

5.5

Market-Based Operating Entity Real-time Actions ................................................

1969

Issued by: T. Graham Edwards, Issuing Officer
Issued on: March ,I, 2(108

Ef'li.,etile: June l, 2008

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O r i g i n a I g h c c t N o 1956

Midwest ISO

FERC I'lcclric Tarilt. lhird Revised \ olume No I

SECTION 6 - RECIPROCAL
6.1

OPERATIONS

....................................................................

1970

R e c i p r o c a l C o o r d i n a t e d F I o w g a t e s ...........................................................................

1970

6.2
1"he R e l a t i o n s h i p B e t w e e n C o o r d i n a t e d F l o w g a t e s a n d R e c i p r o c a l C o o r d i n a t e d
F l o w g a t e s .................................................................................................................................
1970
6.3

C o o r d i n a t i o n P r o c e s s f o r R e c i p r o c a l F l o w g a l e s ......................................................

1972

6.4

C a l c u l a t i n g I i i s t o r i e F i r m Flows ...............................................................................

1972

6.5

R e c a l c u l a t i o n o f Initial l t i s l o r i c F i r m Flow V a l u e s a n d R a t i o s .............................. 1973

6.6

6.7

F o r w a r d C o o r d i n a t i o n P r o c e s s e s ..............................................................................
6.6.1
D e t e r m i n i n g Firm l ' r a n s m i s s i o n Service Impacts ....................................
6.6.2
Rules tbr considering Firm l'ransmission Service ....................................
6.6.3
Limiting Firm T r a n s m i s s i o n Service ........................................................

1974
1978
1979
1080

S h a r i n g o r T r a n s f e r r i n g U n u s e d A l l o c a t i o n s ...........................................................
6.7. I
General Principles .....................................................................................
1983
6.7.2
Provisions for Sharing or "lranst~rring o f Unused Allocations: ............... 1984

1982

6.8

M a r k e t - B a s e d O p e r a t i n g E n t i t i e s Q u a n t i f y a n d P r o v i d e D a t a f o r M a r k e t Flow. 1988

6.9

R e a l - t i m e O p e r a t i o n s P r o c e s s f o r M a r k e t - B a s e d O p e r a t i n g E n t i t i e s .................... 1988
6.9.1
Market-Based Operating Entity Capabilities ............................................
1988
6.9.2
Market-Based Operating Entit) Real-time Actions ..................................
1989

S E C T I O N - 7 A P P E N D I C E S ................................................................................................

1989

A p p e n d i x A - G l n s s a D ' ...........................................................................................................

1989

A p p e n d i x B - D e t e r m i n a t i o n o f M a r g i n a l Z o n e P a r l i e i p a t i o n F a c t o r s .............................. 1992
A p p e n d i x C - F I o w g a t e D e t e r m i n a t i o n P r o c e s s ...................................................................

1993

A p p e n d i x D - T r a i n i n g ...........................................................................................................

2002

Appendix

2003

E -

T L R A v o i d a n c e (or R e s e r v e d ) .......................................................................

A p p e n d i x F - F E R C R C F D i s p u t e R e s o l u t i o n ( o r R e s e r v e d ) .............................................

2004

A p p e n d i x G - Allocation A d j u s t m e n t f o r N e w T r a n s m i s s i o n Facilities a n d / o r D e s i g n a t e d
N e l m o r k R e s o u r c e s (or R e s e r v e d ) .........................................................................................
1923

Issued b~: T Graham Edwards, Issuing Officer
Issued on: March 4. 2008

l:fl~cti~e: June ]. 2008

~0080306-0053

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Original Shecl No. 1957

5,¢idwcst IS()

FERC Electric Tariff, Third Revised Volume No. I

Section I Introduction
It is the intention o f the Reciprocal Entities to utilize the processes within this document. It
is fi.trther the intention to develop this process in a ~a)' that will allo~ other regional entities
with similar concerns to utilize the concepts within this process to aid in the resolution o f
their own seams issues.
-

I. 1 Problem Definition
1.1.1

The Nature of Energy Flows

Energy flows are distinctly different from the manner in which the energy commodit', is
purchased, sold, and ultimately scheduled. In the current practice of"contracl path"
scheduling, schedules identil~. ~a source point for generation o|'energ~,, a series of
~ heeling agreements being utilized to transport that cncrg',, and a specific sink point
','.here that energy is being consumed by a load. l lo,,sever, due to the electrical
charactcrislics of'the Eastern Intcrconnectlon. energy t]ows arc more dispersed than what
is described xsithin that schedule. This disconnect becomes of concern when there is a
need to take actions on contract-path schedules to effect changes on the physical system
(for example, the curtailment of schedules to relieve transmission constraints).
In the Eastern Interconnection, much of this concern has been addressed through the use
of'the North American Electric Reliability' Corporation (NERC) and/or North American
Energy Standards Board (NAESB)"I'I,R process. Through this process, Reliability
Coordinators utilize the IDC to determine appropriate actions to provide that relief. The
IDC bases its calculations on the use o|'transaction tags: electronic documents that
specify a source and a sink, which can be used to estimate real power flows through the
use o f a network model. In order to change llo~ss, the IDC is gi'~en a particular constraint
and a desired change in flows. The IDC returns back all source to sink transactions thai
contribute to that constraint and specifies schedule changes to be made that will effect
that change in flo~ss.

Issued by: r. Graham Edwards. [ssuing Officer
Issued on: March 4. 2008

Efl~cti'.'c: June I. 2008

2 0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/2008

Midv, est ISO
FERC Electric Tariff, l'hird Revised Volume No. I

Original Sheet No 1958

In other parts of the I:~astern Interconnection, however, the use of centralized economic
dispatch results in a solution that does not focus on changing entire transactions
(effectively redispatching through the use o f irnbalancc energ)), but rather redispatch
itself. In this procedure, the part) attempting to provide relief does not need to knov, that
a balanced source to sink transaction should be adjusted; rather, the)' are av, are o f a net
generation to load balance and the impacts of different generators on various constraints.
Bid-based security constrained central dispatch based on [.ocational Marginal Pricing is a
regional implementation of this practice.
Currentl), these tv, o practices are somewhat incompatible, l)ue to the electrical
characteristics of the Interconnection and geographic SCOl~ of the regions, this
incompatibility has b~en of limited concern, lk~wever, regional market expansion has
begun to dra', ~. attention to this operational disjoint, as the expansion itself exacerbates the
negative effects of the incornpatibilit2,.
1.1.2

Granularity in the IDC
The IDC uses an approximation of the lnterconnection to identil~' impacts on a particular
transmission constraint that are caused by flows between Control Areas. This
approximation allows fbr a Reliability Coordinator to identify tagged transactions with
specific sources and sinks that are contributing to the constraint. While tagged
transactions may sp~cif)' sources and sinks in a very specific manner, the IDC in general
cannot respect this detail, and instead consolidates the impacts of several generators and
loads into a homogenous representation o f the impacts o f a single Control Area. "/his is
rel;arred to as the granularity o f the IDC. Current granularity is typically defined to the
Control Area level; finer granularity is present in certain special situations as deemed
necessa D by NERC.

Issued b) : T Graham tid~ards, b, suing Officer
Issued on: March .l, 2008

[!t'l~cti'~e: June I. 2008

2 0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/2008

Midwest IS()
FtLRC Hcctric l~lri~lLThird Revised Volume No I

1.1.,.t

Origimtl Sheet N o IO59

Reduced Data and Granularity Coarseness

As centrally dispatched energy markets expand their tbotprint, tv,'o related changes occur
',~ith regard to the above process. In some cases, data previously sent to the IDC is no
longer sent due to the l~ct that it is no longer tagged. In others, transactions remain
tagged, but the increased market lbolprint results in an increase in granularity coarseness
',~ithin the IDC; that is, the apparent Control Area boundary, hecomes the same as the
rnarket boundar), so that what had been historically 30 or more Control Areas nov.
appears as one.
In the first change, transactions contained entirely within the market footprint arc
considered to be utilizing network service (even when the market spans multiple Control
Areas). As such, there is no requirement lbr them to be tagged (or such requirement is
waived b> NERC), and theretbre, no requirement that they be sent to the ID('. l'his is of
concern from a reliability perspective, as the IDC ,,~.illno longer have a large pool of
transactions from which to provide reliet~ although the energy flox~,smay remain
consistent with those prior to the market expansion. In other words, flows subject to TLR
curtailment prior to the market expansion are no longer available tot that process.
In the second change, the expansion of the footprint itself results in a dilution of the
approximation utilized by the IDC. When a market region is relatively small (or
isolated), the Control Area to Control Area approximation of that region's impact on
transmission constraints is acceptable; actions within the market lbotprint generally have
a similar and consistent impact on all transmission facilities outside the fbotprint.
However, v, hen the market fbotprint expands significantly, and is co-mingled with nonmarket Control Areas, the ability to utilize the historic approximation of electrically
representative flows fails to effectively predict energy flow. Impacts on external
lacilities can vary significantly depending on the dispatch of the resources within the
market tbotprint. With regard to the IDC, this inlbrmation is effectively lost v, ithin the
expanded fbotprint, and results in an increase in the level of granularity coarseness, or a
"loss of granularity."

Issued h~,: T, Graham t.Zd'~.ards, Issuing Officer
Issued on: March 4, 2008

Effective: June I. 2001,1

20080306-0053

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Midx~,est IS()
FEI~,(" Electric larifl~ l h i r d Revised \.olum¢ No I

Original Sheet No. 1960

1.1.4 Accounting for Loop Flows
The processes tbr accounting for loop (lows caused b), uses of the transmission system
between Control Areas are different under a market environment. Absent a market, loop
flows from Transmission Service reservations between Control Areas are identified and
accounted for by importing transmission reservations from surrounding systems. Under a
market environment, the market ~ill not have e.xpJicil transmission reservations for
evolving market dispatch conditions between markel Control Areas. Thus, a mechanism
fbr accounting for anticipated Market Flows on non-market s) stems is necessar).
1.1.5

Conclusion
"lhe net effect of these changes is that reliability must be managed through different
processes than those used belbre the market region's cxpansion. While relief can still be
requested using the current process, both the ability to predict the effectiveness of a
curtailment to provide that relief and the general pool of transactions available tbr
curtailment are rcduced. This congestion management process (CMP) otters a strategy
for eliminating this concern through a process that provides more intbrmation (finer
granularity) to the N I R C IDC for the market area. This new congestion management
process will ensure that reliability is not adversely afi'~ctcd as markets expand by
providing information and relief opportunities previously unavailable to the IDC.

Issued b~: ]" Graham l£d~ards. Issuing Oll]cer
Issued on: March 4, 2008

l-lfl;:cli,,~..; June I. 2008

0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

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I~lid~est ISO
FEP,C Electric Tariff, third Revised Volume No. I

1.2

Proce.~sScope and Limitations

1.2.1

Vision Statement

Original Sheet No, 1961

As Operating Entities become Market-Based Operating Entities, and expand their `. arious
markets, one of'the primar', seams isstles that must be resol,.'ed is ho'e. dil]~zrent
congestion management methodologies (market-based and traditional "ILR) will interact
to ensure parallel flo`.`.s and impacts are recognized and controlled in a manner that
consistently ensures sx stem reliability and equitability. Reliability Coordinators can
mandate emergent', procedures to maintain salb operating limits, ho`.~ever, without
coordination agreements that maintain flow limits in advance, the market would become
•,olatilc and the burden fbr relieving excess llox`. ~`.ould ignore tht: economics o f the
entities v, hich would be required to redispatch. For these entities, this process bill offer a
manner in which Market-Based Operating Entities can coordinate parallel flows with
Operating Entities that have not yet or do not contemplate implementing markets. This
process ".',ill provide more proactive management o f transmission resources, more
accurate information to Reliabilit> Coordinators. and more candidates for providing relief
'.',hen reliability is threatened due to transmission overload conditions.
1.2.2

Process Scope
This process has been written specifically with the goal o f coordinating seams bct~`.een
Reciprocal Entities and their respective neighbors

Issued by: l'. Graham Edv,ards, Issuing Officer
Issued on: March 4, 2008

Effective: June I, 2008

20080306-0053

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Midwest IS,()
FERC Electric "l'ilriff,Third Revised \'olun'te No. I

1.3

Original Sheet No 1962

Goals" and Metrics

This document fucuscs on a solution to meet the t'ollov, ing goals and requirements:
I. Develop a congestion management process whereby transmission overloads can be
prevented through a shared and effective reduction in Flowgate or constraint usage b,,
Reciprocal Entities and adjoining Reliability Coordinators.
2. Agree on a predefincd set of Flowgates or constraints to bc considered by all
Reciprocal Entities, and a process to maintain this set as necessau..
3. Determine the best way to calculate flo,,~ due to market impacts on a defined set of
Flowgates.
4. Develop Reciprocal Coordination Agreements that establish hov, each Operating
Emit) ',',ill consider its o~,,n Elowgate or constraint usage as well as the usage of other
Operating Entities when it determines the amount of Flov, gate or constraint capacit)
remaining. This process ',,,ill include both operating horizon determination as v, ell as
forward looking capacity allocation.
5. Develop a procedure for managing congestion v, hcn l:lowgates arc impacted b) both
tagged and untagged energy tlo~,,.
6. Develop a procedure for determining the priorities of untagged energy llov,'s (created
through parallel tlo',,,s from the market).
7. Agree on steps to be taken b~, Operating Entities to unload a constraint on a shared
basis.
8. Determine whether procedure(s) for managing congestion will differ based on ~,,hcre
the Flowgate is located (t.e., inside Reciprocal Entity A, inside Reciprocal Entity B.
or outside both Reciprocal Entity A and Reciprocal Entity B).

Issued by: T Graham Edv, ards. Issuing Officer
Issued on: ).larch 4. 2008

Eftectise: June I, 2008

0 0 B 0 3 0 6 - 0 0 5 3 FERC PDF

(Unofficial) 03/06/200B

h,lidv. csl IS()
FERC Electric rarifl, third Re',iscdVolumeNo I

Original SheetNo 1963

9. Confirm that the solution ssill be equitable, transparent, auditable, and independent
lbr all parties.
I0. Develop methodology to preserve and accommodate grandl~,thered transmission
rights, contract rights, and other joint-use agreements.
I I. Develop methodology to address changes in "l'otal Transfer Capability (TTC), such as
future system topology changes, new Designated Network Resources (DNRs), [ilcility
uprates/derates, prior outage limitations, etc., with respect to Allocation implications.
12. Develop a methodology for releasing Allocations if other panics do not join the
process or if there is ATC going unused.
1.4

Assumptions
l'hc processes set forth in this document were based on the following assumptions:
]. Point-to-point schedules sinking in, sourcing from, or passing through a MarketBased Operating Entity will be tagged.
2. The IDC or a similar repository o f schedules is needed at the ]nlerconnection's
current stale and for the foreseeable future.
3. l'he Market-Based Operating Entity can compute the impacts o f the untagged market
dispatch on the Flowgates as currently required by the IDC.
4. The Market-Based Operating Entity's Energy Management S3,stem (EMS) has the
capability to monitor and respond to real-lime and projected flows created by its reallime dispatch.
5. ['he Reliability Coordinator o f the area in which a Flowgate exists will be responsible
for monitoring the Flowgate, determining any amount o f relief needed, and entering
the required relief in the IDC.
6. The ]DC has been modified to accept the calculated values o f the impact o f real-time
generation in order to determine which schedules require curtailment in conjunction
with the required Market-Based Operating Entity's redispatch.
7. The IDC can calculate the total amount of MW relief required b,', the Market-Based
Operating Entity (schedule curtailments required plus the relief provided by
redispatch).

Issuedb~: I. Grahaml-dwards,lssuin~Officer
Issuedon: March4, 2008

Effective: June I, 2008

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.....

Original Sheet No. 1964

Midwest ISO
FERC Electric Tariff, Third Revised Volume No. 1

Section 2 - Process Overview

2.1

Summary of Process

In order to coordinate congestion management, a bridge must be established that provides for
comparable actions between Operating Entities. Without such a bridge, it is difficult, if not
impossible, to ensure reliability and system coordination in an efficient and equitable manner.
To effect this coordination of congestion management activities, we propose a methodology for
determining both firm and non-firm flows resulting from Market-Based Operating Entity
dispatch on external parties' Flowgates.

Pre
Market
Expansion

•

Post
Market
Expansion

. ............

,:-:--...:

...-.-:.:-~-.--.v=-:-:--:

Market Flows are defined as the calculated energy flows on a specified Flowgate as a result of
dispatch of generating resources serving market load within a Market-Based Operating Entity's
market. (Note: For the purposes of the Reciprocal Coordination process discussed later, Firm
Transmission Service (7F) will be combined with the untagged firm component of Market Flows
in the calculation of Historic Firm Flow. The Historic Firm Flow is described later in this
document).

Issued by: T. Graham Edwards, Issuing Officer
Issued on: March 4, 2008

Effective: June 1, 2008

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~.Jid~ ~sl I S ( )

Original Sheel No 1965

FER(." l'ledric 3"arifl~ I hird R~:viscd \'olum=: No. l

Market Flows can be divided into Firrn Market Flows and Non-Firm Market FIo',s s. Firm
Market Flo',,,s are considered as firm use or'the transmission s',stem for congestion management
purposes and ;','ill be curtailed on a proportional basis with other firm uses during periods of firm
curtailments and are equivalent to Firm Transmission Service. Non-l:irm Market Flows are
considered as non-firm use ofthe transmission s)slem for congestion management purposes and
',',ill be curtailed on a proportional basis with other non-firm uses during periods or non-firm
curtailments and are equivalent to non-firm Transmission Sere,ice. As such. Re]iabilil)
Coordinators can request Market-Based Operating Entities to provide relief under r l . R based on
these transmission priorities,

B.v applying the above philosophy to the problem of'coordinating congestion management, ,.s'e
can determine not onl)' the impacts of a Market-Based Ol:x:raling Entity's dispatch on a particular
Flov,gatc; we can also determine the appropriate firmness of'those llosss, This results in the
ahilio to coordinale both proacti',e and reactive congestion management bet',seen operating
entities in a ',va~ that respects the current r l . R process, while still allo,,~.ing for the P.exibilit~ of
internal congestion managemenl based on market prices.

Issued b): I Graham rdv, ards. Issuing orficcr
Issued on: Nlarch 4, 2008

[Lfti:cti'.,¢: Jun~ I. 200g

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Midv, est IS()
[-ER(" Electric lariff~ Third Revised Vt)lume No I

Original Sheet No. 1966

1 here are tv, o areas that must bc defined in order lbr this process to v, ork effcctivel> :
•

Coordinated Flowgale Definition. In order to ensure that impacts of dispatch arc
properly recognized, a list of Flowgates must be developed around v, hich congestion
management may be cffected and coordination can be established.

•

Congestion Management B~, coordinating congestion management efforts and
enhancing the TI.R process to recognize both untagged energy flo,,,,s and data of finer
granularity, we can ensure that ','.'hen f i r is called, the appropriate non-firm flows are
reduced before Firm Flows. This coordination ',,,'ill result in a reduction of II.R 5 events,
as more relief will be available in TI.R 3 to mitigate a constraint. This is accomplished
through the calculation of l]ox',s due to economic dispatch, as "~,ell as by providing
marginal unit inlbrmation to aid in interchange transaction management.

The next sections of this document discuss each of these areas in detail.
Section 3 - Impacted Flov,'gate Determination

3.1

Flowgates

Flowgates are |hcilitics or groups of lhcilities that ma? act as significant constraint points on the
system. As such. the) are typically used to analyze or monitor the effects of power flows on the
bulk transmission grid. Operating Entities utilize FIo',,,gates in various capacities to coordinate
operations and manage reliability. For the purpose ot"this process, there are three kinds of
Flowgates: AFC Elowgates. v, hich are defined in Appendix A, Coordinated FIo',~,gates (CEs),
v, hich arc defined belov,, and Reciprocal Coordinated Flowgates (RCEs), which arc defined in
"Reciprocal Operations" Section 6. A diagram illustrating how these three categories of
Flowgates arc determined is included as Appendix C.

3.2

Coordinated Flowgates

An Operating Entity will conduct sensitivit} studies to determine v~hich Flov, gates are
signilicantly impacted by the flovcs of the Operating [intity's Control Zones (historic Control
Areas that existed in the IDC). An Operating Entit,, identifies these Flowgatcs b) performing the
Jblh)wing four studies to determine which Flowgates the Operating Entity will monitor and help
control. A I-lowgate passing any one oftbese studies will be considered a Coordinated
FIowgate. Only AFC FIowgates will be eligible for consideration as Coordinated Flowgates. A
FIowgatc must have AFCs computed and these AFCs must be used to sell Transmission Service
in order to be a Coordinated Flowgate.

]ssut'd b.~: I . Graham lidwards. Issuing Or'ricer
Issued on: March 4, 2008

Effective: June h 2008

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Midv, est IS()
FERC ELectric larit't~ third Revised x, olume No 1

Original Sheet No. 11)67

An Operating I-ntity may' also specify' additional l:lowgates thal have not passed an>' of the lbur
studies to be Coordinated Flowgates. For Flov, gates on which the Operating Entity expects to
utilize the TI.R process to protect system reliability, such specification is required. [:or a list of
Coordinated Flowgates bctv,'een Reciprocal Entities, please see each Reciprocal lintity's Open
Access Samc-'l'ime Information System (OASIS) websitc.
Coordinated Flowgatcs arc identified to determine v, hich I:lov, gates an entity impacts
significantly. This set of Flowgates may then be used in the congestion management processes
and/or Reciprocal Operations defined in this document.
When performing the tbur Elowgate studies, a 5% threshold ',',ill be applied on an absolute basis
without regard to the positive or negative sign of the impact. Use of a 5% threshold in the
studies may not capture all Flov~gates that experience a significant impact due to market
operations. The Operating Entities have agreed It) adopt a Io'.,,er threshold at the time N[-RC
and/or NAESB implements the use of a lower threshold in the "II.R process.

3.2.1

Flowgate Studies

Study 1 ) - IDC Base Case
fusing Ihe IDC tooO
l'his is a one time study done betbre Control Area consolidation. The IDC can provide a list of
Flowgates for an)' user-specified Control Area ,,',hose GI.DF (Generator to Load Distribution
I:actor (NNL)) impact is 5% or greater. "lhe Operating Entity will use the IDC capabilities to
develop a preliminary set of Flowgates. This list will contain Flowgates that are impacted by' 5%
or greater by the Control Areas that will be joining the Operating Entity as Control Zones/areas.
OTDF Flowgates ',,,ill be analyzed with the contingent element out of service. Using the historic
Control Area representation in the IDC (i.e., pre-Operating Entity expansion), if any one
generator has a GI.DF (Generator to t.oad Distribution |:actor) greater than 5% as determined by
the IDC, this Flo'~sgale ',',ill be considered a Coordinated Flov,.gate.

Issuedb): l Grahaml'dwards, lssuingOfficer
Issued on: March 4, 2008

Effu~:tive: June 1,2008

~0080306-0053

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FERC Electric l arift Third Re',ised Volume No

Original Sheet No 1968
I

S t u d y 2) - I D C P S S / E B a s e C a s e
(no Ir¢lnsmi.~'tOlZ oltlo~¢s .. (~ff]ine slltdyJ

For those situations where one or more CAs are being, or have been incorporated into an
Operating Entity's lbotprint after the freeze date. there ~'*ill be a generator anal)sis perlormed to
determine which Flowgates impacted by those (?As will be included in the list of Coordinated
Flow'*gates. In order to confirm the IDC anal)sis, and to provide a better confidence that the
Operating Entity has eflectively captured the subset of FIo'~vgates upon v, hich its generators have
a significant impact, an offlinc study utilizing MUST capabilities ',',ill be conducted, r h e
Operating l-ntity '*'*illperform off-line studies (using the IDC PSS/E base case) to confirm the
IDC analysis. Study I and Stud',' 2 arc separate studies. Thcrc is no requirement that a Flowgate
must pass both studies in order to be coordinated.
S t u d y 3) - I D C P S S / E B a s e C a s e
(tran~mts.~ion o u t a g e - offline s t u d 7)

For those situations ~'*here one or more ('As are being, or have been incorporated into an
Operating Entity's footprint alier the freeze date, there will be a Flowgale analysis performcd to
determine v, hich FIo'*'*'gatesimpacted by those (?As ~sill be included in the list of Coordinated
Flowgates. The Operating Entity, in consuhation with affected operating authorities. ~,ill
perform a prior outage analysis, including both internal and external outages. The FIo','*gates
detcrmined using Study 2 or 4 that have a 3% to 5% distribution factor ,,'*ill be analyzed against
prior outage conditions. This study will be performed offline utilizing MUS'I capabilities. If
any Flo',,,gates with a 3% to 5% distribution factor from Study 2 or 4 are impacted by 5% or
more from a prior outage condition (l.ine Outage Distribution Factor I,ODF) from this method.
the Flowgate will be added to the list of Coordinated Flov.gates.
S t u d y 4) - C o n t r o l A r e a to C o n t r o l A r e a

For thosc situations ~,here one or more CAs are being, or have been incorporated into an
Operating [-ntit)'s footprint after the freeze date, there ',,,ill be a Flowgate analysis performed to
determine which Flov, gates impacted by those CAs ",','illbe included in the list of Coordinated
Flowgates. The Operating I-ntity will analyze transactions between each ne'*v CA and the
existing market, as well as between each CA/CA permutation (if more than one CA is moving
into the tbotprint). O'I'DF Flowgates will be analyzed with the contingent elcment out of service.
This study will use Transfer Distribution Factors (TDFs) from the IDC and offline studies
utilizing MUST capabilities. Flowgates that are impacted by greater than 5% as determined by
the IDC will be considered a Coordinated Flowgate.

Issued by: T Graham Edwards, Issuing Officer
Issued oil: ~.larch4. 2008

Hllzcti'.,c: June I, 2008

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Midv, esl ISO
FERC Electric Tariff; Third Revised Volume No. 1

3.2.2

Original Sheet No. 1969

Disputed Flowgates

lfa Reciprocal Entity believes that another Reciprocal Entit', implementing the congestion
management portion of this process has a significant impact on one of their FIo'.'.gates, but that
Flov,gate was not included in the Coordinated Flowgatc list. the involved Reciprocal Entities
will use the follov, ing process.

If an operating emergency exists invnlving the candidate Flowgatc. the Reciprocal
Entities shall treat the facilities as a temporau, Coordinated Flowgate prior to the study
procedure belov,. If no operating emergency or imminent danger exists, the study
procedure below shall bc pursued prior to the candidate FIo',,,gate being designated as a
Coordinated Flov, gate.
"lhe Reciprc, cal l-ntit) conducts studies to determine the conditions under ~hich the other
Reciprocal Entity would have a significant impact on the Flov, gate in question, l'he
Reciprocal Entity conducting the study then submits these studies to the other Reciprocal
Entity implementing this process. ]'he Reciprocal Entity's studies should include each of
the four studies described above; in addition to any other studies they believe illustrate
the validity of their request. The other Reciprocal Entity ',,,'ill revic~ the studies and
determine if they appear to support the request of the Reciprocal Entity conducting the
study. If they do, the Flowgate will be added to the list of Coordinated Flowgates.
If, following evaluation of the supplied studies, any Reciprocal Entity still disputes
another Reciprocal Entity's request, the Reciprocal Entit', will submit a lbrmal request to
the NERC Operations Reliability Subcommittee (ORS) asking fbr further rc,,iew of the
situation. The ORS ',',ill review the studies of both the requesting Reciprocal Entity and
the other Reciprocal I-ntity. and direct the participating Reciprocal I'ntities to take
appropriate action.

3.2.3

Third I'arty Request Flowgate Additions

Each party shall provide in its stakeholder processes opportunities for third parties or other
entities to propose additional Coordinated FIowgates and procedures for review of relevant nonconfidential data in order to assess the merit of the proposal. The current procedure for the
review and maintenance of Coordinated Flowgates is set fbrth in Appendix C.

Issued b): "1. Graham Edwards. Issuing Officer
Issued on: ",larch 4, 2008

Effective: June I, 2008

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Midssest ISO
FERC Electric tariff" l'hird Revised Volume No. 1

3.2.4

Original Sheet No. 1'970

Frequency of Coordinated Flowgate Determination

The determination of Coordinated Flowgates will be perfbrmed at the initial implementation of
the CMP and then on a p,.:riodic basis, as described in Appendix C.

3.2.5

Dynamic Creation of Coordinated Flowgates

For temporary Flov, gates developed "'on the tly," the IDC will utilize the current II)C
methodology tbr determining NNL contribution until the Market-Based Operating l.lntity has
begun reporting data tot the hey, Flov, gate. Interchange transactions into. out o1~ or across the
Market-Based Operating Entity ',',ill continue to be E-tagged and available tbr curtaih'nent in
TLR 3, 4, or 5. Markct-13ased Operating Entities ,,,.ill study the Flowgate in a timely manner and
begin reporting Flowgate data within no more than two business days (:',here the Flov,'gate has
already been designated as an AI:C l:lowgate). ] h i s will ensure that the Market-Based Operating
l'ntity has the time necessary to properly study the FIo'~',gate using the lbur studies detailed
earlier in this document and determine the l:lo~*gate's relationship with the Market-Based
Operating Entity's dispatch. F'or internal Flowgates, the Market-Based Operating Entity ',~,ill
redispatch during a TI.R 3 to manage the constraint as necessary until it begins reporting the
Firm and Non-I:irm Market Flows; during a TER 5, the IDC will request NNI. relief in the .same
manner as today. Alternatively, for internal and external Flowgates, an Operating Entity may
utilize an appropriate substitute Coordinated Flowgate that has sit'nilar Market Flo',',s and tag
impacts as the temporary Flov,'gate. In this case. an Operating Entity ',~ould have to realize relief
through redispatch and T1.R 3. An example of an appropriate substitute would be a I:lox',gate
',~,ith a monitored element directly in series ,,',ith a temporary Flowgate's monitored clcment and
v, ith the same contingent element. If the Flowgate meets the necessaD criteria, the MarketBased Operating Entity will begin to provide the necessary values to the IDC in the same manner
as Market Flow values are provided to the IDC lbr all other Coordinated Flowgates. The
necessar', criteria for adding a Flowgate are defined in Appendix C. If in the event of a system
emergency (TLR 3b or higher) and the situation requires a response faster than the process may
provide, the Market-Based Operating Entities v, ill coordinate respective actions to provide
immediate relief until final revie',',.

Is.~ued by: l" Graham I-d'~ards. b, suin~ Oflic;cr
Issued ,.~n: March 4, 2008

EtTecU',,~: June I, 2C~0~

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Original Sheet No. 1971

Midwest IS()
EER(" Electric Tariff, Third Revised Volume No. I

Section 4 - Market-Based Operating Entity Flow Calculations: Market Flow, Firm Market
Flow, and Non-Firm Market Flow

Market Flov.s on a Coordinated Flowgate can be quantified and considered in each direction.
Market Flov, is then further designated into two components: Firm Market Flow, v, hich is energy
llow related to contributions from the Nctv, ork and Native l.oad servin,g aspects of the dispatch.
and Non-Firm Market 1:1(9,.',,which is energy flox', related to the Market-Based Operating
Entity's market operations.

..........................

i .....
Non-Firm
M ~ r k ~ t I~lnw.~

Total
Market
Flow on
Flowgate

1

Firm
Market Flows
From
Dispatch

Note: Market flows equal generation to load flows in market areas.

Each Market-Based Operating Entity will calculate their actual real-time and projected
directional Market Flows, as well as their directional Firm and Non-Firm Market Flov.,s, on each
Coordinated Flowgate. The following sections outline hov, these flov, s ",,,'illbe computed.

Issued by: I. Graham Edwards. Issuing Officer
Issued on: March 4, 2008

Efl~cti'.'¢: June I. 20(]8

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ISO
FER(" Electric Iarift~ l'hird Revised Volume No. 1
~.t idv, est

Original Sheet No. 1972

4.1
Market Flow Determination
The determination of Market Flov, s builds on the "'Per Generator" methodologies that ',,,ere
developed by thu NERC Parallel Flow Task Force. l'he "Per Generator Method Without
Counter Flov,'" was presented to and approved b', both the NERC Security Coordinator
Subcommittee (SCS) and the Market Interface Committcc (MIC). ~This methodology is
presently used in the IDC to determine NNL contributions.
Similar to the Per Generator Method, the Market Flow calculation method is based on Generator
Shift Factors (GSFs) of a market area's assigned generation and the l,oad Shift Factors (I,SFs) o f
its load on a specific Flowgate, relative to a systcm swing bus. The GSFs are calculated from a
single bus location in the base case (e.g. the terminal bus of each generator) ~,,hilc the LSFs arc
defined as a general scaling o f the market arca's load. l'hc Generator to l.oad Distribution
Factor (GI,DF) is detcrmined through superposition b) st,btracting the I.SF from the GSI:.
The determination of the Market FIo,,,, contribution o f a unit to a specific Flowgate is the product
of the generator's C,/A)F multiplied by the actual output (in megawatts) of'that generator, l'he
total Market Flow on a specific Flov, gate is calculated in each direction; forv, ard Market Flov, s
is the sum o f the positive Market Flow contributions of each generator v, ithin the market arca,
while reverse Market Flow is the sum o f the negative Market Flow contributions o f each
generator within the market area.
For purposes o f the Market I"1o','~determination, the market area may be the entire RTO
footprint, as in the following illustration, or it may be a subset o f the RTO region, such as a prcintegration NERC-recognized Control Area, as necessary to ensure accurate determinations and
consistency with pre-intcgration flow determinations. In the latter case, the total market flow of
an RTO shall be the sum o f the flows from and between such market areas.

"Parallel f:lo',~ Calculation Procedure Reference Document," NERC ()perafng Manual
.~hup: iwv.~,,,'.nerc.com , oc/operfnanl.hLfnl;.
Issued b,',: l Graham Edx,.ards. Issuing Officer
Issued on ~.larch 4. 2008

I I t:eh, 2003
l'tlectivc: June I, 2008

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....

Original Sheet No. 1973

Midwest ISO
FERC Electric Tariff, Third Revised Volume No. 1

Calculating the Market Flow Illustration
I=r~l~s~'~ ~s~

13~s~,~ rton

l~s~s'~ ~¢

O$:F = Ger~_r~ic~ ~hift Fa,:~or

Impact on ~loLugate :'.,~"trm',

tndMdual Ueneratorto ~wing Bus

N

.

.

.

L SF. = Lo~=t ~-hifi F:sc'['or
Impact on PIowgate. "'~" Irc1"n
5using Bus to ~1 Load

.

GLDF=

GSF- LSF

I heretore...
GLDF1 = G S F 1 - LSF-=
GLDF2= GSF2-LSF=
GLDF3 = G S F 3 - L S F

.5- .1 = . 4
25-:1

=.I5

= [-,'1]-.1 =(-~'}

i heretore...
P/~F1 = .4, x 50P~N = 20 UW Impw~

SPP

M F2 = .15 x 50 I ~ = 7.5 M W

Impact

F3 = i},2i~x 30 P~V = -8 l~IW Irrg,~

TVA

Therefore ...
Market Flov~ aoro~
•F i o ' v ~ e
;"A":

{20}. {7.~}(.s}

27.5 M W Fwd
.6 M W R e v

The Market Flow calculation differs from the Per Generator Method in the following ways:
•

The contribution from all market area generators will be taken into account.

•

In the Per Generator Method, only generators having a GLDF greater than 5% are
included in the calculation. Additionally, generators are included only when the sum of
the maximum generating capacity at a bus is greater than 20 MW. The Market Flow
calculations will use all flows, in both directions, down to a 3% threshold (this Market
Flow threshold is subject to the oUtcome of the NERC approved TLR procedures 12
month field test and the specific terms and conditions and effective date on which each
Market-Based Operating Entity will or has started the 12 month field test). Forward
flows and reverse flows are determined as discrete values.

•

The contribution of all market area generators is based on the present output level of each
individual unit.

•

The contribution of the market area load is based on the present demand at each
individual bus.

Issued by" T. Graham Edwards, Issuing Officer
Issued on" March 4, 2008

Effective: June 1, 2008

0 0 8 0 3 0 6 - 0 0 5 3 FERC PDF

(UnoEEicial) 03/06/2008

Midwest IS()
FER(" Electric "rarii]~ third Revised Volunll: NL~. I

Original Sheet No. 1974

By expanding on the Per Generator Method, the Market FIo,,,. calculation evolves into a
methodolog3, v¢D' similar to the "'Per Generator Method.'" while providing granularity on the
order of the most granular method developed by the IDC Granularity l'ask Force.
Directional flo',~.s are required for this process to ensure a Market-Based Operating lintity can
effectively select the most effective generation pattern to control the flows on both internal and
external constraints, but are considered as distinct directional f'io',,, s to ensure comparability with
existing NFIRC and/or NAF~SB TLR processes. Under this pr(x~ess, the use of real-time values in
concert with the Market Flow calculation effecti',el) implements one o|'the more accurate and
detailed methods oftbe six IDC GranulariD Options considered b.~ the NF~RC II.)C Granularit)
Task Force.
Units assigned to serve a market area's load do not need to reside within the market area's
lbotprint to be considered in the Market Flow calculation, llowever, units outside of the market
area ',,.ill not he considered when those units ~ill have tags associated with their transfers.
Additionally, there may be situations where the participation o f a generator in the market may be
less than 100% (e.g.. a unit.jointly owned in ~hich not all o f the owners are parlicipating in the
market). Such situations ~ill need to be recognized and accounted for in the markets"
operations.
Finally, imports into or exports out o f the rnarket area, and tagged grandtathered transactions
•Mthin the market area, must be properly accounted fbr in the determination o f Market FIo~,.s.
When the actual generation o f the market area exceeds the total load o f that area, the market area
is exporting energy. These exports are tagged transactions that must be accounted for in the
Market Flow calculation. This will be accomplished v, ithin the calculation b v including a new
term that offsets the M W output of the marginal unit(s) by the amount of the net market export.
This ensures that the Market [:low calculation is measuring o n b the effect o£ internal generation
serving internal load.
When the actual generation o|'the market area is less than the total load o|'the market area, that
area is importing energy. These imports are tagged transactions that are inherentl~ not included
in the determination o f Market Flows° as "Market |:lows" are a measure o|'intcrnal generation
serving internal load The processes currentl) within IIX~ ",,,'ill address the counting of these
transactions.

Issued by: I Graham Ed~vards,Issuing Otl]cer
Issued on: Mar~h 4, _.?.008

Effective: June I, 200g

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Mldv,esl IS()
I:ERC Electric tariff, I'hird Re~,isedVolume No. I

Original Sheet No. 1975

Below is a summary o f the calctdations discussed above.
For a specified Floodgate, the Market Flow impact o f a market area is given as:
Total Directional "Market Flows" = Y (Directional "Market Flow" contribution of each
unit in the Market-Based Operating Enti~"s area), grouped by impact direction
sshere.

"Market Flow" contribution of each unit in the Market-Based Operating Entily's area =
(GLDF) (Real-Time generator output) (Participation Percent/100)
and,
G I A ) F is the Generator to I,oad Distribution Factor

Real-Time generator output* is the present MW level of the generator
Participation Percent is the share of the unit participating in the Market-Based Operating
Entity's market
(* if" the Market-Based Operating Enti o' is a net exporter at the time or" the calculation, the
output level o f the marginal unit(s) has been reduced by this export value)

l h e real-time and one-hour ahead projected "'Market Flows" v. ill be calculated on-line utilizing
the Market-Based Operating Entity's state estimator model and solution. This is the same
solution presently used to determine real-time market prices as "~',ellas providing on-line
reliability assessment and the periodicity of the Market Flow calculation will be on the same
order. Inputs to the state estimator solution include the topology of the transmission s).stem and
actual analog values (e.g., line flows, transtormer flows, etc...). This infbrmation is provided to
the stale estimator automaticall> via SCADA s x stems such as N E R C ' s ISN link.
Using an on-line state estimator model to calculate "Market Flows'" provides a more accurate
assessment than using an off-line representation fbr a number of reasons. The calculation
incorporates a significant amount of'real-time data, including:

Issued by: I Graham Edwards, Issuing Ofti,.:cr
Issued on: March 4, 2008

Ef]bctive: June I, 2008