20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Matthew R. Dorsett
Attorney
Direct Dial: 317-249-5299
E-mail: MDorsett@misoenergy.org
VIA ELECTRONIC DELIVERY
October 25, 2012
The Honorable Kimberly D. Bose
Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
Re:
Midwest Independent Transmission System Operator, Inc.’s and
MISO Transmission Owners’ Compliance Filing for Order No. 1000,
Regarding Regional Planning and Cost Allocation of Transmission Projects
with Regional Benefits (Part 1 of 2)
Docket No. ER13-___-000
Dear Secretary Bose:
Pursuant to section 206 of the Federal Power Act (“FPA”), 16 U.S.C. § 824e, and Order
Nos. 1000, 1000-A, and 1000-B1 of the Federal Energy Regulatory Commission (“FERC” or
“Commission”), the Midwest Independent Transmission System Operator, Inc. (“MISO”) and
the MISO Transmission Owners2 (collectively, the “Filing Parties”) respectfully submit this
compliance filing proposing revisions to MISO’s Open Access Transmission, Energy and
Operating Reserve Markets Tariff (“Tariff”) and the Agreement of Transmission Facilities
1
Transmission Planning and Cost Allocation by Transmission Owning and Operating Public
Utilities, Order No. 1000, 136 FERC ¶ 61,051 (2011), order on reh’g, Order No. 1000-A,
139 FERC ¶ 61,132, order on reh’g and clarification, Order No. 1000-B, 141 FERC
¶ 61,044 (2012).
2
The MISO Transmission Owners join only Sections II.D.1 and II.D.3.b of this filing, and
reserve the right to submit separate comments or protests on this filing. The MISO
Transmission Owners for this filing consist of: Ameren Services Company, as agent for
Union Electric Company d/b/a Ameren Missouri, Ameren Illinois Company d/b/a Ameren
Illinois and Ameren Transmission Company of Illinois; City Water, Light & Power
(Springfield, IL); Dairyland Power Cooperative; Great River Energy; Hoosier Energy Rural
Electric Cooperative, Inc.; Indianapolis Power & Light Company; MidAmerican Energy
Company; Minnesota Power (and its subsidiary Superior Water, L&P); Missouri River
Energy Services; Montana-Dakota Utilities Co.; Northern Indiana Public Service Company;
Northern States Power Company, a Minnesota corporation, and Northern States Power
Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern
Wisconsin Electric Company; Otter Tail Power Company; Southern Illinois Power
Cooperative; and Southern Minnesota Municipal Power Agency.
Midwest Independent
Transmission System Operator, Inc.
Mailing Address:
P. O. Box 4202
Overnight Deliveries:
720 City Center Drive
Carmel, IN 46082-4202
Carmel, IN 46032
www.misoenergy.org
317-249-5400
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The Honorable Kimberly D. Bose
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Owners to Organize the Midwest Independent Transmission System Operator, Inc., a Delaware
Non-Stock Corporation (“Transmission Owners Agreement”).3 Certain revisions to the Tariff
and Transmission Owners Agreement proposed in this filing shall only become effective
contingent upon certain Commission findings as discussed in more detail, infra. The Filing
Parties request that the revisions proposed in this filing become effective with the first annual
planning cycle, beginning on June 1, following the issuance of the Commission’s order accepting
this filing. The same effective date is being requested in a concurrent section 205 filing by the
MISO Transmission Owners and MISO proposing to change the cost allocation for Baseline
Reliability Projects (“BRPs”).
I.
BACKGROUND
A. Order Nos. 1000 and 1000-A Set Forth Regional Transmission Planning and
Cost Allocation Requirements
Order No. 1000 amended the regional transmission planning and cost allocation
requirements of Order No. 8904 by imposing a number of requirements regarding new
transmission facilities selected in a regional transmission plan for purposes of cost allocation and
the interregional coordination and cost allocation of transmission facilities that involve
interregional benefits. The Commission required jurisdictional transmission providers to make
compliance filings concerning Order No. 1000’s regional planning and cost allocation
requirements within one year.5 As a Regional Transmission Organization (“RTO”), MISO
submits the present filing to address such requirements, and the MISO Transmission Owners join
Parts II.D.1 and II.D.3.b of this filing. Order No. 1000 also required compliance filings, within
3
Due to constraints related to MISO’s eTariff software, MISO is unable to package revisions
to its Tariff and TOA in the same filing because they do not share the same Tariff Identifier.
Therefore, MISO is submitting the TOA revisions in a separate filing package to the
Commission. This transmittal letter contains the justification for such revisions and the two
filing packages should be treated as one since technicalities related to MISO’s eTariff
software are the sole reason why they are being submitted in two separate filing packages.
4
Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890,
72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order
No. 890–A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 (2007), order on
reh’g and clarification, Order No. 890–B, 73 FR 39092 (July 8, 2008), 123 FERC ¶ 61,299
(2008), order on reh’g, Order No. 890–C, 74 FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228
(2009), order on clarification, Order No. 890–D, 74 FR 61511 (Nov. 25, 2009), 129 FERC
¶ 61,126 (2009).
5
On October 3, 2012, MISO submitted a motion requesting a two-week extension to submit
this filing. Motion of the Midwest Independent Transmission System Operator, Inc. for Brief
Extension of Time to Submit Compliance Filing and for Shortened Answering Period and
Expedited Commission Action, Docket No. RM10-23-000 (Oct. 3, 2012). The Commission
granted MISO’s request for an extension on October 11, 2012.
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18 months, regarding its interregional coordination and cost allocation requirements, which
MISO is currently discussing in stakeholder and interregional forums.
B. MISO’s Current Tariff and Transmission Owners Agreement Already Largely
Comply with Order Nos. 1000 and 1000-A’s Regional Requirements
As further discussed below, the current versions of MISO’s Tariff and the Transmission
Owners Agreement are already largely compliant with the regional transmission planning and
cost allocation requirements of Order Nos. 1000, 1000-A, and 1000-B. The MISO Tariff’s
transmission planning process outlined in Attachment FF (“Transmission Expansion Planning
Protocol”) of the Tariff describes the development of MISO’s Transmission Expansion Plans
(“MTEPs”) that are submitted to MISO’s Board of Directors for approval. The framework of
MISO’s planning process is also laid out in Appendix B (“Planning Framework”) of the
Transmission Owners Agreement. Consistent with Order No. 1000,6 Attachment FF establishes
a regional planning process that is designed to result in a regional plan, on a regular basis, to
identify and implement more efficient and/or cost-effective regional transmission solutions.
MISO’s process previously has been found to comply with the requirements of Order
No. 890,7 which Order Nos. 1000, 1000-A, and 1000-B build upon.8 MISO’s process
appropriately plans for and allocates the cost of transmission projects that address a variety of
needs relating to reliability (e.g., through Baseline Reliability Projects or “BRPs” and MultiValue Projects (“MVPs”)),9 economics (e.g., through Market Efficiency Projects or “MEPs” and
MVPs),10 and public policy (through Multi-Value Projects or “MVPs,” under Criterion 1
thereof).11 The costs of such projects are allocated in a manner that is consistent with cost
causation, and commensurate with the associated benefits.
With respect to MVPs, the Commission previously has found that “the MVP Proposal
represents another step forward in Midwest ISO’s evolution as a Regional Transmission
Organization (RTO) that provides increased efficiencies and benefits to its members that would
6
Order No. 1000 at P 146.
7
Midwest Indep. Transmission Sys. Operator, Inc., 123 FERC ¶ 61,164 (2008) (“Order
No. 890 Compliance Order”), orders on compliance, 127 FERC ¶ 61,169 (2009) and 130
FERC ¶ 61,232 (2010).
8
Order No. 1000 at P 1; Order No. 1000-A at P 1.
9
Midwest Indep. Transmission Sys. Operator, Inc., 114 FERC ¶ 61,106 (2006) (“RECB I
Order”), order on reh’g, 117 FERC ¶ 61,241 (2006).
10
Midwest Indep. Transmission Sys. Operator, Inc., 118 FERC ¶ 61,209 (2007) (“RECB II
Order”), order on reh’g, 120 FERC ¶ 61,080 (2007) (“RECB II Rehearing Order”); Midwest
Indep. Transmission Sys. Operator, Inc., 139 FERC ¶ 61,261 (2012).
11
Midwest Indep. Transmission Sys. Operator, Inc., 133 FERC ¶ 61,221 (2010) (“MVP
Order”), order on reh’g, 137 FERC ¶ 61,074 (2011) (“MVP Rehearing Order”).
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The Honorable Kimberly D. Bose
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otherwise be unattainable except through regionally coordinated operation.”12 Specifically, less
than one year ago, after weighing the Tariff’s MVP provisions in light of Order No. 890, the
Commission:
… continue[d] to find, based on the record, that the MVP Proposal enjoys broad state
authority and stakeholder support, presents significant incentives to construct new
transmission, and [] allocates the costs of new transmission fairly to the market
participants that use the Midwest ISO transmission grid and who will benefit from its
maintenance and further development.13
The MTEP process only needs to be supplemented in some respects to meet additional
requirements of Order Nos. 1000 and 1000-A involving the submission or posting of certain
information. This includes MISO’s explanation of its determinations to evaluate or not to
evaluate public policy-driven transmission needs for potential solutions in the local or regional
planning process;14 information merchant developers must provide to enable the evaluation of
potential reliability or operational impacts of their proposed transmission facilities on other
systems;15 and the enrollment and listing of non-public entities choosing to become part of MISO
for purposes of compliance with Order Nos. 1000 and 1000-A.16 Accordingly, MISO’s Tariff
only requires modest changes to comply with Order Nos. 1000 and 1000-A.17
MISO also includes revisions to the Tariff and the Transmission Owners Agreement in
this filing to address the Commission’s “nonincumbent transmission developer” mandates in
Order Nos. 1000 and 1000-A. The Commission, however, should disregard these revisions
unless the Commission first determines that it has satisfied the requirements of the Mobile-Sierra
doctrine,18 which applies to the Transmission Owners Agreement.19 Under the Mobile-Sierra
doctrine, the Commission is required to demonstrate serious harm to the public interest as a
prerequisite to compel modifications to the Transmission Owners Agreement, such as the
elimination of federal rights of first refusal and related nonincumbent transmission developer
reforms. The Commission has not satisfied, and is unlikely to be able to satisfy, the Mobile-
12
MVP Rehearing Order at P 32.
13
Id. at P 116.
14
Order No. 1000 at P 209.
15
Id. at PP 163-64; Order No. 1000-A at P 297.
16
Order No. 1000-A at PP 275-79.
17
Order No. 1000 at n.142; Order No. 1000-A at P 280.
18
United Gas Pipe Line Co. v. Mobile Gas Serv. Corp., 350 U.S. 332 (1956) (“Mobile”);
Federal Power Comm’n v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (“Sierra”).
19
E.g., Midwest Indep. Transmission Sys., Inc., 122 FERC ¶ 61,090 at n.41 (2008) (“the TO
Agreement … impose[s] a Mobile-Sierra standard of review.”).
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Sierra doctrine, as discussed in more detail in section II.D.1, infra. In Order Nos. 1000-A20 and
1000-B,21 the Commission made clear that it would not review any tariff or agreement revisions
submitted by a public utility transmission provider that has invoked the Mobile-Sierra doctrine
for its Commission-jurisdictional agreement until after the Commission determines that the
requirements of the Mobile-Sierra doctrine have been met. The revisions to the Transmission
Owners Agreement and related revisions to the Tariff should not be considered by the
Commission unless it is able to first demonstrate that existing Transmission Owners Agreement
provisions governing construction rights and obligations seriously harm the public interest.
C. The Present Compliance Filing was Developed Through MISO’s Stakeholder
Process
As stated previously and explained further below, MISO’s current Tariff is already
compliant, to a significant degree, with the regional planning and cost allocation requirements of
Order No. 1000. In addition, MISO is submitting Tariff revisions to supplement, enhance, or
clarify its compliance with such requirements. The proposed Tariff revisions were developed
over several months in consultation with stakeholders, including state regulatory commissions.
As described in the accompanying Affidavit of Jennifer K. Curran, MISO’s Executive
Director of Transmission Infrastructure Strategy, MISO undertook an intensive stakeholder
process involving stakeholder forums, meetings/conference calls, and materials summarized in
the table attached as Exhibit MISO-2 to the Testimony of Jennifer K. Curran. The stakeholder
discussions resulted in significant consensus on most of Order No. 1000’s compliance
requirements, and reasonable compromises on certain issues over which there were more
differences of opinion among stakeholders. The Testimony of Ms. Curran explains how MISO
ultimately decided to adopt certain approaches, such as a developer selection methodology, after
interested stakeholders were given an opportunity to explain their positions and suggest
solutions, and after MISO duly considered potential solutions, and obtained stakeholder votes on
the solutions adopted herein.
II.
DISCUSSION OF TARIFF REVISIONS
20
Order No. 1000-A at P 389 (“The Commission will first decide . . . whether the agreement is
protected by a Mobile-Sierra provision, and if so, whether the Commission has met the
applicable standard of review such that it can require the modification of the particular
provisions. If the Commission determines that the agreement is protected by a MobileSierra provision and that it cannot meet the applicable standard of review, then the
Commission will not consider whether the revisions submitted to the Commission
jurisdictional tariffs and agreements comply with Order No. 1000.”).
21
Order No. 1000-B at P 40 (“[W]e reiterate that the Commission is not requiring public utility
transmission providers to eliminate a federal right of first refusal before the Commission
makes a determination regarding whether an agreement is protected by the Mobile-Sierra
doctrine and whether the Commission has met the applicable standard of review.”).
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A. Planning Cycle Covered by Tariff Revisions
As required by Order No. 1000 (at P 65, 162), MISO has revised its Tariff to describe
how MISO will determine which facilities evaluated in its local and regional planning processes
will be subject to the requirements of Order No. 1000, in a manner that would “not delay current
studies being undertaken pursuant to existing regional transmission planning processes or
impede progress on implementing existing transmission plans.”22 Under MISO’s current
process, as clarified in the proposed Tariff language, an annual planning cycle for a specific
calendar year designation (e.g., “MTEP14”) begins on June 1 of the prior calendar year and
typically ends with the MISO Board’s approval of the final MTEP report, including the projects
recommended therein, in December of the particular MTEP’s designated calendar year (e.g., the
planning for MTEP14 will commence on June 1, 2013 and be completed in December of 2014).
MISO proposes that the Tariff revisions submitted in compliance with Order No. 1000’s regional
requirements be made effective with the first MTEP cycle commencing after issuance of the
FERC Order. For example, if an Order is issued before June 1, 2013, the Tariff revisions will be
effective beginning with the MTEP14 cycle beginning on June 1, 2013, which is MISO’s first
full MTEP planning cycle after the present Order No. 1000 compliance filing. Thus, in this
example, the projects to be covered by Order No. 1000’s regional requirements would be those
that are evaluated and approved as part of the MTEP14, which begins on June 1, 2013. On the
other hand, if an Order is issued after June 1, 2013, but before June 1, 2014, the Tariff revisions
will be effective with the MTEP15 cycle beginning on June 1, 2014.
This timetable for compliance is necessary to facilitate a fair and orderly transition into
the regional planning requirements of Order No. 1000, in a manner that would neither delay
current studies under MISO’s existing planning processes nor impede progress on the
implementation of existing transmission plans.
B. Regional Planning
1. Regional Planning Process and Plan
Order No. 1000 recognizes that RTOs engage in regional transmission planning resulting
in regional plans,23 and that an RTO whose regional planning process is compliant with Order
No. 1000 can describe such compliance without amending its tariff.24 As noted above, MISO’s
22
Order No. 1000 at P 65.
23
Id. at P 80.
24
Id. at n.71, PP 149, 795-96 (“an RTO or ISO … may make a compliance filing that
demonstrates that some or all of its existing RTO and ISO transmission planning processes
are already in compliance”; “many of the existing transmission planning and cost allocation
processes and methods may be similar to what [Order No. 1000] requires”; “it is possible that
some existing RTO and ISO transmission planning and cost allocation processes may already
satisfy [Order No. 1000] in whole or in part”).
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current Tariff largely complies with the requirement of Order No. 100025 to participate in a
regional transmission planning process that, in consultation with stakeholders, produces a
regional transmission plan and complies with the transmission planning principles of Order
No. 890 to consider more efficient or cost-effective alternative solutions for regional needs.26
As noted above, MISO’s existing MTEP protocol is a transparent and not unduly discriminatory
process for evaluating whether to select a proposed transmission facility in the MTEP plan for
purposes of cost allocation.27 This process complies with the Order No. 890 transmission
planning principles, ensuring transparency and the opportunity for stakeholder participation. The
evaluation process is designed to culminate in a determination sufficiently detailed for
stakeholders to understand why a particular project was selected or not selected in the MTEP
plan for purposes of cost allocation. This evaluation also includes the consideration of
alternative non-transmission solutions28 and transmission solutions,29 consistent with Order No.
1000 (at P 148).
The requirements of Order No. 1000 “build on the following transmission planning
principles that [the Commission] required in Order No. 890: (1) coordination; (2) openness;
(3) transparency; (4) information exchange; (5) comparability; (6) dispute resolution; and
(7) economic planning.”30 MISO’s MTEP process, mainly embodied in Attachment FF of the
Tariff, provides for a regional planning process that is designed to result in a regional plan on a
regular basis, and that has been found compliant with Order No. 890.31 MISO’s transmission
planning process remains compliant with Order No. 890, and as revised herein, also complies
25
Id. at PP 6, 116, 146, 148, 151.
26
Section I.A.1 of Attachment FF; Appendix B, Part VI of Transmission Owners Agreement.
27
Section II of Attachment FF.
28
MISO notes that, because resource adequacy is under the jurisdiction of the states, it is not
appropriate for MISO to include in the regional transmission plan recommendations of
“uncommitted” non-transmission alternatives (e.g., Generation Resources and Demand
Response Resources). To ensure compliance with reliability standards, only “committed”
non-transmission alternatives can be considered.
29
Consistent with Order No. 1000 (at P 148), MISO’s process also considers alternative
transmission solutions. Section IX of Appendix B to Transmission Owners Agreement
(MISO shall “identify alternatives for further study and review that could increase the
efficient and economic use of the Transmission System.”); Section I.B.1.b of Attachment FF
(“alternatives may include transmission, generation, and demand-side resources”).
30
Order No. 1000 at P 151.
31
See Order No. 890 Compliance Order, orders on compliance, 127 FERC ¶ 61,169 (2009) and
130 FERC ¶ 61,232 (2010).
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with Order No. 1000’s additional requirements.32 Such compliance is summarized below, and
the requirements of Order No. 1000 will be discussed further in this compliance filing.
(a) Coordination
Order No. 890’s coordination principle involves the full, meaningful and timely
participation of stakeholders and customers in the transmission planning process.33 The
Commission previously found MISO’s Tariff compliant with the coordination requirement.34
Specifically, section I.A.2 of Attachment FF includes procedures for stakeholder participation in,
and provision of input into, the planning process. Stakeholder participation is facilitated
through: (i) the Planning Advisory Committee, which addresses policy issues important to
stakeholders, reports to MISO’s Advisory Committee, and functions subject to the Stakeholder
Governance Guide developed by the Stakeholder Governance Working Group; (ii) the Planning
Subcommittee, a stakeholder-chaired subcommittee of the Planning Advisory Committee;
(iii) Sub-Regional Planning Meetings, held at least three times each year in various locations
throughout MISO’s footprint, to provide additional opportunities for stakeholders to provide
input into the planning process on a more localized or sub-regional basis.35
The mechanisms for stakeholder participation remain in place in MISO’s transmission
planning process. In addition, as further explained infra, the Tariff revisions proposed enhance
stakeholder coordination, clarify the role of the Organization of MISO States (“OMS”) in
transmission planning,36 and provide for the voluntary participation of non-jurisdictional
transmission entities.37
(b) Openness
The openness principle of Order No. 890 involves the accessibility of transmission
planning meetings to all affected parties, including stakeholders, customers, and state authorities,
subject to the appropriate protection of confidential information and Critical Energy
Infrastructure Information (“CEII”).38 The Commission also previously found MISO compliant
32
Order No. 1000 at PP 150, 153, 671.
33
Order No. 890 Compliance Order at P 20.
34
Id. at PP 28-30.
35
Id. at PP 21-22.
36
Section I.B of Attachment FF.
37
Section I.A of Attachment FF.
38
Order No. 890 Compliance Order at P 31; Order No. 1000 at P 157, n.365 (transmission
project “information must be made available subject to appropriate confidentiality
protections and CEII requirements”); Order No. 1000-A at P 281 (providing for data access
“while at the same time protecting information that is commercially sensitive or that is
otherwise considered confidential under Commission regulations”), P 282 (transmission
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with the openness requirement.39 In particular, section I.A.2.c.i of Attachment FF provides that
Sub-Regional Planning Meetings are open to any parties interested in and/or impacted by the
planning process. Section I.A.2.c.ii.f defines stakeholders in such a way as to include various
entities, such as regulators, environmental agencies, and load and generation developers, and
provides that all can participate in the Sub-Regional Planning Meeting process. Confidential
data and CEII data is protected pursuant to section I.A.12 of Attachment FF, which requires
appropriate Non-Disclosure and Confidentiality Agreements to the extent necessary.40
These provisions remain part of Attachment FF, which has also been revised to ensure
the openness of the transmission planning process, as required by the enhanced coordination
features described above regarding state regulatory authorities, and non-jurisdictional entities.
(c) Transparency
Order No. 890 requires transmission planning processes to be transparent by providing
and making available in written form the applicable methodology, criteria, standards, and
procedures.41 The Commission likewise earlier found MISO in compliance with the
transparency requirement.42 MISO’s Tariff meets this requirement in several ways, including
through sections I.A.3 through I.A.13 of Attachment FF, which describe the basis for planning
decisions and the basic methodology, criteria, and processes used to develop the MTEP to ensure
consistent application of planning standards. In addition, Section I.A.7 describes in detail the
procedures MISO will use to collaborate with all stakeholders to develop appropriate planning
models reflecting system conditions expected for the planning horizon. Section I.A.8 describes
the planning assumptions MISO will employ for the planning process, including the requirement
to treat load probability models consistently in planning for Transmission Owners’ native load
planning information should be made publicly available in a manner “consistent with
protecting the confidentiality of customer information”), P 520 (data transparency should be
“subject to appropriate confidentiality protections and CEII requirements”), and n.330.
39
Order No. 890 Compliance Order at P 35.
40
Id. at P 32-33. Section I.B.1 of Attachment FF provides, in part:
These regional planning processes, as provided for in this Attachment FF and in
additional detail in the TPBPM, ensure that the planning decisions for all such
facilities are made in an open and transparent environment. This planning
environment provides opportunity for input from, and review by, stakeholders of
the Open Access Transmission Tariff services throughout the planning process,
and is in accordance with the Planning Principles of the Order 890 Final Rule.
The open and transparent planning provisions of this Attachment FF shall not
preclude interaction between stakeholders and Transmission Owners prior to the
submittal of proposed projects to the regional planning process.
41
Order No. 890 Compliance Order at P 36.
42
Id. at PP 42-44.
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and other customers’ transmission access requests. These Tariff provisions are further detailed
in MISO’s Transmission Planning Business Practices Manual (“BPM”).43
These provisions continue to be features of Attachment FF.
(d) Information Exchange
Order No. 890’s information exchange principle involves network and point-to-point
transmission customers’ submission of projected load, resource (including demand response),
and service need information comparable to data used by transmission providers to plan for
native load.44 The Commission has also made a prior finding of MISO’s compliance with the
information exchange requirement.45 Attachment FF complies with the information exchange
principle in many respects. For example, section I.A.8 includes details about the elements of the
planning assumptions MISO will use in the planning process. In particular, section I.A.8.b
provides details on the coincident peak load projection methods to be employed by MISO to
model load demand for each entity, for the season under study. In addition, section l.A.8.d
addresses how MISO will deal with Demand Response Resources (“DRRs”) by incorporating
relevant information into planning assumptions.
Attachment FF continues to be compliant with the information exchange principle, and
has been supplemented herein to address the information exchange needs arising from Order
No. 1000’s requirements. Such requirements relate to information to be submitted by merchant
transmission developers whose projects may have reliability and operational impacts on other
parts of the Transmission System,46 and by entities seeking to be enrolled in MISO for purposes
of compliance with Order No. 1000.47
(e) Comparability
The comparability principle of Order No. 890 involves treating similarly situated
customers and resources comparably, duly considering the data and inputs of customers and
stakeholders.48 MISO has also been found to have satisfied the comparability principle.49
Attachment FF addresses comparability in several ways. For example, section I.A.13 states that
43
Id. at P 38. MISO’s BPMs, including the BPM for Transmission Planning can be found at:
https://www.misoenergy.org/Library/BusinessPracticesManuals/Pages/BusinessPracticesMan
uals.aspx.
44
Order No. 890 Compliance Order at PP 45-47.
45
Id. at P 52.
46
Section IV of Attachment FF.
47
Section I.A of Attachment FF.
48
Order No. 890 Compliance Order at P 53.
49
Id. at P 55.
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stakeholder comments and suggestions to the MTEP will be treated with equal importance,
whether the suggestions come from a Transmission Owner or a transmission customer. In
addition, under section l.A.8.d, DRRs will be evaluated comparably with Generation Resources
to evaluate the quantity of energy that can reliably be expected to be provided by DRRs in
emergency conditions, and DRRs will be evaluated as equivalent to Generator Resources as part
of the solution for peak load conditions.50
(f) Dispute Resolution
The dispute resolution principle of Order No. 890 requires the identification of a process
(including negotiation, mediation, and arbitration) for managing disputes arising from the
planning process.51 MISO’s Tariff has also been found to be consistent with the dispute
resolution principle.52 For example, section I.A.14 specifies how dispute resolution procedures
will be used for transmission planning disputes. Section I.A.14 of Attachment FF outlines a
three-step dispute resolution process of negotiation, mediation, and arbitration. These dispute
resolution procedures are in addition to the dispute management mechanisms in section 12 of the
Tariff. In addition, the Transmission Planning BPM provides for an Issue Resolution Process for
planning and cost allocation issues that arise in the MTEP development process.53
MISO’s existing dispute resolution process will also apply to matters arising from the
implementation of the proposed Tariff revisions.
(g) Economic Planning
Order No. 890’s economic planning principle requires that transmission planning also
account for and study economic considerations, in addition to reliability.54 The Commission has
previously determined that MISO complies with this requirement as well.55 MEPs, which
involve regional economic benefits, are provided for under section II.B of Attachment FF. MVP
Criterion 1 combines the achievement of public policy mandates with reliability or economic
50
Id. at P 54.
51
Id. at P 57.
52
Id. at P 59.
53
Id. at P 58.
54
Id. at PP 67-69.
55
Id. at P 74.
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drivers,56 while Criterion 2 focuses on multiple economic benefits,57 and MVP Criterion 3
combines economic and reliability benefits.58
Through the Planning Advisory Committee and in consultation with stakeholders, MISO
conducts long-range economic planning. MISO uses a planning horizon of up to 20 years, and
considers a multitude of economic, policy, and operational factors to identify an optimal longterm expansion plan. This long-term planning process provides a blueprint for resolving future
congestion and reliability needs associated with transmission expansion. Attachment FF also
provides stakeholders the opportunity to provide input regarding near-term congestion issues.
The Sub-regional Planning Meeting process enables MISO to review stakeholders’ historical
congestion data, evaluate the expected impact of the approved upgrades, and develop prioritized
study scopes to address the most significant and persistent congestion or generation integration
issues.59
These economic planning provisions remain part of Attachment FF. The particular
features of MISO’s regional planning process are appropriately adapted to MISO’s context and
stakeholder needs, consistent with the flexibility provided by Order No. 1000 for meeting
regional needs.60
2. Consideration of Transmission Needs Driven by Public Policy Requirements
Consistent with Order No. 1000,61 MISO’s Tariff already explicitly includes, and
establishes a procedure for, the identification and consideration of transmission needs driven by
public policy requirements in both local and regional transmission planning processes and the
evaluation of potential transmission solutions.62 The identification, consideration, and evaluation
of these projects is conducted in the open and transparent stakeholder process discussed
previously, allowing ample opportunity for stakeholder input into transmission needs
stakeholders believe are driven by public policy requirements, as required in Order No. 1000 at P
204.
56
Section II.C.2.a of Attachment FF.
57
Section II.C.2.b of Attachment FF.
58
Section II.C.2.c of Attachment FF.
59
Order No. 890 Compliance Order at PP 70-71.
60
Order No. 1000 at PP 157-58, 330, 745; Order No. 1000-A at P 266.
61
Order No. 1000 at PP 6, 82-83, 116, 203, 205-06.
62
As Order No. 1000 (at P 204; see also P 222) recognized, “some public utility transmission
providers already do have processes in place to determine whether transmission needs reflect
Public Policy Requirements.” MISO is among such transmission providers.
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Under MISO’s Tariff, transmission planning criteria require MISO to address
“Transmission Issues,”63 which are defined to include “compliance-based” reasons involving
“the need to comply with all requirements imposed on the Transmission System performance by
entities with jurisdiction or authority over all or part of the Transmission System including, but
not necessarily limited to … compliance with applicable state and federal laws,” and
“compliance with applicable regulatory mandates and obligations, including regulatory
obligations related to serving load, interconnecting generation and providing transmission
service.”64 This is the key mechanism in the Tariff that provides for the consideration of public
policy requirements in the regional transmission planning process. Such policy-related matters
are to be addressed with inputs from stakeholders and customers.65 MISO also proposes to
revise the definition of the MTEP process in Module A of the Tariff to specifically refer to the
goal to “comply with Federal and state laws, regulatory mandates and regulatory obligations,”
and to more fully use the defined term “Transmission Issues.” Section I of Attachment FF has
also been revised to refer to such compliance.
Effective July 16, 2010, the Tariff significantly enhanced the consideration of
transmission needs driven by public policy requirements and potential solutions, in connection
with MISO’s MVPs.66 MVPs include transmission projects that, under Criterion 1 of the Tariff,
are “for the purpose of enabling the Transmission System to reliably and economically deliver
energy in support of documented energy policy mandates or laws that have been enacted or
adopted through state or federal legislation or regulatory requirement that directly or indirectly
govern the minimum or maximum amount of energy that can be generated by specific types of
generation.”67 Such a separate classification of projects planned to meet needs driven by public
policy requirements is allowed by Order No. 1000 (at P 220).
The details of the procedure for the consideration of transmission needs driven by public
policy requirements are set forth in Attachment FF of the Tariff68 and MISO’s BPM for
Transmission Planning.69 This consideration is facilitated by the inclusion of needs arising from
federal and state laws, regulatory mandates, and regulatory obligations in the definition of the
63
Section I.A.5 of Attachment FF; Section 1.429a of the Tariff.
64
Section 1.667b of the Tariff.
65
Section I.A.2 of Attachment FF, referring to “discussions with Transmission Customers and
other stakeholders” regarding “Transmission Issues and solutions”; and providing for the
Planning Advisory Committee (“PAC”), Planning Subcommittee (“PSC”), and Sub-regional
Planning Meetings (“SPM”).
66
See generally MVP Order and MVP Rehearing Order.
67
Section II.C.2.a of Attachment FF; Sections 1.429a (definition of MVPs) and 1.667b
(definition of Transmission Issues) of Module A of the Tariff.
68
Section I.C of Attachment FF.
69
Sections 4.3 and 4.4 of BPM for Transmission Planning.
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Transmission Issues addressed by MISO’s planning process, which seeks to identify
transmission needs driven by various requirements, including those involving public policy
mandates. This ensures a holistic approach, where the determination of specific Transmission
Issues driven by public policy requirements is not done in a vacuum, but instead is integrated
into the overall regional transmission planning process.
MISO also proposes to revise the definition of the MTEP process in Module A of the
Tariff to specifically refer to the goal to “comply with Federal and state laws, regulatory
mandates and regulatory obligations,” and to more fully use the defined term “Transmission
Issues.” Section I of Attachment FF has also been revised to refer to such compliance. In this
regard, pursuant to the directive of Order No. 1000 (at P 209) and Order No. 1000-A (at P 325),
Attachment FF has been revised to provide that MISO will post on its website an explanation of:
(i) which transmission needs driven by public policy requirements will be evaluated for potential
solutions in the local or regional transmission planning process; and (ii) why other suggested
transmission needs will not be evaluated.
Consistent with Order No. 1000-A at P 333, the MISO Tariff currently requires that the
MTEP address all Transmission Issues, which include compliance with state and federal laws
and regulations, regulatory obligations, and regulatory mandates.70 This provision of the MISO
Tariff describes planning processes that result in the recommendation of specific projects within
the regional transmission plan (i.e., MTEP) for approval by the MISO Board. In addition, MISO
explores multiple future scenarios through various studies included in the MTEP analysis in an
effort to determine the robustness and long-term value of the proposals made in the MTEP. 71
These future scenarios with significant stakeholder input, may consider potential public policydriven needs under various future scenarios involving proposed public policies that have not yet
been enacted as laws, regulations, or mandates to ascertain the robustness and/or long-term
projected economic value of transmission projects recommended in the MTEP.
Consistent with Order No. 1000,72 MISO’s consideration is focused on the needs driven
by the public policy requirements, not the policies themselves, the merits of which MISO will
not evaluate either individually or in relation to each other. The MVP provisions do not supplant
integrated resource planning, which is within the purview of the states, and the evaluation of
potential solutions to needs driven by public policy requirements will also take into account the
resource decisions of the transmission planning process, as directed by Order No. 1000 (at
P 221).
3. Participation of Entities in MISO’s Transmission Planning Region
70
Section I.A of Attachment FF.
71
Section II.B of Attachment FF.
72
Order No. 1000 at PP 109, 111; Order No. 1000-A at PP 203-04, 317-18, 326-27, 329, 332.
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As required by Order No. 1000-A (at P 275), the proposed Tariff revisions provide a
clear process for entities, including non-public utility transmission providers, to enroll to
participate in MISO’s transmission planning region for purposes of Order 1000 compliance.
Any such entity that wishes to enroll in the MISO planning process will be required to execute
the Transmission Owners Agreement and become a MISO Transmission Owner. Within a
reasonable period of time from the execution of the Transmission Owners Agreement, such
entities will be obligated to turn the functional control of their existing transmission facilities
over to MISO and take service under the MISO Tariff for all load that is physically located
within the MISO footprint.73 These steps will pave the way for the entity to: (i) assume
obligations to make a good faith effort to construct new transmission facilities and/or
transmission facility upgrades in accordance with the TO Agreement; (ii) fully participate in the
cost recovery and cost sharing mechanisms included in the MISO Tariff and associated revenue
distribution mechanisms included in the TO Agreement; and (iii) participate in the MISO
markets to facilitate realization of the potential production cost and other economic benefits
projected for value-driven transmission projects by market mechanisms, such as market-wide
Security Constrained Unit Commitment (“SCUC”), market-wide Security Constrained Economic
Dispatch (“SCED”), and other market mechanisms. As required in Order 1000-A at P 275, any
entities that do not make the choice to become part of the transmission planning region will be
permitted to act as stakeholders in the regional transmission planning process.
As also directed by Order No. 1000-A (at P 275), the proposed Tariff revisions provide
for the listing of all enrolled non-public and public transmission entities that are part of MISO’s
transmission planning region.74 These entities are listed either in Attachment FF-4 or
Attachment FF-5 of the Tariff.
4. Merchant Transmission Developers
Consistent with Order No. 1000 (at P 164) and Order No. 1000-A (at P 297), under
MISO’s Tariff, merchant transmission developers are not required, but may opt, to participate in
MISO’s regional planning process. In addition, the Tariff has been revised to identify the
information and data that merchant transmission developers are required to provide to MISO to
enable it to assess the potential reliability and operational impacts that the merchant transmission
developer’s proposed transmission facilities will have on other systems in the region.
In particular, MISO has included in the proposed Tariff language a list of information and
data requirements for merchant transmission developers who desire to interconnect to the MISO
Transmission System, in order to support studies by MISO to determine the reliability and
operational impacts of such proposed interconnections. These data requirements include
descriptions and key technical parameters for proposed facilities, points of interconnection, and
proposed facility models to allow for adequate technical analyses of operational and reliability
73
Section I.A of Attachment FF.
74
Section I.A of Attachment FF.
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impacts. The Filing Parties note that MISO currently has a stakeholder initiative underway to
develop formalized processes and procedures regarding analysis of merchant transmission
facility proposals and requirements to interconnect to the MISO Transmission System. This
initiative may result in a section 205 filing with the Commission, subsequent to this compliance
filing, to include additional detail and enhancements regarding the terms and conditions of
merchant transmission project interconnections.
5. Role of States
Order No. 1000-A (at P 294-95) declined to specify the role of states in the regional
planning process, which it left up to the compliance development process to identify. According
to the Commission, the state commissions, either singly or jointly, are in the best position to
define their role in a particular region.75 This role will take into account the authorities and
restrictions conferred by their own state statutes and policy preferences.
Further amendments to the Tariff specifically address the role of the Organization of
MISO States (“OMS”), which is a non-profit, self-governing organization of representatives
from each state with regulatory jurisdiction over entities participating in the MISO. As a general
matter, the OMS serves as a forum for state retail regulatory authorities to coordinate their
MISO-related activities, including developing and making recommendations to MISO, the MISO
Board of Directors, the Commission, other relevant government entities, and state commissions
as appropriate.
These OMS-related amendments create an OMS Committee under MISO’s Tariff and
codify the role of the OMS Committee in MISO’s transmission planning, resource adequacy, and
transmission cost allocation processes under Attachment FF and the Transmission Owners
Agreement. Included in the amendments are provisions that specifically provide for input into
planning principles and objectives, scope elements, modeling inputs or assumptions, and costbenefit analyses for projects that are not proposed strictly for reliability purposes. The
amendments also codify the requirement that MISO will provide a prompt and clear response to
the OMS Committee in response to issues raised. Moreover, the amendments provide for a
process for the OMS Committee to request that MISO reconsider a transmission project
submitted for regional cost allocation in the MTEP under certain circumstances. Finally, these
amendments provide the OMS Committee with the opportunity to request and receive reasonable
assistance from MISO in developing its input into the MTEP.76
75
76
Order No. 1000-A at P 294.
Section I.B of Attachment FF.
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6. Entergy and Cleco Power Integration
Entergy Corporation and its Operating Companies (collectively, “Entergy”),77 as well as
Cleco Power LLC (“Cleco Power”), all of which own both transmission and generation assets
currently located outside of MISO’s planning area, have announced their intent to join MISO.
Upon the integration of Entergy and Cleco Power, MISO will take over responsibility for
planning their transmission systems pursuant to the MISO Tariff,78 as eventually modified as
proposed herein to comply with the requirements of Order Nos. 1000, 1000-A, and 1000-B.79
Their integration process is further described below.
On April 25, 2011, Entergy announced its decision to seek integration into MISO.80 This
integration involves a 5-year transition period provided for in Tariff revisions, mainly in a new
Attachment FF-6, effective June 1, 2013, that the Commission accepted on April 19, 2012 in
Docket No. ER12-480-000. The 5-year transition period is known as the “Second Planning
Area’s Transition Period,” with Entergy’s footprint described as the Second Planning Area and
MISO’s existing footprint called the First Planning Area.81 MISO’s understanding is that the
Entergy Operating Companies intend to sign the Transmission Owners Agreement prior to
June 1, 2013, so they will be governed by MISO’s transmission planning process beginning with
the planning cycle commencing on that date. MISO also understands that Entergy will transfer
functional control of their transmission facilities and integrate their generation and load into
MISO in December 2013.
Such transfer of functional control will start the 5-year transition period, during which
Entergy will be subject to the same transmission planning process and criteria applicable to
MISO’s existing footprint. Also during the 5-year transition period, MISO will endeavor to plan
future projects in a manner that optimizes regional benefits throughout its expanded footprint,
and to determine whether, when pre-integration MVPs are evaluated in combination with newly
planned MVPs, there would be sufficient regional net benefits to Entergy would warrant
77
The Entergy Operating Companies are: Entergy Arkansas, Inc., Entergy Gulf States
Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans,
Inc., and Entergy Texas, Inc.
78
As further discussed below, MISO’s planning, and concomitant cost allocation, of the
Entergy and Cleco transmission systems under Attachment FF will commence with the first
Planning Year that begins after issuance of an order accepting the revisions proposed herein.
79
These provisions include Attachment FF (the MISO Transmission Expansion Plan) and
Attachment FF-6 (transitional cost allocation provisions).
80
See
https://www.misoenergy.org/AboutUs/MediaCenter/PressReleases/Pages/EntergyAnnounces
IntenttoJoinMISO.aspx.
81
Midwest Indep. Transmission Sys. Operator, Inc., 139 FERC ¶ 61,056 (2012)
(“Entergy Transition Order”).
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allocating a share of the cost of pre-integration MVPs to Entergy’s area. To the extent that
MISO’s transmission planning and cost allocation process, as modified in this filing, is found
compliant with Order Nos. 1000 and 1000-A, Entergy will also be compliant.
As noted in its recent Order No. 1000 compliance filing, Cleco Power announced that it
has also decided to join MISO.82 In a compliance filing in Docket No. ER12-480-000, MISO
has defined the Second Planning Area in such a way that Cleco Power would be part of that
Planning Area when it joins MISO. Similarly, if the MISO process is deemed compliant with
Order Nos. 1000 and 1000-A, Cleco Power will likewise be compliant.
On September 24, 2012, MISO, Entergy, and ITC Holdings Corporation (“ITC”), an
entity with three subsidiaries that are existing MISO Transmission Owners,83 made parallel
filings before the Commission relating to the merger of Entergy’s and ITC’s transmission
businesses. The merger is to be accomplished by forming four ITC subsidiaries collectively
known as the ITC Midsouth Companies (“ITC Midsouth”),84 which will be 50.1 percent owned
by Entergy shareholders, and 49.9 percent owned by ITC shareholders. If the mergers close as
scheduled on June 30, 2013, Entergy’s transmission assets will be transferred to MISO’s
functional control on that date for purposes of transmission but not market services.
Additionally, upon closing, the Second Planning Area’s Transition Period will commence (i.e.,
six months earlier than it would have started without the merger). Entergy’s generation and load
will be integrated into MISO’s markets in December 2013. In anticipation of the Entergy-ITC
merger, MISO’s September 24, 2012 filing submitted in Docket No. ER12-2682-000 proposed a
new Tariff Module B-1 providing a 6-month transition period from June through December 2013
for the provision of “Day 1” transmission-only service over Entergy’s transmission facilities.
Because Entergy’s generation and load will not be integrated into MISO’s markets until
December 2013, Entergy’s existing ongoing process will be allowed to wind down and conclude
in December 201385 for the period 2014 through 2018, subject to MISO’s independent reliability
assessment. At the end of the 6-month period, Entergy will be fully integrated into MISO’s
markets.
Whether the above-described merger is completed, MISO intends its planning and
transmission cost allocation pursuant to Order Nos. 1000, 1000-A, and 1000-B to have, as its
effective date, June 1 of the Planning Year after the Commission issues an order accepting the
82
See Cleco Power filing from October 11, 2012 in Docket No. ER13-84, pp. 1-2.
83
ITC’s three subsidiaries are: ITCTransmission; Michigan Electric Transmission Company,
LLC; and ITC Midwest LLC.
84
ITC Midsouth will consist of four operating subsidiaries of ITC: ITC Arkansas LLC; ITC
Louisiana LLC; ITC Mississippi LLC; and ITC Texas LLC.
85
Entergy’s current planning process will be facilitated by its existing Independent Coordinator
of Transmission (“ICT”), Southwest Power Pool, Inc. (“SPP”), until December 2012, after
which MISO will take over as Entergy’s ICT from January through December 2013.
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Tariff revisions proposed herein. As a result, MISO’s planning and transmission cost allocation
for Entergy and Cleco Power will also commence in the same Planning Year.86 On October 11,
2012, Entergy and Cleco Power submitted filings to comply with Order Nos. 1000 and 1000-A,87
indicating that planning processes already underway under their respective tariffs will continue
through December 31, 2013. Accordingly, Entergy’s and Cleco Power’s respective existing
planning processes will be allowed to continue and conclude by December 2013 in parallel with
their initial participation in the Planning Year 2014 process at MISO. Finally, while MISO will
be responsible for planning, full integration and participation by Entergy and Cleco Power’s
generation and load in the MISO markets is not expected to occur until December 2013.88
The phased approach to Entergy and Cleco Power’s integration, as well as to its Order
No. 1000 compliance, is consistent with the flexibility that the Commission accords RTOs in
complying with Order No. 1000’s requirements in a manner that adapts to and addresses the
unique needs and circumstances of each region.89 The Commission has previously allowed a
phased approach for a new Transmission Owner’s integration.90
86
Under MISO’s MTEP process, which is set forth in Attachment FF to the Tariff, Planning
Year 2014 commences on June 1, 2013, and concludes in December 2014 with approval by
the MISO Board of Directions of the recommendations developed through the MTEP
process.
87
See compliance filings submitted on October 11, 2012 in Docket Nos. ER13-95-000 and
ER13-84-000 for Entergy and Cleco Power, respectively
88
It is anticipated that on July 1, 2013, prior to transfer of functional control of the Entergy
transmission facilities to MISO and participation by Entergy’s load and generation in the
MISO markets, Entergy may transfer its interest in its transmission facilities to ITC Midsouth
and/or four subsidiaries of ITC Holding Corporation (“ITC”) (collectively referred to as “ITC
Midsouth”). To facilitate such a transfer, MISO will provide only “Day 1” transmission
service to ITC Midsouth under Module B-1, which was proposed in Docket No. ER12-2682
filed on September 24, 2012. In December 2013, Module B-1 will terminate upon the
integration of Entergy’s generation and load into MISO’s markets.
89
Order No. 1000 at PP 61, 108, 149, 157 (“public utility transmission providers should have
flexibility in determining the most appropriate manner to enhance existing regional
transmission planning processes to comply with this Final Rule”), P 158 (“Public utility
transmission providers have flexibility in developing the necessary enhancements to existing
regional transmission planning processes to comply with this Final Rule, based upon the
needs and characteristics of their transmission planning region”), P 561 (“we intend to be
flexible and are open to a variety of approaches to compliance”), P 604 (“we retain regional
flexibility and allow the public utility transmission providers in each transmission planning
region, as well as pairs of transmission planning regions, to develop transmission cost
allocation methods that best suit the needs of each transmission planning region or pair of
transmission planning regions”), P 624 (“allowing the flexibility to accommodate a variety of
approaches can better advance the goals of this rulemaking”), P 745 (“the Commission
recognizes the need for regions to retain some level of flexibility to account for specific
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Additionally, the phased integration of Entergy and Cleco Power into MISO reasonably
addresses the unique needs and circumstances of new Transmission Owners, in a manner that
appropriately transitions Entergy and Cleco Power into MISO’s regional transmission planning
and cost allocation processes, as a means of complying with Order No. 1000’s regional
requirements. The phased approach is also consistent with the Commission’s finding that “it is
just and reasonable … to adopt a transition period given that Entergy’s proposed integration as a
transmission-owning MISO member presents unique challenges.”91 To the extent that the
regional characteristics, resource types, or policy mandates”); Order No. 1000-A at PP 10,
99, 266 (“public utility transmission providers, in consultation with stakeholders, have the
flexibility to ensure that their respective regional transmission planning process is designed
to accommodate the unique needs of that particular region”), P 272 (“Order No. 1000
appropriately provided flexibility in this regard, and that this flexibility will permit public
utility transmission providers and others the opportunity to form or join a transmission
planning region that best meets their needs and the needs of their transmission customers”), P
289 (“we are providing public utility transmission providers, in consultation with
stakeholders, the flexibility to design a regional transmission planning process that meets
regional needs”).
90
Midwest Indep. Transmission Sys. Operator, Inc., 129 FERC ¶ 61,221 (2009), order on
reh’g, 131 FERC ¶ 61,163 at P 26 (2010) (“Dairyland opted for a phased integration into
Midwest ISO, with nearly nine months between the time it signed the Transmission Owners’
Agreement and the date of full integration.”).
91
Entergy Transition Order at P 71. According to the Commission (at P 181):
We find that proposed allocation of the cost of network upgrades approved
before, during, and after the five-year transition period, as conditioned below, to
be just and reasonable. Given the unique circumstances surrounding Entergy’s
proposed integration into MISO, we find Filing Parties’ proposal regarding how
the Planning Areas begin sharing the cost of certain network upgrades to be just
and reasonable. For example, as discussed above, Entergy and MISO do not
have a seams agreement and have not had any historical opportunity to study their
respective transmission infrastructure levels and plans. The transmission systems
of MISO and Entergy have not been planned using consistent planning criteria
and assumptions such that transmission facilities constructed in one Planning
Area could reasonably be expected to provide benefits to loads in the other.
Implementation of consistent planning in the two Planning Areas will facilitate
MISO’s application of its transmission planning process and planning criteria to
the combined Planning Areas after the transition period has ended. MISO will
then plan for the combined Planning Areas as a single MISO transmission system
and costs will be shared between the two Planning Areas in accordance with
MISO’s existing cost allocation methods under Attachment FF, consistent with
the distribution of the benefits that these transmission facilities have been found to
provide through MISO’s transmission planning process. (Italics added).
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Commission finds MISO’s regional transmission and planning processes, including the rules
applicable to the 5-year transition period, as enhanced by the present filing’s proposed Tariff
revisions, consistent with Order No. 1000, Entergy and Cleco Power will appropriately comply
with Order No. 1000’s requirements by integrating into MISO, and adopting and participating in
such regional processes.
(a) Tariff Changes
MISO has identified a number of changes to its Tariff that will be required to effectuate
the above transition to planning by MISO of the Entergy and Cleco Power facilities that include
the following:
In Attachment FF:




List of Sub-regional planning meetings (Attachment FF – Section IA.2.c – add
new sub-region)
Update to Attachment FF-1 (Excludes list, if applicable)
Update to Attachment FF-3 (Planning Sub-Regions Map)
Update to Attachment FF-4 (listing of TOs integrating local planning process)
In other provisions of the Tariff:





Module A – possible addition of Cleco Power to definition of Second Planning
Area92
Attachment VV and WW – Local Resource Zone maps
Attachment O
Schedules 7, 8, 9, 26
Attachment P
These changes will be filed with the Commission no later than 60 days prior to the
effective date of the modifications proposed herein.
C. Regional Cost Allocation
1. Applicable Project Types Selected in Regional Plan for Cost Allocation
MISO’s existing Tariff already complies with the requirement of Order No. 1000 (at
P 558) to have in place mechanisms to allocate the costs of new transmission facilities that have
been selected in MISO’s regional transmission plan for purposes of cost allocation. Specifically,
Section II of Attachment FF provides the criteria that are used to categorize the projects
92
In the event the Commission does not accept the MISO May 21, 2012 compliance filing, this
definition would have to be revised to specifically address Cleco’s integration.
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depending on their drivers (i.e., associated needs) and beneficiaries, and Section III of
Attachment FF describes the cost responsibility for each type of project. Under MISO’s Tariff,
the two project types that can be selected in the regional plan for purposes of cost allocation,
within the meaning of Order No. 1000, are (i) MEPs and (ii) MVPs. Projects that are not
included in the regional transmission plan for purposes of cost allocation include (i) local
transmission facilities whose costs are recovered from load in the pricing zone where the
transmission facility is located; (ii) projects that are funded by a Market Participant(s) requesting
the facility;93 and (iii) Generation Interconnection Projects, which are excluded from the scope of
Order No. 1000 (at P 760).
2. Compliance with Order No. 1000’s Six Cost Allocation Principles
As required by Order No. 1000 (at P 558, 603), MISO discusses below how its current
Tariff provisions for projects that have been selected in MISO’s regional transmission plan for
cost allocation (i.e., MVPs and MEPs) are in compliance with the six regional cost allocation
principles articulated by Order No. 1000. The development of both the MVP and MEP
classification criteria and cost allocation methodologies resulted from robust stakeholder
processes documented in the respective Tariff filings that established these project categories.94
(a) Regional Cost Allocation Principle 1: Cost Allocated in a Way Roughly
Commensurate with Benefits
The first regional cost allocation principle set forth in Order No. 1000 (at P 622) states:
The cost of new transmission facilities must be allocated to
beneficiaries within the region in a manner at least roughly
commensurate with estimated benefits. In determining beneficiaries, a
regional planning process may consider benefits including, but not
limited to, the extent to which facilities, individually or in the
aggregate, involve maintaining reliability and sharing reserves,
production cost savings and congestion relief, and/or meeting Public
Policy Requirements.
The MISO Tariff ensures that the allocation of the costs of MVPs and MEPs is at least
roughly commensurate with estimated benefits by tailoring the cost allocation to the nature
and/or scope of the needs, benefits, and beneficiaries associated with each type of project. With
regard to MVPs,95 the Tariff requires the consideration, on a portfolio basis (i.e., in the
93
Includes the following project types: Transmission Delivery Service Project, and Other.
94
See MISO’s November 1, 2006 filing in Docket No. ER06-18, pp. 2-4, 9-10 and MISO’s July
15, 2010 filing in Docket No. ER10-1791, pp. 7-11.
95
The portfolio evaluation is in addition to the individual assessment of each MVP, as
described in Section II.C of Attachment FF.
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aggregate), of the regional benefits of MVPs, relating to public-policy-driven-needs (MVP
Criterion 1),96 or combinations of economic and/or reliability needs or benefits (MVP Criteria 2
and 3).97 Because MVP benefits are spread broadly across the footprint,98 100 percent of their
costs are allocated regionally (i.e., system-wide).99
On the other hand, MEPs are focused on addressing congestion relief.100 Based on the
approximate proportion of regional and non-regional benefits of MEPs, 20 percent of their costs
are allocated on a system-wide basis, and the remaining 80 percent is allocated based on the
distribution of the adjusted production cost savings across the MISO Local Resource Zones.101
As Order No. 1000 indicates, benefits need not be determined “with exacting precision,”
down “to the last penny, or for that matter to the last million or ten million or perhaps hundred
million dollars.”102 Within these reasonable parameters, the determination of regional MVP
benefits on a portfolio basis and of MEP benefits to the level of Local Resource Zones103 amply
satisfies Order No. 1000’s requirement that costs be allocated in a manner roughly
commensurate with benefits.
Pursuant to Order No. 1000 (at P 332 and 335), both incumbent Transmission Owners
and non-incumbent transmission developers have an opportunity to seek regional cost allocation
of MVPs and MEPs that they are selected to build under the inclusive evaluation process
discussed infra in section D.3.e.1.
(b) Regional Cost Allocation Principle 2: No Involuntary Allocation to NonBeneficiaries
The second regional cost allocation principle set forth in Order No. 1000 (at P 637)
states:
96
Section II.C.2.a of Attachment FF.
97
Sections II.C.2.b and II.C.2.c of Attachment FF.
98
Section II.C.1 of Attachment FF.
99
Section III.A.2.g of Attachment FF; MVP Rehearing Order at P 27 (“the MVP Proposal is
just and reasonable, and … represents a package of reforms that will enable Midwest ISO
and its stakeholders to identify transmission projects that provide sufficient regional benefits
to warrant regional cost allocation.”) (italics added).
100
Section II.B of Attachment FF.
101
Section III.A.2.f of Attachment FF.
102
Order No. 1000 at P 504 and n.392, P 545 and n.435, and P 586 and n.453.
103
Attachment WW of Tariff.
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Those that receive no benefit from transmission facilities, either at present
or in a likely future scenario, must not be involuntarily allocated any costs
of those facilities.
The Commission has previously found that MISO’s transmission planning process is
appropriately designed to reasonably identify and estimate the benefits expected from MVPs104
and MEPs.105 As such, MISO’s planning process properly identifies anticipated beneficiaries, at
present and/or in likely future scenarios. Indeed, MISO considers multiple future scenarios to
estimate MVP benefits.106 MEPs are also planned based on “future scenarios,”107 and the MEP
benefit metric was in fact recently renamed from “Weighted Gain/No Loss” to “Weighted
Futures/No Loss,” stressing the future scenario analysis.108 By basing MVP and MEP cost
allocation on the appropriate projection of their estimated benefits, MISO’s Tariff ensures that
such costs are not involuntarily allocated to those who receive no current or likely future benefits
from MVPs or MEPs.
(c) Regional Cost Allocation Principle 3: Benefit-to-Cost Threshold Ratio
The third regional cost allocation principle set forth in Order No. 1000 (at P 646) states:
If a benefit to cost threshold is used to determine which transmission facilities
have sufficient net benefits to be selected in a regional transmission plan for the
purpose of cost allocation, it must not be so high that transmission facilities with
significant positive net benefits are excluded from cost allocation. A public utility
transmission provider in a transmission planning region may choose to use such a
threshold to account for uncertainty in the calculation of benefits and costs. If
adopted, such a threshold may not include a ratio of benefits to costs that exceeds
1.25 unless the transmission planning region or public utility transmission
provider justifies and the Commission approves a higher ratio.109
104
MVP Order at PP 193-94; MVP Rehearing Order at PP 27-29.
105
RECB II Order at P 65 (accepting Tariff provisions on Regionally Beneficial Projects or
“RBPs,” the prior term for MEPs); MVP Order at PP 9 and 262 (accepting renaming of RBPs
as MEPs); Midwest Indep. Transmission Sys. Operator, Inc., 139 FERC ¶ 61,261 (2012)
(“MEP Order”).
106
MVP Filing, Tab F, Prepared Direct Testimony of John Lawhorn at 3:21 through 10:15 (e.g.,
“To account for different possible future economic conditions or public policy decisions,
such as a federal RPS or carbon emission regulations, the Midwest ISO uses multiple
scenarios or futures”).
107
Section II.B.1 of Attachment FF.
108
MEP Order at PP 21-23 (“MISO considers alternative future scenarios in its planning
analysis”).
109
See Order No. 1000 at P 647.
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As allowed by Order No. 1000’s third regional cost allocation principle, MISO’s Tariff
uses a cost-benefit threshold of 1.0 or greater for Criterion 2 and Criterion 3 for MVPs;110 and
1.25 for MEPs.111 With respect to the MVP benefit-to-cost ratio, the Commission has previously
found that “because MVPs are projects that provide regional benefits … a benefit-to-cost ratio of
1.0 is just and reasonable because it ensures that the multiple economic benefits to all users is at
least equal to the costs allocated to all users over the 20 years of service that are evaluated.”112
The Commission also recently found that the MEP “fixed benefit-cost ratio of 1.25 is just and
reasonable because it balances the economic uncertainty of transmission projects with the
prospect of approving and constructing projects that provide benefits.”113 The MVP and MEP
benefit-to-cost ratios under MISO’s Tariff, therefore, are compliant with the 1.25 threshold set
by Order No. 1000.
(d) Regional Cost Allocation Principle 4: Allocation Solely Within
Transmission Planning Region Unless Those Outside Voluntarily Assume
Costs
The fourth regional cost allocation principle set forth in Order No. 1000 (at P 657) states:
The allocation method for the cost of a transmission facility selected in a
regional transmission plan must allocate costs solely within that
transmission planning region unless another entity outside the region or
another transmission planning region voluntarily agrees to assume a
portion of those costs. However, the transmission planning process in the
original region must identify consequences for other transmission planning
regions, such as upgrades that may be required in another region and, if
the original region agrees to bear costs associated with such upgrades, then
the original region’s cost allocation method or methods must include
provisions for allocating the costs of the upgrades among the beneficiaries
in the original region.114
Under MISO’s Tariff, the costs of MVPs115 and MEPs116 are only allocated to load in the
MISO region, or to export and wheel-through transactions that customers voluntarily enter
into.117 As the Commission has found with regard to the MVP rate:
110
Section II.C.7 of Attachment FF.
111
Section II.B.1.e of Attachment FF.
112
MVP Order at P 214.
113
MEP Order at P 32.
114
See Order No. 1000 at P 219.
115
Section III.A.2.g of Attachment FF.
116
Section III.A.2.f of Attachment FF.
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[T]here is no involuntary assignment of costs here given that the MVP
usage rate applies to export and wheel-through transactions (i.e., customers that
are taking service from Midwest ISO), rather than an external entity taking no
service or buying no energy from Midwest ISO, which would not be charged
under this proposal.118
MISO’s transmission planning process also takes into account transmission expansion
impacts on other planning regions, e.g., by modeling external systems in connection with the
planning of projects.119 In addition, the Tariff includes interregional coordination mechanisms
that facilitate the evaluation of such impacts,120 and MISO can share certain upgrade costs with
other regions pursuant to appropriate agreements.121
117
MVP and MEP charges are not assessed on Grandfathered Agreements (“GFAs”); see MVP
Order at P 56; see also Schedule 26 for MEPs and Schedule 26-A for MVPs. MVP and MEP
charges are also not assessed on export or through transactions that sink in PJM do not incur
charges for; see MVP Order at PP 56 and 441; see also Schedule 26 Section 3 for MEPs and
Schedule 26-A for MVPs.
118
MVP Order at P 439.
119
For example, Section 4.3.6 of the BPM for Transmission Planning (at 66) states: “Where
MISO and non-MISO systems were highly integrated, contingencies on non-MISO systems
were also analyzed for impacts on MISO members’ systems.”
120
Section I.C of Attachment FF, which states, for example:
The MTEP shall be developed in accordance with the principles of interregional
coordination through collaboration with representatives from adjacent
transmission providers, their designated regional planning organizations, or
regional transmission organizations, as provided for in this Attachment FF, or as
otherwise provided for in existing joint agreements between the Transmission
Provider and other regional entities that engage in planning activities.
The Tariff’s definition the MTEP itself states, in pertinent part, that: “The MTEP shall also
include planning requirements with representatives from adjacent regional transmission
organizations (‘RTOs’) and other transmission providers to develop long-term inter-regional
plans for the benefit of the combined regions, as and to the extent provided for in joint
agreements between the Transmission Provider and other regional transmission
organizations.” (Section 1.419 of Tariff) As earlier noted, the interregional requirements of
Order No. 1000 will be addressed by MISO in a separate compliance filing due on April 11,
2013.
121
E.g., MISO’s Joint Operating Agreement with PJM Interconnection, L.L.C. (“PJM”) includes
provisions on the cost-sharing of cross-border MEPs (9.4.3.2.2, on “Cost Allocation for
Cross-Border Market Efficiency Projects”).
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(e) Regional Cost Allocation Principle 5: Transparency of Method for
Determining Benefits and Identifying Beneficiaries
The fifth regional cost allocation principle set forth in Order No. 1000 (at P 668) states:
The cost allocation method and data requirements for determining benefits
and identifying beneficiaries for a transmission facility must be
transparent with adequate documentation to allow a stakeholder to
determine how they were applied to a proposed transmission facility.
MISO’s transmission project cost allocation process is compliant with Order No. 1000’s
transparency requirement. First, as summarized earlier, the allocation and benefit determination
methods for the projects are duly specified in the Tariff, as supplemented by the BPM for
Transmission Planning. Second, the cost allocation methods are applied in the context of
MISO’s open planning process where, consistent with Order No. 890, stakeholders and
customers have numerous opportunities to participate in various forums (including Sub-regional
Planning Meetings, and technical studies task forces) through which they can review the
documentation and details of each project’s justification. Third, the results of MISO’s analysis
of project benefits are appropriately documented through studies, such as “business case”
reports, and the resulting recommendations are embodied in each year’s MTEP report,122 which
MISO posts publicly on its website.123 Thus, MISO’s cost allocation method, application, and
results are properly transparent.
(f) Regional Cost Allocation Principle 6: Different Method for Different
Types of Facilities
The sixth regional cost allocation principle set forth in Order No. 1000 (at P 685) states:
A transmission planning region may use a different cost allocation method
for different types of transmission facilities in the regional plan, such as
facilities needed for reliability, congestion relief, and/or to achieve Public
Policy Requirements. Each method must be set out clearly and explained
in detail in the compliance filing for Order No. 1000.124
122
Section 1.419 of Tariff (definition of MTEP).
123
E.g., see the MVP Business Case posted at
https://www.misoenergy.org/Library/Repository/Study/Candidate%20MVP%20Analysis/M
VP%20Portfolio%20Analysis%20Full%20Report.pdf; and MTEP11, posted at
https://www.misoenergy.org/Library/Repository/Study/MTEP/MTEP11/MTEP11%20Report
.pdf.
124
See Order No. 1000 at PP 560, 686-87, 689.
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As permitted by Order No. 1000’s sixth regional cost allocation principle,125 MISO’s
Tariff provides for different cost allocation methodologies for different types of projects. As
noted above, the project categories that are selected in the regional transmission plan for
purposes of cost allocation are MVPs (whose costs are 100 percent allocated regionally) and
MEPs (whose allocation includes a 20 percent regional cost allocation). The proposed Tariff
revisions do not modify these cost allocation percentages for MVPs and MEPs.
3. Transitional Cost Allocation for Entergy and Cleco Integration
The 5-year Entergy transition period under Attachment FF-6 to the Tariff is also
consistent with Order No. 1000 because it facilitates Entergy’s compliance with the requirement
to participate in a regional transmission planning process,126 and to allocate the costs of
regionally planned transmission projects in a manner commensurate with associated regional
benefits.127 In particular, in the Entergy Transition Order, the Commission found that:
Filing Parties’ proposal ensures that, after the five-year transition period,
the two Planning Areas will be comparably planned and the estimated benefits
from network upgrades will be roughly commensurate with the allocation of their
associated costs under Attachment FF of the MISO Tariff.128
The Commission explained that, without such a transition, it could not be determined
whether cost allocation between the two Planning Areas would be commensurate with benefits,
to the extent such allocation involves projects that terminate exclusively in only one of the
Planning Areas, and that were planned and approved before Entergy’s integration into MISO:
Before the transition period, projects in the First Planning Area were not
planned for the Second Planning Area, and as a result, it is reasonable for Filing
Parties to propose that those costs not be allocated to the Second Planning Area
without a demonstration of net benefits. Until MISO applies its existing
transmission planning process to the Second Planning Area, so that both Planning
Areas use common processes and criteria, there is no basis to conclude that the
Planning Areas will mutually derive benefits from projects that terminate
exclusively in either Planning Area, such that regional cost sharing would allocate
costs in a manner that is roughly commensurate with the associated benefits. As
the Seventh Circuit has explained, “[a]ll approved rates must reflect to some
degree the costs actually caused by the customer who must pay for them. Not
surprisingly, we evaluate compliance with this unremarkable principle by
125
See Order No. 1000-A at P 678.
126
Order No. 1000 at PP 6, 116, 146, 148, 151.
127
Id. at PP 622, 637, 646, 657, 668.
128
Entergy Transition Order at P 115.
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comparing the costs assessed against a party to the burdens imposed or benefits
drawn by that party.”129
The Commission found that the 5-year Entergy transition appropriately implements such
a comparison of burdens and benefits,130 an approach that Order No. 1000 also articulated and
adopted.131
D. Nonincumbent Developer Participation
1. The Transmission Owners Agreement is Protected by the Mobile-Sierra
Public Interest Standard and Cannot be Compulsorily Amended Absent a
Clear Showing of Serious Harm to Public Interest
The Commission lacks the authority to order modification of the Transmission Owners
Agreement to eliminate existing transmission construction rights and obligations,132 absent
demonstrating that such a mandate complies with the heightened standard of review under the
Mobile-Sierra doctrine.133 Because the Commission has failed to make the requisite showing
under Mobile-Sierra, it cannot order MISO to modify the Transmission Owners Agreement and
therefore should not accept revisions to the Transmission Owners Agreement and related Tariff
revisions proposed in this filing to comply with the Order No. 1000 nonincumbent developer
participation requirements.134 Contrary to the generic and speculative assertions of harm posited
in Order No. 1000, the actual evidence in MISO demonstrates that the Transmission Owners
Agreement has resulted in robust investment in efficient and cost-effective transmission
129
Id. at P 182 (citing Ill. Commerce Comm’n v. FERC, 576 F.3d 470, 476-77 (7th Cir. 2009)).
130
Id. at P 187 (finding that “the cost-benefit test of the Combined MVP Portfolio will provide
the necessary information on whether sharing the associated MVP costs across both
Planning Areas would be roughly commensurate with the corresponding benefits”).
131
Order No. 1000 at PP 536-37 (“courts have acknowledged that cost causation involves
‘comparing the costs assessed against a party to the burdens imposed or benefits drawn by
that party’”), and P 586(1) (cost allocation must be at least “roughly commensurate with
estimated benefits”).
132
The Transmission Owners Agreement establishes the basic division of rights and
responsibilities between MISO, the MISO Transmission Owners, and other members of
MISO, and was submitted as part of the initial filing that established MISO.
133
As explained below, the Mobile-Sierra doctrine, which was established in two cases decided
by the U.S. Supreme Court in 1956, restricts the ability of the Commission and other parties
to impose modifications to negotiated contracts and agreements that have been accepted by
the Commission. See Morgan Stanley Capital Group, Inc. v. Pub. Util. Dist. No. 1, 554 U.S.
527, 532-33 (2008) (“Morgan Stanley”) (citing Mobile; Sierra).
134
See Section II.D.2 and II.D.3, infra.
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expansion to the benefit of the public interest and enables participation in transmission planning
and construction by a variety of entities.
(a) Mobile-Sierra and the Nonincumbent Developer Reforms of Order
Nos. 1000 and 1000-A
In Order No. 1000, the Commission ordered, among other things, that all public utility
transmission providers remove from their Commission-jurisdictional agreements and tariffs any
provisions granting incumbent transmission providers a federal right of first refusal with respect
to transmission facilities selected in a regional transmission plan for purposes of cost
allocation.135 This mandate was premised on the Commission’s speculation that such federal
rights of first refusal have the potential “to undermine the identification and evaluation of a more
efficient or cost-effective solution to regional transmission needs, which in turn can result in
rates for Commission-jurisdictional services that are unjust and unreasonable or otherwise result
in undue discrimination by public utility transmission providers.”136 In response to comments
that its actions violated the Mobile-Sierra doctrine, the Commission declined to address such
arguments, stating that it “generally do[es] not interpret an individual contract in a generic
rulemaking”137 and that such issues should be addressed in the upcoming Order No. 1000
compliance filings.138
In Order No. 1000-A, the Commission affirmed its decision to require the elimination of
rights of first refusal and to defer addressing Mobile-Sierra issues until it reviews the relevant
Order No. 1000 compliance filings.139 After stating that it “did not and cannot shift the burden to
defend” any right of first refusal provision to contracting parties,140 the Commission indicated
that parties that consider their contracts to be protected by the Mobile-Sierra doctrine must make
such arguments in their compliance filings and submit appropriate revisions to the tariffs and
agreements that the Commission should consider in the event that it either finds that the
agreement is not a Mobile-Sierra agreement or that the Commission has met its burden under the
Mobile-Sierra doctrine to order modification of their tariff or agreement.141 In Order No. 1000B, the Commission “reiterate[d] that [it] is not requiring public utility transmission providers to
eliminate a federal right of first refusal before [it] makes a determination regarding whether an
135
Order No. 1000 at P 313.
136
Id. at P 7; see also id. at PP 253, 260.
137
Id. at P 292.
138
Id.
139
Order No. 1000-A at P 388.
140
Id.
141
Id. at P 389 (footnotes omitted).
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agreement is protected by the Mobile-Sierra doctrine and whether the Commission has met the
applicable standard of review.”142
(b) The Commission Cannot Compel MISO to Modify the Transmission
Owners Agreement Without Satisfying the Mobile-Sierra Standard
The rights and obligations to construct transmission facilities approved for construction
under the MISO Tariff are set forth in Appendix B Section VI of the MISO Transmission
Owners Agreement.143 The Transmission Owners Agreement is protected by the Mobile-Sierra
public interest standard, and nothing in the agreement limits or indicates a willingness to forego
the full degree of this protection. The Commission therefore cannot order modification of the
Transmission Owners Agreement without meeting the additional requirements of the MobileSierra doctrine, which the Commission has failed to do. Accordingly, the Commission cannot
require MISO to adopt revisions to the Transmission Owners Agreement and Tariff to address
the nonincumbent transmission developer requirements of Order No. 1000, and therefore should
disregard the revisions to the Transmission Owners Agreement and Tariff proposed in this filing
that relate to the Order No. 1000 nonincumbent developer reforms.
As the courts and Commission have indicated, the Mobile-Sierra doctrine limits the
Commission’s authority to modify or abrogate a valid contract negotiated among sophisticated
utility parties, such as the Transmission Owners Agreement. Specifically, the United States
Supreme Court has indicated that “[u]nder the Mobile-Sierra doctrine, the [Commission] must
presume that the rate set out in a freely negotiated wholesale energy contract meets the ‘just and
reasonable’ requirement [imposed by law]. [T]he presumption may be overcome only if FERC
concludes that the contract seriously harms the public interest.”144 The Court elaborated that
“the regulatory system created by the [FPA] is premised on contractual agreements voluntarily
devised by the regulated companies; it contemplates abrogation of these agreements only in
circumstances of unequivocal public necessity.”145 The Court added that while parties can
142
Order No. 1000-B at P 40.
143
The Commission has found that certain language contained in Appendix B Section VI
provides a federal right of first refusal for incumbent Transmission Owners. See, e.g.,
Pioneer Transmission, LLC v. N. Ind. Pub. Serv. Co., 140 FERC ¶ 61,057 at P 101 (2012).
144
Morgan Stanley, 554 U.S. at 530 (emphasis added); see also, e.g., CAlifornians for
Renewable Energy, Inc. v. Pac. Gas & Elec. Co., 134 FERC ¶ 61,060 at P 62 (2011)
(“Under the Mobile-Sierra doctrine, the Commission must presume that a rate set by a freely
negotiated wholesale-energy contract meets the statutory ‘just and reasonable’ requirement.
The presumption may be overcome only if the Commission concludes that the contract
seriously harms the public interest.”).
145
Morgan Stanley, 554 U.S. at 534 (emphasis added) (quotations omitted) (quoting Permian
Basin Area Rate Cases, 390 U.S. 747, 822 (1968)). It should be noted that the Transmission
Owners Agreement in general and the Appendix B Section VI provisions in particular, were
the result of significant compromise among the founding transmission owner signatories to
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“contract out of the Mobile-Sierra presumption [in whole or in part] . . . the Mobile-Sierra
presumption remains the default rule.”146 Thus, the Court determined that “FERC may abrogate
a valid contract only if it harms the public interest,”147 and that a finding sufficient to satisfy the
standard requires “unequivocal public necessity” due to “extraordinary circumstances.”148 The
Court subsequently elaborated that the Mobile-Sierra public interest standard applies not only to
the contracting parties, but to the Commission and third parties as well.149
The MISO Transmission Owners Agreement is protected by the Mobile-Sierra doctrine,
and the Commission cannot compel a change to the Transmission Owners Agreement unless it
can show that the existing provision “seriously harms the public interest”150 and that the
proposed modification is of “unequivocal public necessity.”151 First, the Commission has
specifically found that the Transmission Owners Agreement “impose[s] a Mobile-Sierra standard
of review that the Commission can amend “only if it ‘adversely affect[s] the public interest.’”152
Additionally, even absent this Commission finding, the Transmission Owners Agreement is
silent on the standard of review, and therefore, according to the “default rule” articulated in
the Transmission Owners Agreement, without which MISO may not have been formed.
This voluntary arrangement “devised by regulated companies” is entitled to Mobile-Sierra
protection.
146
Morgan Stanley, 554 U.S. at 534 (emphasis added). The Commission has acknowledged
that the Mobile-Sierra standard applies to contracts, absent language to the contrary. See,
e.g., People of the State of Cal. v. Powerex Corp., 135 FERC ¶ 61,178, at PP 5, 87 (2011).
147
Morgan Stanley, 554 U.S. at 548; see also id. 545-46 (“Therefore, only when the mutually
agreed-upon contract rate seriously harms the consuming public may the Commission
declare it not to be just and reasonable”).
148
Morgan Stanley, 554 U.S. at 550 (citations omitted); see also id. at 551 (“We think that the
FPA intended to reserve the Commission’s contract-abrogation power for those
extraordinary circumstances where the public will be severely harmed”).
149
NRG Power Mktg., LLC v. Me. Pub. Utils. Comm’n, 130 S. Ct. 693, 696-97 (2010) (“‘The
venerable Mobile-Sierra doctrine’ rests on ‘the stabilizing force of contracts.’ . . . To retain
vitality, the doctrine must control FERC itself, and, we hold, challenges to contract rates
brought by noncontracting as well as contracting parties.” (emphasis added) (quoting
Morgan Stanley, 554 U.S. at 548)).
150
Morgan Stanley, 554 U.S. at 530.
151
Morgan Stanley, 554 U.S. at 534.
152
Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ¶ 61,090, at P 47 n.41 (2008)
(citing Sierra at 355). The Commission added that this “standard is a demanding one,
satisfied only in extraordinary ‘circumstances of unequivocal public necessity.’” Midwest
Indep. Transmission Sys. Operator, Inc., 122 FERC ¶ 61,090, at P 47 n.41 (citing Permian
Basin Area Rate Cases, 390 U.S. at 822).
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Morgan Stanley, the Mobile-Sierra public interest standard of review is presumed to apply.153
Moreover, courts and the Commission have repeatedly found that, absent an express waiver or
limitation in an agreement, the Mobile-Sierra protections apply even if the agreement is silent as
to the standard of review.154
The Transmission Owners Agreement contains no language to support a finding that the
Mobile-Sierra doctrine should not apply to the agreement in general or Appendix B specifically,
and as judicial precedent makes clear in such circumstances, the Mobile-Sierra presumption
remains the “default rule.” Therefore, the Commission must find that the Transmission Owners
Agreement is protected by the Mobile-Sierra doctrine, meaning that the Commission can only
compel changes to the Transmission Owners Agreement upon finding that an existing provision
“seriously harms the public interest” and that the required modification is of “unequivocal public
necessity.” The Commission cannot simply base its demand that MISO modify the Transmission
Owners Agreement on a speculative finding that an existing contract provision may lead to rates
that are unjust and unreasonable, as the Commission did in Order No. 1000.
(c) All Available Evidence Demonstrates that the Transmission Owners
Agreement Is Benefiting, Rather than Harming, the Public Interest
As described above, the Mobile-Sierra doctrine states the Commission can abrogate or
require modification of the Transmission Owners Agreement “only if” the contract seriously
harms the public interest”155 and “extraordinary circumstances” exist such that the modification
is an “unequivocal public necessity.”156 In the Order No. 1000 rulemaking, no party provided
153
See Morgan Stanley, 554 U.S. at 534.
154
See Texaco Inc. v. FERC, 148 F.3d 1091, 1096 (D.C. Cir. 1998) (rejecting argument that the
failure to specifically preclude the Commission from compelling changes to an agreement
authorizes such changes, and stating absent contractual language sufficient to permit such
changes, “the Mobile-Sierra doctrine applies”); Appalachian Power Co. v. FERC, 529 F.2d
342, 348 (D.C. Cir. 1976) (stating that absent any language in a contract “explicitly
conferring that authority [for the utility to make changes without customer consent] or any
indication that such authority was contemplated . . . the Mobile-Sierra proscription comes
into full play”); Standard of Review for Modifications to Jurisdictional Agreements, 125
FERC ¶ 61,310 at PP 4-5 (2008) (stating that since the Supreme Court in Morgan Stanley
determined that “the Mobile-Sierra presumption remains the default rule,” there is no need
for the Commission to promulgate a default standard); Wis. Pub. Serv. Corp., 120 FERC
¶ 61,177, at P 22, n.19 (2007) (stating that “even had the contract been silent as to the future
changes, the [Mobile-Sierra] public interest standard would have applied.”).
155
Morgan Stanley, 554 U.S. 530.
156
Id. at 550 (citations omitted); see also id. at 530 (stating that in order for the Commission to
require modifications to an existing contract, it must first determine that the existing
provisions it seeks to eliminate “seriously harm[] the public interest.”).
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any evidence, and the Commission made no showing that the current Transmission Owners
Agreement provisions regarding construction rights and obligations are seriously harming the
public interest in MISO. In fact, MISO’s track record of transmission expansion under Appendix
B Section VI of the Transmission Owners Agreement demonstrates significant public benefits,
belying any notion of harm to the public interest.
i.
The Order No. 1000 Record Does Not Support a Finding that the
Transmission Owners Agreement Seriously Harms the Public
Interest
The Commission’s directive in Order Nos. 1000 and 1000-A that public utility
transmission providers adopt reforms related to nonincumbent transmission developer
participation in the regional planning process, including eliminating federal rights of first refusal,
was premised on the unsubstantiated presumption that such rights could inhibit the identification
and evaluation of more efficient or cost-effective solutions to regional transmission needs,
potentially leading to rates that were unjust and unreasonable, or otherwise result in undue
discrimination against nonincumbent transmission developers.157 However, as discussed above,
the Commission is required to do more than speculate that a contract provision “may” lead to
unjust and unreasonable rates in order to require modification under the Mobile-Sierra standard.
As an initial matter, it is noteworthy that the rulemaking record in the Order No. 1000
proceeding is devoid of any evidence – let alone evidence of “extraordinary circumstances” of
serious harm to the public interest – that the existing construction and ownership rights and
obligations set forth in Appendix B Section VI of the Transmission Owners Agreement has
created the type of harm identified in Order No. 1000. In fact, the Commission’s findings in
Order Nos. 1000 and 1000-A requiring the elimination of rights of first refusal are premised on a
theoretical threat of harm,158 and not on any specific demonstration that any provision of the
Transmission Owners Agreement or any other Commission-jurisdictional agreement has in fact
resulted in rates that seriously harm the public interest.
A generalized statement of theoretical harm is insufficient to sustain or impose overly
restrictive requirements in the absence of record evidence, or to make the necessary showing that
Appendix B Section VI of the Transmission Owners Agreement “seriously harms the public
interest”159 as required to overcome that agreement’s Mobile-Sierra protections. In National
Fuel Gas Supply Corp. v. FERC,160 the court vacated certain prophylactic restrictions contained
in a rulemaking, expressly finding that the Commission could point to no record evidence
demonstrating that the proposed restrictions were justified, and held that “[p]rofessing that an
157
See, e.g., Order No. 1000 at PP 7, 253; Order No. 1000-A at 360-61.
158
See Order No. 1000 at P 52; Order No. 1000-A at PP 57, 72.
159
Morgan Stanley, 554 U.S. at 530.
160
468 F.3d 831 (D.C. Cir. 2006) (“National Fuel”).
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order ameliorates a real industry problem but then citing no evidence demonstrating that there is
in fact an industry problem is not reasoned decision making.”161 Moreover, the courts have
rejected attempts to require modification of agreements subject to the Mobile-Sierra doctrine on
the basis of mere assertions of harm.162 Consistent with judicial precedent, the Commission
should find that its fear of a theoretical threat does not support its mandate that MISO modify the
Transmission Owners Agreement in the face of the Mobile-Sierra doctrine.
ii.
MISO’s Track Record on Transmission Investment under the
Transmission Owners Agreement Demonstrates Benefits to the
Public Interest
As discussed above, the Order No. 1000 rulemaking record does not support a finding
that the construction and ownership rights and obligations provisions of the Transmission
Owners Agreement seriously harm the public interest sufficient to authorize the Commission to
mandate their modification. Likewise, MISO’s actual track record on transmission expansion
compels the opposite conclusion – that the existing Transmission Owners Agreement is resulting
in robust transmission expansion and increased participation by nonincumbent utilities in MISO,
both of which benefit rather than harm the public interest.
Appendix B Section VI of the Transmission Owners Agreement does not interfere with
efficient transmission planning or result in more costly, less optimal transmission solutions in
MISO. In fact, MISO transmission planning is conducted on a cost-effective basis.163 In the
course of the MTEP process, MISO is obligated to “seek out opportunities to coordinate or
consolidate, where possible, individually defined transmission projects into more comprehensive
cost-effective developments.”164 This was recently demonstrated through the reconfiguration of
two projects in Iowa by MISO during the 2011 Multi Value Portfolio analysis, resulting in a
solution that addressed more reliability issues than the two original projects, at roughly the same
cost. 165
This “collaborative [MTEP] process is designed to ensure that the MTEP address[es]
Transmission Issues within the applicable planning horizon in the most efficient and cost
161
National Fuel, 468 F.3d at 841, 843.
162
See Atl. City Elec. Co. v. FERC, 295 F.3d 1, 14 (D.C. Cir. 2002) (mere assertions that
contract provisions were unreasonable or discriminatory were insufficient to justify
involuntary contract modifications).
163
Curran Testimony at 7-8.
164
Section I.B of Attachment FF.
165
Benefits discussed in MVP report, sections 5.3 and 5.4. See
https://www.misoenergy.org/Library/Repository/Study/Candidate%20MVP%20Analysis/M
VP%20Portfolio%20Analysis%20Full%20Report.pdf; see also Curran Testimony at 14.
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effective manner, while giving consideration to the inputs from all stakeholders.”166 The MTEP
process is open to all stakeholders, including state retail regulators, with multiple opportunities
for stakeholder input into the development of an efficient and cost-effective transmission plan, in
accordance with Order No. 890.
Additionally, the MISO Tariff and Transmission Owners Agreement facilitate, rather
than prohibit, participation by nonincumbent transmission developers in the transmission
planning process.167 Under the Transmission Owners Agreement, MTEP is intended to be a
“multi-party collaborative process . . . designed to ensure the development of the most efficient
and cost-effective Midwest ISO Plan that will meet reliability needs and expand trading
opportunities, better integrate the grid, and alleviate congestion, while giving consideration to the
inputs from all stakeholders.”168 Appendix B Section VI also states that “[t]hird parties shall be
permitted and are encouraged to participate in the financing, construction and ownership of new
transmission facilities as specified in the Midwest ISO Plan.”169
1. MISO’s Robust Transmission Expansion under the Current
Transmission Owners Agreement is in the Public Interest
New transmission is being planned and built within MISO through MISO’s collaborative
MTEP process, which benefits consumers. For example, in MISO’s 2011 Transmission
Expansion Plan report (“MTEP11”), the MISO Board of Directors approved $6.5 billion in new
transmission projects,170 including, among other projects: (i) the first MVP portfolio consisting
of 17 projects with a total estimated cost of $5.2 billion171 and (ii) 40 Baseline Reliability
Projects with a total estimated cost of $424 million required to meet North American Electric
166
Section I.B of Attachment FF.
167
Section I.A.2 of Attachment FF (“The Transmission Provider shall facilitate discussions
with its Transmission Customers and other stakeholders, [and] the Transmission Owners
about the [transmission expansion needs and solutions involving] both transferred and nontransferred facilities.”). Attachment FF contains MISO’s Order No. 890-compliant planning
process.
168
Transmission Owners Agreement, Appendix B, Section VI.
169
Transmission Owners Agreement, Appendix B, Section VI.
170
MTEP11 at 1. The MTEP11 report and related material is posted on the MISO website at
https://www.midwestiso.org/Planning/TransmissionExpansion
Planning/Pages/MTEP11.aspx.
171
Curran Testimony at 12. The total portfolio includes the Michigan Thumb project, approved
in August 2010. Costs are listed in 2011 dollars, as estimated at time of the portfolio
approval. The MVP Portfolio report and related material is posted on the MISO website at
https://www.misoenergy.org/Library/Repository/Study/Candidate%20MVP%20Analysis/M
VP%20Portfolio%20Analysis%20Full%20Report.pdf
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Reliability Corporation (“NERC”) reliability standards. MTEP11 also indicated that the total
number of projects shown as approved in Appendix A is 553, representing an expected
investment of $10.0 billion through 2021.172 Since the first MTEP cycle closed in 2003,
transmission projects recommended for approval have averaged $1.8 billion dollars per cycle, for
a total approved investment of $14.3 billion, of which $4.3 billion is associated with projects
already in service.173
This transmission investment has provided a myriad of benefits to the MISO system. For
example, the 2011 MVP portfolio alone provides substantial economic benefits including: $41
billion of increased market efficiency; $5 billion of deferred generation investment; $3 billion of
benefit for efficient wind turbine siting and avoided transmission investment on a 40-year net
present value basis.174 These benefits are significant when compared against an initial capital
investment of approximately $5.2 billion. In addition, the MVP portfolio resolved reliability
violations on approximately 650 elements for more than 6,700 system conditions and mitigated
31 system instability conditions, making possible the safe and efficient delivery of energy from
renewable resources to meet applicable state public policy requirements.175
In contrast to this evidence that current transmission expansion in MISO is providing
significant net benefits to consumers, the Commission in Order No. 1000 pointed to no actual
evidence in the Order No. 1000 rulemaking record that consumers are being harmed by MISO’s
existing planning process, or that nonincumbent transmission developers could or would
construct transmission facilities in a more efficient or cost-effective manner than current MISO
Transmission Owners. As discussed above, the MISO Tariff and Transmission Owners
Agreement require that transmission planning be conducted in the most efficient and costeffective manner, with MISO independently making final determinations on which projects are
approved for construction in the MTEP. The Commission’s unsupported suggestions that
nonincumbent participation may lead to more efficient or cost-effective transmission
development fail to satisfy the Mobile-Sierra doctrine’s requirement to show serious harm to the
public interest to justify the Commission’s directive to modify the Transmission Owners
Agreement, particularly in light of the strong evidence of significant public benefit that has
resulted from MISO’s current MTEP process under the existing Transmission Owners
Agreement and Tariff.
172
MTEP11 at 4. This figure represents all projects that were approved and were not reported
as in-service as of the end of the MTEP11 cycle. The MTEP11 report and related material
are posted on the MISO website at
https://www.midwestiso.org/Planning/TransmissionExpansion
Planning/Pages/MTEP11.aspx.
173
Curran Testimony at 13; MTEP11 at 4,
174
Curran Testimony at 13-14; MTEP11 at 64.
175
Curran Testimony at 13-14; MTEP11 at 1, 42, 60.
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2. Nonincumbent Transmission Providers Are Participating in
MISO Transmission Planning and Construction under the
Current Transmission Owners Agreement
Contrary to the speculative conclusions of Order No. 1000, the existing Transmission
Owners Agreement is not impeding nonincumbent transmission developer participation in MISO
transmission planning and construction. One example of such participation is the CapX2020
Transmission Capacity Expansion Initiative (“CapX2020 Initiative”), a joint effort by eleven
utilities, including both incumbent and nonincumbent public and non-public utilities, to construct
nearly 700 miles of new, extra-high voltage transmission facilities stretching from North Dakota
and South Dakota, through Minnesota, and into Wisconsin.176 The CapX2020 Initiative has
encouraged participation in transmission investment and ownership by nonincumbent
transmission dependent utilities,177 which the Commission acknowledged in a recent order
granting transmission rate incentives for an entity that, while not currently a MISO Transmission
Owner, will be a participating owner in the CapX2020 Hampton-Rochester-La Crosse Project.178
Moreover, Appendix B Section VI allows Transmission Owners to designate other parties
to construct facilities that the Transmission Owners would otherwise have the right to construct
under this provision. In Pioneer Transmission, LLC v. Northern Indiana Public Service Co., the
parties recently entered into a settlement agreement that will allow a nonincumbent transmission
developer to share equally in the construction and ownership of the Reynolds-Greentown project
(an MVP approved in MTEP11), which resolved a proceeding to determine which parties had the
right to construct this project.179
Both the outcome of the Pioneer proceeding and the wide range of participants in the
CapX2020 projects show that nonincumbent transmission developers are being provided the
opportunity to participate in transmission expansion in MISO under the current construction
rights provisions of Appendix B Section VI. Therefore, there is no evidence that the current
176
Comments of the Midwest ISO Transmission Owners, Docket No. RM10-23-000, at 36-37
(Sept. 29, 2010).
177
Comments of the CapX2020 Utilities, Docket No. RM10-23-000, at 9 (Sept. 29, 2010).
178
See WPPI Energy, 141 FERC ¶ 61,004, at P 2 (2012) (“WPPI is a market participant in the
MISO energy markets, but is not currently a transmission-owning member of MISO.”)
(emphasis added). In his concurrence, Commissioner Norris stated that “the CapX2020
initiative represents a great example of how joint ownership in the upper Midwest can
harness the collaboration of eleven utilities, their regulators and the public to expand the
transmission grid to meet increased demand and support renewable energy development.”
Id., (Norris, Concurring)).
179
See Offer of Settlement of Pioneer Transmission, LLC, Docket No. EL12-24-000 (Aug. 20,
2012). The Reynolds-Greentown project is identified as Project Id. 2202 in MTEP11.
MTEP 11, Project Facilities Table.
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Transmission Owners Agreement provisions are “seriously harming the public interest” such that
unequivocal public necessity compels involuntary modification of the Transmission Owners
Agreement.
(d) The Commission Should Disregard the Modifications to the Tariff
and Transmission Owners Agreement Summarized in Section II.D.2
Below
Because the MISO Transmission Owners Agreement is protected by the Mobile-Sierra
doctrine and the Commission has offered no evidence that existing provisions in the
Transmission Owners Agreement seriously harm the public interest, the Commission cannot
require MISO to adopt the nonincumbent transmission developer reforms required by Order No.
1000, including elimination of federal rights of first refusal. For the Commission’s convenience,
the Filing Parties list below the changes to the Transmission Owners Agreement and the related
changes to the MISO Tariff necessary to implement the nonincumbent transmission developer
requirements of Order No. 1000. These revisions should be disregarded if the Commission
determines, as it properly should, that the Transmission Owners Agreement is subject to MobileSierra protection and that the Commission lacks sufficient evidence to satisfy the public interest
standard to compel changes to the Transmission Owners Agreement (along with the related
revisions to the Tariff). Therefore, the Commission should only accept the Tariff and
Transmission Owners Agreement revisions identified below and described in Section II.D.2
through II.D.4 of this transmittal letter if it finds that: (1) the Transmission Owners Agreement is
not a Mobile-Sierra contract, or (2) the Transmission Owners Agreement is a Mobile-Sierra
contract, and that the public interest standard of review has been met.
2. Non-Incumbent Developer Reforms to Be Disregarded Unless the MobileSierra Standard is Met
As directed by Order No. 1000 (at P 7, 253, 313), which requires the elimination from
jurisdictional tariffs and agreements of federal rights of first refusal to construct regional
transmission facilities, MISO has amended certain provisions of the Transmission Owners
Agreement to the extent that they provide for the designation of construction obligations for
transmission facilities to incumbent Transmission Owners, including transmission facilities
selected in the regional plan for purposes of cost allocation. MISO has also made associated
Tariff revisions to provide for the participation of non-incumbent transmission developers in the
construction of approved MTEP projects that are regionally cost shared, which should also be
disregarded unless the Commission satisfies the Mobile-Sierra public interest standard for the
Transmission Owners Agreement.
The proposed Tariff revisions retain the core features of the MTEP project selection
process, and most changes pertain to the developer selection process. MISO’s project selection
process remains a combination of the “bottom-up” identification of projects in the local planning
processes of Transmission Owners, and MISO’s “top-down” consideration of both locally
identified projects and those identified through other means, in light of regional needs. Such
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regional consideration is an iterative process through which MISO, in consultation with
Transmission Owners, stakeholders, and customers, evaluates potentially efficient or costeffective solutions to regional needs. Projects are finally chosen during each planning cycle
through the MISO Board’s approval of recommended projects described in the MTEP report.
Approved projects will be assigned to Transmission Owners under the existing process
outlined in the Transmission Owners Agreement if they belong to the categories of projects that
Order No. 1000 excludes from the Commission’s directive to eliminate federal rights of first
refusal. The excluded categories, as further described below, are local transmission facilities,
upgrades to existing facilities, facilities associated with use of an existing right of way, and
facilities whose costs are otherwise allocated only to a single pricing zone.
On the other hand, approved projects covered by the Commission’s directive to eliminate
federal rights of first refusal will be classified as Open Transmission Projects, for which MISO
will issue Transmission Proposal Requests, in response to which both non-incumbent
transmission developers and incumbent Transmission Owners may submit New Transmission
Proposals as described in more detail below and in Ms. Curran’s testimony.180 State regulatory
commissions that have, and opt to exercise, the authority to choose transmission developers in
their respective jurisdictions will select the transmission developers for applicable projects. To
the extent state commissions do not have, or do not exercise, such authority, MISO shall select
the transmission developer based on appropriate legal, technical, financial, and other criteria.
(a) Revisions of Transmission Owners Agreement to Address
Nonincumbent Developer Participation
Article, Four, Sections I.C and IV of Appendix B (“Planning Framework”) of the
Transmission Owners Agreement imposes on MISO’s Transmission Owners an obligation to
build projects for which they are designated by MISO as the party responsible for
construction.181 Section VI of Appendix B further references the “responsibilities to construct,”
and equal ownership of, facilities connected between facilities owned by two or more
Transmission Owners.
As noted above, the Commission has found that “the language in Section VI of
Appendix B of the MISO TO Agreement acts to establish a right of first refusal.”182 Moreover,
under the fourth paragraph of Section VI of Appendix B of the Transmission Owners
Agreement, MISO is obligated to designate a Transmission Owner in the first instance to
construct a project proposed by, and/or located in the area of, that Transmission Owner.
180
See Section II.D.4 infra; Curran Testimony at 37-40.
181
Xcel Energy Services Inc. v. American Transmission Company, LLC, 140 FERC ¶ 61,058 at
P 58-61.
182
Xcel Energy Services Inc. v. American Transmission Company, LLC, 140 FERC ¶ 61,058 at
P 64.
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To comply with Order No. 1000’s requirement to remove federal rights of first refusal
MISO proposes revisions to the Transmission Owners Agreement to clarify that for transmission
projects selected in the regional plan for purposes of cost allocation (i.e., MEPs and MVPs),
MISO will select the entity to construct each such project using an inclusive evaluation
approach. Other provisions of the Transmission Owners Agreement on Transmission Owner
obligations to construct “local” facilities (not regionally planned and not regionally costallocated) are retained,183 consistent with Order No. 1000.
3. Exclusions From Requirement to Eliminate Right of First Refusal
(a) Local Transmission Facilities
Order No. 1000’s regional planning and cost allocation requirements are inapplicable to
local transmission facilities, even if “rolled into” the regional plan for purposes other than cost
allocation.184 These consist of all projects that are not selected in the MISO’s regional plan for
purposes of cost allocation as either an MEP or MVP. According to Order No. 1000 (at P 258,
318) and Order No. 1000-A (at P 382), local transmission facilities that are not selected in the
regional transmission plan for purposes of cost allocation, as defined by Order No. 1000, are
exempt from the Commission’s requirements regarding nonincumbent transmission developer
participation. Consistent with Order No. 1000 (at P 262), Transmission Owners may meet their
reliability needs or service obligations by choosing to build new transmission facilities that are
located solely within their retail distribution service territories or footprints and that are not
selected in the regional transmission plan for purposes of cost allocation, in which case those
facilities are not covered by Order No. 1000’s requirement regarding elimination of a federal
right of first refusal.
(b) Multi-Transmission Owner Zones
In Order No. 1000-A (at P 424), the Commission stated that:
In general, any regional allocation of the cost of a new transmission facility
outside a single transmission provider’s retail distribution service territory or
footprint, including an allocation to a ‘zone’ consisting of more than one
transmission provider, is an application of the regional cost allocation method and
that new transmission facility is not a local transmission facility. . . . However, we
recognize. . . that special consideration is needed when a small transmission
provider is located within the footprint of another transmission provider. For
183
As discussed above, MISO and certain MISO Transmission Owners are submitting a separate
filing concurrently with this filing to modify the cost allocation for BRPs, given their local
focus and benefits.
184
Order No. 1000 at P 7, 262; Order No. 1000-A at PP 190 and 357.
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instance, a regional cost allocation method might allocate costs to an area
consisting of one transmission provider that has within its borders one or more
smaller utilities that largely depend on its transmission system but nevertheless
own a little transmission of their own, so that they too are transmission providers.
This situation is not necessarily ‘a zone consisting of more than one transmission
provider’ as this term is used in this order. If the cost of a new transmission
facility is allocated entirely to an area consisting of one transmission provider that
has one or more smaller transmission providers within its borders, this might
qualify as a local cost allocation, not a regional cost allocation.185
In making this finding, the Commission directed public utility transmission providers to include
any specific instances of such multi-transmission provider zones in their compliance filings, so
that the Commission can determine on a case-by-case basis whether allocation of costs to such
zones constitutes “local” cost allocation rather than regional allocation.186
Within MISO, 11 of the 24 pricing zones contain the transmission facilities of more than
one Transmission Owner (referred to in MISO as “joint pricing zones”); 187 however, the
allocation of costs to a single joint pricing zone qualifies as local cost allocation, at least with
respect to the joint pricing zones existing as of the date of this filing. When the cost of a
transmission facility is allocated by MISO solely to one of these joint pricing zones, the cost
allocation is local, just as it would be for the cost of an identical transmission facility that is
allocated to one of the 13 MISO pricing zones consisting of only one Transmission Owner’s
facilities.
In Order No. 1000-A, the Commission stated that, “[f]or example, transmission-owning
members of an RTO may not retain a federal right of first refusal by dividing the RTO into East
and West multi-utility zones and allocating costs just within one zone consisting of more than
one transmission provider.”188 However, there is no evidence to suggest that any of the joint
pricing zones existing as of the date of this filing have been created in this manner for the
purpose of providing the individual transmission owners a federal right of first refusal. In fact,
the creation of the MISO pricing zones predates the issuance of Order No. 1000 and subsequent
orders and is based on historic cooperation among transmission-owning utilities that predate their
membership in MISO. Accordingly, the Commission’s concern regarding the possibility that
transmission owners in RTOs could establish unnaturally large multi-owner zones to retain a
federal right of first refusal does not exist in MISO under the current configuration of joint
pricing zones.
185
Order No. 1000-A at P 424.
186
Order No. 1000-A at P 424.
187
Curran Testimony at 23.
188
Order No. 1000-A at P 424.
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It is important to note that the current pricing zones within MISO, including joint pricing
zones, were established based on factors such as the existence of historic balancing authority
areas and historic stand-alone transmission tariff pricing zones. Joint pricing zones arose from
historic cooperation among transmission-owning utilities to create efficiencies and avoid
construction of redundant transmission facilities by multiple utilities in a local area.189 The
historic cooperation also included coordination between public utilities and non-public utilities to
avoid duplicative transmission development. These historic balancing areas, historic stand-alone
transmission tariff pricing zones, and cooperation formed the basis of the pricing zones that exist
in MISO today, and coordination occurring within these pricing zones is focused on serving local
needs, whether one or more than one entity owns transmission facilities in the zone.190
The fact remains that the presence of facilities owned by more than one Transmission
Owner in a single joint pricing zone in MISO does not make the cost allocation regional. Cost
allocation to MISO joint pricing zones is local for several reasons, including: (1) the local
historical nature of zone development within the MISO system; (2) the small geographic scope
of pricing zones in comparison to the entire MISO footprint; (3) the local investment nature of
joint pricing zones within the MISO system; and (4) the benefits of local cooperation between
Transmission Owners on all levels of the transmission system, including within single pricing
zones.
i. Local Historical Nature of Zone Development
As indicated above, the pricing zones in MISO are comprised of the traditional balancing
authorities in the region, which are now Local Balancing Authorities (“LBAs”) under MISO’s
consolidated balancing authority. When MISO was formed, the pricing zones were specified in
the Tariff.191 For a new Transmission Owner to be assigned a separate zone, the Transmission
Owner had to have been “a transmission provider [that] is or would have been a specified zone
for pricing under an existing or proposed regional transmission tariff.”192 Many Transmission
Owners did not meet this definition and instead became part of an existing pricing zone through
the development of joint pricing zones. Given the highly integrated nature of the transmission
systems of many utilities when they joined MISO, dividing the balancing authority areas into
multiple zones containing only the facilities of each individual utility made no practical sense.193
The MISO transmission pricing zones have been developed based on the local nature of the
facilities and the Transmission Owners. Following acceptance by the Commission of this filing,
the development of subsequent joint pricing zones in MISO would be subject to Commission
189
Curran Testimony at 24.
190
Id.
191
Id.
192
Transmission Owners Agreement, Appendix C, Section II.A.1.
193
Curran Testimony at 25.
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review, including whether such joint zone should be deemed local in nature, as a pricing zone
cannot be added absent a filing under section 205 of the Federal Power Act.
ii. Small Geographic Scope of MISO Joint Pricing Zones
The geographic scope of the each of the pricing zones in MISO, compared to the total
MISO regional footprint, makes each transmission pricing zone by definition local in nature.
Allocating costs to the pricing zones, therefore, is also local, regardless of the number of
Transmission Owners with facilities in the zone. As Exhibit No. MISO-4 demonstrates, each
pricing zone represents a small geographic area in comparison to the entire MISO footprint.194
Given the relatively small geographic size of each pricing zone in comparison to the entire MISO
footprint, any cost allocation limited to one pricing zone is more appropriately considered local,
regardless of the number of Transmission Owners within the pricing zone.195
As discussed above, the Commission in Order No. 1000-A noted that transmission
owning members of an RTO may not divide the RTO into large “East and West multi-utility
zones and [allocate] costs just within one zone consisting of more than one transmission
[owner]” to retain a federal right of first refusal.196 Such is not the case with respect to the MISO
joint pricing zones existing as of the date of the filing.197 As Exhibit No. MISO-4 further
illustrates, MISO has not divided its region into large sub-regional pricing zones for the purpose
of circumventing Order No. 1000. Instead, the pricing zones were established based upon
historical balancing authority boundaries, which are now LBAs in MISO following MISO’s
consolidation of balancing authority functions.198
Therefore, given the relatively small geographic scope of the 24 MISO pricing zones
(including the 11 joint pricing zones) as compared to the MISO footprint overall, allocation of
the costs of a transmission facility to a single pricing zone is local as that term is used in Order
Nos. 1000 and 1000-A.
iii. Local Investment Nature of Multi-Transmission Owner Zones
within the MISO Footprint
Additionally, each of the 11 joint pricing zones can be characterized as local under Order
No. 1000-A based on the respective percentages of transmission investment in each zone. Each
194
See Exhibit No. MISO-4 (showing the relatively small size of the pricing zones in relation to
all of MISO).
195
Curran Testimony at 25.
196
Order No. 1000-A at P 424.
197
Curran Testimony at 26.
198
Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ¶ 61,172, order on reh’g, 123
FERC ¶ 61,297 (2008).
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of the 11 joint pricing zones contains one Transmission Owner that owns the vast majority of
transmission plant within the zone and traditionally performed local balancing authority
functions for the facilities in that zone on behalf of one or more additional Transmission Owners
that own facilities (and have load and/or generation) located within the pricing zone.199 In fact,
as shown in Exhibit No. MISO -5, for all 11 of the zones with more than one Transmission
Owner, a single Transmission Owner owns at least 75 percent of the gross transmission plant in
that pricing zone. Given the disparity in gross transmission plant among owners, what results in
each of the 11 joint pricing zones is a scenario in which the transmission assets of the
Transmission Owners with fewer assets depend in large part upon the transmission assets of the
Transmission Owner with the bulk of the assets. Without the system put in place by the
Transmission Owner with the bulk of the assets, the other Transmission Owners’ systems would
not function in a complete manner.200 Accordingly, each of these joint pricing zones falls toward
the local end of the “continuum” that Order No. 1000-A suggests (i.e., a pricing zone consisting
primarily of one Transmission Owner with one or more additional Transmission Owners that
“own a little transmission of their own” in the zone).201
As stated above, each of the 11 joint pricing zones consist of one main Transmission
Owner in that zone, and one or more local area Transmission Owners with lesser transmission
investment roles that do not affect the local nature of the pricing zone. Each Transmission
Owner typically constructs facilities to serve its local load. In cases of facilities that provide
local reliability or load-serving benefits to more than one Transmission Owner in the zone, the
facilities to be constructed and the responsibility to construct such facilities has historically been
determined through cooperation of the Transmission Owners in the pricing zone, rather than
relying on separate construction of redundant transmission facilities by each Transmission
Owner to serve its own load. Historically, in many of the joint pricing zones, transmission
facilities were added based on a load ratio share within the pricing zone, and were not based on a
regional cost allocation. The historic pricing zones have not been used for the purpose of
allocating the costs of transmission projects with regional benefits among the Transmission
Owners. 202
199
Curran Testimony at 26.
200
Id. As Ms. Curran notes, these are precisely the type of pricing zones that the Commission
indicated in paragraph 424 of Order No. 1000-A would likely not qualify as “‘a zone
consisting of more than one transmission provider’ as that term is used” in Order No. 1000A.
201
Order No. 1000-A at P 424 (“For instance, a regional cost allocation method might allocate
costs to an area consisting of one transmission provider that has within its borders one or
more smaller utilities that largely depend on its transmission system but nevertheless own a
little transmission of their own . . . . This situation is not necessarily ‘a zone consisting of
more than one transmission provider’ as this term is used in this order.”).
202
Curran Testimony at 27.
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iv. Benefits of Local Cooperation
As discussed above, joint pricing zones in the MISO footprint often resulted from the
highly integrated nature of certain Transmission Owners’ systems as a consequence of decades
of cooperation and collaboration predating their membership in MISO. These joint pricing zones
represent a positive example of coordination among Transmission Owners to ensure that their
loads are served as reliably and efficiently as possible. For example, public utility transmission
providers and non-jurisdictional utilities in MISO have a long tradition of cooperative and
collaborative transmission planning and expansion, that resulted in the creation of joint pricing
zones when those utilities joined MISO.203 The local focus of this cooperation within joint
pricing zones belies the notion that the existence of more than one Transmission Owner renders
allocation of costs to the zone “regional” rather than local.
v. Differentiating Between Single Owner Zones and Joint Pricing
Zones Would Result in Undue Discrimination
Given their similarities to zones consisting of a single Transmission Owner, joint pricing
zones are axiomatically local in nature, and any Commission finding to the contrary would be
erroneous and would result in undue discrimination against Transmission Owners located in joint
pricing zones. As explained above, the joint pricing zones arose as a result of the close historical
collaboration of these Transmission Owners in highly integrated areas out of a desire to avoid
construction of redundant transmission facilities. If the Commission declines to find that cost
allocation to a joint pricing zone in MISO is “local” under Order Nos. 1000 and 1000-A as
requested above, transmission facilities that are allocated 100% to a pricing zone consisting of
only one MISO Transmission Owner would be considered “local transmission facilities” for
purposes of Order No. 1000, while an identical transmission facility would not be a “local
transmission facility” if the costs happen to be allocated to a joint pricing zone.204 Transmission
Owners that happen to be located in a single owner pricing zone would be permitted to retain a
federal right of first refusal for transmission facilities allocated to their zone, while similarlysituated Transmission Owners located in joint pricing zones would lose such rights. This
unjustified distinction is the very definition of undue discrimination,205 particularly given the
203
Id.; see also Exhibit No. MISO-5 (listing the zones and showing the relative investment of
members of the joint pricing zones).
204
See Order No. 1000-A at P 424.
205
See, e.g., Sw. Power Pool, Inc., 137 FERC ¶ 61,075, at P 52 (2011) (“The Commission has
determined that discrimination is undue when there is a difference in rates or services among
similarly situated customers that is not justified by some legitimate factor.”) (citing El Paso
Natural Gas Co., 104 FERC ¶ 61,045, at P 115 (2003), order on reh’g, 106 FERC ¶ 61,233
(2004)); W. Grid Dev., LLC, 133 FERC ¶ 61,029, at P 17 (2010) (“The protection against
undue discrimination prohibits the dissimilar treatment of similarly situated entities.”); Cal.
Indep. Sys. Operator Corp., 132 FERC ¶ 61,148, at P 40 (2010) (“The Commission has
determined that discrimination is undue when there is a difference in rates or services among
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Commission’s finding in the MVP Order that “in the context of transmission planning and cost
allocation” the pricing zones in MISO are “similarly situated.”206
vi. Cost Allocation to a Pricing Zone Is “Local” Regardless of
Whether the Zone is a Joint Pricing Zone
For all of these reasons, a transmission project whose costs are allocated exclusively to a
single MISO pricing zone is appropriately characterized as a local project even if the pricing
zone consists of more than one Transmission Owner.
(c) Upgrades to Existing Facilities
In accordance with the Commission orders (Order No. 1000 at P 319; Order No. 1000-A
at P 426-27, 357, 392) recognizing the critical needs for maintaining a federal right of first
refusal by an incumbent transmission provider(s) for upgrades to existing transmission facilities,
MISO has proposed Tariff revisions to address the maintenance of an existing Transmission
Owner’s ability to construct transmission upgrades. As the Commission has recognized,
upgrades to existing facilities are of numerous kinds that can be difficult to list exhaustively.207
Accordingly, MISO’s proposed Tariff revisions characterize the general policies that will be
used to define upgrades to transmission line facilities and transmission substation facilities.208
It is important to note that upgrades versus new construction are determined based on
specific transmission facilities rather than specific transmission projects, and most transmission
projects contain or impact multiple transmission facilities. As such, nearly all transmission
projects that contain new transmission facilities will also contain some facility upgrade work as
well since all new transmission facilities must interconnect with the existing Transmission
System in some manner. In such cases, the project will generally consist of a combination of
upgrades subject to a federal right of first refusal and new facility construction that may or may
not be subject to a federal right of first refusal based on the type of transmission project.
Upgrades are applicable to both transmission line facilities and substation facilities as
discussed below.
i. Upgrades to Transmission Lines
similarly situated customers that is not justified by some legitimate factor.”), reh’g denied,
134 FERC ¶ 61,106 (2011).
206
MVP Order at P 221.
207
Order No. 1000-A at P 426 (“It is not feasible, however, to list every type of improvement or
addition, or name all the parts of lines, towers and other equipment that may be replaced or
otherwise upgrades, and we will not do so here”).
208
Section VIII.B of Attachment FF.
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The proposed Tariff language clarifies that upgrades to existing transmission line
facilities include any replacement, relocation, modification, or expansion of such transmission
line facilities so long as transmission line facilities are classified as transmission plant and owned
by one or more Transmission Owners.209
Furthermore, while the Commission has recognized that the term upgrade does not apply
to an entirely new transmission facility,210 it is important to note that some new transmission
circuit proposals may be implemented as a combination of new transmission line sections and
upgrades to existing transmission line sections. Therefore, it is necessary to establish a policy
for whether an entirely new transmission circuit that is composed of both new transmission line
sections and upgrades to existing transmission line sections should be considered an entirely new
transmission facility or a transmission line facility upgrade. For such situations where a new
transmission circuit is composed of both upgraded existing transmission line sections and new
transmission line sections, the proposed Tariff revisions consider new transmission line sections
on new right-of-way as new transmission facilities when the length of such new transmission line
sections exceeds 20 contiguous miles.211 Otherwise, the construction of the new transmission
line sections would be considered part of the upgrade to the existing transmission facilities. In
any event, upgrades made to the existing transmission line sections would always be considered
upgrades.212
This provision addresses an issue identified in the stakeholder process where a new
transmission circuit is composed mostly of upgrades to existing transmission line facilities, but
some new sections may be required due to right-of-way expansion issues or to tie the
transmission circuits into the appropriate substation terminals. In these cases, it may not be
efficient to separate out the new portion(s) of the facility to a potentially different developer if
the new transmission line section(s) represents a small percentage of the project or there are
many short new transmission sections dispersed along a proposed transmission circuit that
consists mainly of upgrades to an existing transmission line facility. While MISO initially
proposed a percentage threshold, the percentage threshold is problematic. For example, 25% of
a 200 mile project is considerable (i.e., 50 miles) whereas 50% of a 5 mile project is not (i.e., 2.5
miles). Given the fact that most regionally cost shared transmission projects are large, (e.g., the
average mileage of MVP projects approved to date is about 115 miles per project, etc.), a 20 mile
continuous threshold is a just and reasonable threshold that balances the opportunity to compete
for project development with the need to ensure project development efficiency.
ii. Transmission Substation Facilities
209
Section VIII.B.1.1 of Attachment FF.
210
Order No. 1000-A P 426.
211
Section VIII.C.1.1.1 of Attachment FF.
212
Section VIII.C.1.1.1 of Attachment FF.
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The proposed Tariff language clarifies that upgrades to existing substation facilities
include any expansions, replacements, or modifications made, in part or in whole, to any existing
substation or portion thereof that is owned by one or more Transmission Owners, and where
some or all of the plant within the existing substation is classified as transmission plant.213
Upgrades to substations typically fall into one of the following three categories:

Replacing and/or modifying facilities and/or equipment, and/or installing
additional plant, within an existing substation footprint;

Expanding an existing substation footprint within the existing substation site
boundaries and installing additional plant within the expanded area; and/or

Acquiring additional land adjacent to or near an existing substation in conjunction
with installation of additional plant within the boundaries of this additional land,
including facilities to interconnect such plant to the existing substation plant.214
With regard to the last bullet above, it is important to clarify the meaning of “near the
existing substation.” There are existing situations today where expansion of a substation cannot
be made by purchasing land adjacent to the existing substation due to the unavailability of such
land. An example of this would be an existing substation where the substation site is bounded on
all sides by public roadways. In this case, historically transmission owners have often pursued
the purchase of land near the existing substation, such as an empty site across the road from the
existing substation, and expanded the existing substation via a second substation footprint
interconnected to the existing substation footprint by very short overhead transmission circuits
essentially operating as substation buses. In this case, the two substation footprints essentially
operate as a single substation. In other situations, the Transmission Owner may find it
advantageous to simply relocate the existing transmission substation to a larger nearby parcel of
land and reroute existing transmission circuits to the new substation to facilitate long-term
expansion requirements. In either case, these are examples of the expansion of an existing
substation rather than construction of an entirely new substation that did not previously exist to
meet a transmission planning need. Treating these scenarios as substation expansions clearly fits
within the intent of Order No. 1000 to maintain a federal right of first refusal for upgrades to
existing transmission facilities, and therefore MISO has provided Tariff language to clarify this
practice.215
Finally, construction of a new substation that simply interconnects multiple existing
transmission line facilities all owned by a single Transmission Owner or group of Transmission
213
Section VIII.C.1.2 of Attachment FF.
214
Section VIII.C.1.2 of Attachment FF.
215
Section VIII.C.1.2 of Attachment FF.
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Owners should be considered an upgrade.216 For example, a transmission substation may be
installed along an existing two-terminal transmission circuit or at the common junction point of
transmission circuits that contain three or more terminals to facilitate better system protection,
higher load capabilities, increased operating flexibility, reduced facility outage times, higher
levels of customer service reliability and or mitigation of existing contingencies. In these cases,
the installation of the substation is an improvement of the performance of an existing
transmission line facility, and as such, represents an upgrade to that transmission line facility.
Therefore, MISO has proposed Tariff language that classifies this type of new substation facility
as an upgrade to the existing transmission line.
iii. Use of Existing Rights of Way
The MISO Tariff language regarding transmission upgrades is focused on existing
transmission facilities. To the extent an incumbent Transmission Owner owns right-of-way held
for future use that is classified as transmission plant, installation of new transmission facilities on
that right-of-way will be considered a transmission upgrade. For situations where unimproved
right-of-way is held by an incumbent Transmission Owner but not considered transmission plant,
in accordance with Order No. 1000 (at P 226, 319) and Order No. 1000-A (at P 357), the
proposed Tariff revisions do not address such unimproved right-of-way and do not grant or deny
any such rights to incumbent Transmission Owners or non-incumbent transmission developers.
That is, to be recognized, the right-of-way must be owned or contain improvements owned by
the Transmission Owner and classified as transmission plant, in which case any impact to these
improvements would be considered an upgrade in accordance with the proposed Tariff language
and with Order No. 1000 (at P 226, 319) and Order No. 1000-A (at P 357). Where unimproved
right-of-way would be utilized by a proposed transmission project, state laws will govern
whether the incumbent transmission developer maintains the right to such upgrades.
(d) State Rights of First Refusal
According to Order 1000 (at P 227 and n.231), the reforms made in this compliance filing
do not impact in any way state laws and obligations applicable to transmission developers.
Several states have implemented laws that define which entities are eligible to develop
transmission projects in their jurisdiction. MISO will recognize that authority and assign those
projects to the appropriate entity.217 For example, if a state has a law that establishes a right of
first refusal for incumbent Transmission Owners, MISO will assign the obligation to build for all
transmission projects in that state to the respective incumbent Transmission Owner. It would be
inefficient and wasteful to engage in a separate developer selection process in those states
because if a non-eligible developer was selected in the MISO process, the developer would
ultimately be rejected in the state process. MISO will monitor and track which states in the
region have laws impacting developer selection and will include that information in all issued
Transmission Proposal Requests.
216
Section VIII.C.1.2.1 of Attachment FF.
217
Section VIII.A of Attachment FF.
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4. Participation of Non-Incumbent and Incumbent Transmission Developers
(a) Qualification Criteria for Project Submission and Developer
Evaluation
Order No. 1000 (at P 7, 323-24) requires the adoption of qualification criteria for
transmission developers to be eligible to propose regional projects for potential selection in the
regional planning process for purposes of regional cost allocation
MISO will evaluate the qualifications of transmission developers during the evaluation
and selection of transmission developers that submit bids to construct selected projects. This
approach is reasonable in light of: (i) Order No. 1000’s apparently principal concern to avoid the
risk of unduly impeding non-incumbent access; (ii) Order No. 1000-A’s restrictions on
qualification criteria associated with state requirements; (iii) Order No. 1000’s (at P 324) intent
to allow flexibility in the definition of prequalification criteria; and (iv) MISO’s use of an
inclusive evaluation approach (rather than project sponsorship), where qualifications can be more
substantively considered with reference to projects that have already been selected.
This will also facilitate compliance with the requirement of Order No. 1000 (at P 323)
that “[t]he qualification criteria must provide each potential transmission developer the
opportunity to demonstrate that it has the necessary financial resources and technical expertise to
develop, construct, own, operate and maintain transmission facilities.” Such opportunity will be
enhanced by deferring the time for demonstrating qualifications more substantively to the
subsequent evaluation of full proposals to build approved projects.
(b) Request for Proposal and Data Submission
i. Request for Proposal
MISO is proposing an inclusive evaluation process to allow non-incumbent transmission
developers the opportunity to construct, own, operate, maintain, and restore new transmission
facilities not subject to a federal right of first refusal. As required by Order No. 1000 (at P 32526), MISO has revised Attachment FF to the Tariff to identify: (i) the information that must be
submitted by a prospective transmission developer (hereinafter referred to as a New
Transmission Proposal Applicant as defined in the proposed Tariff language) in response to a
Transmission Proposal Request; and (ii) the date by which such information must be submitted
in order for the New Transmission Proposal to be considered.
Upon approval of an MTEP by the MISO Board, MISO will develop and post on its
website, within thirty (30) days, a request for proposal for each transmission project that contains
new transmission facilities that could potentially be constructed by nonincumbent transmission
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developers.218 These projects are referred to as Open Transmission Projects (section 1.477a) in
the Tariff and the request for proposals is referred to as a Transmission Proposal Request
(section 1.671b) in the Tariff.
Based on the proposed Tariff language, the required information to be included in a
specific New Transmission Proposal will be specified in the corresponding Transmission
Proposal Request. The Transmission Proposal Request will require developers to verify that they
meet the general qualifications listed in the Tariff, as well as provide a list of data required for
MISO to evaluate the strengths and capabilities of the transmission developer to implement the
proposed transmission project and to operate, maintain, repair, and restore the proposed
transmission facilities. It will also request data sufficient to determine the proposed costs and
facility design characteristics of the project, as it would be implemented in the proposal.
While not required, the New Transmission Proposal Applicant is also encouraged to
include information regarding past experience in implementing transmission line and
transmission substation projects and operating, maintaining, restoring, and repairing
transmission line and transmission substation projects. 219
Also, while not required, the evaluation process will include a metric for participation in
the MISO regional planning process by a New Transmission Proposal Applicant (section
1.455d). Therefore, if applicable, a New Transmission Proposal Applicant should also include in
the New Transmission Proposal documentation of i) any relevant planning studies performed and
shared in the MISO regional planning process to address the Transmission Issue(s) being
addressed by the Open Transmission Project; and/or ii) any proposed project ideas or project
portfolio ideas submitted by the New Transmission Proposal Applicant in the past in the MISO
regional planning process to address the Transmission Issue(s) being addressed by the Open
Transmission Project.220
The date New Transmission Proposals are due to MISO will be specified in the New
Transmission Proposal Request, but the proposed Tariff revisions state that this date will be no
later than 180 days after the Transmission Proposal Request has been posted by MISO on its
website.221
The proposed Tariff revisions allow for a single cure period of 10 business days should
MISO determine after the due date that there are any deficiencies with regard to data submitted
218
Section VIII.D.1 of Attachment FF.
219
Section VIII.D.7 of Attachment FF.
220
Section VIII.D.9 of Attachment FF.
221
Section VIII.D.2.b. Additional details regarding submission of proposals are also found in
Section VIII.D of Attachment FF.
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in any New Transmission Proposal. The cure period commences upon notification of the
deficiency to the New Transmission Proposal Applicant.222
The proposed Tariff revisions allow MISO to request additional data from the New
Transmission Proposal Applicants following the cure period if it is believed additional data is
needed to make a selection decision. The New Transmission Proposal Applicant will be given a
minimum of ten (10) business days to provide the additional information.223
ii. Confidentiality
The proposed Tariff revisions provide that all information submitted in a New
Transmission Proposal will be considered Confidential Information224 as currently defined in the
Tariff and will be subject to the applicable Tariff provisions, including Section 38.9.225
222
Section VIII.F of Attachment FF.
223
Section VIII.D.12 of Attachment FF.
224
Section VIII.D.13 of Attachment FF.
225
Section VIII.D.6.b.13 of Attachment FF.
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(c) Evaluation and Selection of Development Proposals and Developers
i. Submission Procedure
As allowed by Order No. 1000 (at P 259, 321), MISO proposes to use an inclusive
process, including a New Transmission Proposal Request requiring the submittal of project
proposals, to obtain the information necessary to perform the evaluation and selection of
transmission developers. The New Transmission Proposal Request will require developers to
execute Binding Proposal Agreements further stipulating that the winning proponent shall
execute the Transmission Owners Agreement (as required by Order No. 1000 (at P 265)), and
shall abide by the terms in the MISO Tariff, including those requiring the developer to make a
good faith effort to construct the relevant project.
As required by Order No. 1000 (at P 266, 342-44), MISO has revised Attachment FF to
clarify that all entities, whether incumbents or non-incumbents, that are owners, operators, or
users of the electric bulk power system, must register with the North American Electric
Reliability Corporation (“NERC”) for the performance of applicable reliability functions.
(d) Qualifications
Consistent with Order No. 1000 (P 323) and Order No. 1000-A (at P 432, 439-40), MISO
will require legal, technical, and financial qualifications for transmission developers that submit
proposals to build transmission projects selected by MISO’s regional planning process. Pursuant
to the proposed Tariff revisions, qualified New Transmission Proposal Applicants will be
designated as Qualified Transmission Developers. After MISO notifies a proponent of a
deficiency in the proposal, and the cure period expires, if MISO finds that the New Transmission
Proposal Applicant still does not meet the requirements or qualifications to be considered a
Qualified Transmission Developer, the review will be concluded, and the New Transmission
Proposal will not be reviewed further.
Specific qualifications outlined in the proposed Tariff language that must be satisfied by
a New Transmission Proposal Applicant to be considered a Qualified Transmission Developer
generally include requirements to: execute required agreements such as the Transmission
Owners Agreement; comply with applicable laws and regulations, including those required by
NERC; satisfy all FERC planning criteria; and submit all required data.
(e) Deposit for Study Costs
To insulate load from the costs of evaluating developer proposals, the MISO proposal
requires a deposit with each New Transmission Proposal Request. This deposit will be used to
offset the costs of developer evaluation, with any balance remaining after the evaluation has
concluded being refunded to the transmission developer.
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(f) Evaluation and Selection
MISO’s proposed Tariff revisions allow deference to state laws and regulations with
regard to the maintenance of a right of first refusal; any states with laws or regulations granting a
right of first refusal to any transmission developers do not need to have transmission developers
evaluated through the MISO developer selection process. In the event no laws or mandates
govern the selection of the transmission developer, states will have the first option to select the
transmission developer. States must inform MISO of their intent to exercise this option prior to
approval of a particular recommended Open Transmission Project by the MISO Board of
Directors, and then they must complete their evaluation and selection within the same timeframe
that MISO is allowed (one year from the posting of the New Transmission Proposal Request).
In the event that states do not choose to select the transmission developer, MISO has
proposed Tariff language that specifies three steps that will be used to evaluate New
Transmission Proposals and select Qualified Transmission Developers:

Evaluate each New Transmission Proposal submitted by a Qualified Transmission
Developer;

Select the New Transmission Proposals for implementation based on evaluation
criteria specified in the Tariff; and

Post the selected Qualified Transmission Developer within 180 days of the due
date for submission of New Transmission Proposals.226
i. Evaluation Metrics and Weighting
The proposed Tariff language specifies the following four general criteria to be used in
evaluating New Transmission Proposals and selecting Qualified Transmission Developers:

Cost and reasonably descriptive facility design;

Project implementation capabilities;

Operations, maintenance, repair, and replacement capabilities; and

MISO planning process participation.227
The proposed Tariff language specifies that the cost and reasonably descriptive facility
design metric will be weighted at thirty percent (30%) and MISO planning process participation
226
Section VIII.G.1 of Attachment FF.
227
Section VIII.G.2 of Attachment FF.
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metric will be weighted at five percent (5%). With regard to the project implementation
capabilities metric, a weight of 35% will be used for new transmission line facilities and a weight
of 30% will be used for new substation facilities. With regard to the operations, maintenance,
repair, and replacement capabilities metric, a weight of 30% will be used for new transmission
line facilities and a weight of 35% will be used for new substation facilities.228 Project
implementation capabilities are weighted higher for new transmission line facilities than for new
substation facilities because project implementation tasks tend to be more complex for new
transmission facilities than for new substation facilities. For example, the process of performing
routing evaluation, regulatory permitting and right-of-way acquisition for a new transmission
facility tends to be more complex and have greater impacts than the process of performing site
evaluation, regulatory permitting, and land acquisition for a new substation site.
In addition, the capital costs of transmission facilities, on average, tend to be higher than the
capital costs of substation facilities unless the transmission line length is very short. In a similar
manner, operations, maintenance, repair, and replacement capabilities are weighted higher for
substation facilities than for transmission line facilities because operations, maintenance, repair,
and replacement tasks tend to be more complex for substations and problems in substation often
have greater impacts on the bulk power system than problems on transmission line facilities. For
example, failure of a relay scheme or circuit breaker in a substation or occurrence of a shortcircuit fault within a substation could potentially lead to multiple outages and greater stress on
system stability than a fault on a transmission line circuit. In addition, equipment and systems in
substation tend to be more complex than a transmission line, thus requiring higher levels of
operations, maintenance, repair, and replacement skill and effort.
ii. Development Schedule
Order No. 1000-A clarified that a transmission developer must submit a development
schedule that that indicates the required steps, such as the receipt of state approvals, necessary to
develop and construct the transmission facility. Transmission providers were also directed to
establish a date by which state approvals to construct must have been achieved.229 As part of the
contents of a New Transmission Proposal, applicants must submit a development schedule that
includes, at minimum, state regulatory approvals.230 MISO has also revised attachment FF of the
Tariff to require transmission developers to establish a date by which state approval(s) to
construct must be achieved and to provide MISO authority, through its proposed reevaluation
process231 to reassign an Open Transmission Project should a transmission developer fail to
timely obtain state regulatory approvals.232
228
Sections VIII.G.7.a and G.7.b of Attachment FF.
229
Order No. 1000-A at P 442.
230
Section VIII.7.4 of Attachment FF.
231
Section IX of Attachment FF.
232
Section IX.C.1 of Attachment FF.
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iii. Cost Estimates
As part of the selection criteria, costs will be scrutinized in the same manner whether a
project is proposed by an incumbent or nonincumbent.233 For this purpose, MISO proposes to
require developers to submit cost estimates in the following manner: 1) estimated total capital
cost of the project by facility, including estimates for contingencies and overhead; 2) estimated
annual revenue requirements for the first 40-years of the project’s in-service life to be calculated
in accordance with Attachment MM of the Tariff for Multi-Value Projects and Attachment GG
of the Tariff for Market Efficiency Projects; and 3) supporting detail on the annual allocation
factors used to estimate the annual revenue requirements, including operations and maintenance,
general and common depreciation expense, taxes other than income taxes, income taxes, and
return. By requiring all of the above from both incumbents and nonincumbents, MISO will be
able to evaluate project proposals consistently regardless of whether they are submitted by
incumbents or nonincumbents.
(g) Reevaluation Circumstances and Procedures
As required by Order No. 1000 (at P 7, 263, 329), MISO has revised Attachment FF of
the Tariff to describe the circumstances and procedures under which MISO will reevaluate the
regional transmission plan to determine if delays in the development of a transmission facility
selected in a regional transmission plan for purposes of cost allocation, including delays in
achieving state regulatory approvals, would require the evaluation of alternative solutions,
including those proposed by the incumbent Transmission Owners to ensure they can meet their
reliability needs or service obligations.234 Additionally, to account for changes that may occur
during the implementation of new transmission facilities, MISO has revised Attachment FF to
the Tariff to expand this reevaluation process to consider the impacts of changes in cost or
developer qualifications for projects evaluated through the selection process.235 This process
will begin at the assignment of a project to a Selected Transmission Developer, and it will
conclude when the project construction begins. This reevaluation timeframe is defined to
provide clarity to transmission developers on the risk they will face if cost or schedule drivers
change while they are implementing the project. This end point does not preclude the ongoing
analysis of delays after construction has begun to ensure system reliability, nor does it suspend
the developer’s obligation to build after this point.
i. Procedures
MISO will determine the need for initial variance analysis through the collection of
project and developer status updates, as defined in Section I.A.11 of Attachment FF. These
233
Order No. 1000-A at P 455.
234
Section IX of Attachment FF.
235
Section IX.A.1 andIX.A.3 of Attachment FF.
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status updates will be collected, and to the extent they contain public information, posted for
stakeholders on a quarterly basis, unless otherwise identified by the MISO Board of Directors.
Upon the receipt of a status update that denotes significant changes in the schedule or
cost of a transmission project, or which shows changes to a transmission developer’s
qualifications, MISO will perform a variance analysis to determine the high level potential
impact of the identified changes. This variance analysis will determine if the changes may cause
harm to the system, and it will flag changes of this nature for full reevaluation. During full
reevaluation, MISO will perform full analyses to determine the impact of the changes to a project
or transmission developer. At the conclusion of reevaluation, MISO will determine if any
changes to the project or developer are necessary, or it may recommend no changes to either
item.236
ii. Criteria
a. Cost
Any project cost increase that reduces the benefit-cost ratio of an economically-driven
Open Transmission Project to less than the required benefit-to-cost threshold will trigger a
variance analysis and potential reevaluation.237 The goal of this analysis and potential
reevaluation will be to determine if the project retains sufficient benefits, as compared to its
updated costs, to continue. These benefits may include, but are not limited to, the originally
defined economic benefits, reliability benefits, and public policy benefits.
b. Schedule
A reported or otherwise identified delay of 6 months or more will trigger a variance
analysis and potential reevaluation.238 The goal of this analysis and potential reevaluation is to
determine if delays in the development of the transmission facility require the evaluation of
alternative solutions, a reliability mitigation plan, and/or an updated implementation plan.
c. Developer Qualifications
Any material changes in the characteristics or qualifications of a Selected Transmission
Developer will trigger a variance analysis and potential reevaluation.239 The goal of this analysis
and potential reevaluation is to determine if the changes in the Transmission Developer’s
qualifications impact the ability of the developer to implement, own, operate, maintain, or restore
the transmission facilities.
236
Section IX.C of Attachment FF.
237
Section IX.A.1 of Attachment FF.
238
Section IX.A.2 of Attachment FF.
239
Section IX.A.3 of Attachment FF.
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iii. Reevaluation Results
At the conclusion of any necessary reevaluation, MISO can determine that a reliability
mitigation plan, project cancellation, or developer reassignment is necessary to ensure reliable
operation of the transmission system and maintain just and reasonable rates. These results are
outlined in Section IX.C of this Attachment FF and described in more detail below.
iv. Mitigation Responsibilities and Steps
Pursuant to Order No. 1000 (at P 344), the Tariff has been revised to provide that, if a
violation of a NERC reliability standard would result from a transmission developer’s decision to
abandon a transmission facility, then: (i) the incumbent Transmission Owner does not have the
obligation to construct the nonincumbent’s project; and (ii) MISO will coordinate with the
impacted Transmission Owner(s) to develop a mitigation plan to address the violation. 240
Pursuant to the clarification in Order No. 1000-A (at P 480-81), MISO has also included
Tariff provisions clarifying the mitigation actions required where a transmission developer’s
failure to complete a project in a timely manner may result in reliability violations. Such
responsibilities include, but are not limited to, the development of an updated project
implementation plan, an operating procedure to maintain near term reliability, an alternative
project to mitigate the reliability violation, and/or developer reassignment. MISO will support
and coordinate with the affected Transmission Owner(s) when such mitigation plans are
needed.241
a. Project Cancellation
In order to ensure just and reasonable rates, MISO will evaluate cost increases in projects
driven by economic benefits to ensure that the project will still provide sufficient value to justify
its continued construction. In a situation where cost increases cause the overall benefit-cost ratio
to decrease to the point where a project will no longer bring value greater than its costs, MISO
may cancel the project. Prior to the cancellation of any project, MISO will evaluate the project
to determine that its cancellation will not cause reliability concerns, and MISO will document
any additional benefits, such as public policy needs, that may justify the continuation of the
project.242
Additionally, this economic-based reevaluation, in conjunction with the developer
reassignment provisions described below, will also allow MISO to ensure that the costs
submitted with the developer proposals were developed through a robust process that resulted in
240
Section IX.C.3 of Attachment FF.
241
Section IX.C.3 of Attachment FF.
242
Section IX.C.2 of Attachment FF.
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reasonable estimates, as a subsequent change in cost may lead to the project cancellation and/or
the developer reassignment.
b. Developer Reassignment
The goal of the MISO selection process is to ensure that the transmission developer who
is most efficiently able to implement, operate, maintain, and restore a given transmission project
is selected. However, circumstances may occur during the project implementation in which a
selected transmission developer is unable to implement the project as directed by MISO, or it
becomes clear that once implemented, the developer may be unable to operate, maintain, or
restore the transmission line for which they were selected. In this instance, the MISO process
must quickly replace the selected transmission developer to ensure that the transmission project
is implemented in a timely manner.243
In instances where the selected transmission developer is unable to fulfill the
responsibilities outlined in its transmission proposal and the MISO Tariff, MISO will first offer
the transmission project to the incumbent Transmission Owner. This offer will allow an
expedited in-service date for the transmission project, as it allows the incumbent Transmission
Owner to draw upon its local experience to implement the project in the most efficient manner
possible. It also avoids the delay that additional rounds of the developer selection process would
entail.
In the event that the incumbent Transmission Owner is unable or uninterested in
completing the transmission project, MISO will assign the transmission project to a new
transmission developer through the implementation of the MISO developer selection process
described in Section VIII of Attachment FF. This assignment will be accompanied by an
evaluation of the project to ensure that the delay induced by developer reassignment does not
create reliability concerns. If it is determined that the project’s delay may harm system
reliability, a mitigation plan will be developed to clarify the mitigation actions and
responsibilities. Such actions and responsibilities may include, but are not limited to, the
development of an updated project implementation plan, an operating procedure to maintain
near-term reliability, an alternative project to mitigate the reliability violation, and/or developer
reassignment. MISO will support and coordinate with the affected Transmission Owner(s) when
such mitigation plans are needed.244
243
Section IX.C.1 of Attachment FF.
244
Section IX.C.3 of Attachment FF.
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III.
SUPPORTING DOCUMENTS
In addition to this Transmittal Letter, the following documents are being submitted with
this filing:
Tab A – Redlined Version of Tariff Sheets
Tab B – Clean Version of Tariff Sheets
Tab C – Testimony of Jennifer K. Curran
IV.
PROPOSED EFFECTIVE DATE AND REQUEST FOR EXTENDED COMMENT
PERIOD
MISO respectfully requests that the proposed Tariff revisions be made effective on
June 1 of the calendar year after the Commission issues an order accepting the proposed Tariff
revisions.
In addition, the Filing Parties respectfully request that the Commission provide an
extended period for parties to file comments on this filing until December 24, 2012. Given the
complexity, extent, and importance of the proposed Tariff changes, the Filing Parties believe an
extended comment period is appropriate to permit all interested parties adequate opportunity to
analyze and submit comments on the proposed Tariff changes.
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V.
CORRESPONDENCE AND COMMUNICATIONS
Correspondence and communications with respect to this filing should be sent to the
following persons, who shall also be authorized to receive notice in this docket:
Matthew R. Dorsett*
Attorney
Midwest Independent Transmission
System Operator, Inc.
P.O. Box 4202
Carmel, IN 46082-4202
Telephone: 317-249-5299
Fax: 317-249-5912
mdorsett@misoenergy.org
Daniel M. Malabonga*
Bryan M. Likins
Venable LLP
575 7th Street, N.W.
Washington, D.C. 20004
Telephone: 202-344-4508
Fax: 202-344-8300
dmmalabonga@venable.com
Attorneys for MISO
Wendy N. Reed*
Matthew J. Binette*
Wright & Talisman, P.C.
1200 G Street, N.W., Suite 600
Washington, DC 20005-3802
Telephone: (202) 393-1200
Fax: (202) 393-1240
reed@wrightlaw.com
binette@wrightlaw.com
Attorneys for the
MISO Transmission Owners
*Person authorized to receive official service.
VI.
NOTICE AND SERVICE
MISO notes that it has served a copy of this filing electronically, including attachments,
upon all persons listed on the Commission’s service list for the above-referenced proceeding,
Tariff Customers, MISO Members, Member representatives of Transmission Owners and NonTransmission Owners, MISO Advisory Committee participants, as well as all state commissions
within the Region, and the Organization of MISO States. In addition, the filing has been posted
at https://www.misoenergy.org/Library/FERCFilingsOrders/Pages/FERCFilings.aspx, on
MISO’s website, for other interested parties in this matter.
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VII.
CONCLUSION
MISO respectfully requests that the Commission accept this filing, and the proposed
Tariff and Owners Agreement revisions, as compliant with the requirements of Order Nos. 1000
and 1000-A as discussed above.
Sincerely,
/s/ Matthew R. Dorsett
Matthew R. Dorsett
Attorney
Midwest Independent Transmission
System Operator, Inc.
/s/ Daniel M. Malabonga
Daniel M. Malabonga
Bryan M. Likins
Venable LLP
Attorneys for MISO
/s/ Wendy N. Reed
Wendy N. Reed
Matthew J. Binette
Wright & Talisman, P.C.
Attorneys for the MISO Transmission Owners
/Attachments
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Tab A
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1.49a Binding Proposal Agreement Version: 0.0.0 Effective: 12/31/9998
An agreement that must be signed by an officer or equivalent official of a New Transmission
Proposal Applicant with the authority to bind the latter; that must be submitted with each New
Transmission Proposal; and that binds the New Transmission Proposal Applicant to the terms of
the New Transmission Proposal and the Transmission Proposal Request, and the applicable
requirements of this Tariff. The Binding Proposal Agreement shall be included as an appendix
to the Transmission Proposal Request.
1.109a Cure Period Version: 0.0.0 Effective: 12/31/9998
A period of time, equal to ten (10) business days, allowed for a New Transmission Proposal
Applicant to correct deficiencies identified by the Transmission Provider in a previously
submitted New Transmission Proposal. The Cure Period commences upon notification of
deficiencies in the New Transmission Proposal by the Transmission Provider.
1.419 Midwest ISO Transmission Expansion Plan (MTEP): Version: 1.0.0.0 Effective:
12/31/99987/28/2010
A long range plan used to identify expansions or enhancements to the Transmission System to:
i) support efficiencycompetition in bulk power markets; ii) facilitate compliance with
documented federal and state energy laws, regulatory mandates, and regulatory obligations; and
iii) and to maintain reliability. The MTEP is, developed biennially or more frequently, and
subject to review and approval by the Transmission Provider Board. The MTEP shall address
Transmission Issues including, but not necessarily limited to: i) Transmission Issues include:
transmission needs identified from Facilities Studies; ii) Transmission Issuestransmission needs
associated with Generator Interconnection Projects; iii) Transmission Issuesthe transmission
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needs identified by the Transmission Owners; iv) Transmission Issues identified by the
Transmission Provider working in collaboration with Transmission Owners, their state and local
regulatory commissions and other stakeholders; and v)and the transmission planning obligations
of a Transmission Owner and/or the Transmission Provider, imposed by federal or state law(s),
regulations,) or regulatory authorities. The MTEP shall also consider theinclude planning needs
and drivers ofrequirements with representatives from adjacent regional transmission
organizations (“RTOs”) and other transmission planning regionsproviders to develop long-term
inter-regional plans for the benefit of the combined regions, as and to the extent provided for in
joint agreements between the Transmission Provider and other RTOs, and/or in their respective
tariffsregional transmission organizations.
1.454a New Substation Facility Version: 0.0.0 Effective: 12/31/9998
A transmission substation that does not yet exist and that is proposed within a specific Open
Transmission Project as an electrical substation to be implemented, owned, operated, maintained,
and restored by a Selected Transmission Developer, containing equipment or components
classified as transmission plant. New Substation Facilities do not include upgrades,
modifications and/or expansions to existing substations owned by Transmission Owners that
contain equipment or components classified as transmission plant, where such upgrades,
modifications and/or expansions include but are not limited to: i) expanding or upgrading
facilities within the substation footprint, ii) expanding the substation footprint within the current
site boundaries or iii) procuring additional land adjacent to or near the existing substation site
and expanding the substation footprint into or adding substation facilities on the additional land.
New Substations Facilities also do not include newly constructed transmission substations where
all transmission lines terminating at such substation are owned by an incumbent Transmission
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Owner as further described in Section VIII.C of Attachment FF of the Tariff.
1.455a New Transmission Facility Version: 0.0.0 Effective: 12/31/9998
A New Transmission Line Facility or New Substation Facility.
1.455b New Transmission Line Facility Version: 0.0.0 Effective: 12/31/9998
An entire transmission line or section thereof, containing one or more transmission circuits, that
does not exist prior to the construction of an associated Open Transmission Project as a facility
classified as overhead or underground transmission line plant, and that is proposed within an
associated Open Transmission Project as a transmission line to be implemented, owned, operated
and maintained by a Selected Transmission Developer. New Transmission Line Facilities do not
include upgrades, modifications and/or expansions to existing transmission facilities, as further
described in this Section VIII.C of Attachment FF of the Tariff.
1.455c New Transmission Proposal Version: 0.0.0 Effective: 12/31/9998
A proposal to construct, implement, own, operate, maintain, repair, and restore all New
Transmission Facilities associated with an Open Transmission Project, in response to a
Transmission Proposal Request. Each proposal is considered to be a firm offer of the New
Transmission Proposal Applicant to, at a minimum, perform the following acts if the proposal is
selected: (i) construct, own, operate, maintain, repair and restore the New Transmission
Facility(ies) within the scope of the Open Transmission Project in accordance with the Binding
Proposal Agreement, as well as applicable laws, regulations and standards; (ii) execute the ISO
Agreement; (iii) register with the North American Electric Reliability Corporation (NERC) as
the transmission owner (TO), transmission operator (TOP), transmission planner (TP), and if
applicable, the Local Balancing Authority (LBA) for all New Transmission Facilities associated
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with the Open Transmission Project; and (iv) either execute the Balancing Authority Agreement
and assume the role of LBA for all New Transmission Facilities associated with the Open
Transmission Project or contract with an interconnecting LBA and demonstrate to the
satisfaction of the Transmission Provider and per agreement by the LBA that applicable LBArelated tasks associated with the proposed New Transmission Facilities that are delegated to an
LBA by the Balancing Authority Agreement will be carried out either by the LBA or the
Selected Transmission Developer as required and accepted by FERC.
1.455d New Transmission Proposal Applicant Version: 0.0.0 Effective: 12/31/9998
An entity that submits a New Transmission Proposal in response to a Transmission Proposal
Request.
1.463c Non-owner Member Version: 0.0.0 Effective: 12/31/9998
Non-owner Member as defined in the ISO Agreement.
1.474a OMS Committee Version: 0.0.0 Effective: 12/31/9998
OMS Committee shall be the committee that is composed of members of the Organization of
MISO States, established pursuant to the bylaws of the Organization of MISO States, having the
responsibilities and rights defined in Section I.B of Attachment FF of the Tariff and associated
Business Practices Manual. The OMS Committee has the opportunity to provide input into the
transmission planning, resource adequacy, and transmission cost allocation approach and
processes, and may report periodically to the Transmission Provider Board. To enable it to
exercise the authority described herein, the OMS Committee will be adequately supported by the
Transmission Provider either through reasonable in-kind services or through the provisions of
reasonable funding.
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1.477a Open Transmission Project Version: 0.0.0 Effective: 12/31/9998
A Market Efficiency Project or Multi-Value Project contained in MTEP Appendix A that has
been approved by the Transmission Provider Board and may contain one or more New
Transmission Facilities, subject to Section VIII.A of Attachment FF of this Tariff.
1.528a Qualified Transmission Developer Version: 0.0.0 Effective: 12/31/9998
A New Transmission Proposal Applicant that meets the minimum requirements outlined in a
Transmission Proposal Request and Section VIII of Attachment FF of the Tariff to construct,
implement, own, operate, maintain, repair, and restore New Transmission Facilities.
1.599a Selected Transmission Developer Version: 0.0.0 Effective: 12/31/9998
The Qualified Transmission Developer selected by the Transmission Provider or the applicable
state(s) to construct, implement, own, operate, maintain, repair and restore one or more New
Transmission Facilities, pursuant to Attachment FF of this Tariff.
1.671b Transmission Proposal Request Version: 0.0.0 Effective: 12/31/9998
An invitation, including associated requirements, posted by the Transmission Provider on its
website, to submit a New Transmission Proposal.
1.679 Transmission System: Version: 21.0.0 Effective: 12/31/99987/28/2010
The transmission facilities owned or controlled by Transmission Ownersentities that have
conveyed functionaloperational control to the Transmission Provider, and that are used to
provide Transmission Service under Module B of this Tariff. The Transmission System includes
transmission facilities owned or controlled by Transmission Owners, the functionaloperational
control of which has been transferred to the Transmission Provider subject to Commission
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approval under Section 203 of the Federal Power Act. In addition, the Transmission System
includes other transmission facilities owned or controlled by the Transmission Owner that are
booked to transmission accounts andthat are not controlled or operated by the Transmission
Provider but are facilities that the Transmission Owners, by way of the Agency Agreement, have
allowed the Transmission Provider to use in providing service under this Tariff. While not part
of the Transmission System, service over Distribution Facilities is available through the
execution of a Service Agreement pursuant to Schedule 11 of this Tariff. The term Transmission
System shall include the Transmission System (Michigan).
1.692a Variance Analysis Version: 0.0.0 Effective: 12/31/9998
Additional analysis performed by the Transmission Provider planning staff on an approved Open
Transmission Project regarding its scope and schedule when certain circumstances or events
significantly affect the Open Transmission Project. Additional analysis performed by the
Transmission Provider planning staff regarding the Selected Transmission Developer when
certain circumstances or events significantly affect the Selected Transmission Developer.
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ATTACHMENT FF Transmission Expansion Planning Protocol
Version: 78.0.0 Effective: 12/31/9998
ATTACHMENT FF
TRANSMISSION EXPANSION PLANNING PROTOCOL
I.
Transmission Expansion Plan - Purpose and Scope, Definition and Role of OMS
Committee: This Attachment FF describes the process to be used by the Transmission Provider
to develop the Midwest ISO Transmission Expansion Plan (“MTEP”), subject to review and
approval by the Transmission Provider Board. The provisions of this Attachment FF are
consistent with the applicable provisions of Appendix B of the ISO Agreement and this Tariff.
For purposes of this Attachment FF, all references to Transmission Owner(s) will include ITC(s).
The costs incurred by the Transmission Provider in the performance of data collection, analyses
and review, and in the development of the MTEP report, costs incurred under Section I.B of this
Attachment FF, and costs incurred under Section I.C of this Attachment FF shall be recovered
from all Transmission Customers under Schedule 10 of the Tariff.
A.
Enrollment Process: The MTEP is developed to facilitate the timely and orderly
expansion of and/or modification to the Transmission System to maintain reliability, promote
efficiency in bulk power markets and facilitate compliance with applicable Federal and state
laws, regulatory mandates and regulatory obligations. Any transmission provider that wishes to
enroll in the Transmission Provider planning process for purposes of Order No. 1000 compliance
must become a Transmission Owner, by signing the ISO Agreement, and by, within a reasonable
period of time: (1) turning over functional control of its transmission facilities to the
Transmission Provider; and (2) taking service under this Tariff for all its load that is physically
located within the geographic area comprising the Transmission System. All Transmission
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Owners enrolled in the Transmission Provider’s transmission planning region are listed in either
(1) Attachment FF-4 of this Tariff, for Transmission Owners without a separately filed local
planning process or (2) Attachment FF-5 of this Tariff, for Transmission Owners with a
separately filed local planning process.
B.
OMS Committee Input to MTEP Process: To the extent not otherwise
specifically addressed in other portions of this Attachment FF, with respect to the MTEP process,
the OMS Committee may provide input to the Transmission Provider planning staff and the
System Planning Committee of the Transmission Provider Board, as appropriate, regarding the
following:
1.
At the start of a planning cycle, the OMS Committee may suggest to the
Transmission Provider Board modifications to the Transmission Provider’s
planning principles and planning objectives for that planning cycle;
2.
At the start of a planning cycle, the OMS Committee may suggest additional
scope elements in the MTEP;
3.
Modeling inputs or assumptions used in the development of the MTEP and related
appropriate cost/benefit analyses with respect to certain projects that are not
proposed strictly for reliability; and
4.
Concerns about general or specific issues with the MTEP process as they arise
during the planning year.
Furthermore, at the end of the MTEP development process, but before the MTEP is submitted to
the Transmission Provider Board for its review, the OMS Committee may submit a
reconsideration request to the Transmission Provider planning staff, which shall respond prior to
submitting the final MTEP report to the Transmission Provider Board. This reconsideration
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request can be made only with respect to Network Upgrades eligible to receive regional cost
allocation under Attachment FF if such projects: (1) will be recommended to the Transmission
Provider Board for MTEP Appendix A approval, but have not been considered through the
complete MTEP process or (2) will have a change in project cost of twenty-five percent (25%) or
greater between the final Subregional Planning Meeting in the current planning year and the
project being submitted to the Transmission Provider Board for approval. The Transmission
Provider shall consider such a reconsideration request only if it is endorsed by the OMS acting
by a vote of sixty-six percent (66%) or more of the OMS members.
At the end of each MTEP cycle, the OMS Committee may submit its assessment of the MTEP
process to the Planning Advisory Committee, Transmission Provider, and the System Planning
Committee of the Transmission Provider Board. Upon receipt of any such assessment from the
OMS Committee, the Transmission Provider planning staff shall provide an appropriate response
in a reasonably timely manner.
The manner in which the OMS Committee shall provide its assessment shall be set forth in the
Transmission Planning Business Practices Manual procedures. The general procedures adopted
with respect to the OMS Committee input into the MTEP shall remain unchanged until June 1,
2015, unless otherwise mutually agreed to by the Transmission Provider and the OMS
Committee. Changes to the Transmission Planning Business Practices Manual procedures which
describe OMS Committee input into the MTEP process may not be adopted with less than sixty
(60) days’ notice to the OMS Committee unless the OMS Committee consents to such earlier
adoption. At the end of the two year period the Transmission Provider, the OMS, and other
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stakeholders will assess the success of the input procedures and provide suggestions for
improvement.
AC.
Development of the MTEP: The Transmission Provider, working in
collaboration with representatives of the Transmission Owners, OMS, and the Planning Advisory
Committee, shall develop the MTEP, consistent with Good Utility Practice and taking into
consideration long-range planning horizons, as appropriate. The Transmission Provider shall
develop the MTEP for expected use patterns and analyze the performance of the Transmission
System in meeting both reliability needs and the needs of the competitive bulk power market,
under a wide variety of contingency conditions. The MTEP will give full consideration to the
needs of all Market Participants, will include consideration of demand-side options, and will
identify expansions or enhancements needed to i) support competition and efficiency in bulk
power markets; ii) comply with Applicable Laws and Regulations; and iii) and in maintaining
reliability. This analysis and planning process shall integrate into the development of the MTEP
among other things:
(i) the Transmission Issues identified from Facilities Studies carried out in connection
with specific transmission service requests; (ii) Transmission Issues associated with
generator interconnection service; (iii) the Transmission Issues, including proposed
transmission projects, identified by the Transmission Owners in connection with their
planning analyses in accordance with local planning process described in Section I.B.1.a
to this Attachment FF and the coordination processes of Section I.B.1.b., or developed by
Transmission Owners utilizing their own FERC-approved local transmission planning
process described in Section I.B.2, as applicable, to provide reliable power supply to their
connected load customers and to expand trading opportunities, better integrate the grid
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and alleviate congestion; (iv) the transmission planning obligations of a Transmission
Owner, imposed by federal or state law(s) or regulatory authorities, which can no longer
be performed solely by the Transmission Owner following transfer of functional control
of its transmission facilities to the Transmission Provider; (v) plans and analyses
developed by the Transmission Provider to provide for a reliable Transmission System
and to expand trading opportunities, better integrate the grid and alleviate congestion; (vi)
the identification, evaluation, and analysis of expansions to enable the Transmission
System to fully support the simultaneous feasibility of all State 1A ARRs; (vii) the inputs
provided by the Planning Advisory Committee; and (viii) the inputs, if any, provided by
the state and local regulatory authorities having jurisdiction over any of the Transmission
Owners; and by(ix) the inputs of the OMS Committee.
1.
Planning Cycle and Milestones: The ISO Agreement requires that a
regional transmission plan be developed biennially or more frequently. A typical
MTEP development cycle of 12 to 24 month duration is performed continuously.
An MTEP planning cycle is established for each calendar year. The development
of the MTEP for a planning cycle with a given calendar year designation begins
on June 1 of the year prior to the MTEP calendar year designation and ends with
the approval of the final MTEP report by the Transmission Provider Board. This
approval typically occurs at the Transmission Provider Board Meeting in
December of the MTEP designated year. For example, the development of the
MTEP14 transmission plan will commence on June 1 of 2013 and typically end
with approval in December 2014. The development of the MTEP will follow
specified process steps that are detailed, including process diagrams, in the
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Transmission Provider’s Transmission Planning Business Practices Manual
(“TPBPM”). The TPBPM shall be posted on the website of the Transmission
Provider.
a.
Planning Functions: The planning process includes the following
functions which are described in detail in the TPBPM:
i.
Model Development;
ii.
Generator Interconnection Planning;
iii.
Transmission Service Planning;
iv.
Cyclical Regional Expansion Planning activities;
v.
Coordinated System Plans with other RTOs/regions;
vi.
System Support Resource (“SSR”) Studies for unit decommissioning;
vii.
Transmission-to-Transmission Interconnections;
viii.
Load Interconnections; and
ix.
Focus Studies. These are studies initiated during the
cyclical baseline planning process that cannot be delayed
until the next planning cycle (for example, NERC/FERC
directives, or near-term critical operational issues).
Each of these planning functions may develop system expansions that are taken
into consideration in developing the entirety of the MTEP.
b.
Planning Cycle: The regional planning process is performed
through a continuous series of planning cycles, with each cycle typically
addressing Transmission Issues through a rolling planning horizon. Each
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cycle commences with regional model development, and identification of
potential expansions from the local planning processes of the
Transmission Owners, and concludes with recommendations to the
Transmission Provider Board of Directors of recommended solutions to
identified Transmission Issues. Transmission Owner plans developed
through local planning processes described in Section I.B.1.a are included
in the beginning of each regional planning cycle as potential alternatives
to local Transmission Issues identified by the Transmission Owners.
The regional planning process evaluates, with stakeholder input
throughout the cycle, the local plans of the Transmission Owners, as one
input to the development of the regional plan. Key milestones in the
typical MTEP development process are listed below and requirements and
timelines for data submittal, review, and comment at each of these
milestone points are described in the TPBPM:
i.
Model development;
ii.
Testing models against applicable planning criteria;
iii.
Development of possible solutions to identified
Transmission Issues;
iv.
Selection of preferred solution;
v.
Determination of funding and cost responsibility; and
vi.
Monitoring progress on solution implementation.
The Transmission Provider shall address each of these milestones
throughout the planning cycle through Sub-regional Planning Meetings,
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Planning Subcommittee and Planning Advisory Committee meetings.
2.
Stakeholders Input in Planning Process: The Transmission Provider shall
facilitate discussions with its Transmission Customers, Transmission Owners,
OMS Committee, and other stakeholders, the Transmission Owners about the
Transmission Issues and solutions involving both transferred and non-transferred
facilities, as described in Section I.B.1 of this Attachment FF.
These discussions will take place at Sub-regional Planning Meetings and at
regularly scheduled meetings of the Transmission Provider’s Planning
Subcommittee, at locations provided by the Transmission Provider and with
communication capabilities for those participants unable to have in person
representation at these meetings. Once the MTEP report for a specific planning
cycle has been completed but prior to recommendation to the Transmission
Provider Board for approval, the Transmission Provider shall seek feedback on
the proposed MTEP, including Network Upgrades recommended for approval,
from the Transmission Provider’s stakeholders and the OMS Committee.
a.
Planning Advisory Committee (“PAC”): The Planning Advisory
Committee is a standing committee reporting to the Transmission
Provider’s Advisory Committee, and functions subject to the Stakeholder
Governance Guide developed by the Stakeholder Governance Working
Group, as approved by the Advisory Committee. The PAC is responsible
for addressing planning policy issues of importance to stakeholders and
within the responsibilities of the Transmission Provider. The PAC charter
is maintained on the Transmission Provider’s website.
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b.
Planning Subcommittee (“PS”): The Planning Subcommittee is a
standing stakeholder-chaired subcommittee of the Planning Advisory
Committee, and functions subject to the Stakeholder Governance Guide
developed by the Stakeholder Governance Working Group, as approved
by the Advisory Committee. Planning Subcommittee membership is open
to interested parties, including, but not limited too: transmission delivery
service and interconnection service customers, marketers, developers,
Transmission Owners, state and local regulatory authorities, federal
regulatory staff, and other Market Participants, and observersall interested
parties. The charter for the committee is developed by stakeholders and is
maintained on the Transmission Provider’s website. The Transmission
Provider will seek guidance from Transmission Owners, state and local
regulatory authorities, and other stakeholders through the Planning
Subcommittee and/or the Planning Advisory Committee prior to the
beginning of each new planning cycle. Guidance will include the scope of
planning studies to be undertaken, the development of future scenarios to
be modeled and analyzed in long-term planning studies, and the
development of suitable models and assumptions to support such studies.
The Transmission Provider will also seek guidance from Transmission
Owners, state and local regulatory authorities, and other stakeholders
through the Planning Subcommittee and/or the Planning Advisory
Committee prior to implementing changes or revisions to the scope,
models, and assumptions during the planning cycle. The Planning
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Subcommittee and/or the Planning Advisory Committee may form
working groups at the discretion of stakeholders to perform specific tasks
supporting the planning processes, such as model development and detail
review of study results and draft plan reports.
c.
Sub-regional Planning Meetings (“SPMs”): The Transmission
Provider shall utilize SPMs to provide opportunity for Transmission
Owners, state and local regulatory authorities, and other stakeholders to
provide input to the planning process, and to carry out the tasks of
coordinating transmission plans among the Transmission Owners. Input
and planned coordination may occur through the use of existing subregional planning groups (“SPGs”) where they exist, or through the
establishment of new sub-regional meeting forums. One or more SPMs
will be used or established for each of the three regional Planning Subregions of the Transmission Provider. Planning Sub-regions shall be
defined based upon the Transmission Provider Planning Sub-regions:
West, Central, and East as defined in Attachment FF-3.
i)
SPM Participants: Participants at an SPM will consist of
representatives of the Transmission Owners operating within the
associated Planning Sub-region that integrate their local planning
processes with the regional process, and anyrepresentatives from
state and local regulatory authorities, and any other parties
interested in or impacted by the planning process. For those
Transmission Owners engaged in local planning under their own
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FERC approved local planning processes, such Transmission
Owners shall participate in the SPM in order to coordinate their
planning activities.
Neighboring transmission-owning utilities and regulatory
participants are eligible and encouraged to participate in the SPM
to promote joint planning between the Transmission Provider and
neighboring transmission systems.
ii)
SPM Guidelines. The Sub-regional Planning Meeting
participants shall:
(a)
Make recommendations for a coordinated sub-
regional Plan, after considering sub-regional and regional
needs and alternatives, for the ensuing ten years, for all
transmission facilities in the sub-region;
(b)
Review and comment on proposed Transmission
Owners plans identified in local planning processes
described in Section I.B.1.a. of this Attachment FF, for
additions and modifications to the sub-regional
transmission system, as potential solutions to identify
Transmission Issues and review the transmission plans
developed by those Transmission Owners that have their
own FERC-approved local planning process (described in
Section I.B.2) to ensure coordination of the projects set
forth in such plans with the potential regional planning
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solutions developed in the SPM process consistent with the
requirements of Appendix B of the Transmission Owners’
Agreement;
(c)
Form technical study task forces as required to carry
out the sub-regional planning responsibilities;
(d)
Encourage non-Transmission Provider member
participation to improve understanding by the SPM
participants, the Planning Subcommittee, and the
Transmission Provider staff of facility changes outside the
Transmission Provider Region to ensure the impact of such
changes are considered in the planning studies;
(f)
Promote other stakeholder (i.e. regulators,
environmental agencies, and load and generation
developers) involvement in development of the subregional plans.
(g)
Recommend to the Planning Subcommittee
proposed sub-regional plans to be included in the MTEP.
In addition, the transmission projects developed by any
Transmission Owner or Owners utilizing the provisions of
their own FERC-approved local planning process shall be
submitted for inclusion in the regional MTEP after being
evaluated by the Transmission Provider in the regional
evaluation of SPMs in accordance with Appendix B of the
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Transmission Owners’ Agreement in determining the
Transmission Provider’s recommendation for inclusion in
the MTEP.
(h)
Reflect, as desired, minority opinions to the
Transmission Provider or the Planning Subcommittee.
i)
SPM Frequency, Location and Agenda:
SPMs should meet at least two times per year or as
otherwise provided for in the TPBPM, to provide
input in the planning process, review plans and
recommend changes, if any, needed to address
stakeholder needs and to coordinate proposed plans.
Meetings involving CEII or confidential materials
shall be handled under Section I.A.12 of this
Attachment FF.
3.
Meeting Notifications: Notice shall be provided by way of email exploder
lists distribution by the Transmission Provider of all SPMs, Planning
Subcommittee, and Planning Advisory Committee meetings. These email
exploder lists are established and maintained by the Transmission Provider and it
is the responsibility of stakeholders to have registered as described on the
Transmission Provider website. Meeting dates, times, locations, and materials
will also be posted on the meeting calendar page of the Transmission Provider’s
website. Meeting notification guidelines are set forth in the stakeholder
developed Stakeholder Governance Guidelines.
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4.
Other Meeting Schedules: Planning Subcommittee meetings are regularly
scheduled meetings that occur no less than bimonthly. Annual meeting schedules
and objectives are developed at the December meeting each year for the
subsequent year. Planning Advisory Committee meetings are scheduled as per
the PAC Charter.
5.
Planning Criteria: The Transmission Provider shall evaluate the system to
address Transmission Issues in a manner consistent with the ISO Agreement and
this Attachment FF. Projects included in the MTEP may be based upon any
applicable planning criteria, including accepted NERC reliability standards and
reliability standards adopted by Regional Entities, local planning reliability or
economic planning criteria of the Transmission Owner, or required by State or
local authorities, and any economic or other planning criteria or metrics defined in
this Attachment FF. Transmission Owners are required to annually provide
updated copies of local planning criteria for posting on the Transmission
Provider’s website.
The Transmission Provider will post on its website an explanation of
which transmission needs driven by public policy requirements will be evaluated
for potential solutions in the local or regional transmission planning process, as
well as an explanation of why other suggested potential transmission needs will
not be evaluated.
6.
Planning Analysis Methods: Planning analyses performed by the
Transmission Provider will test the Transmission System under a wide variety of
conditions as described in Section II and using standard industry applications to
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model steady state power flow, angular and voltage stability, short-circuit, and
economic parameters, as determined appropriate by the Transmission Provider to
be compliant with applicable criteria and this Tariff.
7.
Planning Models: The Transmission Provider shall collaborate with
Transmission Owners, other transmission providers, Transmission Customers, and
other stakeholders to develop appropriate planning models that reflect expected
system conditions for the planning horizon. The planning models shall reflect the
projected Load growth of existing Network Customers and other transmission
service and interconnection commitments. The models shall include any
transmission projects identified in Service Agreements or Interconnection
Agreements that are entered into in association with requests for transmission
delivery service or interconnection service, as determined in Facilities Studies
associated with such requests. Load forecasts applied to models will consider the
forecast Load of Network Customers reported to the Transmission Provider in
accordance with the requirements of Module B and Module E of this Tariff, and
the Business Practices Manuals of the Transmission Provider. Models will be
posted on an FTP site maintained by the Transmission Provider and accessible to
stakeholders with security measures as provided for in the TPBPM. The
Transmission Provider will provide an opportunity for stakeholders to review and
comment on the posted models before commencing planning studies.
The schedules for such reviews are maintained in the TPBPM. Stakeholders shall
be afforded opportunities to provide input on Load projections from Tariff
reporting requirements or from Transmission Owner forecasts. After the base line
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forecast and model are established, the Transmission Provider and/or
Transmission Owners may adjust the forecast as necessary on an ad hoc basis
throughout the planning year to address customer requests for new Load
interconnections arising from on-going dialogue with existing and prospective
customers.
8.
Planning Assumptions: Each MTEP report shall list in detail the planning
assumptions upon which the analyses are based. In general, planning analyses
will be based on the following:
a.
Planning Horizons: The MTEP will identify Transmission Issues
for a minimum planning horizon of five years and a maximum planning
horizon of twenty years.
b.
Load: Load demand will generally be modeled by the
Transmission Provider as the most probable (“50/50”) coincident Load
projection for each Transmission Owner’s service territory, for the season
under study. Specific studies may model alternative Load probabilities or
peak Load for areas within a Transmission Owner’s service territory as
dictated by operational and planning experience and/or local planning
criteria, but in any case shall be treated consistently in the planning for
native Load and transmission access requests.
c.
Generation: Planning models of five years or longer will model
generation, taking into consideration applicable planning reserve
requirements, that are: (i) existing and expected to be in existence in the
planning horizon; (ii) not existing but with executed interconnection
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agreements; and (iii) additional generation as determined with stakeholder
input, as necessary to adequately and efficiently meet demand forecasted
through the planning horizon and to facilitate compliance with statutory or
regulatory mandates. The Transmission Provider shall apply a scenario
analysis to determine alternative future generation portfolio possibilities.
Generation portfolio development for planning model purposes will be
developed with input from the Planning Advisory Committee and its
subcommittees, working groups, and task forces. Point-To-Point
Transmission Service and Network Integration Transmission Service
customers will have an opportunity to guide new generation portfolio
development that is reflective of customer future resource plans.
d.
Demand Response Resources: Planning solutions will be based
upon the best available information regarding the expected amount and
location of Load that can be effectively and efficiently reduced by demand
response or energy efficiency programs, as well as the amount of behindthe-meter generation that can reliably be expected to produce Energy that
could impact planning solutions. The Transmission Provider shall
perform and report on sensitivity analyses that indicate the effectiveness of
potential demand response as alternative planning solutions, to the extent
that appropriate methodology for such analyses is developed with
stakeholders and documented in the TPBPM.
e.
Topology: Each planning study will use the best known topology
based upon the most recently approved MTEP. Planning studies will
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include all projects approved by the Transmission Provider Board, and
shall identify, as appropriate, and as detailed in the TPBPM, any system
needs already identified in the most recent approved MTEP.
9.
Evaluation of Alternatives: When the planning analyses, based on the
foregoing principles, identifies Transmission Issues, the Transmission Provider
will consider the inputs from stakeholders derived from the SPM processes, the
inputs from the Planning Subcommittee and the Planning Advisory Committee,
the plans of any Transmission Owner with its own FERC-approved local planning
process, and the MTEP aggregate system analyses against applicable planning
criteria, in determining the solutions to be included in the MTEP and
recommended to the Transmission Provider Board for implementation.
10.
Facility Design: Facility design and system configuration (such as
conductor sizes, transformer design, bus configuration, protection schemes) are
selected by the Transmission Owner, and must be consistently applied by the
Transmission Owner for comparable system service conditions. Comparable
application of system design does not preclude the consideration or selection of
advanced or alternative transmission technology. For New Transmission
Facilities associated with Open Transmission Projects, the Transmission Provider
may provide limitations or requirements regarding facility design when necessary
due to a planning driver or to ensure compatibility with existing transmission
facilities to which the New Transmission Facilities will interconnect as further
described in Section VIII.D of this Attachment FF.
11.
Status of Recommended Facilities: Upon solicitation from the
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Transmission Provider and upon reaching pre-designated milestones in the project
implementation process, the responsible Transmission Owner or Selected
Transmission Developer shall report the status of all projects recommended for
implementation in the MTEP. Status reports shall, at a minimum, include: (i)
changes to the schedule and to the estimated project cost; (ii) an explanation of
the causes of, or reasons for, any such changes; and (iii) changes in project status
(i.e., under construction, in service, or withdrawn). The Transmission Provider
shall report such progress to the Transmission Provider Board on a quarterly
basis, or as otherwise directed by the Transmission Provider Board.
Status of Developer Qualifications: Upon solicitation from the Transmission
Provider and upon reaching pre-designated milestones in the project
implementation process, Selected Transmission Developers shall report the
following: (i) changes to the developer qualifications, as defined in the Binding
Proposal Agreement, including changes in the developer constructing the project;
(ii) an explanation of the causes of, or reasons for, such changes; and (iii) an
assessment of the impact of the changes on the project. The Transmission
Provider shall report such changes and any impact to the Transmission Provider
Board on a quarterly basis, or as otherwise directed by the Transmission Provider
Board.
12.
Treatment of Critical Energy Infrastructure Information (“CEII”) and
Confidential Data: The Transmission Provider shall utilize a Non-Disclosure and
Confidentiality Agreement (“NDA”) to address sharing of CEII transmission
planning information. FTP sites containing such information will require such
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agreements to be executed in order to obtain access to those sites. Stakeholder
meetings at which CEII may be available shall be noticed to email exploders and
shall require execution of NDAs prior to participation in such meetings. In the
alternative, such meetings will be structured to have separate discussion of issues
involving CEII data only with participants that agree to execute the NDA.
Confidential information related to economic (e.g., congestion) studies, as well as
CEII, is clearly sensitive information which must remain confidential. The
Transmission Provider shall use generic, publicly available, cost information from
industry sources in the economic studies to prevent the accidental release of
confidential information. This approach will promote an open planning process
because the results of economic studies are available to all interested parties.
13.
Resolution of Stakeholder Input: The Transmission Provider shall solicit
input and comments from all stakeholders, including Transmission Owners,
during and after stakeholder planning meetings, and will use reasonable efforts to
reply to comments that the Transmission Provider does not elect to implement,
together with reasons for such actions. The Transmission Provider shall develop
a process for the documentation and resolution of stakeholder issues raised in the
planning process, including but not limited to issues related to planning criteria.
14.
Dispute resolution: Consistent with Attachment HH of this Tariff and
Appendix D to the ISO Agreement, the Transmission Provider shall resolve
disputes concerning MTEP issues. The first step will be for designated
representatives of the affected parties to work together to resolve the relevant
issues in a manner that is acceptable to all parties. If that step is unsuccessful,
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each affected party shall designate an officer who shall review disputes involving
them that their designated representatives are unable to resolve. The applicable
officers of the parties involved in such dispute shall work together to resolve the
disputes so referred in a manner that meets the interests of such parties, either
until such agreement is reached, or until an impasse is declared by any party to
such dispute. If such officers are unable to satisfactorily resolve the issues, the
matter shall be referred to mediation, in accordance with the procedures described
in Appendix D to the ISO Agreement. Parties that are not satisfied with the
dispute resolution procedures may only file a complaint with the Commission
during the negotiation or mediation steps.
If a matter remains unresolved, the affected parties may pursue arbitration
pursuant to Appendix D of the ISO Agreement.
BD.
Project Coordination: In the course of the MTEP process, the Transmission
Provider shall seek out opportunities to coordinate or consolidate, where possible, individually
defined transmission projects into more comprehensive cost-effective developments subject to
the limitations imposed by prior commitments and lead-time constraints. The Transmission
Provider shall coordinate with Transmission Owners, and shall consider the input from the
SPMs, Planning Subcommittee, and Planning Advisory Committee to develop expansion plans
to meet the needs of the system. This multi-party collaborative process will allow for all projects
with regional and inter-regional impact to be analyzed for their combined effects on the
Transmission System. Moreover, this collaborative process is designed to ensure that the MTEP
address Transmission Issues within the applicable planning horizon in the most efficient and cost
effective manner, while giving consideration to the inputs from all stakeholders. In addition to
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the requirements of this Attachment FF, there may be state or local procedural requirements
applicable to the planning or siting of transmission facilities by the Transmission Owners. A
current list of those requirements can be found on the Transmission Provider’s website.
1.
Transmission Owners Electing to Integrate their Local Planning Processes into the
Transmission Provider’s Processes: Some Transmission Owners have agreed to integrate
internal planning process with the Transmission Provider’s open and coordinated
planning processes for all of their transmission facilities to comply with Order 890
Planning Principles instead of filing a separate Attachment K. Through this election, the
local planning for all transmission facilities of these Transmission Owners, regardless of
whether the facilities are ultimately transferred to the functional control of the
Transmission Provider, shall be integrated with and included in the regional planning
processes of the Transmission Provider. These regional planning processes, as provided
for in this Attachment FF and in additional detail in the TPBPM, ensure that the planning
decisions for all such facilities are made in an open and transparent environment.
This planning environment provides opportunity for input from, and review by,
stakeholders of the Open Access Transmission Tariff services throughout the planning
process, and is in accordance with the Planning Principles of the Order 890 Final Rule.
The open and transparent planning provisions of this Attachment FF shall not preclude
interaction between stakeholders and Transmission Owners prior to the submittal of
proposed projects to the regional planning process.
Transmission Owners integrating local planning processes into the regional planning
processes are listed in Attachment FF-4. Such Transmission Owners shall be responsible
for providing the Transmission Provider with sufficient information regarding all
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planning activities to enable the Transmission Provider to adequately review and
incorporate all of the Transmission Owner’s transmission facilities into the regional
planning process of the Transmission Provider, as described in Sections I.B.1.a. and
I.B.1.b. of this Attachment FF.
The foregoing Transmission Owners will utilize the planning stakeholder forums of the
Transmission Provider to demonstrate the need for, identify the alternatives to, and report
the status of non-transferred transmission facilities using the same open, transparent and
coordinated planning process provided by the Transmission Provider for transferred
facilities as described in this Attachment FF.
a.
Local Planning Processes of Transmission Owners: In accordance
with the ISO Agreement, each Transmission Owner engages in local
system planning in order to carry out its responsibility for meeting its
respective transmission needs in collaboration with the Transmission
Provider subject to the requirements of applicable state law or regulatory
authority. In meeting its responsibilities under the ISO Agreement, the
Transmission Owners may, as appropriate, develop and propose plans
involving modifications to any of the Transmission Owner’s transmission
facilities which are part of the Transmission System. The Transmission
Owners shall include the following specific local planning steps in order
to develop plans for potential inclusion in the regional plan, in accordance
with the annual regional planning process as described in Section I.B.1.b.
of this Attachment FF, and in accordance with the regional planning
principles of Section I.A of this Attachment. In addition to the local
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planning steps below, Transmission Owners shall adhere to any applicable
state or local regulatory planning processes.
i.
Define local study area and study horizon;
ii.
Develop appropriate power system models;
a)
Utilize existing NERC or Transmission Provider
cases to model external systems;
b)
Insert detailed model of Transmission Owner
system if required;
c)
Insert updated detailed models of neighboring
system models if required; and
d)
iii.
Verify model topology and generation.
Update loads (spatial and magnitude) in study area;
a)
Review historical MW and MVAR data to develop
growth trends;
b)
Obtain Load forecasts from customers in study area;
and
c)
Obtain input from local distribution planners in the
study area.
iv.
Perform contingency analysis using applicable
Transmission Owner planning criteria;
v.
Identify any violations to planning criteria for each of study
period;
vi.
Develop alternative solutions to the criteria violations and
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test against the planning criteria;
a)
Obtain cost estimates for each alternative and
perform economic analyses; and
b)
Determine non-cost attributes of each alternative
such as operating flexibility, robustness, among others.
vii.
Select alternative based on cost and non-cost attributes;
viii.
Submit proposed solution and list of alternatives and
assumptions to the Transmission Provider;
ix.
Participate in stakeholder evaluations and discussions as a
part of annual regional plan development process;
x.
Perform additional analysis as required based on feedback
from stakeholder groups (SPM/PS) in the regional planning
process;
xi.
Submit results of additional analysis (if performed) to the
Transmission Provider for further discussion with stakeholders
(SPM/PS);
xii.
Consider regional planning process results, including
stakeholder feedback on needs, proposed solutions, and
alternatives, in determining whether or not to proceed with
implementation of Transmission Owner proposed expansions; and
xiii.
Post the planning criteria and assumptions, and power flow
models used in development of each Transmission Owner’s current
local planning proposal in accordance with Section I.B.1.b below.
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To the extent that the Transmission Owner uses the Midwest ISO
MTEP models in developing its list of newly proposed projects,
the Transmission Owner shall indicate as per Section I.B.1.b.
below, the associated MTEP model used.
The Transmission Provider will maintain a link to applicable
MTEP models on its website together with instructions for
accessing such models consistent with CEII criteria and suitable
non-disclosure agreements. In the event that the Transmission
Owner applies its own power flow models in developing its
proposed local plans, the Transmission Owner shall provide such
models to the Transmission Provider for posting, or shall provide
to the Transmission Provider a link to the location of such
Transmission Owner model(s) and to instructions for accessing
such models consistent with the Transmission Owner’s CEII and
non-disclosure requirements. Transmission Provider shall post on
its website links to such postings on Transmission Owner’s
website.
b.
Integration of Local Planning Processes of Transmission Owners:
Transmission Owners listed on Attachment FF-4 as integrating local
planning processes with those of the Transmission Provider, shall integrate
proposals for transmission expansions into the regional planning process
as follows. Each Transmission Owner shall submit its proposals for
transmission plans to the Transmission Provider prior to the start of each
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regional planning cycle. Each Transmission Owner’s local plan, which
consists of a list of proposed projects, shall be made available on the
Transmission Provider’s website for review by the PAC, the PS, and the
SPM participants, subject to CEII and the confidentiality provisions in this
Attachment FF. Such local plans shall be posted by September 15 each
year in order to provide time for written comments by stakeholders. In
addition to the list of proposed projects, each Transmission Owner
submitting newly proposed projects by September 15 in any MTEP annual
cycle shall provide to the Transmission Provider by June 1 of the same
year identification of any Midwest ISO base power flow model used by
the Transmission Owner in support of the identification of the list of
proposed projects to be subsequently posted in September, or in the event
that the Transmission Owner uses a non-Midwest ISO base power flow
model in support of the identification of the list of proposed projects the
Transmission Owner shall provide to the Transmission Provider such base
power flow model or a link to the power flow model and assumptions
used.
Each Transmission Owner’s local planning model and associated
assumptions shall be accessible on or through a link on the Transmission
Provider’s website for review, subject to CEII and the confidentiality
provisions in this Attachment FF and consistent with section I.B.1.a. In
the event that the Transmission Owner uses a non-Midwest ISO base
power flow model, the Transmission Owner shall provide for posting
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updates if there are significant changes in the model by July 15, August
15, and September 15 of each year. Comments by stakeholders on the
local planning models and assumptions that are provided to the
Transmission Provider SPM Planning Contact by July 1, or August 1 or
September 1 with respect to updates, shall be forwarded to the applicable
Transmission Owner by July 8, August 8, or September 8, respectively.
The Transmission Provider shall address any unresolved stakeholder
issues through the SPM process.
Each Transmission Owner shall also provide to the Transmission Provider
by June 1 of each year any updates to the posted transmission planning
criteria, or a notification that the posted documents have not changed. In
the event a Transmission Owner has additional significant updates to the
posted transmission planning criteria, the Transmission Owner shall
provide such updates for posting by July 15, August 15, and September 15
of each year.
The Transmission Provider shall post on its website the lists of newly
proposed projects, criteria and assumptions, and supporting base power
flow models or links to supporting base power flow models, as provided
by the Transmission Owners. Initial comments by stakeholders to the
proposed projects should be provided to the Transmission Provider SPM
Planning Contact 45 days after the posting of local plans otherwise
comments may be made pursuant to Section I.A.2.c.ii. The Transmission
Provider SPM Planning Contact shall be identified on the Transmission
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Provider’s web site page devoted to Expansion Planning. The
Transmission Provider shall provide to the applicable Transmission Owner
within five working days of receipt, a copy of all stakeholder comments
received within 45 days of the posted information regarding Transmission
Owner planning criteria and assumptions, models applied, and list of
proposed projects. The Transmission Provider shall address any
unresolved stakeholder issues through the SPM process. Each
Transmission Owner must participate in SPMs in the respective Planning
sub-region as indicated in the Transmission Providers meeting schedule.
Such SPMs shall provide input to and review of the results of the needs
assessments and adequacy of plans proposed by the Transmission Owners,
or by stakeholders to the planning process, or by the Transmission
Provider, to best meet the needs of the sub-region.
Transmission Owners identified in Attachment FF-4, must submit to the
Transmission Provider, on an annual basis and at a time to be determined
by the Transmission Provider, which shall be prior to the beginning of
each regional planning cycle, all proposed transmission plans for both
transferred and non-transferred transmission facilities. The submitted
projects of such Transmission Owners shall be considered potential
alternatives to system needs identified, and as such must be submitted
when initially identified as a potential system solution, in order to permit
the evaluation of such projects along with other potential alternatives that
may be proposed by stakeholders or the Transmission Provider, in the
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SPM processes. Such alternatives may include transmission, generation,
and demand-side resources. The Transmission Provider will review and
evaluate such alternatives on a comparable basis and select the most
appropriate solution. Comparability includes the ability of the
Transmission Provider to obtain contractual assurances that the selected
solution will be implemented by the required in-service dates. Contractual
commitments associated with transmission solutions to be constructedthe
construction of an MTEP Appendix A approved project by Midwest ISO
Transmission Owner(s) and/or Selected Transmission Developer(s) are
provided for by the ISO Agreement, this Tariff, and the Binding Proposal
Agreement.
Contractual commitments associated with generation solutions require that
a generator interconnection agreement be filed with the Commission
pursuant to Attachment X of this Tariff by the time the alternative
transmission solution would need to be committed to in order to ensure
installation on the required need date. Contractual commitments
associated with demand-side resource solutions require demonstration to
the Transmission Provider of an executed contract between LSE and EndUse Customers. Such demand-side contracts must be in place by the time
that the transmission solution would otherwise need to be committed to in
order to ensure a timely solution to the identified planning need, and must
be of a sufficient duration such that a reliable solution can be assured
through the planning horizon. Notwithstanding the provisions of Section
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VII of the ISO Agreement regarding the Transmission Provider review of
Transmission Owner plans, no proposed project of a Transmission Owner
that has elected to integrate their local planning processes into the
Transmission Provider’s processes, as indicated on Attachment FF-4, shall
be recommended in the MTEP for implementation until completion of the
annual needs analysis carried out in the annual MTEP cycle, as described
in Section I. A. of this Attachment FF, except as provided for in Section
I.B.1.c. of this Attachment FF.
c.
Out-of-Cycle Review of Transmission Owner Plans: In the event
that a Transmission Owner determines that system conditions warrant the
urgent development of system enhancements that would be jeopardized
unless the Transmission Provider performs an expedited review of the
impacts of the project, Transmission Provider shall use a streamlined
approval process for reviewing and approving projects proposed by the
Transmission Owners so that decisions will be provided to the Owner
within thirty (30) days of the projects submittal to the Midwest ISO unless
a longer review period is mutually agreed upon.
2.
Transmission Owners Filing Separate Attachment K: Some Transmission
Owners as listed on the last page of Attachment FF-4 have developed individual
open, local planning processes for their facilities, that comply with the Planning
Principles of the Order 890 Final Rule. These Transmission Owners have an
Attachment K that describes how the Transmission Owner will comply with the
Order No. 890 Planning Principles for all transmission facilities that they plan for,
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regardless of whether those facilities are ultimately transferred to the functional
control of the Transmission Provider. With the exception of Sections I.B.1.a and
I.B.1.b., the provisions of this Attachment FF remain applicable to all
Transmission Owners notwithstanding the filing by any Transmission Owner of
an Attachment K pursuant to the Order 890 Final Rule.
CE.
Joint Regional Planning Coordination: The MTEP shall be developed in
accordance with the principles of interregional coordination through collaboration with
representatives from adjacent transmission providers, their designated regional planning
organizations, or regional transmission organizations, as provided for in this Attachment FF, or
as otherwise provided for in existing joint agreements between the Transmission Provider and
other regional entities that engage in planning activities. The Transmission Provider has joint
operating and coordination agreements with MAPPCOR, as contractor for Mid-Continent Area
Power Pool (“MAPP”), the PJM Interconnection (“PJM”), Southwest Power Pool (“SPP”),
Tennessee Valley Authority (“TVA”), and Manitoba Hydro (Manitoba). Because TVA is nonjurisdictional, that agreement has not been submitted for Commission approval, but is available
on the Transmission Provider’s public website.
1.
Initial Contact: The Transmission Provider will initiate a meeting with
representatives of adjacent transmission providers, their designated regional
planning organizations, or regional transmission organizations with which
existing joint agreements are not already established with the Transmission
Provider (“Regional Planning Coordination Entities” or “RPCEs”), in order to
establish a Joint Planning Committee.
2.
Joint Planning Committee. The Transmission Provider shall offer to form
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a Joint Planning Committee (“JPC”) with the RPCE. The JPC shall be comprised
of representatives of the Transmission Provider and the RPCE in numbers and
functions to be identified from time to time. The JPC may combine with or
participate in similarly established joint planning committees amongst multiple
RPCEs or established under joint agreements to which the Transmission Provider
is a signatory, for the purpose of providing for broader and more effective interregional planning coordination. The JPC shall have a Chairman. The Chairman
shall be responsible for: the scheduling of meetings; the preparation of agendas
for meetings; the production of minutes of meetings; and for chairing JPC
meetings. The Chairmanship shall rotate amongst the Transmission Provider and
the RPCEs on a mutually agreed to schedule, with each party responsible for the
Chairmanship for no more than one planning study cycle in succession. The JPC
shall coordinate planning of the systems of the Transmission Provider and the
RPCEs, including the following:
a.
Coordinate the development of common power system analysis
models to perform coordinated system planning studies including power
flow analyses and stability analyses. For studies of interconnections in
close electrical proximity at the boundaries among the systems of the
Transmission Provider and the RPCEs the JPC or its designated working
group will coordinate the performance of a detailed review of the
appropriateness of applicable power system models.
b.
Conduct, on a regular basis, a Coordinated Regional Transmission
Planning Study (CRTPS), as set forth in Section 8.3.4.
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c.
Coordinate planning activities under this Section 8, including the
exchange of data and developing necessary report and study protocols.
d.
Maintain an Internet site and e-mail or other electronic lists for the
communication of information related to the coordinated planning process.
Such sites and lists may be integrated with those existing for the purpose
of communicating the open and transparent planning processes of the
Transmission Provider.
e.
Meet at least semi-annually to review and coordinate transmission
planning activities.
f.
Establish working groups as necessary to address specific issues,
such as the review and development of the regional plans of the RPCE and
the Transmission Provider, and localized seams issues.
g.
Establish a schedule for the rotation of responsibility for data
management, coordination of analysis activities, report preparation, and
other activities.
3.
Data and Information Exchange. The Transmission Provider shall make
available to each RPCE the following planning data and information. Unless
otherwise indicated, such data and information shall be provided annually. The
Transmission Provider shall provide such data in accordance with the applicable
CEII policy, and maintain data and information received from each RPCE in
accordance with their applicable confidentiality policies.
a.
Data required for the development of power flow cases, and
stability cases, incorporating up to a ten year load forecasts as may be
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requested, including all critical assumptions that are used in the
development of these cases.
b.
Fully detailed planning models (up to the next ten (10) years as
requested) on an annual basis and updates as necessary to perform
coordinated studies that reflect system enhancement changes or other
changes.
c.
The regional plan documents, any long-term or short-term
reliability assessment documents, and any operating assessment reports
produced by the Transmission Provider and the RPCE.
d.
The status of expansion studies, system impact studies and
generation interconnection studies, such that the Transmission Provider
and the RPCE have knowledge that a commitment has been made to a
system enhancement as a result of any such studies.
e.
Transmission system maps for the Transmission Provider and the
RPCE bulk transmission systems and lower voltage transmission system
maps that are relevant to the coordination of planning between or among
the systems.
f.
Contingency lists for use in load flow and stability analyses,
including lists of all contingency events required by applicable NERC or
Regional Entity planning standards, as well as breaker diagrams for the
portions of the Transmission Provider and the RPCE transmission systems
that are relevant to the coordination of planning between or among the
systems. Breaker diagrams to be provided on an as requested basis.
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g.
The timing of each planned enhancement, including estimated
completion dates, and indications of the likelihood that a system
enhancement will be completed and whether the system enhancement
should be included in system expansion studies, system impact studies and
generation interconnection studies, and as requested the status of related
applications for regulatory approval. This information shall be provided at
the completion of each planning cycle of the Transmission Provider, and
more frequently as necessary to indicate changes in status that may be
important to the RPCE system.
h.
Quarterly identification of interconnection requests that have been
received and any long-term firm transmission services that have been
approved, that may impact the operation of the Transmission Provider or
the RPCE system.
i.
Quarterly, the status of all interconnection requests that have been
identified.
j.
Information regarding long-term firm transmission services on all
interfaces relevant to the coordination of planning between or among the
systems.
k.
Load flow data initially will be exchanged in PSS/E format. To
the extent practical, the maintenance and exchange of power system
modeling data will be implemented through databases. When feasible,
transmission maps and breaker diagrams will be provided in an electronic
format agreed upon by the Transmission Provider and the RPCE. Formats
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for the exchange of other data will be agreed upon by the Transmission
Provider and the RPCE.
4.
Coordinated System Planning. The Transmission Provider shall agree to
coordinate with the RPCEs studies required to assure the reliable, efficient, and
effective operation of the transmission system. Results of such coordinated
studies will be included in the Coordinated System Plan. The Transmission
Provider shall agree to conduct with the RPCEs such coordinated planning as set
forth below
a.
Single Entity Planning. The Transmission Provider shall engage in
such transmission planning activities, including expansion plans, system
impact studies, and generator interconnection studies, as necessary to
fulfill its obligations under the Tariff. Such planning shall conform to
applicable reliability requirements of NERC, applicable regional reliability
councils, and any successor organizations thereto.
Such planning shall also conform to any and all applicable requirements of
Federal or State regulatory authorities. The Transmission Provider will
prepare a regional transmission planning report that documents the
procedures, methodologies, and business rules utilized in preparing and
completing the report. The Transmission Provider shall agree to share the
transmission planning reports and assessments with each RPCE, as well as
any information that arises in the performance of its individual planning
activities as is necessary or appropriate for effective coordination among
the Transmission Provider and the RPCEs on an ongoing basis. The
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Transmission Provider shall provide such information to the RPCEs in
accordance with the applicable CEII policy and shall maintain such
information received from the RPCEs in accordance with their applicable
confidentiality policies.
b.
Analysis of Interconnection Requests. In accordance with the
procedures under which the Transmission Provider provides
interconnection service, the Transmission Provider will agree to
coordinate with each RPCE the conduct of any studies required in
determining the impact of a request for generator or merchant transmission
interconnection. Results of such coordinated studies will be included in
the impacts reported to the interconnection customers as appropriate.
Coordination of studies shall include the following:
i.
When the Transmission Provider receives a request under
its interconnection procedures for interconnection, it will
determine whether the interconnection potentially impacts
the system of a RPCE. In that event, the Transmission
Provider will notify the RPCE and convey the information
provided in the interconnection queue posting. The
Transmission Provider will provide the study agreement to
the interconnection customer in accordance with applicable
procedures.
ii.
If the RPCE determines that it may be materially impacted
by an interconnection on the Transmission Provider
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System, the RPCE may request participation in the
applicable interconnection studies. The Transmission
Provider will coordinate with the RPCE with respect to the
nature of studies to be performed to test the impacts of the
interconnection on the RPCE System, and who will
perform the studies. The Transmission Provider will strive
to minimize the costs associated with the coordinated study
process undertaken by agreement with the RPCE.
iii.
Any coordinated studies associated with requests for
interconnection to the Transmission Provider’s system will
be performed in accordance with the study timeline
requirements and scope of the applicable generation
interconnection procedures of the Transmission Provider.
iv.
The RPCE may participate in the coordinated study either
by taking responsibility for performance of studies of its
system, if deemed reasonable by the Transmission
Provider, or by providing input to the studies to be
performed by the Transmission Provider. The study cost
estimates indicated in the study agreement between the
Transmission Provider and the interconnection customer,
will reflect the costs, and the associated roles of the study
participants including the RPCE. The Transmission
Provider will review the cost estimates and scope submitted
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by all participants for reasonableness, based on expected
levels of participation, and responsibilities in the study. If
the RPCE agrees to perform any aspects of the study, the
RPCE must comply with the timelines and schedule of the
Transmission Provider’s interconnection procedures.
v.
The Transmission Provider will collect from the
interconnection customer the costs incurred by the RPCE
associated with the performance of such studies and
forward collected amounts, no later than thirty (30) days
after receipt thereof, to the RPCE. Upon the reasonable
request of the RPCE, the Transmission Provider will make
their books and records available to the requestor pertaining
to such requests for collection and receipt of collected
amounts.
vi.
The Transmission Provider will report the combined list of
any transmission infrastructure improvements on either the
RPCE and/or the Transmission Provider’s system required
as a result of the proposed interconnection.
vii.
Construction and cost responsibility associated with any
transmission infrastructure improvements required as a
result of the proposed interconnection shall be
accomplished under the terms of the applicable OATT,
Transmission Service Guidelines, controlling agreements,
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and consistent with applicable Federal or State regulatory
policy and applicable law.
viii.
Each transmission provider will maintain separate
interconnection queues. The JPC will maintain a
composite listing of interconnection requests for all
interconnection projects that have been identified as
potentially impacting the systems of the Transmission
Provider and coordinating RPCEs. The JPC will post this
listing on the Internet site maintained for the
communication of information related to the coordinated
system planning process.
c.
Analysis of Long-Term Firm Transmission Service Requests. In
accordance with applicable procedures under which the Transmission
Provider provides long-term firm transmission service, the Transmission
Provider will coordinate the conduct of any studies required to determine
the impact of a request for such service. Results of such coordinated
studies will be included in the impacts reported to the transmission service
customers as appropriate. Coordination of studies will include the
following:
i.
The Transmission Provider will coordinate the calculation
of ATC values associated with the service, based on
contingencies on their systems that may be impacted by the
granting of the service.
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ii.
When the Transmission Provider receives a request for
long-term firm transmission service, it will determine
whether the request potentially impacts the system of the
RPCE. If the Transmission Provider determines that the
RPCE system is potentially impacted, and that the RPCE
would not receive a transmission service request to
complete the service path, the transmission provider will
notify the RPCE and convey the information provided in
the posting.
iii.
If the RPCE determines that its system may be materially
impacted by granting the service, it may contact the
Transmission Provider and request participation in the
applicable studies. The Transmission Provider will
coordinate with the RPCE with respect to the nature of
studies to be performed to test the impacts of the requested
service on the RPCE system, and will strive to minimize
the costs associated with the coordinated study process.
The JPC will develop screening procedures to assist in the
identification of service requests that may impact systems
of the JPC members other than the transmission provider
receiving the request.
iv.
Any coordinated studies for request on the transmission
Provider’s system will be performed in accordance with the
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study timeline and scope requirements of the applicable
transmission service procedures of the Transmission
Provider.
v.
The RPCE may participate in the coordinated study either
by taking responsibility for performance of studies of its
system, if deemed reasonable by the Transmission Provider
or by providing input to the studies to be performed by the
Transmission Provider. The study cost estimates indicated
in the study agreement between the Transmission Provider
and the transmission service customer will reflect the costs
and the associated roles of the study participants. The
Transmission Provider will review the cost estimates and
scope submitted by all participants for reasonableness,
based on expected levels of participation and
responsibilities in the study.
vi.
The Transmission Provider will collect from the
transmission service customer, and forward to the RPCE,
the costs incurred by the RPCE with the performance of
such studies.
vii.
The Transmission Provider receiving the request will
identify any transmission infrastructure improvements
required as a result of the transmission service request.
viii.
Construction and cost responsibility associated with any
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transmission infrastructure improvements required as a
result of the transmission service request shall be
accomplished under the terms of the applicable OATT,
Transmission Service Guidelines, controlling agreements,
and consistent with applicable Federal or State regulatory
policy and applicable law.
d.
Coordinated Regional Transmission Planning Study: The Transmission
Provider agrees to participate in the conduct of a periodic Coordinated Regional
Transmission Planning Study (CRTPS). The CRTPS shall have as input the
results of ongoing analyses of requests for interconnection and ongoing analyses
of requests for long-term firm transmission service. The Parties shall coordinate
in the analyses of these ongoing service requests in accordance with Sections
8.3.2 and 8.3.3. The results of the CRTPS shall be an integral part of the
expansion plans of each Party. Construction of upgrades on the Transmission
System of the Transmission Provider that are identified as necessary in the
CRTSP shall be under the terms of the Owners Agreement of the Transmission
Provider, applicable to the construction of upgrades identified in the expansion
planning process. Coordination of studies required for the development of the
Coordinated System Plan will include the following:
i.
Every three years, the Transmission Provider shall
participate in the performance of a CRTPS. Sensitivity
analyses will be performed, as required, during the off
years based on a review by the JPC of discrete reliability
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problems or operability issues that arise due to changing
system conditions.
ii.
The CRTPS shall identify all reliability and expansion
issues, and shall propose potential resolutions to be
considered by The Transmission Provider and the
coordinating RPCEs.
iii.
As a result of participation in the CRTPS, except as
provided for in Section II. A. 1., the Transmission Provider
is not obligated in any way to construct, finance, operate, or
otherwise support any transmission infrastructure
improvements or other transmission-related projects
identified in the CRTPS. Any decision to proceed with any
transmission infrastructure improvements or other
transmission-related projects identified in the CRTPS shall
be based on the applicable reliability, operational and
economic planning criteria established for the Transmission
Provider as applicable to the development of the MTEP and
set forth in this Attachment FF.
iv.
As a result of participation in the CRTPS, the RPCEs are
not entitled to any rights to financial compensation due to
the impact of the transmission plans of the Transmission
Provider upon the RPCE system, including but not limited
to its decisions whether or not to construct any transmission
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infrastructure improvements or other transmission-related
projects identified in the CRTPS.
v.
The JPC will develop the scope and procedure for the
CRTPS. The scope of the CRTPSs performed over time
will include evaluations of the transmission systems against
reliability criteria, operational performance criteria, and
economic performance criteria applicable to the
Transmission Provider and the RPCEs.
vi.
In the conduct of the CRTPS, the Transmission Provider
and the coordinating RPCEs will use planning models that
are developed in accordance with the procedures to be
established by the JPC. Exchange of power flow models
will be in a format that is acceptable to the coordinating
parties.
vii.
Stakeholder Review Processes. The Transmission
Provider, in coordination with coordinating RPCEs shall
review the scope and results of the CRTPS with impacted
stakeholders, and shall modify the study scope as deemed
appropriate by the Transmission Provider in agreement
with the coordinating RPCEs, after receiving stakeholder
input. Such reviews will utilize the existing planning
stakeholder forums of the coordinating parties including as
applicable joint Sub Regional Planning Meetings.
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II.
Development Process for MTEP Projects: The Transmission Provider will develop the
MTEP biennially or more frequently. The MTEP will identify expansion projects for inclusion
in the MTEP according to the factors set forth in Appendix B of the ISO Agreement and Section
I.A. of this Attachment FF. For purposes of assigning cost responsibility, expansion projects in
the MTEP shall be categorized pursuant to the following criteria.
A.
Reliability Needs: Reliability projects are identified either in the periodically
performed Baseline Reliability Study, or in Facilities Studies associated with the request
processes for new transmission access. Transmission access includes requests for both new
transmission delivery service and new generation interconnection service.
1.
Baseline Reliability Projects: Baseline Reliability Projects are Network
Upgrades identified in the base case as required to ensure that the Transmission
System is in compliance with applicable national Electric Reliability Organization
(“ERO”) reliability standards and reliability standards adopted by Regional
Reliability Organizations and applicable within the Transmission Provider
Region. Baseline Reliability Projects include projects that are needed to maintain
reliability while accommodating the ongoing needs of existing Market
Participants and Transmission Customers. Baseline Reliability Projects may
consist of a number of individual facilities that in the judgment of the
Transmission Provider constitute a single project for cost allocation purposes.
The Transmission Provider shall collaborate with Transmission Owning
members, other transmission providers, Transmission Customers, and other
stakeholders to develop appropriate planning models that reflect expected system
conditions for the planning horizon. The planning models shall reflect the
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projected load growth of existing network customers and other transmission
service and interconnection commitments, and shall include any transmission
projects identified in Service Agreements or interconnection agreements that are
entered into in association with requests for transmission delivery service or
transmission interconnection service, as determined in Facilities Studies
associated with such requests. The Transmission Provider shall test the MTEP for
adequacy and security based on commonly applicable national Electric Reliability
Organization (“ERO”) standards, and under likely and possible dispatch patterns
of actual and projected Generation Resources within the Transmission System and
of external resources, including dispatch reflective of Long-Term Transmission
Rights of Transmission Customers, and shall produce an efficient expansion plan
that includes all Baseline Reliability Projects determined by the Transmission
Provider to be necessary through the planning horizon of the MTEP. The
Transmission Provider shall obtain the approval of the Transmission Provider
Board, as set forth in Section VI, for each MTEP published.
2.
New Transmission Access Projects: New Transmission Access Projects
are defined for the purposes of Attachment FF as Network Upgrades identified in
Facilities Studies and agreements pursuant to requests for transmission delivery
service or transmission interconnection service under the Tariff. New
Transmission Access Projects include projects that are needed to maintain
reliability while accommodating the incremental needs associated with requests
for new transmission or interconnection service, as determined in Facilities
Studies associated with such requests. New Transmission Access Projects may
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consist of a number of individual facilities, which in the judgment of the
Transmission Provider constitute a single project for cost allocation purposes.
New Transmission Access Projects are either Generation Interconnection Projects
or Transmission Delivery Service Projects as defined in Sections II.A.2.a. and
II.A.2.b. The Transmission Provider shall consider the Baseline Reliability
Projects already determined to be needed in the most current MTEP, as well as
any other base-case needs not associated with the request for new service that
may be identified during the impact study process when determining the need for
New Transmission Access Projects. Any identified base-case needs determined
in the impact study process that are not a part of the Baseline Reliability Projects
already identified in the most current MTEP shall become new Baseline
Reliability Projects and shall be included in the next MTEP. New Transmission
Access Projects identified in Facilities Studies and agreements pursuant to
requests for transmission delivery service or transmission interconnection service
under this Tariff shall be included in the next MTEP.
a.
Generation Interconnection Projects: Generation Interconnection
Projects are New Transmission Access Projects that are associated with
interconnection of new, or increase in generating capacity of existing,
generation under Attachments X to this Tariff.
b.
Transmission Delivery Service Projects: Transmission Delivery
Service Projects are New Transmission Access Projects that are needed to
provide for requests for new Point-To-Point Transmission Service, or
requests under Module B of the Tariff for Network Service or a new
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designation of a Network Resource(s).
B.
Market Efficiency Projects: Market Efficiency Projects are Network Upgrades: (i) that
are proposed by the Transmission Provider, Transmission Owner(s), ITC(s), Market
Participant(s), or regulatory authorities; (ii) that are found to be eligible for inclusion in the
MTEP or are approved pursuant to Appendix B, Section VII of the ISO Agreement after June 16,
2005, applying the factors set forth in Section I.A. of this Attachment FF; (iii) that have a Project
Cost of $5 million or more; (iv) that involve facilities with voltages of 345 kV or higher1; and
that may include any lower voltage facilities of 100kV or above that collectively constitute less
than fifty percent (50%) of the combined project cost, and without which the 345 kV or higher
facilities could not deliver sufficient benefit to meet the required benefit-to-cost ratio threshold
for the project as established in Section II.B.1.e, or that otherwise are needed to relieve
applicable reliability criteria violations that are projected to occur as a direct result of the
development of the 345 kV or higher facilities of the project; (v) that are not determined to be
Multi Value Projects; and (vi) that are found to have regional benefits under the criteria set forth
in Section II.B.1 of this Attachment FF.
1.
Criteria to Determine Whether a Project Should be Included as a Market
Efficiency Project: The Transmission Provider shall employ multiple future scenarios
and multi-year analysis including sensitivity analyses guided by input from the Planning
Advisory Committee to evaluate the anticipated benefits of a proposed Market Efficiency
Project in order to determine if such a project meets the criteria for inclusion in the
regional plan as a Market Efficiency Project eligible for regional cost sharing. Sensitivity
analyses shall include, among other factors, consideration of: (i) variations in amount,
type, and location of future generation supplies as dictated by future scenarios developed
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with stakeholder input and guidance; (ii) alternative transmission proposals; (iii) impacts
of variations in load growth; and (iv) effects of demand response resources on
transmission benefits.
1
Transformer voltage is defined by the voltage of the low-side of the transformer
for these purposes.
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The Transmission Provider shall perform this inclusion analysis as follows:
a.
The Transmission Provider shall utilize a weighted futures, no loss (“WFNL”)
metric to analyze the anticipated annual economic benefits of construction of a proposed
Market Efficiency Project to Transmission Customers in each of the Local Resource
Zones, as defined in Attachment WW, based upon adjusted production cost (“APC”)
savings. APC savings will be calculated as the difference in total production cost of the
Resources in each Local Resource Zone adjusted for import costs and export revenues
with and without the proposed Market Efficiency Project as part of the Transmission
System. The WFNL metric for each Local Resource Zone shall be calculated using the
weighted APC savings determined for each future scenario included in the analysis.
i.
The WFNL metric shall utilize the future scenarios determined and
identified by the Transmission Provider through the planning process, with input
from all stakeholders. The weights applied to the results of each future scenario
shall also be determined by the Transmission Provider with input from all
stakeholders.
b.
Project benefit evaluations will include benefits for the first 20 years of project
life after the projected in-service date, with a maximum planning horizon of 25 years
from the approval year. The annual benefit for a proposed Market Efficiency Project
shall be determined as the sum of the WFNL values for each Local Resource Zone, as
defined in Attachment WW. The total project benefit shall be determined by calculating
the present value of annual benefits for the multiple year scenarios and multi-year
evaluations.
c.
The costs applied in the benefit to cost ratio shall be the present value, over the
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same period for which the project benefits are determined, of the annual Network
Upgrade Charges for the project as determined in accordance with the formula in
Attachment GG for the Transmission Owner constructing the proposed Market Efficiency
Project.
d.
The present value calculation for both the annual benefits and annual costs will
apply a discount rate representing the after-tax weighted average cost of capital of the
Transmission Owners that make up the Transmission Provider Transmission System.
e.
The Transmission Provider shall employ a benefit to cost ratio test to evaluate a
proposed Market Efficiency Project. Only projects that meet a benefit to cost ratio of
1.25 or greater shall be included in the MTEP as a Market Efficiency Project and be
eligible for regional cost sharing.
f.
The benefits of the project and used to determine the associated cost allocations as
a percentage of project cost shall be determined one time at the time that the project is
presented to the Transmission Provider Board for approval. Estimated Project Cost will
be used to estimate the benefit to cost ratio and the eligibility for cost sharing at the time
of project approval. To the extent that the Commission approves the collection of costs
in rates for Construction Work in Progress (“CWIP”) for a constructing Transmission
Owner, costs will be allocated and collected prior to completion of the project.
g.
The aforementioned Market Efficiency Project inclusion criteria shall be used for
the exclusive purpose of determining whether projects are eligible for regional cost sharing
in accordance with Section III.A.2.f below. These criteria shall not affect the existing
criteria set forth in Appendix B of the ISO Agreement for determining whether projects are
eligible for inclusion in the MTEP. Moreover, the costs of projects included in the MTEP,
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but not eligible for regional cost sharing, shall continue to be eligible for inclusion in the
calculation of Transmission Owner revenue requirements under Attachment O of this
Tariff.
C.
Multi Value Projects: A Multi Value Project is one or more Network Upgrades
that address a common set of Transmission Issues and satisfy the conditions listed in Sections
II.C.1, II.C.2., and II.C.3 of Attachment FF. All Network Upgrades associated with a Multi Value
Project including any lower voltage facilities that may be needed to relieve applicable reliability
criteria violations that are projected to occur as a direct result of the development of the Multi
Value Project; may be cost shared per Section III.A.2.g of Attachment FF except for i) any
Network Upgrade cost associated with constructing an underground or underwater transmission
line above and beyond the cost of a feasible alternative overhead transmission line that provides
comparable regional benefits, and ii) any DC transmission line and associated terminal equipment
when scheduling and dispatch of the DC transmission line is not turned over to the Transmission
Provider's markets, real-time control of the DC transmission line is not turned over to the
Transmission Provider's automatic generation control system and/or the DC transmission line is
operated in a manner that requires specific users to subscribe for DC transmission service.
1.
A Multi Value Project must be evaluated as part of a Portfolio of projects, as
designated in the transmission expansion planning process, whose benefits are
spread broadly across the footprint.
2.
A Multi Value Project must meet one of the three criteria outlined below:
a.
Criterion 1. A Multi Value Project must be developed through the
transmission expansion planning process for the purpose of enabling the
Transmission System to reliably and economically deliver energy in support
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of documented energy policy mandates or laws that have been enacted or
adopted through state or federal legislation or regulatory requirement that
directly or indirectly govern the minimum or maximum amount of energy
that can be generated by specific types of generation. The MVP must be
shown to enable the transmission system to deliver such energy in a manner
that is more reliable and/or more economic than it otherwise would be
without the transmission upgrade.
b.
Criterion 2. A Multi Value Project must provide multiple types of
economic value across multiple pricing zones with a Total MVP
Benefit-to-Cost ratio of 1.0 or higher where the Total MVP Benefit to-Cost ratio is described in Section II.C.7 of this Attachment FF.
The reduction of production costs and the associated reduction of
LMPs resulting from a transmission congestion relief project are not
additive and are considered a single type of economic value.
c.
Criterion 3. A Multi Value Project must address at least one
Transmission Issue associated with a projected violation of a NERC
or Regional Entity standard and at least one economic-based
Transmission Issue that provides economic value across multiple
pricing zones. The project must generate total financially
quantifiable benefits, including quantifiable reliability benefits, in
excess of the total project costs based on the definition of financial
benefits and Project Costs provided in Section II.C.7 of Attachment
FF.
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3.
All of the following conditions must be satisfied in order for a project to be
classified as a Multi Value Project:
a.
Facilities associated with the transmission project must not be in service,
under construction, or approved for construction by the Transmission
Provider Board prior to July 16, 2010 or the date a Transmission Owner
becomes a signatory member of the ISO Agreement, whichever is later.
This section II.C.3.a shall not preclude the Multi Value Project classification
of an Open Transmission Project that makes a Selected Transmission
Developer eligible to become a Transmission Owner.
b.
The transmission project must be evaluated through the Transmission
Provider's transmission planning process and approved for construction by
the Transmission Provider Board prior to the start of construction, where
construction does not include preliminary site and route selection activities.
c.
The transmission project must not contain any transmission facilities listed
in Attachment FF-1 of this Tariff.
d.
The total capital cost of the transmission project must be greater than or
equal to the lesser of $20,000,000.00 or 5% of the constructing
Transmission Owner's net transmission plant as reported in Attachment O of
the Tariff at the time the transmission project is approved in an MTEP.
e.
The transmission project must include, but not necessarily be limited to, the
construction or improvement of transmission facilities operating at voltages
above 100 kV. A transformer is considered to operate above 100 kV when
at least two sets of transformer terminals operate at voltages above 100 kV.
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f.
Network Upgrades driven solely by an Interconnection Request, as defined
in Attachment X of the Tariff, or a Transmission Service request will not be
considered Multi Value Projects.
4.
Any transmission project that qualifies as a Multi-Value Project shall be
classified as an MVP irrespective of whether such project is also a Baseline
Reliability Project and/or Market Efficiency Project.
5.
The specific types of economic value provided by a Multi Value Project
include the following:
a.
Production cost savings where production costs include generator
startup, hourly generator no-load, generator energy and generator
Operating Reserve costs. Production cost savings can be realized
through reductions in both transmission congestion and transmission
energy losses. Productions cost savings can also be realized through
reductions in Operating Reserve requirements within Reserve Zones
and, in some cases, reductions in overall Operating Reserve
requirements for the Transmission Provider.
b.
Capacity losses savings where capacity losses represent the amount
of capacity required to serve transmission losses during the system
peak hour including associated planning reserve.
c.
Capacity savings due to reductions in the overall Planning Reserve
Margins resulting from transmission expansion.
d.
Long-term cost savings realized by Transmission Customers by
accelerating a long-term project start date in lieu of implementing a
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short-term project in the interim and/or long-term cost savings
realized by Transmission Customers by deferring or eliminating the
need to perform one or more projects in the future.
e.
Any other financially quantifiable benefit to Transmission
Customers resulting from an enhancement to the Transmission
System and related to the provisions of Transmission Service.
6.
Any project to facilitate like-for-like capital replacements of plant originally
installed as part of a Multi Value Project where replacement is due to aging, failure,
damage or relocation requirements where such replacement is not the result of
negligence by the constructing Transmission Owner will be treated as a Multi
Value Project. The minimum project cost limitation for Multi Value Projects
described in Section II.C.3.d of Attachment FF will not apply to the like for- like
capital replacement projects described in this Section.
7.
The following Total MVP Benefit-to-Cost Ratio will be applied to any
Multi Value Project justified solely on the basis of Sections II.C.2.b or II.C.2.c of
this Attachment FF to ensure such project qualifies as a Multi Value Project:
Total MVP Benefit-to-Cost Ratio = financial benefits / Project Costs.
For the purpose of this calculation, Financial Benefits will be set equal to the
present value of all financially quantifiable benefits provided by the project
projected for the first 20 years of the project's life and Project Costs will be set
equal to the present value of the annual revenue requirements projected for the first
20 years of the project's life.
8.
The aforementioned Multi Value Project inclusion criteria shall be used for
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the exclusive purpose of determining whether projects are eligible for regional cost
sharing in accordance with Section III.A.2.g below. These criteria shall not affect
the existing criteria set forth in Appendix B of the ISO Agreement for determining
whether projects are eligible for inclusion in the MTEP. Moreover, the costs of
projects included in the MTEP, but not eligible for regional cost sharing, shall
continue to be eligible for inclusion in the calculation of Transmission Owner
revenue requirements under Attachment O of this Tariff.
III.
Designation of Cost Responsibility for MTEP Projects: Based on the planning
analysis performed by the Transmission Provider, which shall take into consideration all
appropriate input from Market Participants or external entities, including, but not limited to, any
indications of a willingness to bear cost responsibility for an enhancement or expansion, the
recommended MTEP shall, for any enhancement or expansion that is included in the plan,
designate: (i) the Market Participant(s) in one or more pricing zones that will bear cost
responsibility for such enhancement or expansion, as and to the extent provided by any
applicable provision of the Tariff, including Attachments N, X, or any applicable cost allocation
method ordered by the Commission; or, (ii) in the event and to the extent that no provision of the
Tariff so assigns cost responsibility, the Market Participant(s) or Transmission Customer(s) in
one or more pricing zones from which the cost of such enhancements or expansions shall be
recovered through charges established pursuant to Attachment GG of this Tariff, or as otherwise
provided for under this Attachment FF.
Any designation under clause (ii) of the preceding sentence shall be determined as provided for
in Section III.A and III.B of this Attachment FF. For all such designations, the Transmission
Provider shall calculate the cost allocation impacts to each pricing zone. The results will be
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reviewed for unintended consequences by the Transmission Provider and the Tariff Working
Group and any such identified consequences shall be reported to the Planning Advisory
Committee, and the OMS.
A.
Allocation of Costs Within the Transmission Provider Region
1.
Default Cost Allocation: Except as otherwise provided for in this Attachment FF, or by
any other applicable provision of this Tariff and consistent with the ISO Agreement, the
responsibility for Network Upgrades included in the approved MTEP will be addressed in
accordance with the provisions of the ISO Agreement.
2.
Cost Allocation: The Transmission Provider will designate and assign cost
responsibility on a regional, and sub-regional basis for Network Upgrades identified
in the MTEP subject to the grand-fathered project provisions of Section III.A.2.b.
a.
Market Participant’s Option to Fund: Notwithstanding the
Transmission Provider’s assignment of cost responsibility for a
project included in the MTEP, one or more Market Participants
may elect to assume cost responsibility for any or all costs of a
Network Upgrade that is included in the MTEP. Provided
however, in the event the Market Participant is also a Transmission
Owner such election of the option to fund must be made on a
consistent, non-discriminatory basis.
b.
Grandfathered Projects: The cost allocation provisions of this
Attachment FF shall not be applicable to transmission projects
identified in Attachment FF-1, which is based on the list of
projects designated as Planned Projects in the MTEP approved by
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the Transmission Provider Board on June 16, 2005 (MTEP 05) and
some additions of proposed projects that the Transmission Provider
has determined to be in the advanced stages of planning.
c.
Baseline Reliability Projects: Costs of Baseline Reliability
Projects shall be recovered pursuant to Attachment O of this Tariff
by the Transmission Owner(s) and/or ITC(s) developing such
projects, subject to the requirements of the ISO Agreement.
d.
Generation Interconnection Projects: Costs of Generation
Interconnection Projects that are not determined by the
Transmission Provider to be Baseline Reliability Projects, Market
Efficiency Projects, or Multi-Value Projects, and the Network
Upgrade costs associated with advancing a Baseline Reliability
Project, Market Efficiency Project, or Multi-Value Project
associated with a generator interconnection will be paid for by the
Interconnection Customer(s) in accordance with Attachment X.
For Generator Interconnection Projects interconnecting to the
American Transmission Company LLC transmission system, such
costs will be subject to the provision of Attachment FF –
ATCLLC.
1)
For Network Upgrades to facilities in voltage classes at or
above 345 kV, the Interconnection Customer shall be
repaid 10 percent of the costs of the Generation
Interconnection Project funded by the Interconnection
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Customer once Commercial Operation is achieved. The
Transmission Owner(s) constructing the Generation
Interconnection Project will repay 10% of the Generation
Interconnection Project costs associated with Network
Upgrade facilities in a voltage class of 345 kV or greater to
the Interconnection Customer under repayment terms
consistent with the schedules and other terms of
Attachment X.
The 10% of the Project Cost associated with Network
Upgrade facilities of voltage class 345 kV or above and
repaid to the Interconnection Customer shall be allocated
on a system-wide basis and recovered pursuant to
Attachment GG of this Tariff.
2)
An Interconnection Customer may be required to contribute
to the cost of Shared Network Upgrades, as defined in
Attachment X to the Tariff, that are funded by another
Interconnection Customer as a Generator Interconnection
Project pursuant to Attachment X.
Each Interconnection Customer with one or more
Shared Network Upgrade(s) identified in Appendix A of its
Generator Interconnection Agreement shall make a onetime payment under Schedule 26-B to the Transmission
Provider in accordance with the terms in the Generator
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Interconnection Agreement. The one-time payment will
reflect the cost of the Shared Network Upgrade assigned to
the Interconnection Customer as determined by the
Transmission Provider.
All revenue collected by the Transmission Provider
through Schedule 26-B shall be distributed to the
appropriate Interconnection Customer(s).
3)
The Interconnection Customer shall be entitled, pursuant to
Section 46 of this Tariff, to any Financial Transmission
Rights or other rights to the extent provided for under this
Tariff, for any Network Upgrade costs funded by or
charged to the Interconnection Customer and not subject to
repayment under the provisions of this Section III.A.2.d. In
the event that a Generator Interconnection Project defers or
displaces a Baseline Reliability Project, the costs of the
Generator Interconnection Project up to the costs of the
deferred or displaced Baseline Reliability Project shall be
allocated consistent with the cost allocation for the Baseline
Reliability Project.
4)
International Transmission/Michigan Electric Transmission
Company/ITC Midwest LLC:
(a)
For those Generator Interconnection Projects for
which International Transmission Company, Michigan
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Electric Transmission Company, LLC, or ITC Midwest
LLC (“International” or “METC” or “ITC Midwest”) as
Transmission Owners will be a signatory to the
interconnection agreement under the terms of Attachment
X of this Tariff or any successor provision of the Tariff
executed by the parties after the effective date of this
Attachment FF Section III.A.2.d.4, this Attachment FF
Section III.A.2.d.4 shall apply, except that, where ITC
Midwest is the Transmission Owner, the Interconnection
Customer may elect to have another approved methodology
under Attachment FF Section III.A.2.d apply.
(b)
Generation Interconnection Projects: The cost of
Network Upgrades for Generation Interconnection Projects
that are not determined by the Transmission Provider to be
Baseline Reliability Projects shall be reimbursed by the
Transmission Owner as provided in this Section III.A.2.d.4.
All costs of Network Upgrades for Generation
Interconnection Projects will initially be paid by the
Interconnection Customer in accordance with the terms of
the Interconnection Agreement entered into pursuant to
Attachment X of this Tariff. To the extent the
Interconnection Customer demonstrates at the time of
Commercial Operation of the Generating Facility one of the
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following:
i.
Generating Facility has been designated as a
Network Resource in accordance with the
Tariff, or
ii.
Contractual commitment has been entered into
with a Network Customer for capacity, or in the
case of an Intermittent Resource, for energy,
from the Generating Facility for a period of one
(1) year or longer.
The Interconnection Customer will receive up to one
hundred percent (100%) reimbursement of reimbursable
costs within ninety (90) days of the Commercial Operation
Date, such reimbursement prorated by the percentage of the
Generating Facility capacity or annual available energy
output contracted for and as demonstrated to the
satisfaction of the Transmission Provider.
If the Interconnection Customer is unable to
demonstrate to the satisfaction of the Transmission
Provider at the time of Commercial Operation of the
Generating Facility that the Generating Facility has met the
repayment obligations set forth in Attachment FF Sections
III.A.2.d.4.b.i. or III.A.2.d.4.b.ii. the Interconnection
Customer shall be directly assigned 100% of the costs of
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the Generation Interconnection Project. The Transmission
Owner may effect this direct assignment of costs by either
foregoing any repayment of costs funded by the
Interconnection Customer, or by electing to repay 100% of
the costs under repayment terms consistent with the
schedules and other terms of Attachment X.
The Interconnection Customer shall be entitled, pursuant to
Section 46 of this Tariff, to any Financial Transmission
Rights or other rights to the extent provided for under this
Tariff, for any Network Upgrade costs funded by or
charged to the Interconnection Customer and not subject to
repayment under the provisions of this Attachment FF
Section III.A.2.d.4. In the event that a Generator
Interconnection Project defers or displaces a Baseline
Reliability Project, the costs of the Generator
Interconnection Project up to the costs of the deferred or
displaced Baseline Reliability Project shall be allocated
consistent with the cost allocation for the Baseline
Reliability Project.
(c)
For all amounts to be reimbursed by a Transmission
Owner to an Interconnection Customer in accordance with
this Attachment FF Section III.A.2.d.4, the Transmission
Owner will reimburse the sums received from the
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Interconnection Customer in cash together with any
applicable interest, in accordance with the terms of the
Interconnection Agreement.
(d)
Allocation of Generator Interconnection
Reimbursement. For all amounts reimbursed by a
Transmission Owner to an Interconnection Customer under
this Attachment FF Section III.A.2.d.4, fifty percent (50%)
of the reimbursement will be allocated consistent with the
allocations under this Attachment FF Sections III.A.2.c.i
and III.A.2.c.ii, except that such costs associated with
Generation Interconnection Projects of less than 100 kV
voltage class shall also be allocated consistent with Section
III.A.2.c.i. The remaining fifty percent (50%) of the
reimbursement will not be subject to any regional or subregional cost allocation, but will be recovered by that
Transmission Owner under its Attachment O transmission
rate formula under this Tariff.
e.
Transmission Delivery Service Projects: Costs of Transmission
Delivery Service Projects shall be assigned and recovered in
accordance with Attachment N of this Tariff.
f.
Market Efficiency Projects: Costs of Market Efficiency Projects
shall be allocated as follows:
i)
Twenty percent (20%) of the Project Cost of the Market
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Efficiency Project shall be allocated on a system-wide basis
to all Transmission Customers and recovered through a
system-wide rate.
ii)
Eighty percent (80%) of the costs of the Market Efficiency
Projects shall be allocated to all Transmission Customers in
each of the Local Resource Zones, as defined in Attachment
WW. The cost allocated to each Local Resource Zone shall
be based on the relative benefit determined for each Local
Resource Zone that has a positive present value of annual
benefits over the evaluation period using the methodology
for project benefit determination of Section II.B.1.
iii)
Excessive Funding or Requirements: The Transmission
Provider shall seek to identify and manage the development
of, as a part of the planning process for Market Efficiency
Projects, portfolios of projects that tend to provide benefits
throughout each Local Resource Zone, as defined in
Attachment WW, over the planning horizon. The
Transmission Provider shall analyze on an annual basis
whether the project portfolios developed in accordance with
this goal and the criteria in Section III. A.2.f unintentionally
result in unjust or unreasonable annual capital funding
requirements for any Transmission Owner or rate increases
for Transmission Customers in designated pricing zones; or
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otherwise result in undue discrimination between the
Transmission Customers, Transmission Owners, or any
Market Participants; any such identified consequences shall
be reported to the Planning Advisory Committee and to the
Organization of MISO States. After discussing such
assessments with the aforementioned stakeholder bodies, and
taking into consideration the cumulative experience in
applying this Attachment FF, the Transmission Provider will
make a determination as to whether Tariff modifications are
required, and if so file such modifications.
g.
Multi Value Projects: Costs of Multi Value Projects will be
allocated as follows:
i)
One-hundred percent (100%) of the annual revenue
requirements of the Multi Value Projects shall be allocated
on a system-wide basis to Transmission Customers that
withdraw energy, including External Transactions sinking
outside the Transmission Provider's region, and recovered
through an MVP Usage Charge pursuant to Attachment
MM.
h.
Treatment of Projects that meet both Baseline Reliability Project
Criteria and/or New Transmission Access Project Criteria, and the
Market Efficiency Project Criteria: If the Transmission Provider
determines that a project designated as a Market Efficiency Project
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also meets the criteria to be designated as a Baseline Reliability
Project and/or a New Transmission Access Project, the cost of
such project shall be allocated in accordance with the Market
Efficiency Project allocation procedures.
i.
Other Projects: Unless otherwise agreed upon pursuant to
Section III.A.2.a. of this Attachment FF, the costs of Network
Upgrades that are included in the MTEP, but do not qualify as
Baseline Reliability Projects, New Transmission Access Projects,
Market Efficiency Projects or Multi-Value Projects, shall be
eligible for recovery pursuant to Attachment O of this Tariff by the
Transmission Owner(s) and/or ITC(s) paying the costs of such
project, subject to the requirements of the ISO Agreement.
j.
Withdrawal from Midwest ISO: A Transmission Owner that
withdraws from the Midwest ISO as a Transmission Owner shall
remain responsible for all financial obligations incurred pursuant to
this Attachment FF while a Member of the Midwest ISO and
payments applicable to time periods prior to the effective date of
such withdrawal shall be honored by the Midwest ISO and the
withdrawing Member.
k.
New Transmission Owners: A new Transmission Owner joining
the Midwest ISO will be responsible for the following financial
obligations:
a.
New Transmission Owners will not be responsible for any
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portion of Baseline Reliability Projects, Generator
Interconnection Projects, Transmission Delivery Service
Projects, or Market Efficiency Projects that were approved
prior to their entry date.
b.
For Multi-Value Projects approved prior to the new
Transmission Owner’s entry date, the load interconnected
to the Transmission Owner’s Transmission System will be
responsible for one-hundred percent (100%) of the MVP
usage charge described in Attachment MM for the years
following the Transmission Owner’s entry date applied to
the Monthly Net Actual Energy Withdrawals for Load
interconnected to the Transmission Owner’s Transmission
System.
l.
Only a Transmission Owner shall be authorized to
construct and/or own transmission facilities associated with
a Baseline Reliability Project, Market Efficiency Project
and/or Multi Value Project. For projects jointly developed
between Transmission Owners and other parties the portion
constructed and owned by a Transmission Owner may
qualify as a Baseline Reliability Project, Market Efficiency
Project and/or Multi Value Project.
IV.
[RESERVED FOR FUTURE USE]
IV.
Merchant Transmission Project Data Requirements: A proposed merchant
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transmission developer assumes all financial risk and funding requirements for developing its
transmission project(s) and constructing the proposed transmission facility(ies). In order for a
proposed merchant transmission developer’s facility to be interconnected to the Transmission
System, it is first necessary for the impacted Transmission Owner and the Transmission Provider
to analyze the reliability and operational impact of the proposed new merchant transmission
facility(ies) on the Transmission System to determine if the new merchant transmission facilities
can be reliably supported by the Transmission System, and if not, what Network Upgrades
funded by the merchant transmission developer would be required to reliably support the
proposed merchant transmission facility(ies). In order to perform the required reliability and
operational analyses, the merchant transmission developer must provide the following data to the
Transmission Provider:
(1)
Each transmission circuit and substation, including new facilities, associated with
the merchant transmission proposal;
(2)
Nominal operating voltage level in kV and voltage characteristics (i.e., AC or DC)
for each transmission circuit associated with the merchant transmission proposal;
(3)
Typical and maximum MW power flow schedules, in each direction, for all
proposed DC transmission circuits associated with the merchant transmission proposal;
(4)
Normal and emergency summer and winter load ratings for each transmission
circuit associated with the merchant transmission proposal;
(5)
Maximum allowable positive sequence impedance for each AC transmission circuit
associated with the merchant transmission proposal, when applicable;
(6)
List of all transmission buses associated with the merchant transmission proposal,
including nominal operating voltage level in kV, voltage characteristics, and terminating
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transmission branches and shunts;
(7)
Proposed substation one-line diagrams for all new substations associated with the
merchant transmission proposal, including circuit breaker and bus configuration details;
(8)
Load ratings, winding connections, impedances, tap data, and any other relevant
information for load carrying equipment and facilities associated with the merchant
transmission proposal, as applicable;
(9)
Modeling files to model proposed facilities and relevant new contingencies in
power flow, stability, short-circuit and other relevant study models; and
(10)
Any other data determined pertinent to the study by the Transmission Provider
and/or interconnecting Transmission Owners for the specific merchant transmission facility
proposal.
V.
Designation of Entities to Construct, Implement, Own, Operate, Maintain, Repair,
Restore, and/or Finance MTEP Projects: For With the exception of Open Transmission
Projects, for each project included in the recommended MTEP Appendix A and prior to approval
by the Transmission Provider Board, the plan shall designate one or more Transmission Owners to
construct, own, operate, maintain, repair, restore, and finance the recommended project, based on
the planning analysis performed by the Transmission Provider and based on other input from
participants, including, but not limited to, any indications of a willingness to bear cost
responsibility for the project; and applicable provisions of the ISO Agreement, one or more
Transmission Owners or other entities to construct, own and/or finance the recommended project.
Regarding Open Transmission Projects, upon the determination of the Selected Transmission
Developer for such projects, as set forth in Section VIII of this Attachment FF, the Transmission
Provider shall update the approved MTEP Appendix A by identifying the Selected Transmission
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Developer for each Open Transmission Project. Should the facilities from such Open
Transmission Projects not be approved by state regulatory authorities as New Transmission
Facilities, but instead as upgrades to existing transmission facilities, as defined in Section VIII.C
of this Attachment FF, the Transmission Provider shall update MTEP Appendix A by designating
the appropriate Transmission Owner(s) to construct, own, operate, maintain, repair, restore, and
finance such facilities in accordance with the ISO Agreement.
VI.
Implementation of the MTEP:
A.
If the Transmission Provider and any Transmission Owner’s planning
representatives, or other designated entity(ies), cannot reach agreement on any element of the
MTEP, the dispute may be resolved through the dispute resolution procedures provided in the
Tariff, or in any applicable joint operating agreement, or by the Commission or state regulatory
authorities, where appropriate. The MTEP shall have as one of its goals the satisfaction of all
regulatory requirements as specified in Appendix B or Article IV, Section I, Paragraph C of the
ISO Agreement.
B.
The Transmission Provider shall present the MTEP, along with a summary of
relevant alternative projects that were not selected, to the Transmission Provider Board for
approval on a biennial basis, or more frequently if needed. The proposed MTEP shall include
specific projects already approved as a result of the Transmission Provider entering into Service
Agreements with Transmission Customers where such agreements provide for identification of
needed transmission construction, timetable, cost, and Transmission Owner or other parties’
construction responsibilities.
C.
Approval of the MTEP by the Transmission Provider Board certifies it as the
Transmission Provider plan for meeting the transmission needs of all stakeholders subject to any
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required approvals by federal or state regulatory authorities. The Transmission Provider shall
provide a copy of the MTEP to all applicable federal and state regulatory authorities. The
affected Transmission Owner(s), Selected Transmission Developer(s), or other designated
entity(ies), shall make a good faith effort to design, certify, and build the designated facilities to
fulfill the approved MTEP. However, in the event that a proposed an MTEP Appendix A project
approved by the Transmission Provider Board or the selection of the Selected Transmission
Developer is being challenged through the dispute resolution procedures under this Tariff or in
court proceedings, the obligation of the Transmission Owners, or other designated entity(ies), to
build that specific project (subject to required approvals) is waived until the approved project
emerges from the dispute resolution procedures as an approved project. The Transmission
Provider Board shall allow the Transmission Owners, or other designated entity(ies), to optimize
the final design of specific facilities and their in-service dates if necessary to accommodate
changing conditions, provided that such changes comport with the approved MTEP and provided
that any such changes are accepted by the Transmission Provider through the reevaluation
process described in Section VI of this Attachment FF, as necessary. Any disagreements
concerning such matters shall be subject to the dispute resolution procedures of this Tariff.
D.
The Transmission Provider shall assist the affected Owner(s), Selected
Transmission Developer(s), or other designated entity(ies), in justifying the need for, and
obtaining certification of, any facilities required by the approved MTEP by preparing and
presenting testimony in any proceedings before state or federal courts, regulatory authorities, or
other agencies as may be required. The Transmission Provider shall publish annually, and
distribute to all Members and all appropriate state regulatory authorities, a five-to-ten-year
planning report of forecasted transmission requirements. Annual reports and planning reports
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shall be available to the general public upon request.
VII.
Multi-Value Project Costs and Benefits Review and Reporting
A.
Frequency and Reporting of Multi-Value Project Review: Every three (3)
years, as provided below and in the Business Practices Manual for Transmission
Planning, the Transmission Provider shall conduct a review of the cumulative costs and
benefits associated with MVPs, and shall disseminate the results of such reviews to its
stakeholders. The Transmission Provider shall use the review process and results to
identify potential modifications to the MVP methodology and its implementation for
projects to be approved at a future date.
1.
Triennial Full MVP Review: Beginning with the MTEP for 2014 (“MTEP 14”),
and every third year thereafter, the Transmission Provider shall conduct a full
MVP review, as provided in section VII.B of this Attachment FF.
2.
Annual Limited MVP Review: Beginning with the MTEP for 2015 (“MTEP 15”),
and each year thereafter when there is no full MVP review, the Transmission
Provider shall conduct a limited MVP review, as provided in section VII.C of this
Attachment FF.
3.
Calculation of Costs and Benefits: The reviews shall calculate costs and benefits
on a forward-looking basis over both twenty (20)-year and forty (40)-year
periods. The costs calculation shall use updated project costs and in-service dates
provided in the latest MTEP quarterly status report, and the benefits calculation
shall use updated future scenarios from the latest MTEP planning cycle. The
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results of the costs and benefits calculation shall be provided for each Local
Resource Zone as defined in Module E. If the Local Resource Zones as defined
in accordance with Module E for Resource Adequacy purposes are modified, the
Transmission Provider, working with stakeholders, may define different Local
Resource Zones for purposes of reporting the results of the review. The definition
of different Local Resource Zones in connection with reporting the results of the
review will be detailed in the Business Practices Manual for Transmission
Planning.
4.
Dissemination of the Results of the Full and Limited MVP Reviews: Within a
reasonable time after completion of each MVP review, the Transmission Provider
shall disseminate the results of and supporting analysis for the MVP review
through: (a) publication in the MTEP; (b) posting on the appropriate section of
the Transmission Provider’s public website; and (c) presentation to the
appropriate stakeholder committees.
B.
Scope of Full Multi-Value Project Review: Each full MVP review shall at a
minimum include the following:
1.
Quantitative Benefits: Analysis of the quantifiable economic benefits resulting
from the addition of MVPs, including, but not limited to:
a.
Congestion and Fuel Savings: Savings from increased access to lower
cost Resources;
b.
Decreased Operating Reserves: Savings associated with lower Operating
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Reserve requirements;
c.
Decreased System Planning Reserve Margin: Savings associated with
deferred generation investment due to a reduction in the system-wide
Planning Reserve Margin; and
d.
Decreased Transmission Line Losses: Savings associated with deferred
generation investment due to a reduction in the Capacity required to serve
transmission losses during peak hours, to the extent that MVPs reduce
such losses.
2.
Public Policy and Other Qualitative Benefits: Analysis of the public policy and
other qualitative benefits accruing from MVPs, such as newly interconnected
wind units; and an increase in the percentage of the Transmission Provider’s
Energy needs being supplied by wind and/or other renewable resources, and wind
curtailments.
3.
Historical Data: Provision, beginning with the MTEP for 2017 (“MTEP 17”), and
based on the historical data available to the Transmission Provider for the five (5)
prior years, of information on certain additional market trend metrics including,
but not limited to:
a. Congestion costs;
b. Energy prices;
c. Fuel costs;
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d. Planning Reserve Margin requirements;
e. Number of newly interconnected Resources, by Resource type; and
f. The share of the Transmission Provider’s Energy supplied, by Resource
type.
C.
Scope of Limited Multi-Value Project Review: Each limited MVP review shall
at a minimum include the items described in Sections VII.B.1.a and VII.B.3 of this
Attachment FF, based on the latest available data for the current year, in preparation for the next
full MVP review.
VIII. Transmission Developer Selection
A.
State or Local Rights of First Refusal. The Transmission Provider shall comply
with any Applicable Laws and Regulations granting a right of first refusal to a Transmission
Owner. The Transmission Owner will be assigned any transmission project within the scope,
and in accordance with the terms, of any Applicable Laws and Regulations granting such a right
of first refusal. These Applicable Laws and Regulations include, but are not limited to, those
granting a right of first refusal to the incumbent Transmission Owner(s) or governing the use of
existing developed and undeveloped right of way held by an incumbent utility.
B.
State Selection of Qualified Transmission Developers. In the absence of any
Applicable Laws and Regulations granting a right of first refusal, a state with the authority to do
so may elect to determine the Selected Transmission Developer(s) from the Qualified
Transmission Developers who have submitted Transmission Proposals for any Open
Transmission Projects, or portion of such Open Transmission Projects that are physically located
within such state’s boundaries, in accordance with applicable state criteria and procedures. Prior
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to the Transmission Provider Board’s approval of Open Transmission Project(s) for inclusion in
Appendix A of the MTEP, states may identify any potential Open Transmission Projects within
its state boundaries for which it will determine the Selected Transmission Developer. States that
elect to determine the Selected Transmission Developer may request additional state-specific
data or qualification criteria related to the specific potential Open Transmission Project (s), for
which the state has indicated that it will determine the Selected Transmission Developer to be
included in the corresponding Transmission Proposal Request(s) prior to the Transmission
Provider Board’s approval of potential Open Transmission Project(s) for inclusion in Appendix
A of the MTEP.
Upon receipt of a New Transmission Proposal, the Transmission Provider will review the
New Transmission Proposal to ensure all qualifications and requirements from the Transmission
Proposal Request, including state-specific qualifications, have been satisfied. Should the New
Transmission Proposal not satisfy one or more of the requirements or qualifications outlined in
this Tariff and/or specified in the Transmission Proposal Request, the Transmission Provider will
notify the New Transmission Proposal Applicant and initiate a Cure Period as described in
Section VIII.F of this Tariff. Within five (5) business days following the completion of this Cure
Period, Transmission Provider will submit all applicable New Transmission Proposals, including
any whose deficiencies have been cured, to the appropriate state(s) for their consideration,
subject to execution of appropriate Non-Disclosure Agreements.
If, for any reason, a state is unable or declines to determine the Selected Transmission
Developer within the time period defined in Section VIII.G, the Transmission Provider will
assume responsibility for determining the Selected Transmission Developer. In this event, the
Transmission Provider will, pursuant to the evaluation process outlined in Section VIII.G of this
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Attachment FF: i) evaluate each New Transmission Proposal submitted by a Qualified
Transmission Developer; ii) select one of the New Transmission Proposals for implementation
and; iii) post the Selected Transmission Developer on its website within 180 calendar days of the
notification from a state that it is unable or declines to select a developer, or the lapse of the 180
calendar day timeframe defined in Section VIII.G of this Attachment FF, not to exceed 450
calendar days from posting of the Transmission Proposal Request.
C.
Upgrades to Existing Transmission Facilities. A Transmission Owner shall
have the right to develop, own and operate any upgrade to a transmission facility owned by the
Transmission Owner, in accordance with this Tariff and the ISO Agreement.
1.1
Upgrades to Existing Transmission Lines. Upgrades to existing
transmission line facilities include any expansion, replacement or modification,
for any purpose, made to existing transmission line facilities that are classified as
transmission plant and owned by one or more Transmission Owners, for reasons
including, but not limited to:
(a)
(a)
increasing the load capability of the transmission line or an
associated circuit;
(b)
increasing the nominal operating voltage of the transmission line or an
associated circuit;
(c)
installing additional plant on an existing overhead or underground
transmission line facility, such as, but not limited to:
i.
plant associated with an additional circuit installed on spare
structure positions;
ii.
additional structures to increase a sag limit or for other purposes;
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iii.
a sectionalizing switch installed on an existing transmission line
circuit regardless of whether or not it is installed on an existing
structure; and
iv.
(d)
any other plant additions to existing transmission line facilities.
relocating the existing transmission line, or any portion thereof, for any
purpose;
(e)
replacing an entire existing transmission line facility with a new
transmission line facility on the same right-of-way or on a different rightof-way if the replacement is driven by a relocation request or requirement;
(f)
replacing one or more existing components of any existing transmission
line facility, such as, but not limited to:
i.
replacing existing conductors with higher capacity conductors or
better performing conductors;
ii.
iii.
replacing single-circuit structures with multi circuit structures;
replacing insulators rated at a specific voltage with insulators rated
at a higher voltage;
iv.
replacing aging or defective components associated with the
existing transmission line;
(g)
improving the performance or characteristics of the existing transmission
line for any reason;
(h)
converting an existing overhead transmission line to an underground
transmission line on the same right-of-way and/or converting an existing
underground transmission line to an overhead transmission on the same
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right-of-way;
(i)
improving land and land rights booked under the Commission’s Uniform
System of Accounts, Account Nos. 105, 350, and/or 380; or
(j)
any other modifications to existing transmission facilities.
1.1.1
Combination of Upgrades and New Facilities. If a proposed
transmission project includes a combination of new transmission line
sections and upgrades to existing transmission line sections, and the new
transmission line sections are less than twenty (20) contiguous miles in
total length, construction of the new transmission line sections will be
considered a transmission upgrade for the purpose of retaining a right of
first refusal. In either event, upgrades made to the existing transmission
line sections will be considered transmission upgrades for the purpose of
retaining a right of first refusal.
1.2
Upgrades to Existing Substations. Upgrades to existing substations
include any expansions, replacements or modifications made, in part or in
whole, to any existing substation or portion thereof that is owned by one
or more Transmission Owners, and where some or all of the plant within
the existing substation is classified as transmission plant. These upgrades
include, but are not limited to:
(a)
replacing facilities and/or equipment within an existing substation
footprint;
(b)
installing additional plant within an existing substation footprint;
(c)
modifying facilities and/or equipment within an existing substation
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footprint;
(d)
expanding an existing substation footprint within the existing substation
site boundaries and installing additional plant within the expanded area;
and
(e)
acquiring additional land adjacent to or near the existing substation in
conjunction with installation of additional plant within the boundaries of
this additional land, including facilities to interconnect such plant to the
existing substation plant.
1.2.1
Construction of a new substation facility at the common junction point(s)
of a transmission line containing more than two terminals or along an existing
two terminal transmission line, where such transmission line facilities are owned
by an incumbent Transmission Owner, for the purpose of implementing: i)
transmission line protection system upgrades; ii) improving operational
flexibility; iii) improving customer service reliability indices (e.g., reducing
SAIFI, CAIDI, SAIDI, etc.); iv) increasing the load capability of the transmission
line; v) improving transmission voltages and reactive power management; vi)
mitigating the economic and/or reliability impact of contingencies; and vii) any
other purpose other than facilitating the interconnection of a New Transmission
Line Facility will be considered a transmission upgrade for the purpose of
retaining a right of first refusal. Furthermore, construction of a new substation for
the purpose of interconnecting two or more existing transmission circuits where
all such existing transmission circuits are owned by incumbent Transmission
Owner(s) will be considered a transmission upgrade for the purpose of retaining a
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right of first refusal. Examples of newly constructed substations that will be
considered transmission upgrades for the purpose of retaining a right of first
refusal include, but are not limited to, i) circuit breaker substations installed along
an existing two-terminal transmission line to improve operational flexibility or
customer service reliability via automatic sectionalizing; ii) series capacitor
substations installed within an existing transmission line to increase load
capability; iii) circuit breaker switching substations installed at the common
junction point of a three-terminal line to improve loading and protection
capabilities of protective relay systems; and iv) newly constructed switching
substation to interconnect two existing transmission circuits at the point where
they physically cross each other where such existing transmission circuits are
owned by the same Transmission Owner. Examples of new substation facilities
that would not be considered transmission upgrades for the purpose of retaining a
right of first refusal include, but are not limited to, i) a New Substation Facility
proposed to interconnect three New Transmission Line Facilities; ii) a New
Substation Facility proposed to facilitate connecting a 345 kV New Transmission
Line Facility to the midpoint of an existing 345 kV transmission circuit owned by
an incumbent Transmission Owner; and iii) a 765-345 kV New Substation
Facility constructed to interconnect a 765 kV New Transmission Line Facility
with an existing double circuit 345 kV transmission line, where such 345 kV
double circuit transmission line is owned by incumbent Transmission Owner(s).
D.
Data Submission
1.
Determination of Projects Not Subject to a Right of First Refusal.
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Upon the Transmission Provider Board’s approval of transmission projects for
inclusion in Appendix A of the MTEP, the Transmission Provider will develop a
separate Transmission Proposal Request for each Open Transmission Project.
These Transmission Proposal Request(s) will be posted on the Transmission
Provider website within thirty (30) calendar days of the date the Transmission
Provider Board approved the Open Transmission Project for inclusion in
Appendix A of the MTEP.
2.
Transmission Proposal Requests
a.
Transmission Proposal Request Deposit. The New
Transmission Proposal Applicant will submit a deposit per proposal equal
to one percent (1%) of the projected project cost, not to exceed $500,000.
The Transmission Provider shall track all time and expenses specifically
associated with the evaluation process identified in this Section VIII of
Attachment FF and the Transmission Proposal Request deposits will be
applied to the cost of evaluating the New Transmission Proposals. Any
remaining funds shall be refundable on a pro rata basis to each New
Transmission Proposal Applicant within thirty (30) days following the
designation of the Selected Transmission Developer. No interest will be
paid on any deposit funds held by the Transmission Provider during this
time.
b.
Minimum Contents of Transmission Proposal Requests. The
Transmission Proposal Request will specify i) each New Transmission
Line Facility and/or each New Substation Facility associated with the
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Open Transmission Project that should be included in the New
Transmission Proposal; ii) the date by which the New Transmission
Proposal must be submitted to the Transmission Provider, which shall not
exceed 180 calendar days from the posting of the Transmission Proposal
Request; and iii) a list of the current transmission facility interconnection
standards and requirements established by the Transmission Owner(s) to
which the New Transmission Line Facilities and/or New Substation
Facilities will interconnect.
i.
Furthermore, where it involves one or more New
Transmission Line Facilities, the Transmission Proposal
Request will specify for each New Transmission Line
Facility, at a minimum:
(1)
Expected in-service date;
(2)
Implementation schedule indicating the required
steps to develop and construct the Open
Transmission Project, including, but not limited to,
all required regulatory approvals;
(3)
Nominal operating voltage level in kV and voltage
characteristics (i.e., three-phase AC, bipolar DC,
etc.) for each transmission circuit;
(4)
Terminating substations and buses for each
transmission circuit;
(5)
Minimum required normal and emergency load
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ratings for both summer and winter seasons for each
transmission circuit; and
(6)
Maximum allowable positive sequence impedance
for each transmission circuit when determined
applicable by planning studies performed by the
Transmission Provider.
ii.
Where it involves one or more New Substation Facilities,
the Transmission Proposal Request will specify for each
New Substation Facility, at a minimum, the following
information:
(1)
Expected in-service date;
(2)
Implementation schedule indicating the required
steps to develop and construct the Open
Transmission Project, including, but not limited to,
all required regulatory approvals;
(3)
List of all transmission buses within the New
Substation Facility, including nominal operating
voltage level in kV and voltage characteristics;
(4)
List of all major equipment and facilities within the
New Substation Facility and associated terminating
buses including power transformers, voltage
regulators, phase angle regulators, series reactors,
series capacitors, shunt reactors, shunt capacitors,
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static VAR compensators, DC converters,
transmission line circuit terminals, generator
terminals, and loads;
(5)
Limitations on and/or requirements for bus
configurations when determined applicable by
planning studies performed by the Transmission
Provider including required load ratings of circuit
breakers, disconnects, bus sections and other load
carrying equipment under alternative bus
configurations;
(6)
Required load ratings for all load carrying
equipment and facilities identified in item (4)
above;
(7)
Winding connection and tap requirements for power
transformers, voltage regulators, phase angle
regulators and load tap changers when determined
necessary by planning studies performed by the
Transmission Provider;
(8)
Impedance requirements for power transformers,
phase angle regulators, series reactors and series
capacitors when determined necessary by planning
studies performed by the Transmission Provider;
and
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(9)
Limitations on and/or requirements for protection
systems when determined applicable by a planning
driver or Applicable Reliability Standard or in order
to ensure a compatible interconnection with existing
protection systems associated with existing
transmission facilities to which the New
Transmission Facilities will interconnect.
c.
Other Requirements of Transmission Proposal Requests. The
Transmission Provider reserves the right to specify in Transmission
Proposal Requests, if deemed necessary and/or appropriate, additional
information for any specific New Transmission Line Facilities and/or New
Substation Facilities.
3.
Contents of New Transmission Proposals. New Transmission Proposal
Applicants that submit a New Transmission Proposal in response to a
Transmission Proposal Request must submit all data required by the Transmission
Proposal Request, including, but not limited to:
(1)
Documentation of satisfaction of general requirements for Qualified
Transmission Developers;
(2)
Cost estimate data for each proposed New Transmission Line Facility
and/or New Substation Facility;
(3)
Reasonably descriptive facility design proposals for each New Substation
Facility and/or New Transmission Line Facility included in the Open
Transmission Project;
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(4)
Documentation of project implementation capabilities;
(5)
Documentation of operations, maintenance, repair, and replacement
capabilities;
(6)
Modeling data files for all proposed New Transmission Line Facilities
and/or New Substation Facilities included in the Open Transmission
Project; and
(7)
Descriptions of relevant partnerships or agreements (if applicable).
4. General Requirements for Qualified Transmission Developers. The general
requirements applicable to Qualified Transmission Developers include, but are
not limited to:
(1)
Agreement to execute the ISO Agreement if designated as the Selected
Transmission Developer in the evaluation process to develop, own and
operate New Substation Facilities and/or New Transmission Line
Facilities after the facilities have been constructed but prior to
energization of such New Transmission Facilities, unless New
Transmission Proposal Applicant is already a Transmission Owner;
(2)
Agreement to comply with all Applicable Laws and Regulations, codes,
and standards governing the engineering, design, construction, operation,
and maintenance of transmission facilities including, but not limited to,
federal laws, state laws, local laws, state and local building codes, federal
regulatory requirements, state and local regulatory requirements, state and
local licensing authorities, the National Electric Safety Code, the National
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Electric Code, Applicable Reliability Standards, and Good Utility
Practice;
(3)
Agreement to register with NERC as the transmission owner (TO),
transmission operator (TOP) and transmission planner (TP), as defined by
NERC, for all transmission facilities which the Selected Transmission
Developer will own that are to be part of the Transmission System;
(4)
Agreement to either i) contract with the interconnecting Local Balancing
Authority (LBA) to include the New Transmission Facilities within the
boundaries of the LBA and demonstrate to the satisfaction of the
Transmission Provider and per agreement by the LBA that applicable
LBA-related tasks associated with the proposed New Transmission
Facilities that are delegated to an LBA by the Balancing Authority
Agreement will be carried out either by the LBA or the Selected
Transmission Developer; or ii) execute the Balancing Authority
Agreement, register with NERC as a Balancing Authority (BA), and be
designated as the Local Balancing Authority for the proposed New
Transmission Facilities, unless the New Transmission Proposal Applicant
is already registered with NERC as a BA and designated as an LBA for
one or more of the existing facilities that interconnect directly with the
New Transmission Facilities associated with the Open Transmission
Project in question;
(5)
Agreement to comply with the FERC Form 715 Part 4 TRPC,
Transmission Planning Criteria and Guidelines on file with FERC and
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established by each incumbent Transmission Owner whose existing
transmission facilities will interconnect directly with the New
Transmission Line Facilities and/or New Substation Facilities;
(6)
Agreement to comply with current requirements and standards regarding
the interconnection of transmission facilities published by each
Transmission Owner to which New Transmission Line Facilities and/or
New Substation Facilities will interconnect including, but not limited to,
those standards and requirements required for compliance with the
applicable NERC Facilities Design, Connections, and Maintenance
(“FAC”) reliability standards; and
(7)
Submission of a business plan outlining the strategy and process to obtain
project financing and/or credit rating information applicable to the
entity’s organization from Standard and Poor’s, Moody’s, or Fitch.
5.
Cost Estimates. Proposed cost estimate data must be based on the reasonably
descriptive facility design proposals submitted in the New Transmission Proposal
and will include, at a minimum:
(1)
Estimated project cost for each proposed New Transmission Line
Facility and/or New Substation Facility; and
(2)
Estimated annual revenue requirements for the first 40 years the
facilities included in the New Transmission Proposal will be in
service.
6.
Reasonably Descriptive Facility Design Proposals. Reasonably descriptive
facility design proposals must be submitted for each New Transmission Line
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Facility and/or New Substation Facility included in the Open Transmission
Project. Reasonably descriptive facility design proposals represent descriptions of
the core attributes and features of a design, not the detailed engineering and
design calculations and documents.
a.
Reasonably Descriptive Facility Design Proposals for New
Transmission Facilities. For each New Transmission Line Facility,
reasonably descriptive facility design proposals must include, at a
minimum:
(1)
Estimated length of New Transmission Line Facility in miles and
basis for estimate;
(2)
Proposed conductor type, size, and, if applicable, bundling
configuration;
(3)
Proposed default or typical structure design attribute(s) (e.g., steel
vs. wood vs. aluminum vs. concrete, monopole vs. H-frame vs.
lattice, single circuit vs. double circuit, self-supporting vs. guyed,
structural calculation assumptions, etc.) to be used for tangent,
running angle, in-line dead-end, and angle dead-end structures
when feasible and/or for the majority of the New Transmission
Line Facility;
(4)
Estimated positive sequence line impedance and pi-equivalent
shunt susceptance;
(5)
Calculated normal and emergency seasonal thermal loading
ratings, including basis for calculations;
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(6)
Proposed type of lightning protection system to be used when
feasible and/or for the majority of the New Transmission Line
Facility (e.g., shield wires vs. surge arresters, etc.) and key
attributes (e.g., shielding angle, arrester location and type, etc.);
(7)
Proposed grounding method to be used when feasible and/or for
the majority of the New Transmission Line Facility (e.g., ground
rods only, counterpoise, etc.) and key attributes (e.g., targeted
structure footing grounding resistance, etc.);
(8)
Proposed method to address or mitigate adverse impacts of
galloping conductors and/or Aeolian vibration, if any (e.g.,
Stockbridge dampers, special conductors, etc.);
(9)
Continuous rating of any load carrying switchgear installed on the
New Transmission Line Facility; and
(10)
Assumed communications systems to be used for the New
Transmission Line Facility to facilitate protective relaying (e.g.,
fiber optic, power line carrier, microwave, etc.).
b.
Reasonably Descriptive Facility Design Proposals for New Substation
Facilities. For New Substation Facilities, reasonably descriptive facility
design proposals must include, at a minimum:
(1)
Detailed one-line diagram;
(2)
Proposed protection systems including protection schemes, any
anticipated interaction with existing/other facilities and
conceptual protection system design (including backup
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protection systems, if applicable). Remote system monitoring
capability shall be described with major features listed
(redundancy, monitored parameters, etc.);
(3)
Detailed specifications for proposed power transformers;
(4)
Description of other substation equipment items, including load
ratings, voltage ratings, fault interrupting ratings, tap data, and
impedances as applicable, where other substation equipment
includes, but is not limited to, bus sections, circuit breakers,
circuit switchers, switches, disconnects, regulating
transformers, station service transformers, series and shunt
capacitors, series and shunt reactors, static VAR compensators,
DC conversion equipment, instrument transformers (metering
and relaying), wave traps, and surge arresters;
(5)
Proposed line terminal ratings and basis for calculation,
including limiting element;
(6)
Basis for load rating calculations on any equipment where
nameplate continuous ratings are not used; and
(7)
Description of the communication system for remote
monitoring, control and data acquisition facilities, including
monitoring and control points.
Any specific Transmission Proposal Request may require
submission of additional facility design data when deemed
necessary by the Transmission Provider. Any New
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Transmission Proposal may also include additional facility
data, including but not limited to, optional facility design data
listed in the Business Practices Manual for Transmission
Planning, which may be considered by the Transmission
Provider in the evaluation and selection of New Transmission
Proposals.
7.
Project Implementation Capabilities. Documentation of project
implementation capabilities required in a New Transmission Proposal must
include documented processes and methods to be used by the entity to perform:
(1)
Project management;
(2)
Routing evaluation studies for New Transmission Line Facilities, if
applicable;
(3)
Site evaluation studies for New Substation Facilities, if applicable;
(4)
Regulatory permitting;
(5)
Right-of-way acquisition for New Transmission Line Facilities, if
applicable;
(6)
Land acquisition for New Substation Facilities, if applicable;
(7)
Engineering and surveying required for New Transmission Line
Facilities and/or New Substation Facilities;
(8)
Material procurement for New Transmission Line Facilities and/or
New Substation Facilities;
(9)
Construction of New Transmission Line Facilities and/or New
Substation Facilities; and
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(10)
Commissioning of New Transmission Line Facilities and/or New
Substation Facilities.
Any specific Transmission Proposal Request may require submission of
additional data related to the policies, processes, methods, capabilities,
experience, and past performance of New Transmission Proposal Applicants
regarding project implementation when deemed necessary by the Transmission
Provider.
Any New Transmission Proposal may also include additional information
regarding project implementation capabilities, including but not limited to,
existing capabilities and past experience regarding project implementation, which
may be considered by the Transmission Provider in the evaluation and selection
of New Transmission Proposals.
8.
Operations, Maintenance, Repair, and Replacement Capabilities.
Documentation of operations, maintenance, repair, and replacement capabilities
required in a New Transmission Proposal must include documented processes and
methods to be used by the New Transmission Proposal Applicant to perform the
following as applicable depending on types of facilities included in the Open
Transmission Project:
(1)
Forced outage response for transmission line circuits;
(2)
Forced outage response for substations;
(3)
Switching for transmission line circuits;
(4)
Switching for substations;
(5)
Transmission line emergency repair;
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(6)
Substation emergency repair and testing;
(7)
Transmission line preventative and/or predictive maintenance,
including vegetation management;
(8)
Substation preventative and/or predictive maintenance including
equipment testing;
(9)
Maintenance and management of spare parts, spare structures, and/or
spare equipment inventories for substations and/or transmission lines,
as applicable, including description of any agreements to share spare
equipment, spare parts, and/or spare structures with other transmission
entities;
(10)
Real-time operations monitoring and control capabilities, if the Open
Transmission Project contains one or more New Substation Facilities;
and
(11)
Major facility replacements or rebuilds required as a result of
catastrophic destruction or natural aging through normal wear and tear,
including financial strategy to facilitate timely replacements and/or
rebuilds.
Any specific Transmission Proposal Request may require submission of
additional data related to the policies, processes, methods, capabilities,
experience, and past performance of entities regarding operations, maintenance,
repair, and replacement when deemed necessary by the Transmission Provider.
Additional information regarding operations, maintenance, repair, and
replacement capabilities may also be included in any New Transmission Proposal,
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including but not limited to, existing capabilities and past experience regarding
operations, maintenance, repair and replacement, which may be considered by the
Transmission Provider in the evaluation and selection of New Transmission
Proposals.
9.
Transmission Provider Planning Process Participation Documentation.
While not required, should a New Transmission Proposal Applicant participate in
the Transmission Provider planning process and desire to have such participation
considered in the evaluation as described in Section VIII.G of this Attachment FF,
the New Transmission Proposal Applicant should include in its New
Transmission Proposal documentation regarding relevant planning studies
performed by the New Transmission Proposal Applicant and results supplied to
the Transmission Provider planning process, as well as documentation on past
transmission project ideas submitted by the New Transmission Proposal
Applicant to the Transmission Provider to address the same Transmission Issues
being addressed by the Open Transmission Project for which the New
Transmission Proposal is being submitted.
10.
Modeling Data. Modeling data files submitted with the New Transmission
Proposal must meet the requirements outlined in the Business Practices Manual
for Transmission Planning, including, at a minimum, data files necessary:
(1)
To model New Transmission Line Facilities and/or New Substation
Facilities in power flow and short-circuit models and
(2)
To model new contingencies associated with New Transmission Lines
Facilities and/or New Substation Facilities.
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11.
Period for Submission of New Transmission Proposals. New Transmission
Proposals must be submitted within 180 calendar days from the date the
Transmission Proposal Request is posted, or within the time period specified in
the Transmission Proposal Request, whichever comes first. If the due date falls
on a federal holiday, Saturday, or Sunday, the New Transmission Proposals will
be due on the next business day. Two copies of the New Transmission Proposal
in hard copy form must be delivered to the address specified in the Transmission
Proposal Request no later than 5:00 PM EPT on the due date and one electronic
copy of the New Transmission Proposal must be e-mailed to the e-mail address
specified in the Transmission Proposal Request no later than 5:00 PM EPT on the
due date. Any inquiries by New Transmission Proposal Applicants regarding a
Transmission Proposal Request prior to submission of a New Transmission
Proposal should be made directly with the contacts listed in the Transmission
Proposal Request and not to the interconnecting incumbent Transmission Owners.
12.
Additional Data Requests. If, during the evaluation of New Transmission
Proposals, the Transmission Provider determines that additional information is
required to evaluate the Qualified Transmission Developers, the Transmission
Provider will request, in writing, the additional data from all Qualified
Transmission Developers, along with the timeframe that this data must be
submitted within. If the additional data is not submitted within the specified
timeframe, the New Transmission Proposal will not be evaluated or considered
further. This timeframe will not be less than ten (10) business days from when
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the Transmission Provider issues the additional data request. This data request
will not extend the evaluation timeframe defined in Section VIII.G.
13.
Confidential Treatment of New Transmission Proposals. All information
submitted with the New Transmission Proposal will be considered Confidential
Information and will not be publicly posted or shared with any individual, except
employees of the Transmission Provider, applicable state parties who have elected
to choose the Selected Transmission developers, as specified in Section VIII.A of
this Attachment FF, and/or contractors of the Transmission Provider that have
executed an appropriate non-disclosure agreement.
E.
Developer Qualifications. Any New Transmission Proposal Applicant may
submit a New Transmission Proposal, but must meet the minimum qualifications required for a
Qualified Transmission Developer in order for the Transmission Provider to accept and consider
the New Transmission Proposal. A New Transmission Proposal Applicant must either be a
Transmission Owner as defined in this Tariff or a Non-owner Member as defined in the ISO
Agreement at the time the Transmission Proposal Request is posted, and must maintain such
status throughout the entire process of evaluation and selection of New Transmission Proposals
and project implementation, provided that a Non-owner Member must become a Transmission
Owner. To be eligible to be considered a Qualified Transmission Developer, a New
Transmission Proposal Applicant that submits a New Transmission Proposal must include
therein all the agreements specified in Section VIII.D of this Attachment FF. Furthermore, a
New Transmission Proposal Applicant will not be considered a Qualified Transmission
Developer if all required data specified in the Transmission Proposal Request, including, but not
limited to, the required data outlined in Section VIII.D of this Attachment FF, is not included in
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the New Transmission Proposal as required by Sections VIII.D and VIII.F of this Attachment
FF.
F.
Cure Period. Immediately after the date New Transmission Proposals are due,
the Transmission Provider will review each New Transmission Proposal to ensure all
qualifications and data requirements have been satisfied by each respective New Transmission
Proposal Applicant. Should a New Transmission Proposal fail to satisfy one or more of the
qualifications or data requirements specified in this Tariff and/or in the Transmission Proposal
Request, the Transmission Provider will, within ten (10) business days, via e-mail notify the
submitting New Transmission Proposal Applicant, through the contact person designated in the
New Transmission Proposal, of any deficiency, and that New Transmission Proposal Applicant
will have a single Cure Period of ten (10) business days from this notice to revise and resubmit
the New Transmission Proposal to address the deficiency, except that if the New Transmission
Proposal Applicant is neither a Non-owner Member nor a Transmission Owner on the date the
Transmission Proposal Request was posted or ceases to become a Non-owner Member or
Transmission Owner after the date the Transmission Proposal Request was posted, that New
Transmission Proposal Applicant shall not be designated a Qualified Transmission Developer
and the New Transmission Proposal will not be evaluated or considered further. If a revised
New Transmission Proposal is submitted after the Cure Period has elapsed, or continues to have
one or more deficiencies with regard to qualifications or data requirements, the New
Transmission Proposal Applicant shall not be designated a Qualified Transmission Provider and
the New Transmission Proposal will not be evaluated or considered further. The Transmission
Provider will provide a written explanation identifying why the New Transmission Proposal
Applicant has been disqualified.
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G.
Evaluation
1.
Steps of Evaluation and Selection Process. Upon receipt of all New
Transmission Proposals, sufficient in form and substance, by the due date
specified in the Transmission Proposal Request, and upon completion of
the process outlined in Section VIII.F of this Attachment FF,
notwithstanding the authority of states to elect to choose the Selected
Transmission Developer within 360 days of the Transmission Proposal
Request, the Transmission Provider will:
(1)
Evaluate each New Transmission Proposal submitted by a
Qualified Transmission Developer;
(2)
Select one of the New Transmission Proposals for
implementation based on application of the evaluation criteria
below; and
(3)
Post the name of the Selected Transmission Developer on its
website within 180 calendar days of the due date for the
submission of New Transmission Proposals for the selection of
the developer either by a competent state regulatory authority
that chooses to make the selection, or by the Transmission
Provider, or within 450 calendar days from the posting of the
Transmission Proposal Request if a state initially elects to
perform an evaluation of the New Transmission Proposals
submitted for an Open Transmission Project and then the
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Transmission Provider assumes responsibility for performing
evaluation as outlined in Section VIII.B of this Attachment FF.
2.
General Criteria. In evaluating each New Transmission Proposal, the
Transmission Provider will consider the following general aspects of the
proposal:
3.
(1)
Cost and reasonably descriptive facility design quality;
(2)
Project implementation capabilities;
(3)
Operations, maintenance, repair, and replacement capabilities; and
(4)
Transmission Provider planning process participation.
Cost and Reasonably Descriptive Facility Design. When considering
cost and reasonably descriptive facility design quality, the Transmission
Provider shall evaluate, at a minimum:
(1)
Estimated project cost for each proposed New Transmission Line
Facility and/or New Substation Facility;
(2)
Estimated annual revenue requirements for all New Transmission
Facilities included in the New Transmission Proposal;
(3)
Cost estimate rigor, which shall include financial assumptions and
supporting information to clearly demonstrate a thorough analysis
in support of the cost estimate;
(4)
Reasonably descriptive facility design quality; and
(5)
Reasonably descriptive facility design rigor, which shall include
facility studies performed and other specific supporting data that
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clearly documents and supports consideration and attention given
to the proposed reasonably descriptive facility designs.
4.
Project Implementation Capabilities. When considering project
implementation capabilities, the Transmission Provider shall evaluate, at a
minimum, existing or planned capabilities and processes regarding:
5.
(1)
Project management;
(2)
Route and site evaluation;
(3)
Land acquisition;
(4)
Engineering and surveying;
(5)
Material procurement;
(6)
Facility construction;
(7)
Final facility commissioning; and
(8)
Previous applicable experience and demonstrated ability.
Operations, Maintenance, Repair, and Replacement Capabilities.
When considering operations, maintenance, repair and replacement
capabilities, the Transmission Provider shall evaluate, at a minimum,
existing or planned capabilities and processes regarding the following, as
applicable, based on the types of facilities included in the Transmission
Proposal Request:
(1)
Forced outage response;
(2)
Switching;
(3)
Emergency repair and testing;
(4)
Spare parts;
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(5)
Preventative and/or predictive maintenance and testing;
(6)
Real-time operations monitoring and control; and
(7)
Major facility replacement capabilities, including ongoing
financial capabilities to restore facilities after catastrophic
outages.
6.
Transmission Provider Planning Process Participation. When
considering transmission provider planning process participation, the
Transmission Provider will consider relevant planning studies conducted
by the Qualified Transmission Developer and the associated results
supplied to the Transmission Provider planning process, as well as
transmission project ideas submitted in the past by the Qualified
Transmission Developer as potential solutions to address the same
Transmission Issues addressed by the Open Transmission Project.
7.
General Criteria Weighting. In evaluating each New Transmission
Proposal, the Transmission Provider will apply the following weighting to
each New Transmission Facility criteria evaluated:
a.
New Transmission Line Facilities. The following weights will be
applied to New Transmission Line Facility criteria:
(1)
Cost and reasonably descriptive facility design quality:
30%
(2)
Project implementation capabilities: 35%
(3)
Operations, maintenance, repair, and replacement
capabilities: 30%
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(4)
b.
Transmission Provider planning process participations: 5%
New Substation Facilities. The following weights will be applied
to New Substation Facility criteria:
(1)
Cost and reasonably descriptive facility design quality:
30%
(2)
Project implementation capabilities: 30%
(3)
Operations, maintenance, repair, and replacement
capabilities: 35%
(4)
8.
Transmission Provider planning process participations: 5%
Evaluation and Selection. Specific methods used to evaluate various
aspects of a New Transmission Proposal shall be described in the Business
Practices Manual for Transmission Planning. This evaluation will be
conducted by Transmission Provider planning staff and/or independent
consultants competent in the areas of finance, transmission facility design,
transmission project implementation, and transmission operations,
maintenance, repair, and replacement. The Transmission Provider
planning staff, and any independent consultants, will be overseen by an
executive oversight committee consisting of three or more executive staff
of the Transmission Provider, including at least one officer, and the final
designation of the Selected Transmission Developer will rest with this
committee. The committee shall possess certain specific expertise
necessary for evaluation of New Transmission Proposals, such as, but not
limited to, transmission construction, engineering, project management,
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financing, state regulatory, and operations. Within thirty (30) calendar
days of the designation of the Selected Transmission Developer, the
Transmission Provider will provide a report in which it explains the basis
for designating the Selected Transmission Developer for each Open
Transmission Project. Any disputes regarding the developer selection will
be referred to the Dispute Resolution Process under Attachment HH of
this Tariff.
The Selected Transmission Developer will assume the responsibility and
obligation to construct the facilities it is selected to construct. If the
Selected Transmission Developer is financially incapable of carrying out its
construction responsibilities, alternate construction arrangements shall be
identified. Depending on the specific circumstances, such alternate
arrangements shall include solicitation of Transmission Owners to take on
financial and/or construction responsibilities. If the delay in construction
may adversely affect the Transmission System reliability, the
Transmission Provider shall coordinate with and support the affected
Transmission Owner(s) regarding any mitigation measures that may be
required by Applicable Reliability Standards.
However, in the event that an MTEP Appendix A Open Transmission
Project approved by the Transmission Provider Board or selection of the
designated Selected Transmission Developer to construct the approved
project is being challenged through the Dispute Resolution process under
Attachment HH of this Tariff or a court proceeding, the obligation of the
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Selected Transmission Developer to build the specific Open Transmission
Project (subject to required approvals) is waived until the Open
Transmission Project or Selected Transmission Developer emerges from
the Dispute Resolution process or court proceedings as an approved
project with a Selected Transmission Developer designated to construct,
implement, own, operate, maintain, repair, restore, and/or finance the
recommended Open Transmission Project.
9.
Recourse if No New Transmission Proposals are Received. If no New
Transmission Proposals are received from Qualified Transmission
Developers, the Open Transmission Project will be assigned to the
applicable Transmission Owner(s), as defined below:
(1) Ownership and the responsibility to construct facilities which are
connected to a single Transmission Owner’s system belong to that
Transmission Owner; (2) Ownership and the responsibilities to construct
facilities which are connected between two (2) or more Transmission
Owners’ facilities belong equally to each Transmission Owner, unless such
Transmission Owners otherwise agree; and (3) Ownership and the
responsibility to construct facilities which are connected between a
Transmission Owner(s)’ system and a system or systems that are not part of
the Transmission Provider belong to such Transmission Owner(s) unless the
Transmission Owner(s) and the non-Transmission Provider party or parties
otherwise agree.
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IX.
Reevaluation. After Transmission Provider Board MTEP Appendix A approval, certain
circumstances or events may significantly affect such an Open Transmission Project in a manner
and to a degree that would require the Transmission Provider to perform Variance Analysis.
Such circumstances or events may include, but are not limited to: material schedule delays, cost
increases, or changes to the Selected Transmission Developer’s qualifications, as compared to
the schedule, cost estimates, and qualifications represented in the New Transmission Project
Proposal and/or MTEP Appendix A, as applicable. The Variance Analysis shall consider, among
other things: (i) causes of, or reasons for, any such circumstance or event; (ii) impacts, including
potential reliability impacts of a delay in the Open Transmission Project, canceling the Open
Transmission Project, or replacing the Selected Transmission Developer; (iii) mitigation
measures and responsibilities; and (iv) solutions, and the timetable for the implementation of
such solutions. This process will begin at assignment of an Open Transmission Project and end
when construction begins.
A.
Grounds for Variance Analysis
The following factors shall trigger the Transmission Provider’s Variance Analysis
for an Open Transmission Project. The Variance Analysis will focus on the materiality
of the changes identified and determine the need for full reevaluation.
1.
Cost Increases
Any project cost increase which reduces the benefit-cost ratio of an
economically-driven Open Transmission Project to less than the required
benefit-to-cost threshold, as defined in Section II.B.1.e or Section II.C.7 of
this Attachment FF of the Tariff.
2.
Schedule Delays
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A reported or otherwise identified delay of 6 months or more from the inservice date established in MTEP Appendix A and agreed upon in the
accepted New Transmission Proposal and Binding Proposal Agreement of
any assigned Open Transmission Project. This analysis may also be based
upon failure to obtain necessary regulatory approvals; failure to execute
necessary agreements; or failure to take the actions described in the
Selected Transmission Developer’s accepted New Transmission Proposal.
3.
Deviation From Selected Transmission Developer Qualifications
Material changes in the condition and characteristics of the Selected
Transmission Developer, as described in its accepted New Transmission
Proposal.
Material changes in this subsection may include, but are not limited to,
any delegation or assignment not described in the New Transmission
Proposal of project responsibilities to another entity, including affiliates,
or a partner that is either previously undisclosed, or disclosed but assigned
to or designated for different responsibilities or failure to conform to the
terms described in the Selected Transmission Developer’s accepted New
Transmission Proposal.
B.
Project Reevaluation
If required by the results of the above-described additional analysis, the
Transmission Provider shall perform a reevaluation of the Open Transmission Project
and/or Selected Transmission Developer, including, but not limited to:
1.
Cost Increases
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As applicable and necessary based upon the Variance Analysis, the
Transmission Provider shall use the Open Transmission Project’s current
cost estimate to perform an analysis and determine if said Open
Transmission Project’s currently estimated benefit is sufficient to justify
its continued construction.
2.
Schedule Delays
As necessary based upon the Variance Analysis, the Transmission
Provider shall perform an analysis to determine if the delay in the
achievement of any significant schedule milestone(s) (including, but not
limited to, failure to obtain necessary regulatory approvals) will delay the
applicable Open Transmission Project’s in-service date, and if so, whether
such delay poses risks of adverse impacts on Transmission System
reliability, and what mitigation measures and plan should be implemented.
3.
Deviation From Selected Transmission Developer Qualifications
As necessary based upon the Variance Analysis, the Transmission
Provider shall perform an analysis to determine if the Selected
Transmission Developer remains qualified to construct, implement,
operate, maintain, and/or restore the Open Transmission Project.
C.
Reevaluation Outcomes
Based on all the required analysis described in subparagraphs a and b of this
section, the Transmission Provider may decide to (i) make no change to the Open
Transmission Project; (ii) reassign the Open Transmission Project to a different Qualified
Transmission Developer; (iii) cancel the Open Transmission Project (iv) implement a
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reliability mitigation plan, in coordination with the affected Transmission Owner(s); or
(v) such other remedy or solution as may be appropriate under the circumstances,
including a suitable combination of two or more of the foregoing courses of action.
1.
Reassignment
If a Selected Transmission Developer is found to no longer be a Qualified
Transmission Developer, the applicable Open Transmission Project may
be reassigned. Open Transmission Projects will be offered to the
applicable Transmission Owner, as defined below:
(1) Ownership and the responsibility to construct facilities which are
connected to a single Transmission Owner’s system belong to that
Transmission Owner; (2) Ownership and the responsibilities to construct
facilities which are connected between two (2) or more Owners’ facilities
belong equally to each Transmission Owner, unless such Transmission
Owners otherwise agree; and (3) Ownership and the responsibility to
construct facilities which are connected between a Transmission Owner(s)’
system and a system or systems that are not part of the Transmission
Provider belong to such Transmission Owner(s) unless the Transmission
Owner(s) and the non-Transmission Provider party or parties otherwise
agree.
If the applicable Transmission Owner(s) decline to construct the Open
Transmission Project, it will be reassigned, as applicable, through the
developer evaluation process, as described in Section VIII.F.
2.
Project Cancellation
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Following reevaluation, the Transmission Provider may cancel
economically-driven Open Transmission Projects if (1) cost increases
reduce the benefit-cost ratio to the point where the currently estimated cost
exceed previously defined benefits; and (2) reliability and/or public policy
benefits (if any), are insufficient to justify continuation and completion of
the project.
3.
Reliability Mitigation Plan
If the Transmission Provider’s analysis determines that Transmission
System reliability may be adversely affected by the delay of an assigned
Open Transmission Project, the Transmission Provider shall coordinate
with and support the affected Transmission Owner(s) regarding any
mitigation measures that may be required by Applicable Reliability
Standards. The mitigation measures may include, without limitation, any
one or combination of the following components: i) an updated
implementation plan of the Selected Transmission Developer to meet the
required in-service date; ii) an operating procedure; or iii) an alternative
project to mitigate the reliability violation.
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TAB B
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1.49a Binding Proposal Agreement Version: 0.0.0 Effective: 12/31/9998
An agreement that must be signed by an officer or equivalent official of a New Transmission
Proposal Applicant with the authority to bind the latter; that must be submitted with each New
Transmission Proposal; and that binds the New Transmission Proposal Applicant to the terms of
the New Transmission Proposal and the Transmission Proposal Request, and the applicable
requirements of this Tariff. The Binding Proposal Agreement shall be included as an appendix
to the Transmission Proposal Request.
1.109a Cure Period Version: 0.0.0 Effective: 12/31/9998
A period of time, equal to ten (10) business days, allowed for a New Transmission Proposal
Applicant to correct deficiencies identified by the Transmission Provider in a previously
submitted New Transmission Proposal. The Cure Period commences upon notification of
deficiencies in the New Transmission Proposal by the Transmission Provider.
1.419 Midwest ISO Transmission Expansion Plan (MTEP): Version: 1.0.0 Effective:
12/31/9998
A long range plan used to identify expansions or enhancements to the Transmission System to:
i) support efficiency in bulk power markets; ii) facilitate compliance with documented federal
and state energy laws, regulatory mandates, and regulatory obligations; and iii) maintain
reliability. The MTEP is developed biennially or more frequently, and subject to review and
approval by the Transmission Provider Board. The MTEP shall address Transmission Issues
including, but not necessarily limited to: i) Transmission Issues identified from Facilities
Studies; ii) Transmission Issues associated with Generator Interconnection Projects; iii)
Transmission Issues identified by the Transmission Owners; iv) Transmission Issues identified
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by the Transmission Provider working in collaboration with Transmission Owners, their state
and local regulatory commissions and other stakeholders; and v) the transmission planning
obligations of a Transmission Owner and/or the Transmission Provider, imposed by federal or
state law(s), regulations, or regulatory authorities. The MTEP shall also consider the planning
needs and drivers of adjacent regional transmission organizations (“RTOs”) and other
transmission planning regions to develop long-term inter-regional plans for the benefit of the
combined regions, as and to the extent provided for in joint agreements between the
Transmission Provider and other RTOs, and/or in their respective tariffs.
1.454a New Substation Facility Version: 0.0.0 Effective: 12/31/9998
A transmission substation that does not yet exist and that is proposed within a specific Open
Transmission Project as an electrical substation to be implemented, owned, operated, maintained,
and restored by a Selected Transmission Developer, containing equipment or components
classified as transmission plant. New Substation Facilities do not include upgrades,
modifications and/or expansions to existing substations owned by Transmission Owners that
contain equipment or components classified as transmission plant, where such upgrades,
modifications and/or expansions include but are not limited to: i) expanding or upgrading
facilities within the substation footprint, ii) expanding the substation footprint within the current
site boundaries or iii) procuring additional land adjacent to or near the existing substation site
and expanding the substation footprint into or adding substation facilities on the additional land.
New Substations Facilities also do not include newly constructed transmission substations where
all transmission lines terminating at such substation are owned by an incumbent Transmission
Owner as further described in Section VIII.C of Attachment FF of the Tariff.
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1.455a New Transmission Facility Version: 0.0.0 Effective: 12/31/9998
A New Transmission Line Facility or New Substation Facility.
1.455b New Transmission Line Facility Version: 0.0.0 Effective: 12/31/9998
An entire transmission line or section thereof, containing one or more transmission circuits, that
does not exist prior to the construction of an associated Open Transmission Project as a facility
classified as overhead or underground transmission line plant, and that is proposed within an
associated Open Transmission Project as a transmission line to be implemented, owned, operated
and maintained by a Selected Transmission Developer. New Transmission Line Facilities do not
include upgrades, modifications and/or expansions to existing transmission facilities, as further
described in this Section VIII.C of Attachment FF of the Tariff.
1.455c New Transmission Proposal Version: 0.0.0 Effective: 12/31/9998
A proposal to construct, implement, own, operate, maintain, repair, and restore all New
Transmission Facilities associated with an Open Transmission Project, in response to a
Transmission Proposal Request. Each proposal is considered to be a firm offer of the New
Transmission Proposal Applicant to, at a minimum, perform the following acts if the proposal is
selected: (i) construct, own, operate, maintain, repair and restore the New Transmission
Facility(ies) within the scope of the Open Transmission Project in accordance with the Binding
Proposal Agreement, as well as applicable laws, regulations and standards; (ii) execute the ISO
Agreement; (iii) register with the North American Electric Reliability Corporation (NERC) as
the transmission owner (TO), transmission operator (TOP), transmission planner (TP), and if
applicable, the Local Balancing Authority (LBA) for all New Transmission Facilities associated
with the Open Transmission Project; and (iv) either execute the Balancing Authority Agreement
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and assume the role of LBA for all New Transmission Facilities associated with the Open
Transmission Project or contract with an interconnecting LBA and demonstrate to the
satisfaction of the Transmission Provider and per agreement by the LBA that applicable LBArelated tasks associated with the proposed New Transmission Facilities that are delegated to an
LBA by the Balancing Authority Agreement will be carried out either by the LBA or the
Selected Transmission Developer as required and accepted by FERC.
1.455d New Transmission Proposal Applicant Version: 0.0.0 Effective: 12/31/9998
An entity that submits a New Transmission Proposal in response to a Transmission Proposal
Request.
1.463c Non-owner Member Version: 0.0.0 Effective: 12/31/9998
Non-owner Member as defined in the ISO Agreement.
1.474a OMS Committee Version: 0.0.0 Effective: 12/31/9998
OMS Committee shall be the committee that is composed of members of the Organization of
MISO States, established pursuant to the bylaws of the Organization of MISO States, having the
responsibilities and rights defined in Section I.B of Attachment FF of the Tariff and associated
Business Practices Manual. The OMS Committee has the opportunity to provide input into the
transmission planning, resource adequacy, and transmission cost allocation approach and
processes, and may report periodically to the Transmission Provider Board. To enable it to
exercise the authority described herein, the OMS Committee will be adequately supported by the
Transmission Provider either through reasonable in-kind services or through the provisions of
reasonable funding.
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1.477a Open Transmission Project Version: 0.0.0 Effective: 12/31/9998
A Market Efficiency Project or Multi-Value Project contained in MTEP Appendix A that has
been approved by the Transmission Provider Board and may contain one or more New
Transmission Facilities, subject to Section VIII.A of Attachment FF of this Tariff.
1.528a Qualified Transmission Developer Version: 0.0.0 Effective: 12/31/9998
A New Transmission Proposal Applicant that meets the minimum requirements outlined in a
Transmission Proposal Request and Section VIII of Attachment FF of the Tariff to construct,
implement, own, operate, maintain, repair, and restore New Transmission Facilities.
1.599a Selected Transmission Developer Version: 0.0.0 Effective: 12/31/9998
The Qualified Transmission Developer selected by the Transmission Provider or the applicable
state(s) to construct, implement, own, operate, maintain, repair and restore one or more New
Transmission Facilities, pursuant to Attachment FF of this Tariff.
1.671b Transmission Proposal Request Version: 0.0.0 Effective: 12/31/9998
An invitation, including associated requirements, posted by the Transmission Provider on its
website, to submit a New Transmission Proposal.
1.679 Transmission System: Version: 2.0.0 Effective: 12/31/9998
The transmission facilities owned or controlled by Transmission Owners that have conveyed
functional control to the Transmission Provider, and are used to provide Transmission Service
under Module B of this Tariff. The Transmission System includes transmission facilities owned
or controlled by Transmission Owners, the functional control of which has been transferred to
the Transmission Provider subject to Commission approval under Section 203 of the Federal
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Power Act. In addition, the Transmission System includes other transmission facilities owned or
controlled by the Transmission Owner that are booked to transmission accounts and are not
controlled or operated by the Transmission Provider but are facilities that the Transmission
Owners, by way of the Agency Agreement, have allowed the Transmission Provider to use in
providing service under this Tariff. While not part of the Transmission System, service over
Distribution Facilities is available through the execution of a Service Agreement pursuant to
Schedule 11 of this Tariff. The term Transmission System shall include the Transmission
System (Michigan).
1.692a Variance Analysis Version: 0.0.0 Effective: 12/31/9998
Additional analysis performed by the Transmission Provider planning staff on an approved Open
Transmission Project regarding its scope and schedule when certain circumstances or events
significantly affect the Open Transmission Project. Additional analysis performed by the
Transmission Provider planning staff regarding the Selected Transmission Developer when
certain circumstances or events significantly affect the Selected Transmission Developer.
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ATTACHMENT FF Transmission Expansion Planning Protocol
Version: 8.0.0 Effective: 12/31/9998
ATTACHMENT FF
TRANSMISSION EXPANSION PLANNING PROTOCOL
I.
Transmission Expansion Plan - Purpose and Scope, Definition and Role of OMS
Committee: This Attachment FF describes the process to be used by the Transmission Provider
to develop the Midwest ISO Transmission Expansion Plan (“MTEP”), subject to review and
approval by the Transmission Provider Board. The provisions of this Attachment FF are
consistent with the applicable provisions of Appendix B of the ISO Agreement and this Tariff.
For purposes of this Attachment FF, all references to Transmission Owner(s) will include ITC(s).
The costs incurred by the Transmission Provider in the performance of data collection, analyses
and review, and in the development of the MTEP report, costs incurred under Section I.B of this
Attachment FF, and costs incurred under Section I.C of this Attachment FF shall be recovered
from all Transmission Customers under Schedule 10 of the Tariff.
A.
Enrollment Process: The MTEP is developed to facilitate the timely and orderly
expansion of and/or modification to the Transmission System to maintain reliability, promote
efficiency in bulk power markets and facilitate compliance with applicable Federal and state
laws, regulatory mandates and regulatory obligations. Any transmission provider that wishes to
enroll in the Transmission Provider planning process for purposes of Order No. 1000 compliance
must become a Transmission Owner, by signing the ISO Agreement, and by, within a reasonable
period of time: (1) turning over functional control of its transmission facilities to the
Transmission Provider; and (2) taking service under this Tariff for all its load that is physically
located within the geographic area comprising the Transmission System. All Transmission
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Owners enrolled in the Transmission Provider’s transmission planning region are listed in either
(1) Attachment FF-4 of this Tariff, for Transmission Owners without a separately filed local
planning process or (2) Attachment FF-5 of this Tariff, for Transmission Owners with a
separately filed local planning process.
B.
OMS Committee Input to MTEP Process: To the extent not otherwise
specifically addressed in other portions of this Attachment FF, with respect to the MTEP process,
the OMS Committee may provide input to the Transmission Provider planning staff and the
System Planning Committee of the Transmission Provider Board, as appropriate, regarding the
following:
1.
At the start of a planning cycle, the OMS Committee may suggest to the
Transmission Provider Board modifications to the Transmission Provider’s
planning principles and planning objectives for that planning cycle;
2.
At the start of a planning cycle, the OMS Committee may suggest additional
scope elements in the MTEP;
3.
Modeling inputs or assumptions used in the development of the MTEP and related
appropriate cost/benefit analyses with respect to certain projects that are not
proposed strictly for reliability; and
4.
Concerns about general or specific issues with the MTEP process as they arise
during the planning year.
Furthermore, at the end of the MTEP development process, but before the MTEP is submitted to
the Transmission Provider Board for its review, the OMS Committee may submit a
reconsideration request to the Transmission Provider planning staff, which shall respond prior to
submitting the final MTEP report to the Transmission Provider Board. This reconsideration
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request can be made only with respect to Network Upgrades eligible to receive regional cost
allocation under Attachment FF if such projects: (1) will be recommended to the Transmission
Provider Board for MTEP Appendix A approval, but have not been considered through the
complete MTEP process or (2) will have a change in project cost of twenty-five percent (25%) or
greater between the final Subregional Planning Meeting in the current planning year and the
project being submitted to the Transmission Provider Board for approval. The Transmission
Provider shall consider such a reconsideration request only if it is endorsed by the OMS acting
by a vote of sixty-six percent (66%) or more of the OMS members.
At the end of each MTEP cycle, the OMS Committee may submit its assessment of the MTEP
process to the Planning Advisory Committee, Transmission Provider, and the System Planning
Committee of the Transmission Provider Board. Upon receipt of any such assessment from the
OMS Committee, the Transmission Provider planning staff shall provide an appropriate response
in a reasonably timely manner.
The manner in which the OMS Committee shall provide its assessment shall be set forth in the
Transmission Planning Business Practices Manual procedures. The general procedures adopted
with respect to the OMS Committee input into the MTEP shall remain unchanged until June 1,
2015, unless otherwise mutually agreed to by the Transmission Provider and the OMS
Committee. Changes to the Transmission Planning Business Practices Manual procedures which
describe OMS Committee input into the MTEP process may not be adopted with less than sixty
(60) days’ notice to the OMS Committee unless the OMS Committee consents to such earlier
adoption. At the end of the two year period the Transmission Provider, the OMS, and other
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stakeholders will assess the success of the input procedures and provide suggestions for
improvement.
C.
Development of the MTEP: The Transmission Provider, working in
collaboration with representatives of the Transmission Owners, OMS, and the Planning Advisory
Committee, shall develop the MTEP, consistent with Good Utility Practice and taking into
consideration long-range planning horizons, as appropriate. The Transmission Provider shall
develop the MTEP for expected use patterns and analyze the performance of the Transmission
System in meeting both reliability needs and the needs of the competitive bulk power market,
under a wide variety of contingency conditions. The MTEP will give full consideration to the
needs of all Market Participants, will include consideration of demand-side options, and will
identify expansions or enhancements needed to i) support competition and efficiency in bulk
power markets; ii) comply with Applicable Laws and Regulations; and iii) maintain reliability.
This analysis and planning process shall integrate into the development of the MTEP among
other things:
(i) the Transmission Issues identified from Facilities Studies carried out in connection
with specific transmission service requests; (ii) Transmission Issues associated with
generator interconnection service; (iii) the Transmission Issues, including proposed
transmission projects, identified by the Transmission Owners in connection with their
planning analyses in accordance with local planning process described in Section I.B.1.a
to this Attachment FF and the coordination processes of Section I.B.1.b., or developed by
Transmission Owners utilizing their own FERC-approved local transmission planning
process described in Section I.B.2, as applicable, to provide reliable power supply to their
connected load customers and to expand trading opportunities, better integrate the grid
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and alleviate congestion; (iv) the transmission planning obligations of a Transmission
Owner, imposed by federal or state law(s) or regulatory authorities, which can no longer
be performed solely by the Transmission Owner following transfer of functional control
of its transmission facilities to the Transmission Provider; (v) plans and analyses
developed by the Transmission Provider to provide for a reliable Transmission System
and to expand trading opportunities, better integrate the grid and alleviate congestion; (vi)
the identification, evaluation, and analysis of expansions to enable the Transmission
System to fully support the simultaneous feasibility of all State 1A ARRs; (vii) the inputs
provided by the Planning Advisory Committee; (viii) the inputs, if any, provided by the
state and local regulatory authorities having jurisdiction over any of the Transmission
Owners; and (ix) the inputs of the OMS Committee.
1.
Planning Cycle and Milestones: The ISO Agreement requires that a
regional transmission plan be developed biennially or more frequently. An MTEP
planning cycle is established for each calendar year. The development of the
MTEP for a planning cycle with a given calendar year designation begins on June
1 of the year prior to the MTEP calendar year designation and ends with the
approval of the final MTEP report by the Transmission Provider Board. This
approval typically occurs at the Transmission Provider Board Meeting in
December of the MTEP designated year. For example, the development of the
MTEP14 transmission plan will commence on June 1 of 2013 and typically end
with approval in December 2014. The development of the MTEP will follow
specified process steps that are detailed, including process diagrams, in the
Transmission Provider’s Transmission Planning Business Practices Manual
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(“TPBPM”). The TPBPM shall be posted on the website of the Transmission
Provider.
a.
Planning Functions: The planning process includes the following
functions which are described in detail in the TPBPM:
i.
Model Development;
ii.
Generator Interconnection Planning;
iii.
Transmission Service Planning;
iv.
Cyclical Regional Expansion Planning activities;
v.
Coordinated System Plans with other RTOs/regions;
vi.
System Support Resource (“SSR”) Studies for unit decommissioning;
vii.
Transmission-to-Transmission Interconnections;
viii.
Load Interconnections; and
ix.
Focus Studies. These are studies initiated during the
cyclical baseline planning process that cannot be delayed
until the next planning cycle (for example, NERC/FERC
directives, or near-term critical operational issues).
Each of these planning functions may develop system expansions that are taken
into consideration in developing the entirety of the MTEP.
b.
Planning Cycle: The regional planning process is performed
through a continuous series of planning cycles, with each cycle typically
addressing Transmission Issues through a rolling planning horizon. Each
cycle commences with regional model development, and identification of
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potential expansions from the local planning processes of the
Transmission Owners, and concludes with recommendations to the
Transmission Provider Board of Directors of recommended solutions to
identified Transmission Issues. Transmission Owner plans developed
through local planning processes described in Section I.B.1.a are included
in the beginning of each regional planning cycle as potential alternatives
to local Transmission Issues identified by the Transmission Owners.
The regional planning process evaluates, with stakeholder input
throughout the cycle, the local plans of the Transmission Owners, as one
input to the development of the regional plan. Key milestones in the
typical MTEP development process are listed below and requirements and
timelines for data submittal, review, and comment at each of these
milestone points are described in the TPBPM:
i.
Model development;
ii.
Testing models against applicable planning criteria;
iii.
Development of possible solutions to identified
Transmission Issues;
iv.
Selection of preferred solution;
v.
Determination of funding and cost responsibility; and
vi.
Monitoring progress on solution implementation.
The Transmission Provider shall address each of these milestones
throughout the planning cycle through Sub-regional Planning Meetings,
Planning Subcommittee and Planning Advisory Committee meetings.
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2.
Stakeholders Input in Planning Process: The Transmission Provider shall
facilitate discussions with its Transmission Customers, Transmission Owners,
OMS Committee, and other stakeholders about the Transmission Issues and
solutions involving both transferred and non-transferred facilities, as described in
Section I.B.1 of this Attachment FF.
These discussions will take place at Sub-regional Planning Meetings and at
regularly scheduled meetings of the Transmission Provider’s Planning
Subcommittee, at locations provided by the Transmission Provider and with
communication capabilities for those participants unable to have in person
representation at these meetings. Once the MTEP report for a specific planning
cycle has been completed but prior to recommendation to the Transmission
Provider Board for approval, the Transmission Provider shall seek feedback on
the proposed MTEP, including Network Upgrades recommended for approval,
from the Transmission Provider’s stakeholders and the OMS Committee.
a.
Planning Advisory Committee (“PAC”): The Planning Advisory
Committee is a standing committee reporting to the Transmission
Provider’s Advisory Committee, and functions subject to the Stakeholder
Governance Guide developed by the Stakeholder Governance Working
Group, as approved by the Advisory Committee. The PAC is responsible
for addressing planning policy issues of importance to stakeholders and
within the responsibilities of the Transmission Provider. The PAC charter
is maintained on the Transmission Provider’s website.
b.
Planning Subcommittee (“PS”): The Planning Subcommittee is a
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standing stakeholder-chaired subcommittee of the Planning Advisory
Committee, and functions subject to the Stakeholder Governance Guide
developed by the Stakeholder Governance Working Group, as approved
by the Advisory Committee. Planning Subcommittee membership is open
to interested parties, including, but not limited too: transmission delivery
service and interconnection service customers, marketers, developers,
Transmission Owners, state and local regulatory authorities, federal
regulatory staff, other Market Participants, and all interested parties. The
charter for the committee is developed by stakeholders and is maintained
on the Transmission Provider’s website. The Transmission Provider will
seek guidance from Transmission Owners, state and local regulatory
authorities, and other stakeholders through the Planning Subcommittee
and/or the Planning Advisory Committee prior to the beginning of each
new planning cycle. Guidance will include the scope of planning studies
to be undertaken, the development of future scenarios to be modeled and
analyzed in long-term planning studies, and the development of suitable
models and assumptions to support such studies. The Transmission
Provider will also seek guidance from Transmission Owners, state and
local regulatory authorities, and other stakeholders through the Planning
Subcommittee and/or the Planning Advisory Committee prior to
implementing changes or revisions to the scope, models, and assumptions
during the planning cycle. The Planning Subcommittee and/or the
Planning Advisory Committee may form working groups at the discretion
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of stakeholders to perform specific tasks supporting the planning
processes, such as model development and detail review of study results
and draft plan reports.
c.
Sub-regional Planning Meetings (“SPMs”): The Transmission
Provider shall utilize SPMs to provide opportunity for Transmission
Owners, state and local regulatory authorities, and other stakeholders to
provide input to the planning process, and to carry out the tasks of
coordinating transmission plans among the Transmission Owners. Input
and planned coordination may occur through the use of existing subregional planning groups (“SPGs”) where they exist, or through the
establishment of new sub-regional meeting forums. One or more SPMs
will be used or established for each of the three regional Planning Subregions of the Transmission Provider. Planning Sub-regions shall be
defined based upon the Transmission Provider Planning Sub-regions:
West, Central, and East as defined in Attachment FF-3.
i)
SPM Participants: Participants at an SPM will consist of
representatives of the Transmission Owners operating within the
associated Planning Sub-region that integrate their local planning
processes with the regional process, representatives from state and
local regulatory authorities, and any other parties interested in or
impacted by the planning process. For those Transmission Owners
engaged in local planning under their own FERC approved local
planning processes, such Transmission Owners shall participate in
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the SPM in order to coordinate their planning activities.
Neighboring transmission-owning utilities and regulatory
participants are eligible and encouraged to participate in the SPM
to promote joint planning between the Transmission Provider and
neighboring transmission systems.
ii)
SPM Guidelines. The Sub-regional Planning Meeting
participants shall:
(a)
Make recommendations for a coordinated sub-
regional Plan, after considering sub-regional and regional
needs and alternatives, for the ensuing ten years, for all
transmission facilities in the sub-region;
(b)
Review and comment on proposed Transmission
Owners plans identified in local planning processes
described in Section I.B.1.a. of this Attachment FF, for
additions and modifications to the sub-regional
transmission system, as potential solutions to identify
Transmission Issues and review the transmission plans
developed by those Transmission Owners that have their
own FERC-approved local planning process (described in
Section I.B.2) to ensure coordination of the projects set
forth in such plans with the potential regional planning
solutions developed in the SPM process consistent with the
requirements of Appendix B of the Transmission Owners’
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Agreement;
(c)
Form technical study task forces as required to carry
out the sub-regional planning responsibilities;
(d)
Encourage non-Transmission Provider member
participation to improve understanding by the SPM
participants, the Planning Subcommittee, and the
Transmission Provider staff of facility changes outside the
Transmission Provider Region to ensure the impact of such
changes are considered in the planning studies;
(f)
Promote other stakeholder (i.e., environmental
agencies, and load and generation developers) involvement
in development of the sub-regional plans.
(g)
Recommend to the Planning Subcommittee
proposed sub-regional plans to be included in the MTEP.
In addition, the transmission projects developed by any
Transmission Owner or Owners utilizing the provisions of
their own FERC-approved local planning process shall be
submitted for inclusion in the regional MTEP after being
evaluated by the Transmission Provider in the regional
evaluation of SPMs in accordance with Appendix B of the
Transmission Owners’ Agreement in determining the
Transmission Provider’s recommendation for inclusion in
the MTEP.
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(h)
Reflect, as desired, minority opinions to the
Transmission Provider or the Planning Subcommittee.
i)
SPM Frequency, Location and Agenda:
SPMs should meet at least two times per year or as
otherwise provided for in the TPBPM, to provide
input in the planning process, review plans and
recommend changes, if any, needed to address
stakeholder needs and to coordinate proposed plans.
Meetings involving CEII or confidential materials
shall be handled under Section I.A.12 of this
Attachment FF.
3.
Meeting Notifications: Notice shall be provided by way of email exploder
lists distribution by the Transmission Provider of all SPMs, Planning
Subcommittee, and Planning Advisory Committee meetings. These email
exploder lists are established and maintained by the Transmission Provider and it
is the responsibility of stakeholders to have registered as described on the
Transmission Provider website. Meeting dates, times, locations, and materials
will also be posted on the meeting calendar page of the Transmission Provider’s
website. Meeting notification guidelines are set forth in the stakeholder
developed Stakeholder Governance Guidelines.
4.
Other Meeting Schedules: Planning Subcommittee meetings are regularly
scheduled meetings that occur no less than bimonthly. Annual meeting schedules
and objectives are developed at the December meeting each year for the
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subsequent year. Planning Advisory Committee meetings are scheduled as per
the PAC Charter.
5.
Planning Criteria: The Transmission Provider shall evaluate the system to
address Transmission Issues in a manner consistent with the ISO Agreement and
this Attachment FF. Projects included in the MTEP may be based upon any
applicable planning criteria, including accepted NERC reliability standards and
reliability standards adopted by Regional Entities, local planning reliability or
economic planning criteria of the Transmission Owner, or required by State or
local authorities, and any economic or other planning criteria or metrics defined in
this Attachment FF. Transmission Owners are required to annually provide
updated copies of local planning criteria for posting on the Transmission
Provider’s website.
The Transmission Provider will post on its website an explanation of
which transmission needs driven by public policy requirements will be evaluated
for potential solutions in the local or regional transmission planning process, as
well as an explanation of why other suggested potential transmission needs will
not be evaluated.
6.
Planning Analysis Methods: Planning analyses performed by the
Transmission Provider will test the Transmission System under a wide variety of
conditions as described in Section II and using standard industry applications to
model steady state power flow, angular and voltage stability, short-circuit, and
economic parameters, as determined appropriate by the Transmission Provider to
be compliant with applicable criteria and this Tariff.
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7.
Planning Models: The Transmission Provider shall collaborate with
Transmission Owners, other transmission providers, Transmission Customers, and
other stakeholders to develop appropriate planning models that reflect expected
system conditions for the planning horizon. The planning models shall reflect the
projected Load growth of existing Network Customers and other transmission
service and interconnection commitments. The models shall include any
transmission projects identified in Service Agreements or Interconnection
Agreements that are entered into in association with requests for transmission
delivery service or interconnection service, as determined in Facilities Studies
associated with such requests. Load forecasts applied to models will consider the
forecast Load of Network Customers reported to the Transmission Provider in
accordance with the requirements of Module B and Module E of this Tariff, and
the Business Practices Manuals of the Transmission Provider. Models will be
posted on an FTP site maintained by the Transmission Provider and accessible to
stakeholders with security measures as provided for in the TPBPM. The
Transmission Provider will provide an opportunity for stakeholders to review and
comment on the posted models before commencing planning studies.
The schedules for such reviews are maintained in the TPBPM. Stakeholders shall
be afforded opportunities to provide input on Load projections from Tariff
reporting requirements or from Transmission Owner forecasts. After the base line
forecast and model are established, the Transmission Provider and/or
Transmission Owners may adjust the forecast as necessary on an ad hoc basis
throughout the planning year to address customer requests for new Load
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interconnections arising from on-going dialogue with existing and prospective
customers.
8.
Planning Assumptions: Each MTEP report shall list in detail the planning
assumptions upon which the analyses are based. In general, planning analyses
will be based on the following:
a.
Planning Horizons: The MTEP will identify Transmission Issues
for a minimum planning horizon of five years and a maximum planning
horizon of twenty years.
b.
Load: Load demand will generally be modeled by the
Transmission Provider as the most probable (“50/50”) coincident Load
projection for each Transmission Owner’s service territory, for the season
under study. Specific studies may model alternative Load probabilities or
peak Load for areas within a Transmission Owner’s service territory as
dictated by operational and planning experience and/or local planning
criteria, but in any case shall be treated consistently in the planning for
native Load and transmission access requests.
c.
Generation: Planning models of five years or longer will model
generation, taking into consideration applicable planning reserve
requirements, that are: (i) existing and expected to be in existence in the
planning horizon; (ii) not existing but with executed interconnection
agreements; and (iii) additional generation as determined with stakeholder
input, as necessary to adequately and efficiently meet demand forecasted
through the planning horizon and to facilitate compliance with statutory or
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regulatory mandates. The Transmission Provider shall apply a scenario
analysis to determine alternative future generation portfolio possibilities.
Generation portfolio development for planning model purposes will be
developed with input from the Planning Advisory Committee and its
subcommittees, working groups, and task forces. Point-To-Point
Transmission Service and Network Integration Transmission Service
customers will have an opportunity to guide new generation portfolio
development that is reflective of customer future resource plans.
d.
Demand Response Resources: Planning solutions will be based
upon the best available information regarding the expected amount and
location of Load that can be effectively and efficiently reduced by demand
response or energy efficiency programs, as well as the amount of behindthe-meter generation that can reliably be expected to produce Energy that
could impact planning solutions. The Transmission Provider shall
perform and report on sensitivity analyses that indicate the effectiveness of
potential demand response as alternative planning solutions, to the extent
that appropriate methodology for such analyses is developed with
stakeholders and documented in the TPBPM.
e.
Topology: Each planning study will use the best known topology
based upon the most recently approved MTEP. Planning studies will
include all projects approved by the Transmission Provider Board, and
shall identify, as appropriate, and as detailed in the TPBPM, any system
needs already identified in the most recent approved MTEP.
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9.
Evaluation of Alternatives: When the planning analyses, based on the
foregoing principles, identifies Transmission Issues, the Transmission Provider
will consider the inputs from stakeholders derived from the SPM processes, the
inputs from the Planning Subcommittee and the Planning Advisory Committee,
the plans of any Transmission Owner with its own FERC-approved local planning
process, and the MTEP aggregate system analyses against applicable planning
criteria, in determining the solutions to be included in the MTEP and
recommended to the Transmission Provider Board for implementation.
10.
Facility Design: Facility design and system configuration (such as
conductor sizes, transformer design, bus configuration, protection schemes) are
selected by the Transmission Owner, and must be consistently applied by the
Transmission Owner for comparable system service conditions. Comparable
application of system design does not preclude the consideration or selection of
advanced or alternative transmission technology. For New Transmission
Facilities associated with Open Transmission Projects, the Transmission Provider
may provide limitations or requirements regarding facility design when necessary
due to a planning driver or to ensure compatibility with existing transmission
facilities to which the New Transmission Facilities will interconnect as further
described in Section VIII.D of this Attachment FF.
11.
Status of Recommended Facilities: Upon solicitation from the
Transmission Provider and upon reaching pre-designated milestones in the project
implementation process, the responsible Transmission Owner or Selected
Transmission Developer shall report the status of all projects recommended for
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implementation in the MTEP. Status reports shall, at a minimum, include: (i)
changes to the schedule and to the estimated project cost; (ii) an explanation of
the causes of, or reasons for, any such changes; and (iii) changes in project status
(i.e., under construction, in service, or withdrawn). The Transmission Provider
shall report such progress to the Transmission Provider Board on a quarterly
basis, or as otherwise directed by the Transmission Provider Board.
Status of Developer Qualifications: Upon solicitation from the Transmission
Provider and upon reaching pre-designated milestones in the project
implementation process, Selected Transmission Developers shall report the
following: (i) changes to the developer qualifications, as defined in the Binding
Proposal Agreement, including changes in the developer constructing the project;
(ii) an explanation of the causes of, or reasons for, such changes; and (iii) an
assessment of the impact of the changes on the project. The Transmission
Provider shall report such changes and any impact to the Transmission Provider
Board on a quarterly basis, or as otherwise directed by the Transmission Provider
Board.
12.
Treatment of Critical Energy Infrastructure Information (“CEII”) and
Confidential Data: The Transmission Provider shall utilize a Non-Disclosure and
Confidentiality Agreement (“NDA”) to address sharing of CEII transmission
planning information. FTP sites containing such information will require such
agreements to be executed in order to obtain access to those sites. Stakeholder
meetings at which CEII may be available shall be noticed to email exploders and
shall require execution of NDAs prior to participation in such meetings. In the
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alternative, such meetings will be structured to have separate discussion of issues
involving CEII data only with participants that agree to execute the NDA.
Confidential information related to economic (e.g., congestion) studies, as well as
CEII, is clearly sensitive information which must remain confidential. The
Transmission Provider shall use generic, publicly available, cost information from
industry sources in the economic studies to prevent the accidental release of
confidential information. This approach will promote an open planning process
because the results of economic studies are available to all interested parties.
13.
Resolution of Stakeholder Input: The Transmission Provider shall solicit
input and comments from all stakeholders, including Transmission Owners,
during and after stakeholder planning meetings, and will use reasonable efforts to
reply to comments that the Transmission Provider does not elect to implement,
together with reasons for such actions. The Transmission Provider shall develop
a process for the documentation and resolution of stakeholder issues raised in the
planning process, including but not limited to issues related to planning criteria.
14.
Dispute resolution: Consistent with Attachment HH of this Tariff, the
Transmission Provider shall resolve disputes concerning MTEP issues. The first
step will be for designated representatives of the affected parties to work together
to resolve the relevant issues in a manner that is acceptable to all parties. If that
step is unsuccessful, each affected party shall designate an officer who shall
review disputes involving them that their designated representatives are unable to
resolve. The applicable officers of the parties involved in such dispute shall work
together to resolve the disputes so referred in a manner that meets the interests of
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such parties, either until such agreement is reached, or until an impasse is
declared by any party to such dispute. If such officers are unable to satisfactorily
resolve the issues, the matter shall be referred to mediation. Parties that are not
satisfied with the dispute resolution procedures may only file a complaint with the
Commission during the negotiation or mediation steps.
If a matter remains unresolved, the affected parties may pursue arbitration.
D.
Project Coordination: In the course of the MTEP process, the Transmission
Provider shall seek out opportunities to coordinate or consolidate, where possible, individually
defined transmission projects into more comprehensive cost-effective developments subject to
the limitations imposed by prior commitments and lead-time constraints. The Transmission
Provider shall coordinate with Transmission Owners, and shall consider the input from the
SPMs, Planning Subcommittee, and Planning Advisory Committee to develop expansion plans
to meet the needs of the system. This multi-party collaborative process will allow for all projects
with regional and inter-regional impact to be analyzed for their combined effects on the
Transmission System. Moreover, this collaborative process is designed to ensure that the MTEP
address Transmission Issues within the applicable planning horizon in the most efficient and cost
effective manner, while giving consideration to the inputs from all stakeholders. In addition to
the requirements of this Attachment FF, there may be state or local procedural requirements
applicable to the planning or siting of transmission facilities by the Transmission Owners. A
current list of those requirements can be found on the Transmission Provider’s website.
1.
Transmission Owners Electing to Integrate their Local Planning Processes into the
Transmission Provider’s Processes: Some Transmission Owners have agreed to integrate
internal planning process with the Transmission Provider’s open and coordinated
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planning processes for all of their transmission facilities to comply with Order 890
Planning Principles instead of filing a separate Attachment K. Through this election, the
local planning for all transmission facilities of these Transmission Owners, regardless of
whether the facilities are ultimately transferred to the functional control of the
Transmission Provider, shall be integrated with and included in the regional planning
processes of the Transmission Provider. These regional planning processes, as provided
for in this Attachment FF and in additional detail in the TPBPM, ensure that the planning
decisions for all such facilities are made in an open and transparent environment.
This planning environment provides opportunity for input from, and review by,
stakeholders of the Open Access Transmission Tariff services throughout the planning
process, and is in accordance with the Planning Principles of the Order 890 Final Rule.
The open and transparent planning provisions of this Attachment FF shall not preclude
interaction between stakeholders and Transmission Owners prior to the submittal of
proposed projects to the regional planning process.
Transmission Owners integrating local planning processes into the regional planning
processes are listed in Attachment FF-4. Such Transmission Owners shall be responsible
for providing the Transmission Provider with sufficient information regarding all
planning activities to enable the Transmission Provider to adequately review and
incorporate all of the Transmission Owner’s transmission facilities into the regional
planning process of the Transmission Provider, as described in Sections I.B.1.a. and
I.B.1.b. of this Attachment FF.
The foregoing Transmission Owners will utilize the planning stakeholder forums of the
Transmission Provider to demonstrate the need for, identify the alternatives to, and report
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the status of non-transferred transmission facilities using the same open, transparent and
coordinated planning process provided by the Transmission Provider for transferred
facilities as described in this Attachment FF.
a.
Local Planning Processes of Transmission Owners: In accordance
with the ISO Agreement, each Transmission Owner engages in local
system planning in order to carry out its responsibility for meeting its
respective transmission needs in collaboration with the Transmission
Provider subject to the requirements of applicable state law or regulatory
authority. In meeting its responsibilities under the ISO Agreement, the
Transmission Owners may, as appropriate, develop and propose plans
involving modifications to any of the Transmission Owner’s transmission
facilities which are part of the Transmission System. The Transmission
Owners shall include the following specific local planning steps in order
to develop plans for potential inclusion in the regional plan, in accordance
with the annual regional planning process as described in Section I.B.1.b.
of this Attachment FF, and in accordance with the regional planning
principles of Section I.A of this Attachment. In addition to the local
planning steps below, Transmission Owners shall adhere to any applicable
state or local regulatory planning processes.
i.
Define local study area and study horizon;
ii.
Develop appropriate power system models;
a)
Utilize existing NERC or Transmission Provider
cases to model external systems;
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b)
Insert detailed model of Transmission Owner
system if required;
c)
Insert updated detailed models of neighboring
system models if required; and
d)
iii.
Verify model topology and generation.
Update loads (spatial and magnitude) in study area;
a)
Review historical MW and MVAR data to develop
growth trends;
b)
Obtain Load forecasts from customers in study area;
and
c)
Obtain input from local distribution planners in the
study area.
iv.
Perform contingency analysis using applicable
Transmission Owner planning criteria;
v.
Identify any violations to planning criteria for each of study
period;
vi.
Develop alternative solutions to the criteria violations and
test against the planning criteria;
a)
Obtain cost estimates for each alternative and
perform economic analyses; and
b)
Determine non-cost attributes of each alternative
such as operating flexibility, robustness, among others.
vii.
Select alternative based on cost and non-cost attributes;
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viii.
Submit proposed solution and list of alternatives and
assumptions to the Transmission Provider;
ix.
Participate in stakeholder evaluations and discussions as a
part of annual regional plan development process;
x.
Perform additional analysis as required based on feedback
from stakeholder groups (SPM/PS) in the regional planning
process;
xi.
Submit results of additional analysis (if performed) to the
Transmission Provider for further discussion with stakeholders
(SPM/PS);
xii.
Consider regional planning process results, including
stakeholder feedback on needs, proposed solutions, and
alternatives, in determining whether or not to proceed with
implementation of Transmission Owner proposed expansions; and
xiii.
Post the planning criteria and assumptions, and power flow
models used in development of each Transmission Owner’s current
local planning proposal in accordance with Section I.B.1.b below.
To the extent that the Transmission Owner uses the Midwest ISO
MTEP models in developing its list of newly proposed projects,
the Transmission Owner shall indicate as per Section I.B.1.b.
below, the associated MTEP model used.
The Transmission Provider will maintain a link to applicable
MTEP models on its website together with instructions for
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accessing such models consistent with CEII criteria and suitable
non-disclosure agreements. In the event that the Transmission
Owner applies its own power flow models in developing its
proposed local plans, the Transmission Owner shall provide such
models to the Transmission Provider for posting, or shall provide
to the Transmission Provider a link to the location of such
Transmission Owner model(s) and to instructions for accessing
such models consistent with the Transmission Owner’s CEII and
non-disclosure requirements. Transmission Provider shall post on
its website links to such postings on Transmission Owner’s
website.
b.
Integration of Local Planning Processes of Transmission Owners:
Transmission Owners listed on Attachment FF-4 as integrating local
planning processes with those of the Transmission Provider, shall integrate
proposals for transmission expansions into the regional planning process
as follows. Each Transmission Owner shall submit its proposals for
transmission plans to the Transmission Provider prior to the start of each
regional planning cycle. Each Transmission Owner’s local plan, which
consists of a list of proposed projects, shall be made available on the
Transmission Provider’s website for review by the PAC, the PS, and the
SPM participants, subject to CEII and the confidentiality provisions in this
Attachment FF. Such local plans shall be posted by September 15 each
year in order to provide time for written comments by stakeholders. In
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addition to the list of proposed projects, each Transmission Owner
submitting newly proposed projects by September 15 in any MTEP annual
cycle shall provide to the Transmission Provider by June 1 of the same
year identification of any Midwest ISO base power flow model used by
the Transmission Owner in support of the identification of the list of
proposed projects to be subsequently posted in September, or in the event
that the Transmission Owner uses a non-Midwest ISO base power flow
model in support of the identification of the list of proposed projects the
Transmission Owner shall provide to the Transmission Provider such base
power flow model or a link to the power flow model and assumptions
used.
Each Transmission Owner’s local planning model and associated
assumptions shall be accessible on or through a link on the Transmission
Provider’s website for review, subject to CEII and the confidentiality
provisions in this Attachment FF and consistent with section I.B.1.a. In
the event that the Transmission Owner uses a non-Midwest ISO base
power flow model, the Transmission Owner shall provide for posting
updates if there are significant changes in the model by July 15, August
15, and September 15 of each year. Comments by stakeholders on the
local planning models and assumptions that are provided to the
Transmission Provider SPM Planning Contact by July 1, or August 1 or
September 1 with respect to updates, shall be forwarded to the applicable
Transmission Owner by July 8, August 8, or September 8, respectively.
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The Transmission Provider shall address any unresolved stakeholder
issues through the SPM process.
Each Transmission Owner shall also provide to the Transmission Provider
by June 1 of each year any updates to the posted transmission planning
criteria, or a notification that the posted documents have not changed. In
the event a Transmission Owner has additional significant updates to the
posted transmission planning criteria, the Transmission Owner shall
provide such updates for posting by July 15, August 15, and September 15
of each year.
The Transmission Provider shall post on its website the lists of newly
proposed projects, criteria and assumptions, and supporting base power
flow models or links to supporting base power flow models, as provided
by the Transmission Owners. Initial comments by stakeholders to the
proposed projects should be provided to the Transmission Provider SPM
Planning Contact 45 days after the posting of local plans otherwise
comments may be made pursuant to Section I.A.2.c.ii. The Transmission
Provider SPM Planning Contact shall be identified on the Transmission
Provider’s web site page devoted to Expansion Planning. The
Transmission Provider shall provide to the applicable Transmission Owner
within five working days of receipt, a copy of all stakeholder comments
received within 45 days of the posted information regarding Transmission
Owner planning criteria and assumptions, models applied, and list of
proposed projects. The Transmission Provider shall address any
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unresolved stakeholder issues through the SPM process. Each
Transmission Owner must participate in SPMs in the respective Planning
sub-region as indicated in the Transmission Providers meeting schedule.
Such SPMs shall provide input to and review of the results of the needs
assessments and adequacy of plans proposed by the Transmission Owners,
or by stakeholders to the planning process, or by the Transmission
Provider, to best meet the needs of the sub-region.
Transmission Owners identified in Attachment FF-4, must submit to the
Transmission Provider, on an annual basis and at a time to be determined
by the Transmission Provider, which shall be prior to the beginning of
each regional planning cycle, all proposed transmission plans for both
transferred and non-transferred transmission facilities. The submitted
projects of such Transmission Owners shall be considered potential
alternatives to system needs identified, and as such must be submitted
when initially identified as a potential system solution, in order to permit
the evaluation of such projects along with other potential alternatives that
may be proposed by stakeholders or the Transmission Provider, in the
SPM processes. Such alternatives may include transmission, generation,
and demand-side resources. The Transmission Provider will review and
evaluate such alternatives on a comparable basis and select the most
appropriate solution. Comparability includes the ability of the
Transmission Provider to obtain contractual assurances that the selected
solution will be implemented by the required in-service dates. Contractual
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commitments associated with the construction of an MTEP Appendix A
approved project by Midwest ISO Transmission Owner(s) and/or Selected
Transmission Developer(s) are provided for by the ISO Agreement, this
Tariff, and the Binding Proposal Agreement.
Contractual commitments associated with generation solutions require that
a generator interconnection agreement be filed with the Commission
pursuant to Attachment X of this Tariff by the time the alternative
transmission solution would need to be committed to in order to ensure
installation on the required need date. Contractual commitments
associated with demand-side resource solutions require demonstration to
the Transmission Provider of an executed contract between LSE and EndUse Customers. Such demand-side contracts must be in place by the time
that the transmission solution would otherwise need to be committed to in
order to ensure a timely solution to the identified planning need, and must
be of a sufficient duration such that a reliable solution can be assured
through the planning horizon. Notwithstanding the provisions of Section
VII of the ISO Agreement regarding the Transmission Provider review of
Transmission Owner plans, no proposed project of a Transmission Owner
that has elected to integrate their local planning processes into the
Transmission Provider’s processes, as indicated on Attachment FF-4, shall
be recommended in the MTEP for implementation until completion of the
annual needs analysis carried out in the annual MTEP cycle, as described
in Section I. A. of this Attachment FF, except as provided for in Section
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I.B.1.c. of this Attachment FF.
c.
Out-of-Cycle Review of Transmission Owner Plans: In the event
that a Transmission Owner determines that system conditions warrant the
urgent development of system enhancements that would be jeopardized
unless the Transmission Provider performs an expedited review of the
impacts of the project, Transmission Provider shall use a streamlined
approval process for reviewing and approving projects proposed by the
Transmission Owners so that decisions will be provided to the Owner
within thirty (30) days of the projects submittal to the Midwest ISO unless
a longer review period is mutually agreed upon.
2.
Transmission Owners Filing Separate Attachment K: Some Transmission
Owners as listed on the last page of Attachment FF-4 have developed individual
open, local planning processes for their facilities, that comply with the Planning
Principles of the Order 890 Final Rule. These Transmission Owners have an
Attachment K that describes how the Transmission Owner will comply with the
Order No. 890 Planning Principles for all transmission facilities that they plan for,
regardless of whether those facilities are ultimately transferred to the functional
control of the Transmission Provider. With the exception of Sections I.B.1.a and
I.B.1.b., the provisions of this Attachment FF remain applicable to all
Transmission Owners notwithstanding the filing by any Transmission Owner of
an Attachment K pursuant to the Order 890 Final Rule.
E.
Joint Regional Planning Coordination: The MTEP shall be developed in
accordance with the principles of interregional coordination through collaboration with
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representatives from adjacent transmission providers, their designated regional planning
organizations, or regional transmission organizations, as provided for in this Attachment FF, or
as otherwise provided for in existing joint agreements between the Transmission Provider and
other regional entities that engage in planning activities. The Transmission Provider has joint
operating and coordination agreements with MAPPCOR, as contractor for Mid-Continent Area
Power Pool (“MAPP”), the PJM Interconnection (“PJM”), Southwest Power Pool (“SPP”),
Tennessee Valley Authority (“TVA”), and Manitoba Hydro (Manitoba). Because TVA is nonjurisdictional, that agreement has not been submitted for Commission approval, but is available
on the Transmission Provider’s public website.
1.
Initial Contact: The Transmission Provider will initiate a meeting with
representatives of adjacent transmission providers, their designated regional
planning organizations, or regional transmission organizations with which
existing joint agreements are not already established with the Transmission
Provider (“Regional Planning Coordination Entities” or “RPCEs”), in order to
establish a Joint Planning Committee.
2.
Joint Planning Committee. The Transmission Provider shall offer to form
a Joint Planning Committee (“JPC”) with the RPCE. The JPC shall be comprised
of representatives of the Transmission Provider and the RPCE in numbers and
functions to be identified from time to time. The JPC may combine with or
participate in similarly established joint planning committees amongst multiple
RPCEs or established under joint agreements to which the Transmission Provider
is a signatory, for the purpose of providing for broader and more effective interregional planning coordination. The JPC shall have a Chairman. The Chairman
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shall be responsible for: the scheduling of meetings; the preparation of agendas
for meetings; the production of minutes of meetings; and for chairing JPC
meetings. The Chairmanship shall rotate amongst the Transmission Provider and
the RPCEs on a mutually agreed to schedule, with each party responsible for the
Chairmanship for no more than one planning study cycle in succession. The JPC
shall coordinate planning of the systems of the Transmission Provider and the
RPCEs, including the following:
a.
Coordinate the development of common power system analysis
models to perform coordinated system planning studies including power
flow analyses and stability analyses. For studies of interconnections in
close electrical proximity at the boundaries among the systems of the
Transmission Provider and the RPCEs the JPC or its designated working
group will coordinate the performance of a detailed review of the
appropriateness of applicable power system models.
b.
Conduct, on a regular basis, a Coordinated Regional Transmission
Planning Study (CRTPS), as set forth in Section 8.3.4.
c.
Coordinate planning activities under this Section 8, including the
exchange of data and developing necessary report and study protocols.
d.
Maintain an Internet site and e-mail or other electronic lists for the
communication of information related to the coordinated planning process.
Such sites and lists may be integrated with those existing for the purpose
of communicating the open and transparent planning processes of the
Transmission Provider.
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e.
Meet at least semi-annually to review and coordinate transmission
planning activities.
f.
Establish working groups as necessary to address specific issues,
such as the review and development of the regional plans of the RPCE and
the Transmission Provider, and localized seams issues.
g.
Establish a schedule for the rotation of responsibility for data
management, coordination of analysis activities, report preparation, and
other activities.
3.
Data and Information Exchange. The Transmission Provider shall make
available to each RPCE the following planning data and information. Unless
otherwise indicated, such data and information shall be provided annually. The
Transmission Provider shall provide such data in accordance with the applicable
CEII policy, and maintain data and information received from each RPCE in
accordance with their applicable confidentiality policies.
a.
Data required for the development of power flow cases, and
stability cases, incorporating up to a ten year load forecasts as may be
requested, including all critical assumptions that are used in the
development of these cases.
b.
Fully detailed planning models (up to the next ten (10) years as
requested) on an annual basis and updates as necessary to perform
coordinated studies that reflect system enhancement changes or other
changes.
c.
The regional plan documents, any long-term or short-term
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reliability assessment documents, and any operating assessment reports
produced by the Transmission Provider and the RPCE.
d.
The status of expansion studies, system impact studies and
generation interconnection studies, such that the Transmission Provider
and the RPCE have knowledge that a commitment has been made to a
system enhancement as a result of any such studies.
e.
Transmission system maps for the Transmission Provider and the
RPCE bulk transmission systems and lower voltage transmission system
maps that are relevant to the coordination of planning between or among
the systems.
f.
Contingency lists for use in load flow and stability analyses,
including lists of all contingency events required by applicable NERC or
Regional Entity planning standards, as well as breaker diagrams for the
portions of the Transmission Provider and the RPCE transmission systems
that are relevant to the coordination of planning between or among the
systems. Breaker diagrams to be provided on an as requested basis.
g.
The timing of each planned enhancement, including estimated
completion dates, and indications of the likelihood that a system
enhancement will be completed and whether the system enhancement
should be included in system expansion studies, system impact studies and
generation interconnection studies, and as requested the status of related
applications for regulatory approval. This information shall be provided at
the completion of each planning cycle of the Transmission Provider, and
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more frequently as necessary to indicate changes in status that may be
important to the RPCE system.
h.
Quarterly identification of interconnection requests that have been
received and any long-term firm transmission services that have been
approved, that may impact the operation of the Transmission Provider or
the RPCE system.
i.
Quarterly, the status of all interconnection requests that have been
identified.
j.
Information regarding long-term firm transmission services on all
interfaces relevant to the coordination of planning between or among the
systems.
k.
Load flow data initially will be exchanged in PSS/E format. To
the extent practical, the maintenance and exchange of power system
modeling data will be implemented through databases. When feasible,
transmission maps and breaker diagrams will be provided in an electronic
format agreed upon by the Transmission Provider and the RPCE. Formats
for the exchange of other data will be agreed upon by the Transmission
Provider and the RPCE.
4.
Coordinated System Planning. The Transmission Provider shall agree to
coordinate with the RPCEs studies required to assure the reliable, efficient, and
effective operation of the transmission system. Results of such coordinated
studies will be included in the Coordinated System Plan. The Transmission
Provider shall agree to conduct with the RPCEs such coordinated planning as set
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forth below
a.
Single Entity Planning. The Transmission Provider shall engage in
such transmission planning activities, including expansion plans, system
impact studies, and generator interconnection studies, as necessary to
fulfill its obligations under the Tariff. Such planning shall conform to
applicable reliability requirements of NERC, applicable regional reliability
councils, and any successor organizations thereto.
Such planning shall also conform to any and all applicable requirements of
Federal or State regulatory authorities. The Transmission Provider will
prepare a regional transmission planning report that documents the
procedures, methodologies, and business rules utilized in preparing and
completing the report. The Transmission Provider shall agree to share the
transmission planning reports and assessments with each RPCE, as well as
any information that arises in the performance of its individual planning
activities as is necessary or appropriate for effective coordination among
the Transmission Provider and the RPCEs on an ongoing basis. The
Transmission Provider shall provide such information to the RPCEs in
accordance with the applicable CEII policy and shall maintain such
information received from the RPCEs in accordance with their applicable
confidentiality policies.
b.
Analysis of Interconnection Requests. In accordance with the
procedures under which the Transmission Provider provides
interconnection service, the Transmission Provider will agree to
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coordinate with each RPCE the conduct of any studies required in
determining the impact of a request for generator or merchant transmission
interconnection. Results of such coordinated studies will be included in
the impacts reported to the interconnection customers as appropriate.
Coordination of studies shall include the following:
i.
When the Transmission Provider receives a request under
its interconnection procedures for interconnection, it will
determine whether the interconnection potentially impacts
the system of a RPCE. In that event, the Transmission
Provider will notify the RPCE and convey the information
provided in the interconnection queue posting. The
Transmission Provider will provide the study agreement to
the interconnection customer in accordance with applicable
procedures.
ii.
If the RPCE determines that it may be materially impacted
by an interconnection on the Transmission Provider
System, the RPCE may request participation in the
applicable interconnection studies. The Transmission
Provider will coordinate with the RPCE with respect to the
nature of studies to be performed to test the impacts of the
interconnection on the RPCE System, and who will
perform the studies. The Transmission Provider will strive
to minimize the costs associated with the coordinated study
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process undertaken by agreement with the RPCE.
iii.
Any coordinated studies associated with requests for
interconnection to the Transmission Provider’s system will
be performed in accordance with the study timeline
requirements and scope of the applicable generation
interconnection procedures of the Transmission Provider.
iv.
The RPCE may participate in the coordinated study either
by taking responsibility for performance of studies of its
system, if deemed reasonable by the Transmission
Provider, or by providing input to the studies to be
performed by the Transmission Provider. The study cost
estimates indicated in the study agreement between the
Transmission Provider and the interconnection customer,
will reflect the costs, and the associated roles of the study
participants including the RPCE. The Transmission
Provider will review the cost estimates and scope submitted
by all participants for reasonableness, based on expected
levels of participation, and responsibilities in the study. If
the RPCE agrees to perform any aspects of the study, the
RPCE must comply with the timelines and schedule of the
Transmission Provider’s interconnection procedures.
v.
The Transmission Provider will collect from the
interconnection customer the costs incurred by the RPCE
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associated with the performance of such studies and
forward collected amounts, no later than thirty (30) days
after receipt thereof, to the RPCE. Upon the reasonable
request of the RPCE, the Transmission Provider will make
their books and records available to the requestor pertaining
to such requests for collection and receipt of collected
amounts.
vi.
The Transmission Provider will report the combined list of
any transmission infrastructure improvements on either the
RPCE and/or the Transmission Provider’s system required
as a result of the proposed interconnection.
vii.
Construction and cost responsibility associated with any
transmission infrastructure improvements required as a
result of the proposed interconnection shall be
accomplished under the terms of the applicable OATT,
Transmission Service Guidelines, controlling agreements,
and consistent with applicable Federal or State regulatory
policy and applicable law.
viii.
Each transmission provider will maintain separate
interconnection queues. The JPC will maintain a
composite listing of interconnection requests for all
interconnection projects that have been identified as
potentially impacting the systems of the Transmission
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Provider and coordinating RPCEs. The JPC will post this
listing on the Internet site maintained for the
communication of information related to the coordinated
system planning process.
c.
Analysis of Long-Term Firm Transmission Service Requests. In
accordance with applicable procedures under which the Transmission
Provider provides long-term firm transmission service, the Transmission
Provider will coordinate the conduct of any studies required to determine
the impact of a request for such service. Results of such coordinated
studies will be included in the impacts reported to the transmission service
customers as appropriate. Coordination of studies will include the
following:
i.
The Transmission Provider will coordinate the calculation
of ATC values associated with the service, based on
contingencies on their systems that may be impacted by the
granting of the service.
ii.
When the Transmission Provider receives a request for
long-term firm transmission service, it will determine
whether the request potentially impacts the system of the
RPCE. If the Transmission Provider determines that the
RPCE system is potentially impacted, and that the RPCE
would not receive a transmission service request to
complete the service path, the transmission provider will
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notify the RPCE and convey the information provided in
the posting.
iii.
If the RPCE determines that its system may be materially
impacted by granting the service, it may contact the
Transmission Provider and request participation in the
applicable studies. The Transmission Provider will
coordinate with the RPCE with respect to the nature of
studies to be performed to test the impacts of the requested
service on the RPCE system, and will strive to minimize
the costs associated with the coordinated study process.
The JPC will develop screening procedures to assist in the
identification of service requests that may impact systems
of the JPC members other than the transmission provider
receiving the request.
iv.
Any coordinated studies for request on the transmission
Provider’s system will be performed in accordance with the
study timeline and scope requirements of the applicable
transmission service procedures of the Transmission
Provider.
v.
The RPCE may participate in the coordinated study either
by taking responsibility for performance of studies of its
system, if deemed reasonable by the Transmission Provider
or by providing input to the studies to be performed by the
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Transmission Provider. The study cost estimates indicated
in the study agreement between the Transmission Provider
and the transmission service customer will reflect the costs
and the associated roles of the study participants. The
Transmission Provider will review the cost estimates and
scope submitted by all participants for reasonableness,
based on expected levels of participation and
responsibilities in the study.
vi.
The Transmission Provider will collect from the
transmission service customer, and forward to the RPCE,
the costs incurred by the RPCE with the performance of
such studies.
vii.
The Transmission Provider receiving the request will
identify any transmission infrastructure improvements
required as a result of the transmission service request.
viii.
Construction and cost responsibility associated with any
transmission infrastructure improvements required as a
result of the transmission service request shall be
accomplished under the terms of the applicable OATT,
Transmission Service Guidelines, controlling agreements,
and consistent with applicable Federal or State regulatory
policy and applicable law.
d.
Coordinated Regional Transmission Planning Study: The Transmission
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Provider agrees to participate in the conduct of a periodic Coordinated Regional
Transmission Planning Study (CRTPS). The CRTPS shall have as input the
results of ongoing analyses of requests for interconnection and ongoing analyses
of requests for long-term firm transmission service. The Parties shall coordinate
in the analyses of these ongoing service requests in accordance with Sections
8.3.2 and 8.3.3. The results of the CRTPS shall be an integral part of the
expansion plans of each Party. Construction of upgrades on the Transmission
System of the Transmission Provider that are identified as necessary in the
CRTSP shall be under the terms of the Owners Agreement of the Transmission
Provider, applicable to the construction of upgrades identified in the expansion
planning process. Coordination of studies required for the development of the
Coordinated System Plan will include the following:
i.
Every three years, the Transmission Provider shall
participate in the performance of a CRTPS. Sensitivity
analyses will be performed, as required, during the off
years based on a review by the JPC of discrete reliability
problems or operability issues that arise due to changing
system conditions.
ii.
The CRTPS shall identify all reliability and expansion
issues, and shall propose potential resolutions to be
considered by The Transmission Provider and the
coordinating RPCEs.
iii.
As a result of participation in the CRTPS, except as
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provided for in Section II. A. 1., the Transmission Provider
is not obligated in any way to construct, finance, operate, or
otherwise support any transmission infrastructure
improvements or other transmission-related projects
identified in the CRTPS. Any decision to proceed with any
transmission infrastructure improvements or other
transmission-related projects identified in the CRTPS shall
be based on the applicable reliability, operational and
economic planning criteria established for the Transmission
Provider as applicable to the development of the MTEP and
set forth in this Attachment FF.
iv.
As a result of participation in the CRTPS, the RPCEs are
not entitled to any rights to financial compensation due to
the impact of the transmission plans of the Transmission
Provider upon the RPCE system, including but not limited
to its decisions whether or not to construct any transmission
infrastructure improvements or other transmission-related
projects identified in the CRTPS.
v.
The JPC will develop the scope and procedure for the
CRTPS. The scope of the CRTPSs performed over time
will include evaluations of the transmission systems against
reliability criteria, operational performance criteria, and
economic performance criteria applicable to the
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Transmission Provider and the RPCEs.
vi.
In the conduct of the CRTPS, the Transmission Provider
and the coordinating RPCEs will use planning models that
are developed in accordance with the procedures to be
established by the JPC. Exchange of power flow models
will be in a format that is acceptable to the coordinating
parties.
vii.
Stakeholder Review Processes. The Transmission
Provider, in coordination with coordinating RPCEs shall
review the scope and results of the CRTPS with impacted
stakeholders, and shall modify the study scope as deemed
appropriate by the Transmission Provider in agreement
with the coordinating RPCEs, after receiving stakeholder
input. Such reviews will utilize the existing planning
stakeholder forums of the coordinating parties including as
applicable joint Sub Regional Planning Meetings.
II.
Development Process for MTEP Projects: The Transmission Provider will develop the
MTEP biennially or more frequently. The MTEP will identify expansion projects for inclusion
in the MTEP according to the factors set forth in Appendix B of the ISO Agreement and Section
I.A. of this Attachment FF. For purposes of assigning cost responsibility, expansion projects in
the MTEP shall be categorized pursuant to the following criteria.
A.
Reliability Needs: Reliability projects are identified either in the periodically
performed Baseline Reliability Study, or in Facilities Studies associated with the request
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processes for new transmission access. Transmission access includes requests for both new
transmission delivery service and new generation interconnection service.
1.
Baseline Reliability Projects: Baseline Reliability Projects are Network
Upgrades identified in the base case as required to ensure that the Transmission
System is in compliance with applicable national Electric Reliability Organization
(“ERO”) reliability standards and reliability standards adopted by Regional
Reliability Organizations and applicable within the Transmission Provider
Region. Baseline Reliability Projects include projects that are needed to maintain
reliability while accommodating the ongoing needs of existing Market
Participants and Transmission Customers. Baseline Reliability Projects may
consist of a number of individual facilities that in the judgment of the
Transmission Provider constitute a single project for cost allocation purposes.
The Transmission Provider shall collaborate with Transmission Owning
members, other transmission providers, Transmission Customers, and other
stakeholders to develop appropriate planning models that reflect expected system
conditions for the planning horizon. The planning models shall reflect the
projected load growth of existing network customers and other transmission
service and interconnection commitments, and shall include any transmission
projects identified in Service Agreements or interconnection agreements that are
entered into in association with requests for transmission delivery service or
transmission interconnection service, as determined in Facilities Studies
associated with such requests. The Transmission Provider shall test the MTEP for
adequacy and security based on commonly applicable national Electric Reliability
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Organization (“ERO”) standards, and under likely and possible dispatch patterns
of actual and projected Generation Resources within the Transmission System and
of external resources, including dispatch reflective of Long-Term Transmission
Rights of Transmission Customers, and shall produce an efficient expansion plan
that includes all Baseline Reliability Projects determined by the Transmission
Provider to be necessary through the planning horizon of the MTEP. The
Transmission Provider shall obtain the approval of the Transmission Provider
Board, as set forth in Section VI, for each MTEP published.
2.
New Transmission Access Projects: New Transmission Access Projects
are defined for the purposes of Attachment FF as Network Upgrades identified in
Facilities Studies and agreements pursuant to requests for transmission delivery
service or transmission interconnection service under the Tariff. New
Transmission Access Projects include projects that are needed to maintain
reliability while accommodating the incremental needs associated with requests
for new transmission or interconnection service, as determined in Facilities
Studies associated with such requests. New Transmission Access Projects may
consist of a number of individual facilities, which in the judgment of the
Transmission Provider constitute a single project for cost allocation purposes.
New Transmission Access Projects are either Generation Interconnection Projects
or Transmission Delivery Service Projects as defined in Sections II.A.2.a. and
II.A.2.b. The Transmission Provider shall consider the Baseline Reliability
Projects already determined to be needed in the most current MTEP, as well as
any other base-case needs not associated with the request for new service that
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may be identified during the impact study process when determining the need for
New Transmission Access Projects. Any identified base-case needs determined
in the impact study process that are not a part of the Baseline Reliability Projects
already identified in the most current MTEP shall become new Baseline
Reliability Projects and shall be included in the next MTEP. New Transmission
Access Projects identified in Facilities Studies and agreements pursuant to
requests for transmission delivery service or transmission interconnection service
under this Tariff shall be included in the next MTEP.
a.
Generation Interconnection Projects: Generation Interconnection
Projects are New Transmission Access Projects that are associated with
interconnection of new, or increase in generating capacity of existing,
generation under Attachments X to this Tariff.
b.
Transmission Delivery Service Projects: Transmission Delivery
Service Projects are New Transmission Access Projects that are needed to
provide for requests for new Point-To-Point Transmission Service, or
requests under Module B of the Tariff for Network Service or a new
designation of a Network Resource(s).
B.
Market Efficiency Projects: Market Efficiency Projects are Network Upgrades: (i) that
are proposed by the Transmission Provider, Transmission Owner(s), ITC(s), Market
Participant(s), or regulatory authorities; (ii) that are found to be eligible for inclusion in the
MTEP or are approved pursuant to Appendix B, Section VII of the ISO Agreement after June 16,
2005, applying the factors set forth in Section I.A. of this Attachment FF; (iii) that have a Project
Cost of $5 million or more; (iv) that involve facilities with voltages of 345 kV or higher1; and
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that may include any lower voltage facilities of 100kV or above that collectively constitute less
than fifty percent (50%) of the combined project cost, and without which the 345 kV or higher
facilities could not deliver sufficient benefit to meet the required benefit-to-cost ratio threshold
for the project as established in Section II.B.1.e, or that otherwise are needed to relieve
applicable reliability criteria violations that are projected to occur as a direct result of the
development of the 345 kV or higher facilities of the project; (v) that are not determined to be
Multi Value Projects; and (vi) that are found to have regional benefits under the criteria set forth
in Section II.B.1 of this Attachment FF.
1.
Criteria to Determine Whether a Project Should be Included as a Market
Efficiency Project: The Transmission Provider shall employ multiple future scenarios
and multi-year analysis including sensitivity analyses guided by input from the Planning
Advisory Committee to evaluate the anticipated benefits of a proposed Market Efficiency
Project in order to determine if such a project meets the criteria for inclusion in the
regional plan as a Market Efficiency Project eligible for regional cost sharing. Sensitivity
analyses shall include, among other factors, consideration of: (i) variations in amount,
type, and location of future generation supplies as dictated by future scenarios developed
with stakeholder input and guidance; (ii) alternative transmission proposals; (iii) impacts
of variations in load growth; and (iv) effects of demand response resources on
transmission benefits.
1
Transformer voltage is defined by the voltage of the low-side of the transformer
for these purposes.
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The Transmission Provider shall perform this inclusion analysis as follows:
a.
The Transmission Provider shall utilize a weighted futures, no loss (“WFNL”)
metric to analyze the anticipated annual economic benefits of construction of a proposed
Market Efficiency Project to Transmission Customers in each of the Local Resource
Zones, as defined in Attachment WW, based upon adjusted production cost (“APC”)
savings. APC savings will be calculated as the difference in total production cost of the
Resources in each Local Resource Zone adjusted for import costs and export revenues
with and without the proposed Market Efficiency Project as part of the Transmission
System. The WFNL metric for each Local Resource Zone shall be calculated using the
weighted APC savings determined for each future scenario included in the analysis.
i.
The WFNL metric shall utilize the future scenarios determined and
identified by the Transmission Provider through the planning process, with input
from all stakeholders. The weights applied to the results of each future scenario
shall also be determined by the Transmission Provider with input from all
stakeholders.
b.
Project benefit evaluations will include benefits for the first 20 years of project
life after the projected in-service date, with a maximum planning horizon of 25 years
from the approval year. The annual benefit for a proposed Market Efficiency Project
shall be determined as the sum of the WFNL values for each Local Resource Zone, as
defined in Attachment WW. The total project benefit shall be determined by calculating
the present value of annual benefits for the multiple year scenarios and multi-year
evaluations.
c.
The costs applied in the benefit to cost ratio shall be the present value, over the
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same period for which the project benefits are determined, of the annual Network
Upgrade Charges for the project as determined in accordance with the formula in
Attachment GG.
d.
The present value calculation for both the annual benefits and annual costs will
apply a discount rate representing the after-tax weighted average cost of capital of the
Transmission Owners that make up the Transmission Provider Transmission System.
e.
The Transmission Provider shall employ a benefit to cost ratio test to evaluate a
proposed Market Efficiency Project. Only projects that meet a benefit to cost ratio of
1.25 or greater shall be included in the MTEP as a Market Efficiency Project and be
eligible for regional cost sharing.
f.
The benefits of the project used to determine the associated cost allocations as a
percentage of project cost shall be determined one time at the time that the project is
presented to the Transmission Provider Board for approval. Estimated Project Cost will
be used to estimate the benefit to cost ratio and the eligibility for cost sharing at the time
of project approval. To the extent that the Commission approves the collection of costs
in rates for Construction Work in Progress (“CWIP”) for a constructing Transmission
Owner, costs will be allocated and collected prior to completion of the project.
g.
The aforementioned Market Efficiency Project inclusion criteria shall be used for
the exclusive purpose of determining whether projects are eligible for regional cost sharing
in accordance with Section III.A.2.f below. These criteria shall not affect the existing
criteria set forth in Appendix B of the ISO Agreement for determining whether projects are
eligible for inclusion in the MTEP. Moreover, the costs of projects included in the MTEP,
but not eligible for regional cost sharing, shall continue to be eligible for inclusion in the
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calculation of Transmission Owner revenue requirements under Attachment O of this
Tariff.
C.
Multi Value Projects: A Multi Value Project is one or more Network Upgrades
that address a common set of Transmission Issues and satisfy the conditions listed in Sections
II.C.1, II.C.2., and II.C.3 of Attachment FF. All Network Upgrades associated with a Multi Value
Project including any lower voltage facilities that may be needed to relieve applicable reliability
criteria violations that are projected to occur as a direct result of the development of the Multi
Value Project; may be cost shared per Section III.A.2.g of Attachment FF except for i) any
Network Upgrade cost associated with constructing an underground or underwater transmission
line above and beyond the cost of a feasible alternative overhead transmission line that provides
comparable regional benefits, and ii) any DC transmission line and associated terminal equipment
when scheduling and dispatch of the DC transmission line is not turned over to the Transmission
Provider's markets, real-time control of the DC transmission line is not turned over to the
Transmission Provider's automatic generation control system and/or the DC transmission line is
operated in a manner that requires specific users to subscribe for DC transmission service.
1.
A Multi Value Project must be evaluated as part of a Portfolio of projects, as
designated in the transmission expansion planning process, whose benefits are
spread broadly across the footprint.
2.
A Multi Value Project must meet one of the three criteria outlined below:
a.
Criterion 1. A Multi Value Project must be developed through the
transmission expansion planning process for the purpose of enabling the
Transmission System to reliably and economically deliver energy in support
of documented energy policy mandates or laws that have been enacted or
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adopted through state or federal legislation or regulatory requirement that
directly or indirectly govern the minimum or maximum amount of energy
that can be generated by specific types of generation. The MVP must be
shown to enable the transmission system to deliver such energy in a manner
that is more reliable and/or more economic than it otherwise would be
without the transmission upgrade.
b.
Criterion 2. A Multi Value Project must provide multiple types of
economic value across multiple pricing zones with a Total MVP
Benefit-to-Cost ratio of 1.0 or higher where the Total MVP Benefit to-Cost ratio is described in Section II.C.7 of this Attachment FF.
The reduction of production costs and the associated reduction of
LMPs resulting from a transmission congestion relief project are not
additive and are considered a single type of economic value.
c.
Criterion 3. A Multi Value Project must address at least one
Transmission Issue associated with a projected violation of a NERC
or Regional Entity standard and at least one economic-based
Transmission Issue that provides economic value across multiple
pricing zones. The project must generate total financially
quantifiable benefits, including quantifiable reliability benefits, in
excess of the total project costs based on the definition of financial
benefits and Project Costs provided in Section II.C.7 of Attachment
FF.
3.
All of the following conditions must be satisfied in order for a project to be
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classified as a Multi Value Project:
a.
Facilities associated with the transmission project must not be in service,
under construction, or approved for construction by the Transmission
Provider Board prior to July 16, 2010 or the date a Transmission Owner
becomes a signatory member of the ISO Agreement, whichever is later.
This section II.C.3.a shall not preclude the Multi Value Project classification
of an Open Transmission Project that makes a Selected Transmission
Developer eligible to become a Transmission Owner.
b.
The transmission project must be evaluated through the Transmission
Provider's transmission planning process and approved for construction by
the Transmission Provider Board prior to the start of construction, where
construction does not include preliminary site and route selection activities.
c.
The transmission project must not contain any transmission facilities listed
in Attachment FF-1 of this Tariff.
d.
The total capital cost of the transmission project must be greater than or
equal to $20,000,000.00.
e.
The transmission project must include, but not necessarily be limited to, the
construction or improvement of transmission facilities operating at voltages
above 100 kV. A transformer is considered to operate above 100 kV when
at least two sets of transformer terminals operate at voltages above 100 kV.
f.
Network Upgrades driven solely by an Interconnection Request, as defined
in Attachment X of the Tariff, or a Transmission Service request will not be
considered Multi Value Projects.
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4.
Any transmission project that qualifies as a Multi-Value Project shall be
classified as an MVP irrespective of whether such project is also a Baseline
Reliability Project and/or Market Efficiency Project.
5.
The specific types of economic value provided by a Multi Value Project
include the following:
a.
Production cost savings where production costs include generator
startup, hourly generator no-load, generator energy and generator
Operating Reserve costs. Production cost savings can be realized
through reductions in both transmission congestion and transmission
energy losses. Productions cost savings can also be realized through
reductions in Operating Reserve requirements within Reserve Zones
and, in some cases, reductions in overall Operating Reserve
requirements for the Transmission Provider.
b.
Capacity losses savings where capacity losses represent the amount
of capacity required to serve transmission losses during the system
peak hour including associated planning reserve.
c.
Capacity savings due to reductions in the overall Planning Reserve
Margins resulting from transmission expansion.
d.
Long-term cost savings realized by Transmission Customers by
accelerating a long-term project start date in lieu of implementing a
short-term project in the interim and/or long-term cost savings
realized by Transmission Customers by deferring or eliminating the
need to perform one or more projects in the future.
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e.
Any other financially quantifiable benefit to Transmission
Customers resulting from an enhancement to the Transmission
System and related to the provisions of Transmission Service.
6.
Any project to facilitate like-for-like capital replacements of plant originally
installed as part of a Multi Value Project where replacement is due to aging, failure,
damage or relocation requirements where such replacement is not the result of
negligence by the constructing Transmission Owner will be treated as a Multi
Value Project. The minimum project cost limitation for Multi Value Projects
described in Section II.C.3.d of Attachment FF will not apply to the like for- like
capital replacement projects described in this Section.
7.
The following Total MVP Benefit-to-Cost Ratio will be applied to any
Multi Value Project justified solely on the basis of Sections II.C.2.b or II.C.2.c of
this Attachment FF to ensure such project qualifies as a Multi Value Project:
Total MVP Benefit-to-Cost Ratio = financial benefits / Project Costs.
For the purpose of this calculation, Financial Benefits will be set equal to the
present value of all financially quantifiable benefits provided by the project
projected for the first 20 years of the project's life and Project Costs will be set
equal to the present value of the annual revenue requirements projected for the first
20 years of the project's life.
8.
The aforementioned Multi Value Project inclusion criteria shall be used for
the exclusive purpose of determining whether projects are eligible for regional cost
sharing in accordance with Section III.A.2.g below. These criteria shall not affect
the existing criteria set forth in Appendix B of the ISO Agreement for determining
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whether projects are eligible for inclusion in the MTEP. Moreover, the costs of
projects included in the MTEP, but not eligible for regional cost sharing, shall
continue to be eligible for inclusion in the calculation of Transmission Owner
revenue requirements under Attachment O of this Tariff.
III.
Designation of Cost Responsibility for MTEP Projects: Based on the planning
analysis performed by the Transmission Provider, which shall take into consideration all
appropriate input from Market Participants or external entities, including, but not limited to, any
indications of a willingness to bear cost responsibility for an enhancement or expansion, the
recommended MTEP shall, for any enhancement or expansion that is included in the plan,
designate: (i) the Market Participant(s) in one or more pricing zones that will bear cost
responsibility for such enhancement or expansion, as and to the extent provided by any
applicable provision of the Tariff, including Attachments N, X, or any applicable cost allocation
method ordered by the Commission; or, (ii) in the event and to the extent that no provision of the
Tariff so assigns cost responsibility, the Market Participant(s) or Transmission Customer(s) in
one or more pricing zones from which the cost of such enhancements or expansions shall be
recovered through charges established pursuant to Attachment GG of this Tariff, or as otherwise
provided for under this Attachment FF.
Any designation under clause (ii) of the preceding sentence shall be determined as provided for
in Section III.A and III.B of this Attachment FF. For all such designations, the Transmission
Provider shall calculate the cost allocation impacts to each pricing zone. The results will be
reviewed for unintended consequences by the Transmission Provider and the Tariff Working
Group and any such identified consequences shall be reported to the Planning Advisory
Committee, and the OMS.
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A.
Allocation of Costs Within the Transmission Provider Region
1.
Default Cost Allocation: Except as otherwise provided for in this Attachment FF, or by
any other applicable provision of this Tariff and consistent with the ISO Agreement, the
responsibility for Network Upgrades included in the approved MTEP will be addressed in
accordance with the provisions of the ISO Agreement.
2.
Cost Allocation: The Transmission Provider will designate and assign cost
responsibility on a regional, and sub-regional basis for Network Upgrades identified
in the MTEP subject to the grand-fathered project provisions of Section III.A.2.b.
a.
Market Participant’s Option to Fund: Notwithstanding the
Transmission Provider’s assignment of cost responsibility for a
project included in the MTEP, one or more Market Participants
may elect to assume cost responsibility for any or all costs of a
Network Upgrade that is included in the MTEP. Provided
however, in the event the Market Participant is also a Transmission
Owner such election of the option to fund must be made on a
consistent, non-discriminatory basis.
b.
Grandfathered Projects: The cost allocation provisions of this
Attachment FF shall not be applicable to transmission projects
identified in Attachment FF-1, which is based on the list of
projects designated as Planned Projects in the MTEP approved by
the Transmission Provider Board on June 16, 2005 (MTEP 05) and
some additions of proposed projects that the Transmission Provider
has determined to be in the advanced stages of planning.
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c.
Baseline Reliability Projects: Costs of Baseline Reliability
Projects shall be recovered pursuant to Attachment O of this Tariff
by the Transmission Owner(s) and/or ITC(s) developing such
projects, subject to the requirements of the ISO Agreement.
d.
Generation Interconnection Projects: Costs of Generation
Interconnection Projects that are not determined by the
Transmission Provider to be Baseline Reliability Projects, Market
Efficiency Projects, or Multi-Value Projects, and the Network
Upgrade costs associated with advancing a Baseline Reliability
Project, Market Efficiency Project, or Multi-Value Project
associated with a generator interconnection will be paid for by the
Interconnection Customer(s) in accordance with Attachment X.
For Generator Interconnection Projects interconnecting to the
American Transmission Company LLC transmission system, such
costs will be subject to the provision of Attachment FF –
ATCLLC.
1)
For Network Upgrades to facilities in voltage classes at or
above 345 kV, the Interconnection Customer shall be
repaid 10 percent of the costs of the Generation
Interconnection Project funded by the Interconnection
Customer once Commercial Operation is achieved. The
Transmission Owner(s) constructing the Generation
Interconnection Project will repay 10% of the Generation
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Interconnection Project costs associated with Network
Upgrade facilities in a voltage class of 345 kV or greater to
the Interconnection Customer under repayment terms
consistent with the schedules and other terms of
Attachment X.
The 10% of the Project Cost associated with Network
Upgrade facilities of voltage class 345 kV or above and
repaid to the Interconnection Customer shall be allocated
on a system-wide basis and recovered pursuant to
Attachment GG of this Tariff.
2)
An Interconnection Customer may be required to contribute
to the cost of Shared Network Upgrades, as defined in
Attachment X to the Tariff, that are funded by another
Interconnection Customer as a Generator Interconnection
Project pursuant to Attachment X.
Each Interconnection Customer with one or more
Shared Network Upgrade(s) identified in Appendix A of its
Generator Interconnection Agreement shall make a onetime payment under Schedule 26-B to the Transmission
Provider in accordance with the terms in the Generator
Interconnection Agreement. The one-time payment will
reflect the cost of the Shared Network Upgrade assigned to
the Interconnection Customer as determined by the
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Transmission Provider.
All revenue collected by the Transmission Provider
through Schedule 26-B shall be distributed to the
appropriate Interconnection Customer(s).
3)
The Interconnection Customer shall be entitled, pursuant to
Section 46 of this Tariff, to any Financial Transmission
Rights or other rights to the extent provided for under this
Tariff, for any Network Upgrade costs funded by or
charged to the Interconnection Customer and not subject to
repayment under the provisions of this Section III.A.2.d. In
the event that a Generator Interconnection Project defers or
displaces a Baseline Reliability Project, the costs of the
Generator Interconnection Project up to the costs of the
deferred or displaced Baseline Reliability Project shall be
allocated consistent with the cost allocation for the Baseline
Reliability Project.
4)
International Transmission/Michigan Electric Transmission
Company/ITC Midwest LLC:
(a)
For those Generator Interconnection Projects for
which International Transmission Company, Michigan
Electric Transmission Company, LLC, or ITC Midwest
LLC (“International” or “METC” or “ITC Midwest”) as
Transmission Owners will be a signatory to the
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interconnection agreement under the terms of Attachment
X of this Tariff or any successor provision of the Tariff
executed by the parties after the effective date of this
Attachment FF Section III.A.2.d.4, this Attachment FF
Section III.A.2.d.4 shall apply, except that, where ITC
Midwest is the Transmission Owner, the Interconnection
Customer may elect to have another approved methodology
under Attachment FF Section III.A.2.d apply.
(b)
Generation Interconnection Projects: The cost of
Network Upgrades for Generation Interconnection Projects
that are not determined by the Transmission Provider to be
Baseline Reliability Projects shall be reimbursed by the
Transmission Owner as provided in this Section III.A.2.d.4.
All costs of Network Upgrades for Generation
Interconnection Projects will initially be paid by the
Interconnection Customer in accordance with the terms of
the Interconnection Agreement entered into pursuant to
Attachment X of this Tariff. To the extent the
Interconnection Customer demonstrates at the time of
Commercial Operation of the Generating Facility one of the
following:
i.
Generating Facility has been designated as a
Network Resource in accordance with the
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Tariff, or
ii.
Contractual commitment has been entered into
with a Network Customer for capacity, or in the
case of an Intermittent Resource, for energy,
from the Generating Facility for a period of one
(1) year or longer.
The Interconnection Customer will receive up to one
hundred percent (100%) reimbursement of reimbursable
costs within ninety (90) days of the Commercial Operation
Date, such reimbursement prorated by the percentage of the
Generating Facility capacity or annual available energy
output contracted for and as demonstrated to the
satisfaction of the Transmission Provider.
If the Interconnection Customer is unable to
demonstrate to the satisfaction of the Transmission
Provider at the time of Commercial Operation of the
Generating Facility that the Generating Facility has met the
repayment obligations set forth in Attachment FF Sections
III.A.2.d.4.b.i. or III.A.2.d.4.b.ii. the Interconnection
Customer shall be directly assigned 100% of the costs of
the Generation Interconnection Project. The Transmission
Owner may effect this direct assignment of costs by either
foregoing any repayment of costs funded by the
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Interconnection Customer, or by electing to repay 100% of
the costs under repayment terms consistent with the
schedules and other terms of Attachment X.
The Interconnection Customer shall be entitled, pursuant to
Section 46 of this Tariff, to any Financial Transmission
Rights or other rights to the extent provided for under this
Tariff, for any Network Upgrade costs funded by or
charged to the Interconnection Customer and not subject to
repayment under the provisions of this Attachment FF
Section III.A.2.d.4. In the event that a Generator
Interconnection Project defers or displaces a Baseline
Reliability Project, the costs of the Generator
Interconnection Project up to the costs of the deferred or
displaced Baseline Reliability Project shall be allocated
consistent with the cost allocation for the Baseline
Reliability Project.
(c)
For all amounts to be reimbursed by a Transmission
Owner to an Interconnection Customer in accordance with
this Attachment FF Section III.A.2.d.4, the Transmission
Owner will reimburse the sums received from the
Interconnection Customer in cash together with any
applicable interest, in accordance with the terms of the
Interconnection Agreement.
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(d)
Allocation of Generator Interconnection
Reimbursement. For all amounts reimbursed by a
Transmission Owner to an Interconnection Customer under
this Attachment FF Section III.A.2.d.4, fifty percent (50%)
of the reimbursement will be allocated consistent with the
allocations under this Attachment FF Sections III.A.2.c.i
and III.A.2.c.ii, except that such costs associated with
Generation Interconnection Projects of less than 100 kV
voltage class shall also be allocated consistent with Section
III.A.2.c.i. The remaining fifty percent (50%) of the
reimbursement will not be subject to any regional or subregional cost allocation, but will be recovered by that
Transmission Owner under its Attachment O transmission
rate formula under this Tariff.
e.
Transmission Delivery Service Projects: Costs of Transmission
Delivery Service Projects shall be assigned and recovered in
accordance with Attachment N of this Tariff.
f.
Market Efficiency Projects: Costs of Market Efficiency Projects
shall be allocated as follows:
i)
Twenty percent (20%) of the Project Cost of the Market
Efficiency Project shall be allocated on a system-wide basis
to all Transmission Customers and recovered through a
system-wide rate.
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ii)
Eighty percent (80%) of the costs of the Market Efficiency
Projects shall be allocated to all Transmission Customers in
each of the Local Resource Zones, as defined in Attachment
WW. The cost allocated to each Local Resource Zone shall
be based on the relative benefit determined for each Local
Resource Zone that has a positive present value of annual
benefits over the evaluation period using the methodology
for project benefit determination of Section II.B.1.
iii)
Excessive Funding or Requirements: The Transmission
Provider shall seek to identify and manage the development
of, as a part of the planning process for Market Efficiency
Projects, portfolios of projects that tend to provide benefits
throughout each Local Resource Zone, as defined in
Attachment WW, over the planning horizon. The
Transmission Provider shall analyze on an annual basis
whether the project portfolios developed in accordance with
this goal and the criteria in Section III. A.2.f unintentionally
result in unjust or unreasonable annual capital funding
requirements for any Transmission Owner or rate increases
for Transmission Customers in designated pricing zones; or
otherwise result in undue discrimination between the
Transmission Customers, Transmission Owners, or any
Market Participants; any such identified consequences shall
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be reported to the Planning Advisory Committee and to the
Organization of MISO States. After discussing such
assessments with the aforementioned stakeholder bodies, and
taking into consideration the cumulative experience in
applying this Attachment FF, the Transmission Provider will
make a determination as to whether Tariff modifications are
required, and if so file such modifications.
g.
Multi Value Projects: Costs of Multi Value Projects will be
allocated as follows:
i)
One-hundred percent (100%) of the annual revenue
requirements of the Multi Value Projects shall be allocated
on a system-wide basis to Transmission Customers that
withdraw energy, including External Transactions sinking
outside the Transmission Provider's region, and recovered
through an MVP Usage Charge pursuant to Attachment
MM.
h.
Treatment of Projects that meet both Baseline Reliability Project
Criteria and/or New Transmission Access Project Criteria, and the
Market Efficiency Project Criteria: If the Transmission Provider
determines that a project designated as a Market Efficiency Project
also meets the criteria to be designated as a Baseline Reliability
Project and/or a New Transmission Access Project, the cost of
such project shall be allocated in accordance with the Market
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Efficiency Project allocation procedures.
i.
Other Projects: Unless otherwise agreed upon pursuant to
Section III.A.2.a. of this Attachment FF, the costs of Network
Upgrades that are included in the MTEP, but do not qualify as
Baseline Reliability Projects, New Transmission Access Projects,
Market Efficiency Projects or Multi-Value Projects, shall be
eligible for recovery pursuant to Attachment O of this Tariff by the
Transmission Owner(s) and/or ITC(s) paying the costs of such
project, subject to the requirements of the ISO Agreement.
j.
Withdrawal from Midwest ISO: A Transmission Owner that
withdraws from the Midwest ISO as a Transmission Owner shall
remain responsible for all financial obligations incurred pursuant to
this Attachment FF while a Member of the Midwest ISO and
payments applicable to time periods prior to the effective date of
such withdrawal shall be honored by the Midwest ISO and the
withdrawing Member.
k.
New Transmission Owners: A new Transmission Owner joining
the Midwest ISO will be responsible for the following financial
obligations:
a.
New Transmission Owners will not be responsible for any
portion of Baseline Reliability Projects, Generator
Interconnection Projects, Transmission Delivery Service
Projects, or Market Efficiency Projects that were approved
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prior to their entry date.
b.
For Multi-Value Projects approved prior to the new
Transmission Owner’s entry date, the load interconnected
to the Transmission Owner’s Transmission System will be
responsible for one-hundred percent (100%) of the MVP
usage charge described in Attachment MM for the years
following the Transmission Owner’s entry date applied to
the Monthly Net Actual Energy Withdrawals for Load
interconnected to the Transmission Owner’s Transmission
System.
l.
Only a Transmission Owner shall be authorized to
construct and/or own transmission facilities associated with
a Baseline Reliability Project, Market Efficiency Project
and/or Multi Value Project. For projects jointly developed
between Transmission Owners and other parties the portion
constructed and owned by a Transmission Owner may
qualify as a Baseline Reliability Project, Market Efficiency
Project and/or Multi Value Project.
IV.
Merchant Transmission Project Data Requirements: A proposed merchant
transmission developer assumes all financial risk and funding requirements for developing its
transmission project(s) and constructing the proposed transmission facility(ies). In order for a
proposed merchant transmission developer’s facility to be interconnected to the Transmission
System, it is first necessary for the impacted Transmission Owner and the Transmission Provider
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to analyze the reliability and operational impact of the proposed new merchant transmission
facility(ies) on the Transmission System to determine if the new merchant transmission facilities
can be reliably supported by the Transmission System, and if not, what Network Upgrades
funded by the merchant transmission developer would be required to reliably support the
proposed merchant transmission facility(ies). In order to perform the required reliability and
operational analyses, the merchant transmission developer must provide the following data to the
Transmission Provider:
(1)
Each transmission circuit and substation, including new facilities, associated with
the merchant transmission proposal;
(2)
Nominal operating voltage level in kV and voltage characteristics (i.e., AC or DC)
for each transmission circuit associated with the merchant transmission proposal;
(3)
Typical and maximum MW power flow schedules, in each direction, for all
proposed DC transmission circuits associated with the merchant transmission proposal;
(4)
Normal and emergency summer and winter load ratings for each transmission
circuit associated with the merchant transmission proposal;
(5)
Maximum allowable positive sequence impedance for each AC transmission circuit
associated with the merchant transmission proposal, when applicable;
(6)
List of all transmission buses associated with the merchant transmission proposal,
including nominal operating voltage level in kV, voltage characteristics, and terminating
transmission branches and shunts;
(7)
Proposed substation one-line diagrams for all new substations associated with the
merchant transmission proposal, including circuit breaker and bus configuration details;
(8)
Load ratings, winding connections, impedances, tap data, and any other relevant
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information for load carrying equipment and facilities associated with the merchant
transmission proposal, as applicable;
(9)
Modeling files to model proposed facilities and relevant new contingencies in
power flow, stability, short-circuit and other relevant study models; and
(10)
Any other data determined pertinent to the study by the Transmission Provider
and/or interconnecting Transmission Owners for the specific merchant transmission facility
proposal.
V.
Designation of Entities to Construct, Implement, Own, Operate, Maintain, Repair,
Restore, and/or Finance MTEP Projects: With the exception of Open Transmission Projects,
for each project included in the recommended MTEP Appendix A and prior to approval by the
Transmission Provider Board, the plan shall designate one or more Transmission Owners to
construct, own, operate, maintain, repair, restore, and finance the recommended project, based on
the planning analysis performed by the Transmission Provider and based on other input from
participants, including, but not limited to, any indications of a willingness to bear cost
responsibility for the project; and applicable provisions of the ISO Agreement. Regarding Open
Transmission Projects, upon the determination of the Selected Transmission Developer for such
projects, as set forth in Section VIII of this Attachment FF, the Transmission Provider shall update
the approved MTEP Appendix A by identifying the Selected Transmission Developer for each
Open Transmission Project. Should the facilities from such Open Transmission Projects not be
approved by state regulatory authorities as New Transmission Facilities, but instead as upgrades to
existing transmission facilities, as defined in Section VIII.C of this Attachment FF, the
Transmission Provider shall update MTEP Appendix A by designating the appropriate
Transmission Owner(s) to construct, own, operate, maintain, repair, restore, and finance such
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facilities in accordance with the ISO Agreement.
VI.
Implementation of the MTEP:
A.
If the Transmission Provider and any Transmission Owner’s planning
representatives, or other designated entity(ies), cannot reach agreement on any element of the
MTEP, the dispute may be resolved through the dispute resolution procedures provided in the
Tariff, or in any applicable joint operating agreement, or by the Commission or state regulatory
authorities, where appropriate. The MTEP shall have as one of its goals the satisfaction of all
regulatory requirements as specified in Appendix B or Article IV, Section I, Paragraph C of the
ISO Agreement.
B.
The Transmission Provider shall present the MTEP, along with a summary of
relevant alternative projects that were not selected, to the Transmission Provider Board for
approval on a biennial basis, or more frequently if needed. The proposed MTEP shall include
specific projects already approved as a result of the Transmission Provider entering into Service
Agreements with Transmission Customers where such agreements provide for identification of
needed transmission construction, timetable, cost, and Transmission Owner or other parties’
construction responsibilities.
C.
Approval of the MTEP by the Transmission Provider Board certifies it as the
Transmission Provider plan for meeting the transmission needs of all stakeholders subject to any
required approvals by federal or state regulatory authorities. The Transmission Provider shall
provide a copy of the MTEP to all applicable federal and state regulatory authorities. The
affected Transmission Owner(s), Selected Transmission Developer(s), or other designated
entity(ies), shall make a good faith effort to design, certify, and build the designated facilities to
fulfill the approved MTEP. However, in the event that an MTEP Appendix A project approved
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by the Transmission Provider Board or the selection of the Selected Transmission Developer is
being challenged through the dispute resolution procedures under this Tariff or in court
proceedings, the obligation of the Transmission Owners, or other designated entity(ies), to build
that specific project (subject to required approvals) is waived until the approved project emerges
from the dispute resolution procedures. The Transmission Provider Board shall allow the
Transmission Owners, or other designated entity(ies), to optimize the final design of specific
facilities and their in-service dates if necessary to accommodate changing conditions, provided
that such changes comport with the approved MTEP and provided that any such changes are
accepted by the Transmission Provider through the reevaluation process described in Section VI
of this Attachment FF, as necessary. Any disagreements concerning such matters shall be
subject to the dispute resolution procedures of this Tariff.
D.
The Transmission Provider shall assist the affected Owner(s), Selected
Transmission Developer(s), or other designated entity(ies), in justifying the need for, and
obtaining certification of, any facilities required by the approved MTEP by preparing and
presenting testimony in any proceedings before state or federal courts, regulatory authorities, or
other agencies as may be required. The Transmission Provider shall publish annually, and
distribute to all Members and all appropriate state regulatory authorities, a five-to-ten-year
planning report of forecasted transmission requirements. Annual reports and planning reports
shall be available to the general public upon request.
VII.
Multi-Value Project Costs and Benefits Review and Reporting
A.
Frequency and Reporting of Multi-Value Project Review: Every three (3)
years, as provided below and in the Business Practices Manual for Transmission
Planning, the Transmission Provider shall conduct a review of the cumulative costs and
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benefits associated with MVPs, and shall disseminate the results of such reviews to its
stakeholders. The Transmission Provider shall use the review process and results to
identify potential modifications to the MVP methodology and its implementation for
projects to be approved at a future date.
1.
Triennial Full MVP Review: Beginning with the MTEP for 2014 (“MTEP 14”),
and every third year thereafter, the Transmission Provider shall conduct a full
MVP review, as provided in section VII.B of this Attachment FF.
2.
Annual Limited MVP Review: Beginning with the MTEP for 2015 (“MTEP 15”),
and each year thereafter when there is no full MVP review, the Transmission
Provider shall conduct a limited MVP review, as provided in section VII.C of this
Attachment FF.
3.
Calculation of Costs and Benefits: The reviews shall calculate costs and benefits
on a forward-looking basis over both twenty (20)-year and forty (40)-year
periods. The costs calculation shall use updated project costs and in-service dates
provided in the latest MTEP quarterly status report, and the benefits calculation
shall use updated future scenarios from the latest MTEP planning cycle. The
results of the costs and benefits calculation shall be provided for each Local
Resource Zone as defined in Module E. If the Local Resource Zones as defined
in accordance with Module E for Resource Adequacy purposes are modified, the
Transmission Provider, working with stakeholders, may define different Local
Resource Zones for purposes of reporting the results of the review. The definition
of different Local Resource Zones in connection with reporting the results of the
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review will be detailed in the Business Practices Manual for Transmission
Planning.
4.
Dissemination of the Results of the Full and Limited MVP Reviews: Within a
reasonable time after completion of each MVP review, the Transmission Provider
shall disseminate the results of and supporting analysis for the MVP review
through: (a) publication in the MTEP; (b) posting on the appropriate section of
the Transmission Provider’s public website; and (c) presentation to the
appropriate stakeholder committees.
B.
Scope of Full Multi-Value Project Review: Each full MVP review shall at a
minimum include the following:
1.
Quantitative Benefits: Analysis of the quantifiable economic benefits resulting
from the addition of MVPs, including, but not limited to:
a.
Congestion and Fuel Savings: Savings from increased access to lower
cost Resources;
b.
Decreased Operating Reserves: Savings associated with lower Operating
Reserve requirements;
c.
Decreased System Planning Reserve Margin: Savings associated with
deferred generation investment due to a reduction in the system-wide
Planning Reserve Margin; and
d.
Decreased Transmission Line Losses: Savings associated with deferred
generation investment due to a reduction in the Capacity required to serve
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transmission losses during peak hours, to the extent that MVPs reduce
such losses.
2.
Public Policy and Other Qualitative Benefits: Analysis of the public policy and
other qualitative benefits accruing from MVPs, such as newly interconnected
wind units; and an increase in the percentage of the Transmission Provider’s
Energy needs being supplied by wind and/or other renewable resources, and wind
curtailments.
3.
Historical Data: Provision, beginning with the MTEP for 2017 (“MTEP 17”), and
based on the historical data available to the Transmission Provider for the five (5)
prior years, of information on certain additional market trend metrics including,
but not limited to:
a. Congestion costs;
b. Energy prices;
c. Fuel costs;
d. Planning Reserve Margin requirements;
e. Number of newly interconnected Resources, by Resource type; and
f. The share of the Transmission Provider’s Energy supplied, by Resource
type.
C.
Scope of Limited Multi-Value Project Review: Each limited MVP review shall
at a minimum include the items described in Sections VII.B.1.a and VII.B.3 of this
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Attachment FF, based on the latest available data for the current year, in preparation for the next
full MVP review.
VIII. Transmission Developer Selection
A.
State or Local Rights of First Refusal. The Transmission Provider shall comply
with any Applicable Laws and Regulations granting a right of first refusal to a Transmission
Owner. The Transmission Owner will be assigned any transmission project within the scope,
and in accordance with the terms, of any Applicable Laws and Regulations granting such a right
of first refusal. These Applicable Laws and Regulations include, but are not limited to, those
granting a right of first refusal to the incumbent Transmission Owner(s) or governing the use of
existing developed and undeveloped right of way held by an incumbent utility.
B.
State Selection of Qualified Transmission Developers. In the absence of any
Applicable Laws and Regulations granting a right of first refusal, a state with the authority to do
so may elect to determine the Selected Transmission Developer(s) from the Qualified
Transmission Developers who have submitted Transmission Proposals for any Open
Transmission Projects, or portion of such Open Transmission Projects that are physically located
within such state’s boundaries, in accordance with applicable state criteria and procedures. Prior
to the Transmission Provider Board’s approval of Open Transmission Project(s) for inclusion in
Appendix A of the MTEP, states may identify any potential Open Transmission Projects within
its state boundaries for which it will determine the Selected Transmission Developer. States that
elect to determine the Selected Transmission Developer may request additional state-specific
data or qualification criteria related to the specific potential Open Transmission Project (s), for
which the state has indicated that it will determine the Selected Transmission Developer to be
included in the corresponding Transmission Proposal Request(s) prior to the Transmission
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Provider Board’s approval of potential Open Transmission Project(s) for inclusion in Appendix
A of the MTEP.
Upon receipt of a New Transmission Proposal, the Transmission Provider will review the
New Transmission Proposal to ensure all qualifications and requirements from the Transmission
Proposal Request, including state-specific qualifications, have been satisfied. Should the New
Transmission Proposal not satisfy one or more of the requirements or qualifications outlined in
this Tariff and/or specified in the Transmission Proposal Request, the Transmission Provider will
notify the New Transmission Proposal Applicant and initiate a Cure Period as described in
Section VIII.F of this Tariff. Within five (5) business days following the completion of this Cure
Period, Transmission Provider will submit all applicable New Transmission Proposals, including
any whose deficiencies have been cured, to the appropriate state(s) for their consideration,
subject to execution of appropriate Non-Disclosure Agreements.
If, for any reason, a state is unable or declines to determine the Selected Transmission
Developer within the time period defined in Section VIII.G, the Transmission Provider will
assume responsibility for determining the Selected Transmission Developer. In this event, the
Transmission Provider will, pursuant to the evaluation process outlined in Section VIII.G of this
Attachment FF: i) evaluate each New Transmission Proposal submitted by a Qualified
Transmission Developer; ii) select one of the New Transmission Proposals for implementation
and; iii) post the Selected Transmission Developer on its website within 180 calendar days of the
notification from a state that it is unable or declines to select a developer, or the lapse of the 180
calendar day timeframe defined in Section VIII.G of this Attachment FF, not to exceed 450
calendar days from posting of the Transmission Proposal Request.
C.
Upgrades to Existing Transmission Facilities. A Transmission Owner shall
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have the right to develop, own and operate any upgrade to a transmission facility owned by the
Transmission Owner, in accordance with this Tariff and the ISO Agreement.
1.1
Upgrades to Existing Transmission Lines. Upgrades to existing
transmission line facilities include any expansion, replacement or modification,
for any purpose, made to existing transmission line facilities that are classified as
transmission plant and owned by one or more Transmission Owners, for reasons
including, but not limited to:
(a)
increasing the load capability of the transmission line or an associated
circuit;
(b)
increasing the nominal operating voltage of the transmission line or an
associated circuit;
(c)
installing additional plant on an existing overhead or underground
transmission line facility, such as, but not limited to:
i.
plant associated with an additional circuit installed on spare
structure positions;
ii.
iii.
additional structures to increase a sag limit or for other purposes;
a sectionalizing switch installed on an existing transmission line
circuit regardless of whether or not it is installed on an existing
structure; and
iv.
(d)
any other plant additions to existing transmission line facilities.
relocating the existing transmission line, or any portion thereof, for any
purpose;
(e)
replacing an entire existing transmission line facility with a new
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transmission line facility on the same right-of-way or on a different rightof-way if the replacement is driven by a relocation request or requirement;
(f)
replacing one or more existing components of any existing transmission
line facility, such as, but not limited to:
i.
replacing existing conductors with higher capacity conductors or
better performing conductors;
ii.
iii.
replacing single-circuit structures with multi circuit structures;
replacing insulators rated at a specific voltage with insulators rated
at a higher voltage;
iv.
replacing aging or defective components associated with the
existing transmission line;
(g)
improving the performance or characteristics of the existing transmission
line for any reason;
(h)
converting an existing overhead transmission line to an underground
transmission line on the same right-of-way and/or converting an existing
underground transmission line to an overhead transmission on the same
right-of-way;
(i)
improving land and land rights booked under the Commission’s Uniform
System of Accounts, Account Nos. 105, 350, and/or 380; or
(j)
any other modifications to existing transmission facilities.
1.1.1
Combination of Upgrades and New Facilities. If a proposed
transmission project includes a combination of new transmission line
sections and upgrades to existing transmission line sections, and the new
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transmission line sections are less than twenty (20) contiguous miles in
total length, construction of the new transmission line sections will be
considered a transmission upgrade for the purpose of retaining a right of
first refusal. In either event, upgrades made to the existing transmission
line sections will be considered transmission upgrades for the purpose of
retaining a right of first refusal.
1.2
Upgrades to Existing Substations. Upgrades to existing substations
include any expansions, replacements or modifications made, in part or in
whole, to any existing substation or portion thereof that is owned by one
or more Transmission Owners, and where some or all of the plant within
the existing substation is classified as transmission plant. These upgrades
include, but are not limited to:
(a)
replacing facilities and/or equipment within an existing substation
footprint;
(b)
installing additional plant within an existing substation footprint;
(c)
modifying facilities and/or equipment within an existing substation
footprint;
(d)
expanding an existing substation footprint within the existing
substation site boundaries and installing additional plant within the
expanded area; and
(e)
acquiring additional land adjacent to or near the existing substation
in conjunction with installation of additional plant within the boundaries
of this additional land, including facilities to interconnect such plant to the
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existing substation plant.
1.2.1
Construction of a new substation facility at the common junction point(s)
of a transmission line containing more than two terminals or along an existing
two terminal transmission line, where such transmission line facilities are owned
by an incumbent Transmission Owner, for the purpose of implementing: i)
transmission line protection system upgrades; ii) improving operational
flexibility; iii) improving customer service reliability indices (e.g., reducing
SAIFI, CAIDI, SAIDI, etc.); iv) increasing the load capability of the transmission
line; v) improving transmission voltages and reactive power management; vi)
mitigating the economic and/or reliability impact of contingencies; and vii) any
other purpose other than facilitating the interconnection of a New Transmission
Line Facility will be considered a transmission upgrade for the purpose of
retaining a right of first refusal. Furthermore, construction of a new substation for
the purpose of interconnecting two or more existing transmission circuits where
all such existing transmission circuits are owned by incumbent Transmission
Owner(s) will be considered a transmission upgrade for the purpose of retaining a
right of first refusal. Examples of newly constructed substations that will be
considered transmission upgrades for the purpose of retaining a right of first
refusal include, but are not limited to, i) circuit breaker substations installed along
an existing two-terminal transmission line to improve operational flexibility or
customer service reliability via automatic sectionalizing; ii) series capacitor
substations installed within an existing transmission line to increase load
capability; iii) circuit breaker switching substations installed at the common
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junction point of a three-terminal line to improve loading and protection
capabilities of protective relay systems; and iv) newly constructed switching
substation to interconnect two existing transmission circuits at the point where
they physically cross each other where such existing transmission circuits are
owned by the same Transmission Owner. Examples of new substation facilities
that would not be considered transmission upgrades for the purpose of retaining a
right of first refusal include, but are not limited to, i) a New Substation Facility
proposed to interconnect three New Transmission Line Facilities; ii) a New
Substation Facility proposed to facilitate connecting a 345 kV New Transmission
Line Facility to the midpoint of an existing 345 kV transmission circuit owned by
an incumbent Transmission Owner; and iii) a 765-345 kV New Substation
Facility constructed to interconnect a 765 kV New Transmission Line Facility
with an existing double circuit 345 kV transmission line, where such 345 kV
double circuit transmission line is owned by incumbent Transmission Owner(s).
D.
Data Submission
1.
Determination of Projects Not Subject to a Right of First Refusal.
Upon the Transmission Provider Board’s approval of transmission projects for
inclusion in Appendix A of the MTEP, the Transmission Provider will develop a
separate Transmission Proposal Request for each Open Transmission Project.
These Transmission Proposal Request(s) will be posted on the Transmission
Provider website within thirty (30) calendar days of the date the Transmission
Provider Board approved the Open Transmission Project for inclusion in
Appendix A of the MTEP.
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2.
Transmission Proposal Requests
a.
Transmission Proposal Request Deposit. The New
Transmission Proposal Applicant will submit a deposit per proposal equal
to one percent (1%) of the projected project cost, not to exceed $500,000.
The Transmission Provider shall track all time and expenses specifically
associated with the evaluation process identified in this Section VIII of
Attachment FF and the Transmission Proposal Request deposits will be
applied to the cost of evaluating the New Transmission Proposals. Any
remaining funds shall be refundable on a pro rata basis to each New
Transmission Proposal Applicant within thirty (30) days following the
designation of the Selected Transmission Developer. No interest will be
paid on any deposit funds held by the Transmission Provider during this
time.
b.
Minimum Contents of Transmission Proposal Requests. The
Transmission Proposal Request will specify i) each New Transmission
Line Facility and/or each New Substation Facility associated with the
Open Transmission Project that should be included in the New
Transmission Proposal; ii) the date by which the New Transmission
Proposal must be submitted to the Transmission Provider, which shall not
exceed 180 calendar days from the posting of the Transmission Proposal
Request; and iii) a list of the current transmission facility interconnection
standards and requirements established by the Transmission Owner(s) to
which the New Transmission Line Facilities and/or New Substation
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Facilities will interconnect.
i.
Furthermore, where it involves one or more New
Transmission Line Facilities, the Transmission Proposal
Request will specify for each New Transmission Line
Facility, at a minimum:
(1)
Expected in-service date;
(2)
Implementation schedule indicating the required
steps to develop and construct the Open
Transmission Project, including, but not limited to,
all required regulatory approvals;
(3)
Nominal operating voltage level in kV and voltage
characteristics (i.e., three-phase AC, bipolar DC,
etc.) for each transmission circuit;
(4)
Terminating substations and buses for each
transmission circuit;
(5)
Minimum required normal and emergency load
ratings for both summer and winter seasons for each
transmission circuit; and
(6)
Maximum allowable positive sequence impedance
for each transmission circuit when determined
applicable by planning studies performed by the
Transmission Provider.
ii.
Where it involves one or more New Substation Facilities,
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the Transmission Proposal Request will specify for each
New Substation Facility, at a minimum, the following
information:
(1)
Expected in-service date;
(2)
Implementation schedule indicating the required
steps to develop and construct the Open
Transmission Project, including, but not limited to,
all required regulatory approvals;
(3)
List of all transmission buses within the New
Substation Facility, including nominal operating
voltage level in kV and voltage characteristics;
(4)
List of all major equipment and facilities within the
New Substation Facility and associated terminating
buses including power transformers, voltage
regulators, phase angle regulators, series reactors,
series capacitors, shunt reactors, shunt capacitors,
static VAR compensators, DC converters,
transmission line circuit terminals, generator
terminals, and loads;
(5)
Limitations on and/or requirements for bus
configurations when determined applicable by
planning studies performed by the Transmission
Provider including required load ratings of circuit
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breakers, disconnects, bus sections and other load
carrying equipment under alternative bus
configurations;
(6)
Required load ratings for all load carrying
equipment and facilities identified in item (4)
above;
(7)
Winding connection and tap requirements for power
transformers, voltage regulators, phase angle
regulators and load tap changers when determined
necessary by planning studies performed by the
Transmission Provider;
(8)
Impedance requirements for power transformers,
phase angle regulators, series reactors and series
capacitors when determined necessary by planning
studies performed by the Transmission Provider;
and
(9)
Limitations on and/or requirements for protection
systems when determined applicable by a planning
driver or Applicable Reliability Standard or in order
to ensure a compatible interconnection with existing
protection systems associated with existing
transmission facilities to which the New
Transmission Facilities will interconnect.
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c.
Other Requirements of Transmission Proposal Requests. The
Transmission Provider reserves the right to specify in Transmission
Proposal Requests, if deemed necessary and/or appropriate, additional
information for any specific New Transmission Line Facilities and/or New
Substation Facilities.
3.
Contents of New Transmission Proposals. New Transmission Proposal
Applicants that submit a New Transmission Proposal in response to a
Transmission Proposal Request must submit all data required by the Transmission
Proposal Request, including, but not limited to:
(1)
Documentation of satisfaction of general requirements for Qualified
Transmission Developers;
(2)
Cost estimate data for each proposed New Transmission Line Facility
and/or New Substation Facility;
(3)
Reasonably descriptive facility design proposals for each New Substation
Facility and/or New Transmission Line Facility included in the Open
Transmission Project;
(4)
Documentation of project implementation capabilities;
(5)
Documentation of operations, maintenance, repair, and replacement
capabilities;
(6)
Modeling data files for all proposed New Transmission Line Facilities
and/or New Substation Facilities included in the Open Transmission
Project; and
(7)
Descriptions of relevant partnerships or agreements (if applicable).
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4.
General Requirements for Qualified Transmission Developers. The general
requirements applicable to Qualified Transmission Developers include, but are
not limited to:
(1)
Agreement to execute the ISO Agreement if designated as the Selected
Transmission Developer in the evaluation process to develop, own and
operate New Substation Facilities and/or New Transmission Line
Facilities after the facilities have been constructed but prior to
energization of such New Transmission Facilities, unless New
Transmission Proposal Applicant is already a Transmission Owner;
(2)
Agreement to comply with all Applicable Laws and Regulations, codes,
and standards governing the engineering, design, construction, operation,
and maintenance of transmission facilities including, but not limited to,
federal laws, state laws, local laws, state and local building codes, federal
regulatory requirements, state and local regulatory requirements, state and
local licensing authorities, the National Electric Safety Code, the National
Electric Code, Applicable Reliability Standards, and Good Utility
Practice;
(3)
Agreement to register with NERC as the transmission owner (TO),
transmission operator (TOP) and transmission planner (TP), as defined by
NERC, for all transmission facilities which the Selected Transmission
Developer will own that are to be part of the Transmission System;
(4)
Agreement to either i) contract with the interconnecting Local Balancing
Authority (LBA) to include the New Transmission Facilities within the
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boundaries of the LBA and demonstrate to the satisfaction of the
Transmission Provider and per agreement by the LBA that applicable
LBA-related tasks associated with the proposed New Transmission
Facilities that are delegated to an LBA by the Balancing Authority
Agreement will be carried out either by the LBA or the Selected
Transmission Developer; or ii) execute the Balancing Authority
Agreement, register with NERC as a Balancing Authority (BA), and be
designated as the Local Balancing Authority for the proposed New
Transmission Facilities, unless the New Transmission Proposal Applicant
is already registered with NERC as a BA and designated as an LBA for
one or more of the existing facilities that interconnect directly with the
New Transmission Facilities associated with the Open Transmission
Project in question;
(5)
Agreement to comply with the FERC Form 715 Part 4 TRPC,
Transmission Planning Criteria and Guidelines on file with FERC and
established by each incumbent Transmission Owner whose existing
transmission facilities will interconnect directly with the New
Transmission Line Facilities and/or New Substation Facilities;
(6)
Agreement to comply with current requirements and standards regarding
the interconnection of transmission facilities published by each
Transmission Owner to which New Transmission Line Facilities and/or
New Substation Facilities will interconnect including, but not limited to,
those standards and requirements required for compliance with the
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applicable NERC Facilities Design, Connections, and Maintenance
(“FAC”) reliability standards; and
(7) Submission of a business plan outlining the strategy and process to obtain
project financing and/or credit rating information applicable to the
entity’s organization from Standard and Poor’s, Moody’s, or Fitch.
5.
Cost Estimates. Proposed cost estimate data must be based on the reasonably
descriptive facility design proposals submitted in the New Transmission Proposal
and will include, at a minimum:
(1)
Estimated project cost for each proposed New Transmission Line
Facility and/or New Substation Facility; and
(2)
Estimated annual revenue requirements for the first 40 years the
facilities included in the New Transmission Proposal will be in
service.
6.
Reasonably Descriptive Facility Design Proposals. Reasonably descriptive
facility design proposals must be submitted for each New Transmission Line
Facility and/or New Substation Facility included in the Open Transmission
Project. Reasonably descriptive facility design proposals represent descriptions of
the core attributes and features of a design, not the detailed engineering and
design calculations and documents.
a.
Reasonably Descriptive Facility Design Proposals for New
Transmission Facilities. For each New Transmission Line Facility,
reasonably descriptive facility design proposals must include, at a
minimum:
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(1)
Estimated length of New Transmission Line Facility in miles and
basis for estimate;
(2)
Proposed conductor type, size, and, if applicable, bundling
configuration;
(3)
Proposed default or typical structure design attribute(s) (e.g., steel
vs. wood vs. aluminum vs. concrete, monopole vs. H-frame vs.
lattice, single circuit vs. double circuit, self-supporting vs. guyed,
structural calculation assumptions, etc.) to be used for tangent,
running angle, in-line dead-end, and angle dead-end structures
when feasible and/or for the majority of the New Transmission
Line Facility;
(4)
Estimated positive sequence line impedance and pi-equivalent
shunt susceptance;
(5)
Calculated normal and emergency seasonal thermal loading
ratings, including basis for calculations;
(6)
Proposed type of lightning protection system to be used when
feasible and/or for the majority of the New Transmission Line
Facility (e.g., shield wires vs. surge arresters, etc.) and key
attributes (e.g., shielding angle, arrester location and type, etc.);
(7)
Proposed grounding method to be used when feasible and/or for
the majority of the New Transmission Line Facility (e.g., ground
rods only, counterpoise, etc.) and key attributes (e.g., targeted
structure footing grounding resistance, etc.);
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(8)
Proposed method to address or mitigate adverse impacts of
galloping conductors and/or Aeolian vibration, if any (e.g.,
Stockbridge dampers, special conductors, etc.);
(9)
Continuous rating of any load carrying switchgear installed on the
New Transmission Line Facility; and
(10)
Assumed communications systems to be used for the New
Transmission Line Facility to facilitate protective relaying (e.g.,
fiber optic, power line carrier, microwave, etc.).
b.
Reasonably Descriptive Facility Design Proposals for New Substation
Facilities. For New Substation Facilities, reasonably descriptive facility
design proposals must include, at a minimum:
(1)
Detailed one-line diagram;
(2)
Proposed protection systems including protection schemes, any
anticipated interaction with existing/other facilities and
conceptual protection system design (including backup
protection systems, if applicable). Remote system monitoring
capability shall be described with major features listed
(redundancy, monitored parameters, etc.);
(3)
Detailed specifications for proposed power transformers;
(4)
Description of other substation equipment items, including load
ratings, voltage ratings, fault interrupting ratings, tap data, and
impedances as applicable, where other substation equipment
includes, but is not limited to, bus sections, circuit breakers,
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circuit switchers, switches, disconnects, regulating
transformers, station service transformers, series and shunt
capacitors, series and shunt reactors, static VAR compensators,
DC conversion equipment, instrument transformers (metering
and relaying), wave traps, and surge arresters;
(5)
Proposed line terminal ratings and basis for calculation,
including limiting element;
(6)
Basis for load rating calculations on any equipment where
nameplate continuous ratings are not used; and
(7)
Description of the communication system for remote
monitoring, control and data acquisition facilities, including
monitoring and control points.
Any specific Transmission Proposal Request may require
submission of additional facility design data when deemed
necessary by the Transmission Provider. Any New
Transmission Proposal may also include additional facility
data, including but not limited to, optional facility design data
listed in the Business Practices Manual for Transmission
Planning, which may be considered by the Transmission
Provider in the evaluation and selection of New Transmission
Proposals.
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7.
Project Implementation Capabilities. Documentation of project
implementation capabilities required in a New Transmission Proposal must
include documented processes and methods to be used by the entity to perform:
(1)
Project management;
(2)
Routing evaluation studies for New Transmission Line Facilities, if
applicable;
(3)
Site evaluation studies for New Substation Facilities, if applicable;
(4)
Regulatory permitting;
(5)
Right-of-way acquisition for New Transmission Line Facilities, if
applicable;
(6)
Land acquisition for New Substation Facilities, if applicable;
(7)
Engineering and surveying required for New Transmission Line
Facilities and/or New Substation Facilities;
(8)
Material procurement for New Transmission Line Facilities and/or
New Substation Facilities;
(9)
Construction of New Transmission Line Facilities and/or New
Substation Facilities; and
(10)
Commissioning of New Transmission Line Facilities and/or New
Substation Facilities.
Any specific Transmission Proposal Request may require submission of
additional data related to the policies, processes, methods, capabilities,
experience, and past performance of New Transmission Proposal Applicants
regarding project implementation when deemed necessary by the Transmission
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Provider.
Any New Transmission Proposal may also include additional information
regarding project implementation capabilities, including but not limited to,
existing capabilities and past experience regarding project implementation, which
may be considered by the Transmission Provider in the evaluation and selection
of New Transmission Proposals.
8.
Operations, Maintenance, Repair, and Replacement Capabilities.
Documentation of operations, maintenance, repair, and replacement capabilities
required in a New Transmission Proposal must include documented processes and
methods to be used by the New Transmission Proposal Applicant to perform the
following as applicable depending on types of facilities included in the Open
Transmission Project:
(1)
Forced outage response for transmission line circuits;
(2)
Forced outage response for substations;
(3)
Switching for transmission line circuits;
(4)
Switching for substations;
(5)
Transmission line emergency repair;
(6)
Substation emergency repair and testing;
(7)
Transmission line preventative and/or predictive maintenance,
including vegetation management;
(8)
Substation preventative and/or predictive maintenance including
equipment testing;
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(9)
Maintenance and management of spare parts, spare structures, and/or
spare equipment inventories for substations and/or transmission lines,
as applicable, including description of any agreements to share spare
equipment, spare parts, and/or spare structures with other transmission
entities;
(10)
Real-time operations monitoring and control capabilities, if the Open
Transmission Project contains one or more New Substation Facilities;
and
(11)
Major facility replacements or rebuilds required as a result of
catastrophic destruction or natural aging through normal wear and tear,
including financial strategy to facilitate timely replacements and/or
rebuilds.
Any specific Transmission Proposal Request may require submission of
additional data related to the policies, processes, methods, capabilities,
experience, and past performance of entities regarding operations, maintenance,
repair, and replacement when deemed necessary by the Transmission Provider.
Additional information regarding operations, maintenance, repair, and
replacement capabilities may also be included in any New Transmission Proposal,
including but not limited to, existing capabilities and past experience regarding
operations, maintenance, repair and replacement, which may be considered by the
Transmission Provider in the evaluation and selection of New Transmission
Proposals.
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9.
Transmission Provider Planning Process Participation Documentation.
While not required, should a New Transmission Proposal Applicant participate in
the Transmission Provider planning process and desire to have such participation
considered in the evaluation as described in Section VIII.G of this Attachment FF,
the New Transmission Proposal Applicant should include in its New
Transmission Proposal documentation regarding relevant planning studies
performed by the New Transmission Proposal Applicant and results supplied to
the Transmission Provider planning process, as well as documentation on past
transmission project ideas submitted by the New Transmission Proposal
Applicant to the Transmission Provider to address the same Transmission Issues
being addressed by the Open Transmission Project for which the New
Transmission Proposal is being submitted.
10.
Modeling Data. Modeling data files submitted with the New Transmission
Proposal must meet the requirements outlined in the Business Practices Manual
for Transmission Planning, including, at a minimum, data files necessary:
(1)
To model New Transmission Line Facilities and/or New Substation
Facilities in power flow and short-circuit models and
(2)
To model new contingencies associated with New Transmission Lines
Facilities and/or New Substation Facilities.
11.
Period for Submission of New Transmission Proposals. New Transmission
Proposals must be submitted within 180 calendar days from the date the
Transmission Proposal Request is posted, or within the time period specified in
the Transmission Proposal Request, whichever comes first. If the due date falls
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on a federal holiday, Saturday, or Sunday, the New Transmission Proposals will
be due on the next business day. Two copies of the New Transmission Proposal
in hard copy form must be delivered to the address specified in the Transmission
Proposal Request no later than 5:00 PM EPT on the due date and one electronic
copy of the New Transmission Proposal must be e-mailed to the e-mail address
specified in the Transmission Proposal Request no later than 5:00 PM EPT on the
due date. Any inquiries by New Transmission Proposal Applicants regarding a
Transmission Proposal Request prior to submission of a New Transmission
Proposal should be made directly with the contacts listed in the Transmission
Proposal Request and not to the interconnecting incumbent Transmission Owners.
12.
Additional Data Requests. If, during the evaluation of New Transmission
Proposals, the Transmission Provider determines that additional information is
required to evaluate the Qualified Transmission Developers, the Transmission
Provider will request, in writing, the additional data from all Qualified
Transmission Developers, along with the timeframe that this data must be
submitted within. If the additional data is not submitted within the specified
timeframe, the New Transmission Proposal will not be evaluated or considered
further. This timeframe will not be less than ten (10) business days from when
the Transmission Provider issues the additional data request. This data request
will not extend the evaluation timeframe defined in Section VIII.G.
13.
Confidential Treatment of New Transmission Proposals. All information
submitted with the New Transmission Proposal will be considered Confidential
Information and will not be publicly posted or shared with any individual, except
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employees of the Transmission Provider, applicable state parties who have elected
to choose the Selected Transmission developers, as specified in Section VIII.A of
this Attachment FF, and/or contractors of the Transmission Provider that have
executed an appropriate non-disclosure agreement.
E.
Developer Qualifications. Any New Transmission Proposal Applicant may
submit a New Transmission Proposal, but must meet the minimum qualifications required for a
Qualified Transmission Developer in order for the Transmission Provider to accept and consider
the New Transmission Proposal. A New Transmission Proposal Applicant must either be a
Transmission Owner as defined in this Tariff or a Non-owner Member as defined in the ISO
Agreement at the time the Transmission Proposal Request is posted, and must maintain such
status throughout the entire process of evaluation and selection of New Transmission Proposals
and project implementation, provided that a Non-owner Member must become a Transmission
Owner. To be eligible to be considered a Qualified Transmission Developer, a New
Transmission Proposal Applicant that submits a New Transmission Proposal must include
therein all the agreements specified in Section VIII.D of this Attachment FF. Furthermore, a
New Transmission Proposal Applicant will not be considered a Qualified Transmission
Developer if all required data specified in the Transmission Proposal Request, including, but not
limited to, the required data outlined in Section VIII.D of this Attachment FF, is not included in
the New Transmission Proposal as required by Sections VIII.D and VIII.F of this Attachment
FF.
F.
Cure Period. Immediately after the date New Transmission Proposals are due,
the Transmission Provider will review each New Transmission Proposal to ensure all
qualifications and data requirements have been satisfied by each respective New Transmission
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Proposal Applicant. Should a New Transmission Proposal fail to satisfy one or more of the
qualifications or data requirements specified in this Tariff and/or in the Transmission Proposal
Request, the Transmission Provider will, within ten (10) business days, via e-mail notify the
submitting New Transmission Proposal Applicant, through the contact person designated in the
New Transmission Proposal, of any deficiency, and that New Transmission Proposal Applicant
will have a single Cure Period of ten (10) business days from this notice to revise and resubmit
the New Transmission Proposal to address the deficiency, except that if the New Transmission
Proposal Applicant is neither a Non-owner Member nor a Transmission Owner on the date the
Transmission Proposal Request was posted or ceases to become a Non-owner Member or
Transmission Owner after the date the Transmission Proposal Request was posted, that New
Transmission Proposal Applicant shall not be designated a Qualified Transmission Developer
and the New Transmission Proposal will not be evaluated or considered further. If a revised
New Transmission Proposal is submitted after the Cure Period has elapsed, or continues to have
one or more deficiencies with regard to qualifications or data requirements, the New
Transmission Proposal Applicant shall not be designated a Qualified Transmission Provider and
the New Transmission Proposal will not be evaluated or considered further. The Transmission
Provider will provide a written explanation identifying why the New Transmission Proposal
Applicant has been disqualified.
G.
Evaluation
1.
Steps of Evaluation and Selection Process. Upon receipt of all New
Transmission Proposals, sufficient in form and substance, by the due date
specified in the Transmission Proposal Request, and upon completion of
the process outlined in Section VIII.F of this Attachment FF,
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notwithstanding the authority of states to elect to choose the Selected
Transmission Developer within 360 days of the Transmission Proposal
Request, the Transmission Provider will:
(1)
Evaluate each New Transmission Proposal submitted by a
Qualified Transmission Developer;
(2)
Select one of the New Transmission Proposals for
implementation based on application of the evaluation criteria
below; and
(3)
Post the name of the Selected Transmission Developer on its
website within 180 calendar days of the due date for the
submission of New Transmission Proposals for the selection of
the developer either by a competent state regulatory authority
that chooses to make the selection, or by the Transmission
Provider, or within 450 calendar days from the posting of the
Transmission Proposal Request if a state initially elects to
perform an evaluation of the New Transmission Proposals
submitted for an Open Transmission Project and then the
Transmission Provider assumes responsibility for performing
evaluation as outlined in Section VIII.B of this Attachment FF.
2.
General Criteria. In evaluating each New Transmission Proposal, the
Transmission Provider will consider the following general aspects of the
proposal:
(1)
Cost and reasonably descriptive facility design quality;
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3.
(2)
Project implementation capabilities;
(3)
Operations, maintenance, repair, and replacement capabilities; and
(4)
Transmission Provider planning process participation.
Cost and Reasonably Descriptive Facility Design. When considering
cost and reasonably descriptive facility design quality, the Transmission
Provider shall evaluate, at a minimum:
(1)
Estimated project cost for each proposed New Transmission Line
Facility and/or New Substation Facility;
(2)
Estimated annual revenue requirements for all New Transmission
Facilities included in the New Transmission Proposal;
(3)
Cost estimate rigor, which shall include financial assumptions and
supporting information to clearly demonstrate a thorough analysis
in support of the cost estimate;
(4)
Reasonably descriptive facility design quality; and
(5)
Reasonably descriptive facility design rigor, which shall include
facility studies performed and other specific supporting data that
clearly documents and supports consideration and attention given
to the proposed reasonably descriptive facility designs.
4.
Project Implementation Capabilities. When considering project
implementation capabilities, the Transmission Provider shall evaluate, at a
minimum, existing or planned capabilities and processes regarding:
(1)
Project management;
(2)
Route and site evaluation;
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5.
(3)
Land acquisition;
(4)
Engineering and surveying;
(5)
Material procurement;
(6)
Facility construction;
(7)
Final facility commissioning; and
(8)
Previous applicable experience and demonstrated ability.
Operations, Maintenance, Repair, and Replacement Capabilities.
When considering operations, maintenance, repair and replacement
capabilities, the Transmission Provider shall evaluate, at a minimum,
existing or planned capabilities and processes regarding the following, as
applicable, based on the types of facilities included in the Transmission
Proposal Request:
(1)
Forced outage response;
(2)
Switching;
(3)
Emergency repair and testing;
(4)
Spare parts;
(5)
Preventative and/or predictive maintenance and testing;
(6)
Real-time operations monitoring and control; and
(7)
Major facility replacement capabilities, including ongoing
financial capabilities to restore facilities after catastrophic
outages.
6.
Transmission Provider Planning Process Participation. When
considering transmission provider planning process participation, the
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Transmission Provider will consider relevant planning studies conducted
by the Qualified Transmission Developer and the associated results
supplied to the Transmission Provider planning process, as well as
transmission project ideas submitted in the past by the Qualified
Transmission Developer as potential solutions to address the same
Transmission Issues addressed by the Open Transmission Project.
7.
General Criteria Weighting. In evaluating each New Transmission
Proposal, the Transmission Provider will apply the following weighting to
each New Transmission Facility criteria evaluated:
a.
New Transmission Line Facilities. The following weights will be
applied to New Transmission Line Facility criteria:
(1)
Cost and reasonably descriptive facility design quality:
30%
(2)
Project implementation capabilities: 35%
(3)
Operations, maintenance, repair, and replacement
capabilities: 30%
(4)
b.
Transmission Provider planning process participations: 5%
New Substation Facilities. The following weights will be applied
to New Substation Facility criteria:
(1)
Cost and reasonably descriptive facility design quality:
30%
(2)
Project implementation capabilities: 30%
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(3)
Operations, maintenance, repair, and replacement
capabilities: 35%
(4)
8.
Transmission Provider planning process participations: 5%
Evaluation and Selection. Specific methods used to evaluate various
aspects of a New Transmission Proposal shall be described in the Business
Practices Manual for Transmission Planning. This evaluation will be
conducted by Transmission Provider planning staff and/or independent
consultants competent in the areas of finance, transmission facility design,
transmission project implementation, and transmission operations,
maintenance, repair, and replacement. The Transmission Provider
planning staff, and any independent consultants, will be overseen by an
executive oversight committee consisting of three or more executive staff
of the Transmission Provider, including at least one officer, and the final
designation of the Selected Transmission Developer will rest with this
committee. The committee shall possess certain specific expertise
necessary for evaluation of New Transmission Proposals, such as, but not
limited to, transmission construction, engineering, project management,
financing, state regulatory, and operations. Within thirty (30) calendar
days of the designation of the Selected Transmission Developer, the
Transmission Provider will provide a report in which it explains the basis
for designating the Selected Transmission Developer for each Open
Transmission Project. Any disputes regarding the developer selection will
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be referred to the Dispute Resolution Process under Attachment HH of
this Tariff.
The Selected Transmission Developer will assume the responsibility and
obligation to construct the facilities it is selected to construct. If the
Selected Transmission Developer is financially incapable of carrying out its
construction responsibilities, alternate construction arrangements shall be
identified. Depending on the specific circumstances, such alternate
arrangements shall include solicitation of Transmission Owners to take on
financial and/or construction responsibilities. If the delay in construction
may adversely affect the Transmission System reliability, the
Transmission Provider shall coordinate with and support the affected
Transmission Owner(s) regarding any mitigation measures that may be
required by Applicable Reliability Standards.
However, in the event that an MTEP Appendix A Open Transmission
Project approved by the Transmission Provider Board or selection of the
designated Selected Transmission Developer to construct the approved
project is being challenged through the Dispute Resolution process under
Attachment HH of this Tariff or a court proceeding, the obligation of the
Selected Transmission Developer to build the specific Open Transmission
Project (subject to required approvals) is waived until the Open
Transmission Project or Selected Transmission Developer emerges from
the Dispute Resolution process or court proceedings as an approved
project with a Selected Transmission Developer designated to construct,
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implement, own, operate, maintain, repair, restore, and/or finance the
recommended Open Transmission Project.
9.
Recourse if No New Transmission Proposals are Received. If no New
Transmission Proposals are received from Qualified Transmission
Developers, the Open Transmission Project will be assigned to the
applicable Transmission Owner(s), as defined below:
(1) Ownership and the responsibility to construct facilities which are
connected to a single Transmission Owner’s system belong to that
Transmission Owner; (2) Ownership and the responsibilities to construct
facilities which are connected between two (2) or more Transmission
Owners’ facilities belong equally to each Transmission Owner, unless such
Transmission Owners otherwise agree; and (3) Ownership and the
responsibility to construct facilities which are connected between a
Transmission Owner(s)’ system and a system or systems that are not part of
the Transmission Provider belong to such Transmission Owner(s) unless the
Transmission Owner(s) and the non-Transmission Provider party or parties
otherwise agree.
IX.
Reevaluation. After Transmission Provider Board MTEP Appendix A approval, certain
circumstances or events may significantly affect such an Open Transmission Project in a manner
and to a degree that would require the Transmission Provider to perform Variance Analysis.
Such circumstances or events may include, but are not limited to: material schedule delays, cost
increases, or changes to the Selected Transmission Developer’s qualifications, as compared to
the schedule, cost estimates, and qualifications represented in the New Transmission Project
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Proposal and/or MTEP Appendix A, as applicable. The Variance Analysis shall consider, among
other things: (i) causes of, or reasons for, any such circumstance or event; (ii) impacts, including
potential reliability impacts of a delay in the Open Transmission Project, canceling the Open
Transmission Project, or replacing the Selected Transmission Developer; (iii) mitigation
measures and responsibilities; and (iv) solutions, and the timetable for the implementation of
such solutions. This process will begin at assignment of an Open Transmission Project and end
when construction begins.
A.
Grounds for Variance Analysis
The following factors shall trigger the Transmission Provider’s Variance Analysis
for an Open Transmission Project. The Variance Analysis will focus on the materiality
of the changes identified and determine the need for full reevaluation.
1.
Cost Increases
Any project cost increase which reduces the benefit-cost ratio of an
economically-driven Open Transmission Project to less than the required
benefit-to-cost threshold, as defined in Section II.B.1.e or Section II.C.7 of
this Attachment FF of the Tariff.
2.
Schedule Delays
A reported or otherwise identified delay of 6 months or more from the inservice date established in MTEP Appendix A and agreed upon in the
accepted New Transmission Proposal and Binding Proposal Agreement of
any assigned Open Transmission Project. This analysis may also be based
upon failure to obtain necessary regulatory approvals; failure to execute
necessary agreements; or failure to take the actions described in the
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Selected Transmission Developer’s accepted New Transmission Proposal.
3.
Deviation From Selected Transmission Developer Qualifications
Material changes in the condition and characteristics of the Selected
Transmission Developer, as described in its accepted New Transmission
Proposal.
Material changes in this subsection may include, but are not limited to,
any delegation or assignment not described in the New Transmission
Proposal of project responsibilities to another entity, including affiliates,
or a partner that is either previously undisclosed, or disclosed but assigned
to or designated for different responsibilities or failure to conform to the
terms described in the Selected Transmission Developer’s accepted New
Transmission Proposal.
B.
Project Reevaluation
If required by the results of the above-described additional analysis, the
Transmission Provider shall perform a reevaluation of the Open Transmission Project
and/or Selected Transmission Developer, including, but not limited to:
1.
Cost Increases
As applicable and necessary based upon the Variance Analysis, the
Transmission Provider shall use the Open Transmission Project’s current
cost estimate to perform an analysis and determine if said Open
Transmission Project’s currently estimated benefit is sufficient to justify
its continued construction.
2.
Schedule Delays
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As necessary based upon the Variance Analysis, the Transmission
Provider shall perform an analysis to determine if the delay in the
achievement of any significant schedule milestone(s) (including, but not
limited to, failure to obtain necessary regulatory approvals) will delay the
applicable Open Transmission Project’s in-service date, and if so, whether
such delay poses risks of adverse impacts on Transmission System
reliability, and what mitigation measures and plan should be implemented.
3.
Deviation From Selected Transmission Developer Qualifications
As necessary based upon the Variance Analysis, the Transmission
Provider shall perform an analysis to determine if the Selected
Transmission Developer remains qualified to construct, implement,
operate, maintain, and/or restore the Open Transmission Project.
C.
Reevaluation Outcomes
Based on all the required analysis described in subparagraphs a and b of this
section, the Transmission Provider may decide to (i) make no change to the Open
Transmission Project; (ii) reassign the Open Transmission Project to a different Qualified
Transmission Developer; (iii) cancel the Open Transmission Project (iv) implement a
reliability mitigation plan, in coordination with the affected Transmission Owner(s); or
(v) such other remedy or solution as may be appropriate under the circumstances,
including a suitable combination of two or more of the foregoing courses of action.
1.
Reassignment
If a Selected Transmission Developer is found to no longer be a Qualified
Transmission Developer, the applicable Open Transmission Project may
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be reassigned. Open Transmission Projects will be offered to the
applicable Transmission Owner, as defined below:
(1) Ownership and the responsibility to construct facilities which are
connected to a single Transmission Owner’s system belong to that
Transmission Owner; (2) Ownership and the responsibilities to construct
facilities which are connected between two (2) or more Owners’ facilities
belong equally to each Transmission Owner, unless such Transmission
Owners otherwise agree; and (3) Ownership and the responsibility to
construct facilities which are connected between a Transmission Owner(s)’
system and a system or systems that are not part of the Transmission
Provider belong to such Transmission Owner(s) unless the Transmission
Owner(s) and the non-Transmission Provider party or parties otherwise
agree.
If the applicable Transmission Owner(s) decline to construct the Open
Transmission Project, it will be reassigned, as applicable, through the
developer evaluation process, as described in Section VIII.F.
2.
Project Cancellation
Following reevaluation, the Transmission Provider may cancel
economically-driven Open Transmission Projects if (1) cost increases
reduce the benefit-cost ratio to the point where the currently estimated cost
exceed previously defined benefits; and (2) reliability and/or public policy
benefits (if any), are insufficient to justify continuation and completion of
the project.
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3.
Reliability Mitigation Plan
If the Transmission Provider’s analysis determines that Transmission
System reliability may be adversely affected by the delay of an assigned
Open Transmission Project, the Transmission Provider shall coordinate
with and support the affected Transmission Owner(s) regarding any
mitigation measures that may be required by Applicable Reliability
Standards. The mitigation measures may include, without limitation, any
one or combination of the following components: i) an updated
implementation plan of the Selected Transmission Developer to meet the
required in-service date; ii) an operating procedure; or iii) an alternative
project to mitigate the reliability violation.
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Exhibit No. MISO-1
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Midwest Independent
Transmission System
Operator, Inc.
)
)
Docket No. ER13-___-000
PREPARED DIRECT TESTIMONY OF JENNIFER CURRAN
ON BEHALF OF
MIDWEST INDEPENDENT TRANSMISSION
SYSTEM OPERATOR, INC.
AND MISO TRANSMISSION OWNERS
October 25, 2012
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Exhibit No. MISO-1
Page 1 of 41
INTRODUCTION
Witness Background
Q.
Please state your name, current position, and business address.
A.
My name is Jennifer Curran. I am employed by the Midwest Independent Transmission
System Operator, Inc. (“MISO”), and my business address is at 720 City Center Drive,
Carmel, Indiana 46032.
Q.
Please briefly describe your educational background and professional experience.
A.
I hold a Bachelor of Science in Mechanical Engineering from Rice University, and a
Master of Business Administration from Duke University. Prior to joining MISO in July
2004, I was Manager of Power Generation & Supply Strategy for the Mid-Atlantic and
Mid-Continent Regions at what was then known as Reliant Resources.
Q.
Please describe your responsibilities with MISO.
A.
I am Executive Director of Transmission Infrastructure Strategy, a position I have held
since October 2009.
From February 2007 to October 2009, I was Director of
Transmission Infrastructure Strategy.
I am currently responsible for directing the
development and execution of strategies to enable increased transmission infrastructure
investment through the MISO transmission planning process. In this role, I focus on
supporting the state and federal regulatory and business case requirements for
transmission infrastructure. In addition, I am responsible for leading the development of
effective transmission cost allocation methodologies. I also serve as a MISO staff liaison
to the Board of Directors System Planning Committee, which is responsible for providing
overall direction to the MISO planning staff and reviewing the MISO Transmission
Expansion Plan (“MTEP”).
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I previously served as the MISO staff liaison to the stakeholder committee charged with
improvement of the current cost allocation method, the Regional Expansion Criteria and
Benefits Task Force (“RECB TF”). Also, I previously served as the MISO staff liaison to
the Planning Advisory Committee, which is the stakeholder committee that provides
advice to the MISO planning staff on policy matters related to the process, integrity, and
fairness of the MISO-wide transmission expansion plan and cost allocation. I have also
served as the Director of Performance Assurance at MISO, responsible for business and
financial planning for the operations areas of the company.
Q.
Have you sponsored any other testimony before regulatory commissions?
A.
Yes.
I have submitted prepared testimony before the Federal Energy Regulatory
Commission (“FERC” or “Commission”) involving matters specific to MISO.
For
example, I submitted testimony in Docket No. ER10-1791-000, where the Commission
approved MISO’s Open Access Transmission, Energy and Operating Reserve Markets
Tariff (“Tariff”) provisions establishing Multi-Value Projects (“MVPs”) and the regional
(i.e., system-wide) allocation of MVP-related costs. Most recently, I submitted testimony
in Docket Nos. ER12-715-000 and ER12-715-003, where MISO and the MISO
Transmission Owners submitted revisions to the MISO Tariff relating to a new proposed
Schedule 39 and the responsibility of two withdrawing Transmission Owners for costs
under that schedule. I have also submitted testimony in support of MISO in other
proceedings before the Commission and state regulatory commissions.
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Purpose of Testimony
Q:
What is the purpose of your testimony?
A:
The purpose of this testimony is to support MISO’s Order No. 10001 compliance filing
and related Tariff revisions.
Q:
Are you sponsoring any exhibits along with your testimony?
A:
Yes. In addition to this testimony, I am sponsoring the following exhibits: Exhibit No.
MISO-2, which describes MISO’s stakeholder process for developing this compliance
filing; Exhibit No. MISO-3, which outlines the Organization of MISO States (“OMS”)
proposal on participation in MISO transmission planning; Exhibit No. MISO-4, which is
a map of the MISO pricing zones; Exhibit No. MISO-5, which demonstrates the relative
transmission owner investment in each pricing zone; Exhibit No. MISO-6, which
demonstrates potential transmission lines previously identified; Exhibit No. MISO-7,
which demonstrates the hierarchy of MISO transmission project types and related cost
allocation; and Exhibit No. MISO-8, which is a Hypothetical Transmission Proposal
Request.
ICURRENT PLANNING PROCESS
Compliance with Order No. 1000 Requirements – Regional Planning
Q.
How does MISO plan for reliability?
A.
MISO is registered with NERC as a Planning Coordinator and, as such, fully evaluates
and plans for the reliability of the transmission system in accordance with the NERC
1
Transmission Planning and Cost Allocation by Transmission Owning and Operating Public
Utilities, Order No. 1000, III FERC Stats. & Regs., Regs. Preambles ¶ 31,323 (2011), order
on reh’g and clarification, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g and
clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012).
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planning standards.
MISO develops an annual regional expansion plan based on
expected use patterns and analysis of the performance of the Transmission System in
meeting both reliability needs and the needs of the competitive bulk power market, under
a wide variety of contingency conditions. These efforts are undertaken collaboratively
with member Transmission Owners and other stakeholders, consistent with the
Transmission Owners Agreement.
Q.
How does MISO plan for economics?
A.
This regional plan also considers the long-range economic impacts of proposed
transmission projects. Through the Planning Advisory Committee and in consultation
with stakeholders, MISO considers a multitude of economic, policy, and operational
factors to identify an optimal long-term expansion plan. This long-term planning process
provides a blueprint for resolving future congestion and reliability needs associated with
the evolving generation mix, load growth, and other issues that must be addressed by
transmission expansion. The MISO planning process also provides stakeholders the
opportunity to provide input regarding near-term congestion issues. This review enables
MISO to understand stakeholders’ historical congestion data, evaluate the expected
impact of the approved upgrades, and develop prioritized study scopes to address the
most significant and persistent congestion or generation integration issues.
Q.
How does MISO plan for public policy?
A.
MISO’s planning process includes procedures for the identification and consideration of
transmission needs driven by public policy requirements in both local and regional
transmission planning processes, and the evaluation of potential transmission solutions.
The identification, consideration, and evaluation of these projects is conducted in the
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open and transparent stakeholder process, allowing ample opportunity for stakeholder
input into transmission needs stakeholders believe are transmission needs driven by
public policy requirements.
Q.
How does the MISO planning process include stakeholder input?
A.
The above-described analysis of projects, and MISO’s “bottom-up, top-down” planning
process, which is explained below, integrates into the development of the regional plan
many factors, including:
(i) the transmission needs identified by the Transmission
Owners in planning analyses conducted as part of their local planning processes, to
provide reliable power supply to their connected load customers and to expand trading
opportunities, better integrate the grid, and alleviate congestion; (ii) the transmission
planning obligations of a Transmission Owner, imposed by federal or state laws or
regulatory authorities; (iii) plans and analyses developed by MISO to provide for a
reliable Transmission System and to expand trading opportunities, better integrate the
grid and alleviate congestion; (iv) the inputs provided by the Planning Advisory
Committee; and (v) the inputs provided by the OMS Committee,2 which is comprised of
members representing regulators from each state with retail regulatory jurisdiction over
entities participating in MISO.
Q.
Please provide an example of when MISO used stakeholder input to determine
public policy driven requirements.
A.
In 2008, MISO, with the assistance of state regulators and industry stakeholders such as
the Midwest Governor’s Association (MGA), the Upper Midwest Transmission
Development Initiative (UMTDI) and the Organization of MISO States (OMS), began the
2
I discuss the formation of the OMS Committee below.
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Regional Generation Outlet Study (RGOS) to identify a set of value-based transmission
projects necessary to enable load-serving entities located in the MISO footprint to meet
their Renewable Portfolio Standard (“RPS”) mandates. The level and type of renewable
requirements were solicited directly from the affected states and load serving entities and
converted – through a robust stakeholder process into energy zones that served as a key
input into the study. The ultimate goal of the RGOS analysis was to design transmission
portfolios that would enable RPS mandates to be met at the lowest delivered wholesale
energy cost.
This analysis continued through several MTEP cycles and eventually
culminated in the Candidate MVP Portfolio analysis and the recommendation of the
MVP portfolio to the Board of Directors, which reliably and economically integrated the
renewable energy required for the public policy driven requirements in the region.
Q.
Does the MISO planning process comply with Order No. 1000 compliance
requirements?
A.
MISO’s existing planning process is largely compliant with the regional planning
requirements described in Order Nos. 1000, 1000-A, and 1000-B. MISO’s planning
process previously has been found to comply with the requirements of Order No. 890,3
which Order Nos. 1000 and 1000-A build upon.4 The MISO planning process creates a
regional transmission plan that addresses reliability, economic, and public policy needs,
as discussed above. This process evaluates whether to select a proposed transmission
facility in the regional MISO Transmission Expansion Plan (“MTEP”) for purposes of
3
Midwest Indep. Transmission Sys. Operator, Inc., 123 FERC ¶ 61,164 (2008) (“Order
No. 890 Compliance Order”), orders on compliance, 127 FERC ¶ 61,169 (2009) and 130
FERC ¶ 61,232 (2010).
4
Order No. 1000 at P 1; Order No. 1000-A at P 1.
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cost allocation5 and is designed to culminate in a determination sufficiently detailed for
stakeholders to understand why a particular project was selected or not selected in the
MTEP for purposes of cost allocation.
This evaluation considers alternative non-
transmission solutions6 and transmission solutions,7 consistent with Order Nos. 890 and
1000 (at P 148). The development of the regional plan is undertaken in an open and
transparent planning process, which provides multiple opportunities for all stakeholders
to review and provide input into the plan.
COMPLIANCE WITH ORDER NO. 1000 REQUIREMENTS
Regional Cost Allocation
Q.
Please explain the MISO approach to local and regional project classification.
A.
Through MISO’s Order No. 890-compliant planning protocols set forth in Attachment FF
of the Tariff, MISO evaluates and subsequently approves projects to address certain
Transmission Issues, including economic, reliability, and public policy requirements.
Through MISO’s bottom up, top-down planning process, it evaluates both local and
regional transmission projects. MISO’s regional planning process seeks to identify the
most efficient or cost-effective solution to address multiple regional needs. For example,
5
Sections II and III of Attachment FF of the Tariff.
6
MISO notes that, because resource adequacy is under the jurisdiction of the states, it is not
appropriate for MISO to include in the regional transmission plan recommendations of
“uncommitted” non-transmission alternatives (e.g., Generation Resources and Demand
Response Resources). To ensure compliance with reliability standards, only “committed”
non-transmission alternatives can be considered.
7
Consistent with Order No. 1000 (at P 148), MISO’s process also considers alternative
transmission solutions. Section IX of Appendix B to Transmission Owners Agreement
(MISO shall “identify alternatives for further study and review that could increase the
efficient and economic use of the Transmission System.”); Section I.B.1.b of Attachment FF
(“alternatives may include transmission, generation, and demand-side resources”).
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in the MISO planning process, Transmission Owners identify local reliability issues and
propose potential solutions (“bottom-up”), while MISO assesses Transmission Issues and
possible solutions on a regional basis (“top-down”) that may be more cost-effective
and/or efficient solutions that provide greater regional reliability, market, and public
policy benefits.
Q.
What project types does MISO evaluate as part of its planning process?
A.
Under Attachment FF of the Tariff, there are multiple project types that are evaluated
under specific criteria as part of the MISO MTEP process to determine allocation of
costs. These project types include Baseline Reliability Projects (“BRPs”), Generation
Interconnection Projects (“GIPs”), Market Efficiency Projects (“MEPs”), MVPs,
Transmission Delivery Service Projects, and other projects that do not meet one of the
prior identified project types.8 Upon a project being approved in Appendix A of MTEP,
the identified party is obligated to construct the project.
Q.
Are the costs of any of these projects allocated outside of a single pricing zone?
A.
Yes. Under the current MISO Tariff, three project types (BRPs, MEPs, and MVPs) have
costs that are allocated to load outside of the pricing zone where the project is located.9
In the case of BRPs, costs may be allocated to more than one pricing zone, while MEPs
are partially and MVPs are wholly allocated on a system-wide basis. MEPs and MVPs,
given their broad regional cost allocation and benefits meet the definition in Order No.
8
Other projects are network upgrades that do not qualify as a BRP, GIP, MEP, MVP, or
TDSP with the costs remaining within the zone where the project is located. TDSP are
network upgrades due to transmission service requests, and are recovered either from the
requestor or load in the pricing zone where the project is located.
9
Under certain circumstances, GIP costs can also be allocated beyond a single pricing zone.
GIPs are beyond the scope of Order No. 1000, and are not discussed further.
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1000 for a “transmission facility selected in the regional transmission plan for purposes
of cost allocation.”10 As discussed in the concurrent BRP cost allocation modification
filing, MISO is proposing to modify the BRP cost allocation methodology in recognition
of the fact that these projects are driven by local reliability needs and therefore should be
designated as local transmission facilities that are not purposely included in the regional
transmission plan for purposes of regional cost allocation.
Q.
Please explain the BRP project type.
A.
BRPs are Network Upgrades designed to ensure that the MISO Transmission System
remains in compliance with applicable national Electric Reliability Organization
(“ERO”) reliability standards, and reliability standards adopted by Regional Reliability
Organizations that are applicable within MISO.11 BRPs include projects operating at 100
kV or greater that are needed to maintain reliability while accommodating the ongoing
needs of existing Transmission Customers.
Under the current Tariff, BRPs can be
categorized as cost shared or not cost shared depending on project cost. For a BRP to be
considered for cost sharing it must have: (1) a project cost of $5 million or greater; or (2)
a project cost under $5 million that is 5% or more of the constructing Transmission
Owner’s net transmission plant. Cost shared BRPs are allocated in the following manner:
10
Transmission Planning and Cost Allocation by Transmission Owning and Operating Public
Utilities, Order No. 1000, III FERC Stats. & Regs., Regs. Preambles ¶ 31,323, at P 63
(2011), order on reh’g and clarification, Order No. 1000-A, 139 FERC ¶ 61,132, order on
reh’g and clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012).
11
See Section II.A.1 in Attachment FF of the Tariff, defining BRPs. See also Cost Allocation
Policy Filing of Midwest Independent Transmission System Operator, Inc., Docket No.
ER06-18-000, at 16 (Oct. 7, 2005) (“RECB I Filing”), which at that time referred to the
“North American Electric Reliability Council (‘NERC’), regional reliability councils, or
successor organizations.”
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(1) for facilities less than 345 kV, 100% of the costs are allocated to individual pricing
zones on the basis of a Line Outage Distribution Factor (“LODF”) analysis; and (2) for
facilities 345 kV or greater, 80% of the costs are allocated to individual pricing zones on
the basis of a LODF analysis, and 20% of the costs are allocated on a system-wide basis
to all pricing zones. The LODF analysis assigns the BRP project costs to pricing zones
based on a flow-based impact that the new transmission line would have on the total
flows in any other pricing zone as a total percentage of all other pricing zones.12
Q.
Please explain the MEP category of transmission projects.
A.
MEPs are economic upgrades that meet specific criteria, including that the project costs
$5 million or greater, primarily involves facilities with a voltage of 345 kV or greater,
and meets a defined benefit-to-cost requirement.13 For projects that meet the MEP
criteria, 80% of the costs are allocated to all Transmission Customers in the appropriate
Local Resource Zones based on the distribution of benefits across the Local Resource
Zones, and 20% of the costs are allocated on a system-wide basis to all Transmission
Customers. 14
12
Section 1.356 of the Tariff defines the LODF as: “The percent of flow on line A, which is
transferred to line B for the loss of line A. Further explanation on the LODF analysis is
available in the Transmission Planning Business Practices Manual No. 020 (Nov. 15, 2011),
https://www.midwestiso.org/Library/BusinessPracticesManuals/Pages/BusinesPracticesMan
uals.aspx. .
13
Compliance Filing of Midwest Independent Transmission System Operator, Inc., Docket
No. ER06-18-004, at 8 (Nov. 1, 2006) (“RECB II Filing”); see also Tariff, Attachment FF,
Sections II.B and III.A.2.f.
14
The cost allocation across the Local Resource Zones is determined using the distribution of
adjusted production cost savings. Adjusted production cost is defined as the total production
cost of the generation fleet adjusted for import costs and export revenues. Tariff,
Attachment FF, Sections II.B.1.a and III.A.2.f.ii.
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Q.
Please explain the MVP category of transmission projects.
A.
MVPs are defined as one or more Network Upgrades that address a common set of
Transmission Issues and satisfy the conditions listed in Sections II.C.1, II.C.2, and II.C.3
of Attachment FF of the Tariff. MVPs are evaluated as portfolios of projects, whose
benefits are spread broadly across the MISO footprint, to enable the reliable and
economic delivery of energy in support of documented energy policy mandates or laws
that have been enacted or adopted through state or federal legislation, provide multiple
types of economic value across multiple pricing zones, or address, through the
development of a robust Transmission System, multiple Transmission Issues associated
with reliability and economic issues affecting multiple pricing zones.15 The costs of
approved MVPs are allocated 100% on a system-wide basis.16 The MVP transmission
project category, and its associated broad-based cost allocation, is designed to, among
other things, enable MISO to address multiple reliability needs and provide economic
value through regional transmission development, while addressing identified
transmission needs driven by public policy requirements.
Q.
Do the MISO cost allocation methodologies comply with Order No. 1000 compliance
requirements?
A.
Yes. MISO’s cost allocation process has previously been found to comply with the
requirements of Order No. 890,17 which Order Nos. 1000 and 1000-A build upon.18
15
Attachment FF Sections II.C.1, II.C.2 and II.C.3
16
Section III.A.2.g of Attachment FF.
17
Midwest Indep. Transmission Sys. Operator, Inc., 123 FERC ¶ 61,164 (2008) (“Order
No. 890 Compliance Order”), orders on compliance, , 127 FERC ¶ 61,169 (2009) and 130
FERC ¶ 61,232 (2010).
18
Order No. 1000 at P 1; Order No. 1000-A at P 1.
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MISO’s process appropriately allocates the cost of transmission projects that address a
variety of needs, relating to reliability (e.g., through Baseline Reliability Projects or
“BRPs”),19 economics (e.g., through Market Efficiency Projects or “MEPs”),20 and
reliability, economics, and public policy (through Multi-Value Projects or “MVPs,”
under Criterion 1 thereof).21 The costs of such projects are allocated in a manner that is
consistent with cost causation, and commensurate with the associated benefits, without
involuntary allocation to non-beneficiaries or outside of the MISO region. These cost
allocation methods use benefit-to-cost ratio thresholds of 1.0 to 1.25 for economic-based
projects, and they rely upon the transparent determination of benefits and identification of
beneficiaries, as discussed previously.
Benefits of MISO Transmission Process
Q.
How much investment is made in a typical MTEP?
A.
In MISO’s 2011 Transmission Expansion Plan report (“MTEP11”), the MISO Board of
Directors approved $6.5 billion in new transmission projects,22 including, among other
projects: (i) the first MVP portfolio consisting of 17 projects with a total estimated cost of
19
Midwest Indep. Transmission Sys. Operator, Inc., 114 FERC ¶ 61,106 (“RECB I Order”),
order on reh’g, 117 FERC ¶ 61,241 (2006).
20
Midwest Indep. Transmission Sys. Operator, Inc., 118 FERC ¶ 61,209 (“RECB II Order”),
order on reh’g, 120 FERC ¶ 61,080 (2007) (“RECB II Rehearing Order”); Midwest Indep.
Transmission Sys. Operator, Inc., 139 FERC ¶ 61,261 (2012).
21
Midwest Indep. Transmission Sys. Operator, Inc., 133 FERC ¶ 61,221 (2010) (“MVP
Order”), order on reh’g, 137 FERC ¶ 61,074 (2011) (“MVP Rehearing Order”).
22
MTEP11 at 1. The MTEP11 report and related material are posted on the MISO website at
https://www.midwestiso.org/Planning/TransmissionExpansion
Planning/Pages/MTEP11.aspx.
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$5.2 billion;23 and (ii) 40 Baseline Reliability Projects with a total estimated cost of $424
million required to meet North American Electric Reliability Corporation (“NERC”)
reliability standards.24
The MTEP process recommends a significant portion of transmission investment in each
planning cycle, although the $6.5 billion recommended for approval in MTEP11 is higher
than average. Since the first MTEP cycle closed in 2003, an average of $1.8 billion25 in
transmission projects have been approved in each planning cycle, for a cumulative
approved investment of $14.3 billion for 553 projects, of which $4.3 billion is associated
with projects that are now in service.26
Q.
Has this investment been efficient and cost-effective?
A.
Yes. For example, the 2011 MVP portfolio alone provides substantial economic benefits
according to MISO’s analysis in the MTEP11 Report, including: $41 billion of increased
market efficiency; $5 billion of deferred generation investment; $3 billion of benefit for
efficient wind turbine siting and avoided transmission investment on a 40 year net present
value basis.27 These benefits are significant when compared against a capital investment
23
Total portfolio includes the Michigan Thumb project, approved in August 2010. Costs listed
in 2011 dollars, as estimated at time of the portfolio approval. The Multi Value Project
Portfolio report and related material is posted on the MISO website at
https://www.midwestiso.org/Library/Repository/Study/Candidate%20MVP%20Analysis/M
VP%20Portfolio%20Analysis%20Full%20Report.pdf]
24
MTEP11 at 4. The MTEP11 report and related material is posted on the MISO website at
https://www.midwestiso.org/Planning/TransmissionExpansion
Planning/Pages/MTEP11.aspx.
25
SOURCE IS MTEP12 report, section 3.2
26
MTEP11 at 4.
27
MTEP11 at 64.
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of approximately $5.2 billion.28 In addition, the 2011 MVP portfolio resolved reliability
violations on approximately 650 elements for more than 6,700 system conditions and
mitigated 31 system instability conditions, making possible the safe and efficient delivery
of renewable resources to meet applicable state public policy requirements.29
Q.
Can you provide a specific example of when the MISO Planning Process identified a
more efficient or cost-effective regional solution that replaced local projects.
A.
As I indicated above, MISO recently evaluated and approved the 2011 MVP portfolio, a
$5.2 billion set of transmission projects that will, as a group, improve system reliability,
provide economic value, and enable public policy mandates. As part of this analysis, two
projects in Iowa that were defined in previous studies and stakeholder input were
reconfigured, resulting in a solution that addressed more reliability issues than the two
original projects at roughly the same cost.
REVISIONS OVERVIEW
Stakeholder Process
Q.
Please describe stakeholder involvement in developing the instant filing.
A.
In developing the instant filing to comply with the requirements of Order No. 1000,
MISO and its stakeholders engaged in an intensive process involving robust discussion
through multiple forums. As detailed in the attached Exhibit No. MISO-2, MISO began
discussions with its stakeholders through the Planning Advisory Committee (PAC) and
the RECB Task Force in October 2011. In February 2012, the Right of First Refusal
(ROFR) Task Team was formed specifically to consider and address the directives in
28
MTEP11 at 1; Value shown is in 2011 dollar terms.
29
MTEP11 at 1, 7, 42, 60.
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Order No. 1000 to remove from Commission-jurisdictional tariffs and agreements
provisions granting incumbent transmission providers a federal ROFR for certain
facilities. These comprehensive stakeholder discussions resulted in significant consensus
on most compliance requirements, although there were differences of opinion among
stakeholders and between MISO and its stakeholders on certain issues, including, as
discussed below, the transmission developer selection process.
MISO and its
stakeholders were effectively able to reach compromises on some of these contested
issues after interested stakeholders were given an opportunity to explain their positions
and suggest solutions, and after MISO duly considered potential solutions and obtained
both formal and informal stakeholder votes and comments on the solutions proposed in
this filing.
State Involvement in the Planning Process
Q:
What is the Organization of MISO States?
A:
The Organization of MISO States or “OMS,” is a non-profit, self-governing organization
of representative regulators from each state with retail regulatory jurisdiction over entities
participating in the MISO. As a general matter, the OMS serves as a forum for state
retail regulatory authorities to coordinate their MISO-related activities, including
developing and making recommendations to MISO, the MISO Board of Directors, the
Federal Energy Regulatory Commission (“FERC” or “Commission”), other relevant
government entities, and state commissions as appropriate.
Q:
Is MISO proposing amendments to codify the OMS role in transmission planning?
A:
Yes.
To effectuate clarification and enhancement of the OMS role in transmission
planning, and consistent with the requirements of Order No. 1000, the OMS unanimously
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approved a proposal regarding its participation in the MISO transmission planning
process on August 16, 2012, a copy of which is attached to my testimony as Exhibit No.
MISO-3. MISO is proposing associated amendments to Attachment FF of the Tariff and
to the Transmission Owners Agreement to incorporate the provisions of the OMS
proposal.
Q:
Please describe the general purpose of the amendments MISO is proposing to
Attachment FF of the Tariff and Transmission Owners Agreement to incorporate
the OMS transmission planning proposal.
A:
The amendments that MISO is proposing to Attachment FF of the Tariff create an OMS
Committee and codify in the Tariff the continued opportunity for the OMS Committee to
provide input into MISO’s transmission planning, resource adequacy, and transmission
cost allocation processes.
Similar conforming revisions are proposed for the
Transmission Owners Agreement.
Q:
How does the OMS Committee differ from the OMS?
A:
The OMS Committee is composed of the members of the OMS and is a committee within
the MISO structure through which the OMS provides its transmission planning inputs
under Attachment FF of the Tariff.
Q:
Please provide an overview of the most important amendments to Attachment FF
that would effectuate the OMS transmission planning proposal.
A:
Included in the amendments are provisions that specifically provide for the OMS
Committee to have input into transmission planning principles and objectives,
transmission planning scope elements, transmission planning modeling inputs and/or
assumptions, and cost-benefit analyses for transmission projects that are not proposed
strictly for reliability purposes. The amendments also indicate that MISO will provide a
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prompt and clear response to the OMS Committee’s inquiries and requests. Moreover,
the amendments provide for a process for the OMS Committee to request that MISO
reconsider, under certain circumstances, a transmission project submitted for regional
cost allocation and recommended for inclusion in the MISO Transmission Expansion
Plan (“MTEP”).
Finally, these amendments provide the OMS Committee with the
opportunity to request and receive reasonable assistance from MISO in developing OMS
Committee input into the MTEP process. While the amendments to Attachment FF of
the Tariff provide a general framework, more specific issues and processes will be
addressed in MISO’s Business Practices Manuals.
Also, conforming revisions are
included in the Transmission Owners Agreement.
APPLICABILITY OF NONINCUMBENT TRANSMISSION DEVELOPER REFORMS
Project Applicability – Local and Regional Projects
Q.
What is the definition of local transmission facilities in Order No. 1000?
A.
The Commission defined “local transmission facilities” as “transmission facility[ies]
located solely within a public utility transmission provider’s retail distribution service
territory or footprint that [are] not selected in the regional transmission plan for purposes
of cost allocation.”30 Local transmission facilities are not “transmission facilities selected
in the regional transmission plan for purposes of cost allocation,”31 which the
Commission defined as “transmission facilities that have been selected pursuant to a
transmission planning region’s Commission-approved regional transmission planning
30
Order No. 1000 at P 63.
31
Order No. 1000 at PP 226, 318 (indicating that the “focus” of Order No. 1000 is
“transmission facilities that are evaluated at the regional level and selected in a regional
transmission plan for purposes of cost allocation”).
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process for inclusion in a regional transmission plan for purposes of cost allocation
because they are more efficient or cost-effective solutions to regional transmission
needs.”32
Q.
What is the significance in Order No. 1000 of being a local transmission facility?
A.
In Order No. 1000, the Commission indicated that public utility transmission providers
are not required to eliminate provisions granting a federal right of first refusal for local
transmission facilities. The Commission elaborated in paragraph 423 of Order No. 1000A that “Order No. 1000 does not require elimination of a federal right of first refusal for a
new transmission facility if the regional cost allocation method results in 100% of the
facility’s cost being allocated to the public utility transmission provider in whose retail
distribution service territory or footprint the facility is to be located.” Order No. 1000-B
affirmed this finding.
Q.
What projects in MISO are not local transmission facilities?
A.
MEPs and MVPs are not local transmission facilities. These projects are solutions to
regional needs, and their justification is based upon the determination and quantification
of regional benefits to the Transmission System.
Q.
How do BRPs relate to the definition of local transmission facilities in Order No.
1000?
A.
BRPs are the type of “local transmission facility” contemplated by Order Nos. 1000 and
1000-A.
First, BRPs are projects that are identified to enable MISO Transmission
Owners to maintain local reliability while accommodating the ongoing needs of existing
Transmission Customers. BRPs are transmission facilities that are planned and approved
32
Order No. 1000 at P 63.
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in MTEP because they address local reliability needs and aid a MISO Transmission
Owner in meeting its state-imposed obligation to serve retail customers, and not
necessarily because they are more efficient or cost-effective solutions to regional
transmission needs. Additionally, MISO demonstrates in its concurrent filing to revise
BRP cost allocation that, to date, the benefits of BRPs have accrued primarily to the
pricing zone in which the BRP is located. Finally, as discussed below, with the addition
of the MEP and MVP categories, reliability projects that also satisfy the MEP or MVP
criteria will be categorized as MEPs or MVPs rather than as BRPs, meaning that the
BRPs will continue to address local needs.
Q.
Do BRPs typically involve 345 kV or greater facilities that include a 20% postage
stamp allocation?
A.
No. Only 17 out of the 78 BRPs approved for cost sharing since MTEP06 have included
at least one 345 kV or greater facility resulting in a 20% postage stamp allocation. The
limited number of higher voltage facilities (e.g. 345 kV or greater) further illustrates the
local nature of the Transmission Issues being addressed by BRPs. Also, with the addition
of MVPs to regional cost allocation, which will “sweep up” additional reliability projects,
it is likely that going forward fewer 345 kV facilities would be categorized as BRPs.
Project Classification and Hierarchy Safeguards
Q.
Would the elimination of regional cost allocation for BRPs allow for regional
projects to be categorized as BRPs, and therefore, by design, be excluded from the
inclusive evaluation process MISO proposes in this filing?
A.
No. MISO planning and cost allocation practices are designed to ensure that projects are
identified and assigned to the appropriate cost allocation category that matches the
benefits that the projects provide to the Transmission System. These practices include:
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(1) a combined bottom-up and top-down planning approach; (2) cost allocation
procedures that contain a hierarchy that precludes projects that meet the MEP or MVP
criteria from being categorized as BRPs; and (3) updated MEP cost allocation and study
procedures.
Q.
Please explain the MISO bottom-up, top-down, planning approach.
A.
As discussed above, the MISO Order No. 890-compliant planning process uses a bottomup, top-down approach to generate the annual MTEP. The bottom-up portion relies on
the ongoing responsibilities of the individual Transmission Owners to review and plan
continuously to meet the needs of their local systems reliably and efficiently. MISO
reviews these local planning activities with stakeholders and then performs a top-down
review of the adequacy and appropriateness of the local plans in a coordinated fashion
with all of the other local plans to ensure that collectively the needs are met in an
efficient and cost-effective manner. As part of this process, projects initially considered
as local transmission solutions may be combined, altered, replaced by a new project that
addresses multiple local needs, or analyzed for their benefits as part of a regionally-based
MVP portfolio or as MEPs.
Q.
Please describe the MISO cost allocation hierarchy
A.
MISO has established a hierarchy of transmission project types as shown on Exhibit No.
MISO-7, with BRPs focused on the local end of the spectrum of Transmission Issues,
MEPs focused on sub-regional and regional Transmission Issues, and MVPs focused on
resolving regional Transmission Issues in a more efficient and cost-effective manner.
The purpose of MISO’s Order No. 890-compliant top-down planning process is to seek
transmission solutions that more cost-effectively address multiple Transmission Issues,
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rather than developing individual solutions for each identified Transmission Issue.
Specifically, MISO is obligated in the course of the MTEP process to “seek out
opportunities to coordinate or consolidate, where possible, individually defined
transmission projects into more comprehensive cost-effective developments.”33
The
“collaborative [MTEP] process is designed to ensure that the MTEP address[es]
Transmission Issues within the applicable planning horizon in the most efficient and cost
effective manner, while giving consideration to the inputs from all stakeholders.”34 If a
MVP or MEP will resolve multiple issues more efficiently and cost-effectively than
individual BRPs, the regional solution will be pursued. This identification of more
efficient and cost-effective regional solutions is a key component and benefit of the topdown regional planning process. In fact, if a BRP also meets the criteria to be a MEP,
under Attachment FF of the Tariff, the project will be considered a MEP.35 In addition,
under Attachment FF of the Tariff, BRPs that provide regional benefits may also qualify
as MVPs, with the associated regional cost allocation.36
Q.
Can you provide examples of how this hierarchy has been applied in the past?
A.
As discussed above, the MISO Board of Directors approved a MVP portfolio in 2011
because of the portfolio’s strong reliability, economic, and public policy benefits. As a
whole, the portfolio resolved 650 reliability violations caused by the integration of
33
Tariff, Attachment FF, Section I.B.
34
Tariff, Attachment FF, Section I.B.
35
Tariff, Attachment FF, Section III.A.2.h.
36
Tariff, Attachment FF, Section II.C.2.c (MVP Criterion 3); id., Attachment FF, Section
II.C.4.
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renewable energy, under more than 6,700 system conditions.37 By addressing these
reliability violations, the approved MVP portfolio avoided the need for 23 future BRPs.38
The identified reliability violations could have led to the designation of multiple Baseline
Reliability Projects. Instead, under the current MISO top-down planning process, MISO
identifies more cost-effective and efficient regional solutions that may address the
individual reliability issues more cost-effectively.
Q.
Does MISO anticipate that the adoption of MVPs and changes to MEPs will result
in more of these projects being approved in lieu of BRPs?
A.
Yes. With the adoption of MVPs and recent changes to MISO’s MEP methodology,
MISO anticipates the likelihood that multiple local transmission reliability issues could
be addressed through regional solutions that are subject to some level of regional cost
allocation, as either a MEP or a MVP. As discussed in the MVP Filing, MVPs are
specifically designed to, among other things, address Transmission Issues associated with
projected violations of mandatory reliability standards.39 In addition, MISO is working
with stakeholders to improve the MEP identification and evaluation study process so that
it will better identify and quantify the economic benefits of transmission projects targeted
specifically at congestion reduction. As part of this updated MEP evaluation process,
MISO will consider grouping facilities together to address common areas of congestion
on the system. MISO anticipates that between the study process improvement and recent
37
MISO, Multi Value Project Portfolio Results and Analyses, Section 6 (Jan. 10, 2012),
https://www.misoenergy.org/Library/Repository/Study/Candidate%20MVP%20Analysis/M
VP%20Portfolio%20Analysis%20Full%20Report.pdf.
38
See id., Section 8.6.
39
MVP Filing, Transmittal Letter at 21 (citing Attachment FF § II.C.6).
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cost allocation changes, such as lowering the benefit to cost ratio to fixed 1.25 to 1, more
MEPs may be selected in the MTEP than in the past, which also might lead to the
displacement of the need for multiple BRPs.
Multi-Transmission Owner Zones
Q.
What is the most granular allocation utilized by MISO to allocate the costs of
transmission investments?
A.
At the lowest level, and subject to the cost allocation methods discussed previously,
transmission costs within the MISO Transmission System are allocated to pricing zones.
Q.
How many pricing zones are there in MISO?
A.
Within MISO there are 24 pricing zones. Eleven of the 24 pricing zones contain the
transmission facilities of more than one Transmission Owner, and such zones are referred
to in MISO as “joint pricing zones.”
Q.
Is cost allocation to a single joint pricing zone regional?
A.
No.
Cost allocation to a single pricing zone, whether it contains one or more
Transmission Owners, is not regional. The allocation of costs to a single joint pricing
zone qualifies as local cost allocation, at least with respect to the joint pricing zones
existing as of today. When the cost of a transmission facility is allocated by MISO solely
to one of these joint pricing zones, the cost allocation is local, just as it would be for the
cost of an identical transmission facility that is allocated to one of the 13 MISO pricing
zones consisting of only one Transmission Owner’s facilities.
Q.
Why is cost allocation to a single joint pricing zone not regional?
A.
The presence of facilities owned by more than one Transmission Owner in a single joint
pricing zone in MISO does not make the cost allocation regional. Cost allocation to
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MISO joint pricing zones is local for several reasons, including: (1) the local historical
nature of zone development within the MISO system; (2) the small geographic scope of
pricing zones in comparison to the entire MISO footprint; (3) the local investment nature
of joint pricing zones within the MISO system; and (4) the benefits of local cooperation
between transmission owners on all levels of the transmission system, including within
single pricing zones.
Q.
Please explain the local historical nature of the zone development.
A.
The current pricing zones within MISO, including joint pricing zones, were established
based on factors such as the existence of historic balancing authority areas and historic
stand-alone transmission tariff pricing zones. Joint pricing zones arose from historic
cooperation among transmission-owning utilities to create efficiencies and avoid
construction of redundant transmission facilities by multiple utilities in a local area. The
historic cooperation also included coordination between public utilities and non-public
utilities to avoid duplicative transmission development. These historic balancing areas,
historic stand-alone transmission tariffs, and cooperation formed the basis of the pricing
zones that exist in MISO today, and coordination occurring within these pricing zones is
focused on serving local needs, whether one or more than one entity owns transmission
facilities in the zone.
Q.
Please explain how the pricing zones in MISO were formed.
A.
As indicated above, the pricing zones in MISO are comprised of the traditional balancing
authorities in the region, which are now Local Balancing Authorities (“LBA”) under
MISO’s consolidated balancing authority. When MISO was formed, the pricing zones
were specified in the Tariff. To be assigned a separate zone for a new Transmission
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Owner, the Transmission Owner had to have been “a transmission provider [that] is or
would have been a specified zone for pricing under an existing or proposed regional
transmission tariff.”40
Many Transmission Owners did not meet this definition and
instead became part of an existing pricing zone through the development of joint pricing
zones. Given the highly integrated nature of the transmission systems of many utilities
when they joined MISO, dividing the balancing authority areas into multiple zones
containing only the facilities of each individual utility made no practical sense. The
MISO transmission pricing zones have been developed based on the local nature of the
facilities and the Transmission Owners.
Q.
Please explain the small geographic scope of the MISO joint pricing zones.
A.
The geographic scope of the each of the pricing zones in MISO, compared to the total
MISO regional footprint, makes each transmission pricing zone by definition local in
nature, regardless of the number of Transmission Owners with facilities in the zone.
Exhibit No. MISO-4 is a map showing the pricing zones in MISO.
As this map
demonstrates, each pricing zone represents a small geographic area in comparison to the
entire MISO footprint. Given the relatively small geographic size of each pricing zone in
comparison to the entire MISO footprint, any cost allocation limited to one pricing zone
is more appropriately considered local in nature, regardless of the number of
Transmission Owners within the pricing zone.
Q.
40
Are the pricing zones in MISO designed to circumvent Order No. 1000
requirements?
Owners Agreement, Appendix C, Section II.A.1.
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A.
No. The Commission in Order No. 1000-A noted that transmission-owning members of
an RTO may not divide the RTO into large “East and West multi-utility zones and
[allocate] costs just within one zone consisting of more than one transmission [owner]” to
retain a federal right of first refusal.41 Such is not the case with respect to the MISO joint
pricing zones existing as of the date of the filing. As Exhibit No. MISO-4 further
illustrates, MISO has not divided its region into large sub-regional pricing zones for the
purpose of circumventing Order No. 1000. Instead, the pricing zones were established
based upon historical balancing authority boundaries, which are now LBAs in MISO
following MISO’s consolidation of balancing authority functions.
Q.
Please explain the local investment nature of multi-transmission owner zones within
the MISO footprint.
A.
Each of the 11 joint pricing zones contains one Transmission Owner that owns the vast
majority of transmission plant within the zone and traditionally performed local
balancing authority functions for the facilities in that zone on behalf of one or more
additional Transmission Owners that own facilities (and have load and/or generation)
located within the pricing zone. In fact, as shown in Exhibit No. MISO-5, for all 11 of
the zones with more than one Transmission Owner, a single Transmission Owner owns at
least 75 percent of the gross transmission plant in that pricing zone. Given the disparity
in gross transmission plant among owners, what results in each of the 11 joint pricing
zones is a scenario in which the transmission assets of the Transmission Owners with
fewer assets depend in large part upon the transmission assets of the Transmission Owner
with the bulk of the assets. Without the system in place by the Transmission Owner with
41
Order No. 1000-A at P 424.
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the bulk of the assets, other Transmission Owners’ systems would not function in a
complete manner. This is precisely the type of multi-transmission owner zone that the
Commission indicated in Order No. 1000-A (at P 424) is “not necessarily ‘a zone
consisting of more than one transmission provider’ as that term is used in this order.”
In cases of facilities that provide local reliability or load-serving benefits to more than
one Transmission Owner in the zone, the facilities to be constructed and the
responsibility to construct such facilities has historically been determined through
cooperation of the Transmission Owners in the pricing zone, rather than relying on
separate construction of redundant transmission facilities by each Transmission Owner to
serve its own load. Historically, in many of the joint pricing zones, transmission facilities
for decades were added based on a load ratio share within the pricing zone, and were not
based on a regional cost allocation. The historic pricing zones have not been used for the
purpose of allocating the costs of transmission projects with regional benefits among the
Transmission Owners.
Q.
Please explain the benefits of local cooperation.
A.
As explained above, joint pricing zones in the MISO footprint often resulted from the
highly integrated nature of certain Transmission Owners’ systems as a consequence of
decades of cooperation and collaboration predating their membership in MISO. These
joint pricing zones represent a positive example of coordination among Transmission
Owners to ensure that their loads are served as reliably and efficiently as possible. For
example, public utility transmission providers and non-jurisdictional utilities in MISO
have a long tradition of cooperative and collaborative transmission planning and
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expansion that resulted in the creation of joint pricing zones when those utilities joined
MISO. The local focus of this cooperation within joint pricing zones belies the notion
that the existence of more than one Transmission Owner renders allocation of costs to the
zone “regional” rather than local.
PROPOSED
NON-INCUMBENT
TRANSMISSION
DEVELOPER
PROCESS
DEVELOPMENT
Sponsorship versus Inclusive Evaluation
Q.
What transmission developer selection approaches did MISO consider as part of its
stakeholder process for Order No. 1000 compliance?
A.
Order No. 1000 provided flexibility for regions to devise a transmission developer
selection method that is just and reasonable and appropriate for the region. MISO and its
stakeholders considered and extensively discussed two primary approaches in the MISO
stakeholder process: (i) sponsorship and (ii) inclusive evaluation. (The latter approach
was also referred to during the stakeholder process as comprehensive evaluation or
competitive bidding.)
Q.
Please describe generally the different developer selection processes that were
considered.
A.
A sponsorship model combines the selection of projects and developers, as developers
are selected based on the quality of the projects they propose in the planning process. If a
potential developer’s sponsored project is selected as the recommended solution to
address one or more Transmission Issue(s) in the regional planning process, then that
project sponsor is assigned the obligation to build that project.
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In an inclusive evaluation approach, transmission projects and transmission developers
are selected independently from one another. The current MISO transmission planning
process is first performed, culminating in a set of projects approved for inclusion in the
regional plan. A subset of these projects, which represent regional solutions to regional
needs, then go through a competitive developer selection process, and the developers are
selected based on the strength of their overall proposals. This approach is more inclusive
because it more freely and flexibly considers all projects, including those suggested by
entities not necessarily interested in developing the proposed projects.
Q.
What transmission developer selection process is MISO adopting?
A.
MISO is implementing the inclusive evaluation process for selecting transmission
developers for Open Transmission Projects approved in the regional plan for purposes of
cost allocation (i.e. MEPs and MVPs). The developer selection will be based on a
number of criteria including: the full life cycle cost of the project, including capital,
implementation, and ongoing costs; the preliminary facility design; the potential
developer’s abilities to efficiently operate, maintain, repair, and restore the transmission
facilities associated with the transmission project; the potential developer’s project
implementation and construction plan; and the potential developer’s submission of useful
project ideas or analyses to the MISO planning process.
States will have the first
opportunity to select the developer for approved transmission facilities open to
competition. To the extent the applicable state chooses not to or is unable to select the
transmission developer within a specified time frame, MISO will make the selection.
Q.
Why is MISO proposing to use an inclusive evaluation approach?
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A.
MISO is proposing to use an inclusive evaluation approach because MISO desires to
minimize the number of changes required to its current Commission-approved planning
process that already results in projects selected in the regional plan.
In fact, it is
imperative that MISO fully retains its Order No. 890-compliant planning process, as
MISO has found its current transmission planning process maximizes the open,
transparent, and robust nature of analyses and stakeholder discussions, resulting in
efficient and cost-effective solutions to local and regional transmission needs. Given this
need to preserve the success and effectiveness of its current planning process, MISO is
pursuing the addition of an inclusive evaluation approach for developer selection, which
can be added to the back end of its planning process. This approach fits well within and
does not disrupt the overall MISO transmission planning process. From a high level, the
MISO regional planning process begins with identification of Transmission Issues, based
on stakeholder input and reliability, economic, and/or public policy concerns. Then,
through a robust and collaborative effort with MISO stakeholders and staff, potential
solutions are identified to address Transmission Issues. These solutions are evaluated
through an open and transparent planning process, and, when all factors and input are
considered, the best overall plan for the region is identified. This evaluation process
frequently involves modifying the original set of potential solutions to identify the most
efficient and cost effective regional solution, when considered in the context of other
proposed solutions and the full set of Transmission Issues identified.
Q.
What is a recent example of the MISO planning process?
A.
A recent example of the MISO regional planning process is development of the MVP
portfolio, a $5.2 billion transmission portfolio that will provide reliability, public policy,
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and economic benefits in excess of its costs to the full MISO footprint that I discussed
earlier in my testimony. The development of this portfolio began in 2003 with initial
exploratory analyses in the MTEP and evolved through the MTEPs in subsequent years.
In 2008, MISO, with the assistance of state regulators and industry stakeholders such as
the Midwest Governor’s Association (“MGA”), the Upper Midwest Transmission
Development Initiative (“UMTDI”), and the OMS, began the Regional Generator Outlet
Study to identify a set of value based transmission projects necessary to enable the
renewable energy mandates in the MISO footprint. The input from these studies was
then compiled and analyzed to identify a set of “no regrets” projects that will provide
multiple types of benefits under all alternate futures studied. These “no regrets” projects
were approved by the MISO Board of Directors as the first MVP portfolio in December
2011. In every step along the way, projects were modified, added, and/or removed from
the plan in order to find the most efficient and cost-effective overall plan for the region.
Q.
Why does this planning approach preclude a sponsorship method?
A.
The sponsorship approach to planning is fundamentally different from the planning
process described above, which MISO has developed with substantial stakeholder input.
As noted above, MISO’s planning framework is dynamic and iterative, as projects can
and do evolve throughout the process. Project modifications can be suggested by any
stakeholders or MISO staff, and they frequently arise out of public stakeholder meetings
and discussion.
The involvement of a sponsor would both hamper and complicate
MISO’s fine-tuning of a proposed project, as any modification(s) potentially implicate
the identity and qualifications of sponsors for modified projects. For example, questions
(and ultimately litigation) can arise regarding who the project sponsor is – and therefore
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the project developer is – if a proposed project is modified in order to make it a more
efficient and cost-effective regional solution. Analyses would have to be performed, and
processes would have to be developed, to determine if any such changes are substantive,
and these analyses would be complicated by the incentive for project sponsors to lobby
that changes are insignificant or entirely unnecessary, while other potential developers
who did not sponsor the project would be incented to argue that any changes are
substantive.
A sponsorship method would also change the open dialogue that currently occurs in
MISO meetings, as information regarding potential modifications or project ideas would
be competitively sensitive. Sponsors would have an incentive to flood MISO with
proposed project solutions to any identified Transmission Issue, delaying the process as
all ideas regardless of their value are evaluated and debated in an open stakeholder
process. Also, in the event of multiple sponsors submitting the same project, MISO
would have to resort to some sort of competitive evaluation to determine who should
build the project. In essence, a sponsorship approach is prone to the potential assertion
of, and disputes over, broad intellectual property claims, which in turn could have
adverse impacts on openness, transparency, sharing of ideas and realization of the best
overall solutions. Additionally, it is unclear if intellectual property could be rewarded in
the near term, as it would be difficult to assign intellectual ownership to ideas which
already exist in the public domain. As shown in Exhibit No. MISO-6, a multitude of
regional and interregional transmission projects have already been identified in the MISO
process through stakeholder submissions or regional and interregional study efforts.
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In order to maintain the MISO approach to planning, which has proven effective in
developing efficient and cost-effective regional plans, MISO does not support a
sponsorship model for developer selection. MISO recommends the more inclusive and
iterative evaluation approach that separates project selection (i.e., solution formulation)
from developer selection (i.e., solution implementation).
On a final note, while MISO values the intellectual input of all stakeholders into the
planning process, MISO also values attributes such as: (i) cost competiveness, (ii)
facility design quality, (iii) project implementation capability, and (iv) facility operations
and maintenance capabilities. The inclusive evaluation process considers these other
attributes independently of intellectual input, thus allowing for both the best intellectual
solutions and the most attractive proposals from a cost, quality, and capability standpoint.
Under a sponsorship approach, everything is tied together, and the best intellectual
solution may not necessarily be linked to developer with the most attractive cost, quality,
and capabilities.
Q.
Will an inclusive evaluation process delay the implementation of transmission
projects?
A.
The inclusive evaluation process developed by MISO to select a project developer will
add approximately one year to the project development process. This extra year is
required to allow for a competitive process under which MISO will issue a transmission
proposal request, interested transmission developers will submit sufficiently detailed
transmission proposals in response to MISO’s request, MISO or the applicable state(s)
will conduct a robust and full evaluation, and ultimately, this process will result in the
determination of the project developer designated with the obligation to construct the
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Open Transmission Project in a reliable, efficient, and cost-effective manner. While the
inclusive evaluation process will delay the implementation of transmission projects as
compared to MISO’s process in effect today, such a delay is inevitable given the
requirements of Order No. 1000 and would result regardless of which developer selection
method MISO chose to implement. The inclusive evaluation process that MISO has
developed is designed to minimize the impact of this inevitable delay.
Q.
Would a sponsorship method allow for the more rapid implementation of
transmission projects?
A.
In general, a sponsorship method would not lead to more rapid implementation of
transmission projects, and it may insert additional delays into the planning and developer
selection process. In a sponsorship process, after the identification of Transmission
Issues, sponsors would (in isolation) evaluate and design business cases for potential
solutions. These potential solutions would then be submitted to MISO, who would
perform subsequent analyses to select the optimal solutions. MISO would spend
considerable time reviewing these business cases to not only select the optimal solution
but also to prevent the developer from having an excessively broad claim to future
projects by claiming intellectual property rights.
Also, it is expected that MISO’s evaluation of these project ideas would require a
lengthier amount of time, as compared to the current process. This extension would be
required to sufficiently document why each alternative project was not selected, as
conventional explanations would be insufficient due to the heightened impacts of not
selecting a transmission project, and therefore a transmission developer.
Also,
stakeholders would have an incentive to lobby for a certain set of results, leading to
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public discussions that may not be based on technical merits, but instead may rely upon a
sponsor’s desire to see its project selected. Moreover, the robust vetting of ideas and
solutions that the MISO planning process enjoys today would be stifled given that such
ideas would become “competitive information” under a sponsorship model. Stakeholders
would therefore have an incentive to withhold information to gain an advantage in the
project selection process, whereas today, the stakeholder process is open and transparent,
with a robust vetting of ideas and solutions to Transmission Issues.
Finally, in the likely event that two sponsors submit similar ideas, or if a project is
modified by MISO during the planning process, the developer for that project would need
to be chosen through a competitive evaluation process like the inclusive evaluation
process that MISO is proposing, which would add approximately an additional year or
more to the timeline for any particular project’s implementation.
Q.
Will an inclusive evaluation process rely too heavily on subjective metrics?
A.
No. Several metrics must be considered when selecting a transmission developer, one of
which is costs. The cost metrics include: the upfront capital costs; other costs recovered
from customers such as taxes and depreciation; implementation (i.e., construction) costs;
operations, maintenance, repair, and restoration costs; and costs to develop the best
transmission solution for the region. Although some of these costs may be quantified at
the time of developer selection, many of the costs occur during the implementation or
ongoing operation phases of the project lifecycle. Also, the substantial risks of improper
construction, including costs due to a delay in the construction of an economic project,
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and the financial impacts of a failure to operate, maintain, restore, or replace facilities
properly, cannot be easily translated to a dollar figure.
Q.
How does MISO plan to address these uncertainties?
A.
Due to these uncertainties, MISO is including both quantitative and qualitative factors in
the inclusive evaluation process. These factors attempt to capture the qualifications and
strengths of each developer throughout the lifecycle of the transmission project, including
its ability to restore and/or replace the facility after catastrophic outages (e.g., major
storms, etc), to navigate through state regulatory processes during construction, and to
comply with state and federal regulations. These factors allow a more accurate estimate
of the project costs, including those nested within subjective assessments of operations
and implementation capabilities and plans.
Q.
Will an inclusive evaluation process create a disincentive for creative planning by
developers?
A.
No.
MISO prides itself on having a robust, open, transparent, and Order No. 890
compliant planning process.
This process is supported by significant stakeholder
participation (including state involvement), and it fosters and encourages diverse input
and alternative ideas to provide for a cost-effective recommendation of regionally
beneficial transmission solutions.
The implementation of an inclusive evaluation
approach will not impact the project evaluation or stakeholder input relied upon to
recommend reliable, efficient, and cost-effective transmission projects for construction.
In contrast, as noted above, the sponsorship process would stifle the collaboration
between MISO and its stakeholders. The inclusive approach more effectively fosters
continued open and transparent dialogue between MISO and all stakeholders, allowing
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-1
Page 37 of 41
MISO and the stakeholder body to determine the best solutions for the region in a
collaborative fashion. Furthermore, the inclusive evaluation process allows for some
consideration of prior or ongoing participation in MISO’s planning process (e.g.,
submission of project ideas, etc.) as well, thus providing incentives for continued
participation by transmission developers in the planning process.
Developer Selection Process
Q.
Please describe the inclusive evaluation approach.
A.
MISO is proposing to use an inclusive evaluation approach to select the transmission
developers for any facilities approved in the MISO transmission plan that do not retain a
right of first refusal. This approach will consider the lifecycle cost of each developer’s
proposal and select the developer who will be best able to implement, operate, maintain,
repair, and restore the transmission facility(ies) over the project’s life. The process, as
outlined in sections X and XI of Attachment FF to the Tariff, will include: (i) the
determination of facilities that may be eligible for construction by nonincumbent
transmission developers, (ii) the creation and posting of a request for proposal for each
set of facilities, (iii) the submission of proposals from interested developers to build,
operate, maintain, repair, and restore the affected facilities, (iv) the qualification
requirements for developers and their proposals, (v) the evaluation and selection of a
transmission developer, and (vi) the reevaluation of the project or developer, if required.
Q.
How will projects that are subject to the inclusive evaluation process be
determined?
A.
MISO will determine which recommended projects in a planning cycle may qualify as
“Open Transmission Projects” subject to the inclusive evaluation process, which will
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-1
Page 38 of 41
include only MEPs and MVPs given that these are the only types of projects selected in
the regional plan for purposes of cost allocation per Order No. 1000. These projects, if
ultimately approved by the MISO Board for inclusion in MTEP Appendix A, will be
designated as Open Transmission Projects by MISO, and a Transmission Proposal
Request for each project will be developed and posted on the MISO website within 30
days of MISO Board of Directors approval.
Q.
What happens after MISO posts a Transmission Proposal Request?
A.
Once MISO has posted a Transmission Proposal Request, prospective transmission
developers (referred to in the proposed tariff language as New Transmission Proposal
Applicants) may submit proposals to MISO (referred to as New Transmission Proposals
in the proposed tariff language) to compete to be selected to develop and have the
obligation to own, operate, maintain, repair, and restore the facilities associated with an
Open Transmission Project. Applicants will be required to develop and submit their New
Transmission Proposals within the timeframe specified in the Transmission Proposal
Request, which will not exceed 180 calendar days from the date the Transmission
Proposal Requests have been posted on the MISO website.
Q.
Please explain what occurs after the 180-day period to submit a New Transmission
Proposal ends.
A.
At the end of the 180-day period, MISO will review the each applicant’s proposal to
determine if there are any deficiencies in the New Transmission Proposals submitted
(e.g., incomplete proposals, undocumented qualifications, etc.). MISO will notify any
New Transmission Proposal Applicants with deficiencies, and the New Transmission
Proposal Applicants will have a single cure period of 10 business days from the date of
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-1
Page 39 of 41
notification to cure any deficiencies and resubmit the New Transmission Proposals.
Once the cure period has closed, MISO will designate New Transmission Proposal
Applicants as Qualified Transmission Developers if all deficiencies have been cured and
all qualifications have been met. Any New Transmission Proposal Applicants who failed
to cure their deficiency will be removed from consideration, and their New Transmission
Proposal(s) will not be considered in the evaluation phase.
MISO will evaluate the New Transmission Proposals submitted by Qualified
Transmission Developers and select the developer, referred to in the proposed Tariff
language as the Selected Transmission Developer, within 180 days of the New
Transmission Proposal due date. The Selected Transmission Developers will be posted
on the MISO website. Metrics used to evaluate proposals include: (i) cost estimate and
facility design quality, (ii) project implementation capabilities, (iii) facility operations,
maintenance, repair, and replacement capabilities and (iv) MISO planning process
participation.
Q.
Does this timeline vary if a state opts to select the transmission developer?
A.
Potentially. In general, if a state regulatory authority elects to select the transmission
developer for an Open Transmission Project within its jurisdiction, it must abide by the
same timeline for developer evaluation that MISO will use (e.g., no more than 180 days).
However, if the state is unable or chooses not to select a transmission developer during
this timeframe, MISO will select the transmission developer. In this situation, MISO will
have no less than 90 days to select the transmission developer; such a selection must
occur within 270 days of the New Transmission Proposal due date.
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-1
Page 40 of 41
Q.
Does the inclusive evaluation process allow for reevaluation of approved Open
Transmission Projects?
A.
Yes.
MISO will reevaluate Open Transmission Projects and Selected Transmission
Developers on an as-needed basis during the early portions of a project’s implementation,
before the spending of significant funds associated with the physical project construction
has begun. This reevaluation will be triggered by changes reported in status reports on
the project and developer qualifications. From a project basis, reevaluation will focus on
cost and schedule changes. An Open Transmission Project will be reevaluated if an
increase in its cost causes its benefit-to-cost ratio to drop below the defined economic
thresholds, as specified in sections II.B.1.f and II.C.2.b of Attachment FF of the Tariff.
This reevaluation may result in project cancellation if insufficient benefits remain to
warrant the project’s completion. Projects will also be reevaluated if they miss key
milestones in their implementation and the project completion date is threatened.
Mitigation plans will be developed as necessary to ensure system reliability is
maintained. With regard to each developer, any change in the developer characteristics
and qualifications may trigger reevaluation. This reevaluation will determine if the
developer will still be able to implement, operate, maintain, repair, and restore the
transmission facilities, and, in the event the developer is deemed unable to do so, will
MISO reassign the transmission facilities.
CONCLUSION
Q:
Does this complete your testimony?
A:
Yes.
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-2. MISO Stakeholder Meeting and Materials on Order No. 1000 Compliance
Stakeholder Forums
Right of First Refusal (“ROFR”)
Task Team
Dates of Meetings and Conference
Calls
February 1, 2012
Posted Materials
•
11 MISO draft
positions
presentations
•
9 stakeholder
position
presentations
•
2 presentation
from the
Organization
of MISO
States on state
requirements
•
Over 100 sets
of stakeholder
comments
•
7 sets of
stakeholder
comments
•
20 sets of
stakeholder
comments
•
7 MISO
presentations
February 29, 2012
March 23, 2012
April 26, 2012
June 1, 2012
June 14, 2012
June 28/29, 2012
July 30/31, 2012
August 13, 2012
August 23, 2012
September 17, 2012
September 24, 2012
Regional Expansion and Benefits
Criteria (“RECB”) Task Force
October 27, 2011
November 29, 2011
September 27, 2012
Planning Advisory Committee
(“PAC”)
October 26, 2011
November 30, 2011
January 25, 2012
March 21, 2012
June 27, 2012
August 1, 2012
September 26, 2012
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-3
OMS PROPOSAL FOR ENHANCED PLANNING AUTHORITY
August 16, 2012
This draft identifies changes in the planning process that would enhance the role of OMS in
MISO planning, and act as a further step towards compliance with FERC Order 1000. It is an
attempt to find compromise between the OMS Proposal on Enhanced OMS Planning Authority,
adopted July 6, 2012, the discussions held by the OMS and its Executive Committee at a variety of
meetings in June and July, 2012, the feedback received from the MISO Advisory Committee, and
various communications held with MISO.
The principal purpose of this draft is to find common ground that accommodates the needs of
OMS, MISO, and MISO stakeholders.
MISO Organizational Changes:
1. Modify Attachment FF to the MISO tariff to specifically identify the expectations and
responsibilities of the OMS to provide feedback at key points in the transmission process, including
specifically, that wherever Attachment FF states “the Transmission Owners and other stakeholders,”
it shall be modified to state “the Transmission Owners, OMS, and other stakeholders.” While the
details of the opportunities and processes related to providing input to the Transmission Planning
Process shall be contained within the Transmission Planning Business Practice Manual, MISO shall
also modify its tariff, in Attachment FF or elsewhere, to include a brief description of those
opportunities and processes. In addition:
a. MISO shall provide in its tariff that changes affecting Business Practice Manual (BPM)
changes adopted by this proposal may not be made on less that 60 days’ notice to OMS.
1
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Exhibit No. MISO-3
b. Notwithstanding a. above, the first BPM procedures adopted to implement this proposal
shall remain unchanged for not less than two years, unless changes are mutually agreed upon by the
MISO and OMS.
c. At the end of two years of operation of the initial BPM procedures implementing this
proposal, OMS and MISO shall conduct an assessment to determine whether the BPM procedures
worked successfully as intended and what suggestions or improvements, if any, should be made.
This assessment will occur through an open and transparent MISO stakeholder process.
Comment: The intention is to structure OMS participation in MISO planning by changes
that affect the organization and the transmission planning process itself. Since the latter
is part of the MISO tariff, but also involves business practices not typically subject to
tariffing, a choice arises as to dividing the definition of the OMS role between necessary,
high level tariff components and those more granular procedures in the Business
Practices Manual (BPM) that may need greater flexibility. This provision No. 1 sets forth
the principle right of OMS to have rights and obligations in the MISO transmission
planning process, protects certain procedures with respect to BPM changes, and includes
certain fundamental planning process steps identified in Nos. 1-7 below that are to be
protected at the tariff level. This elevates certain steps to tariff protection that may
implement MISO’s compliance with Order 1000.
With respect to BPMs, the tariff provides for an initial two year freeze (except
where changes are effected upon mutual OMS and MISO agreement), no changes to
BPMs relating to this proposal without at least 60 days’ notice, and joint study after two
years to assess effectiveness.
2. Modify the Transmission Owners’ Agreement to identify OMS as a committee (OMS
Committee) that:
a. Reports periodically to the MISO Board; and
b. Has responsibility for input into the transmission planning, resource adequacy, and
transmission cost allocation approach and processes.
Comment: This provision elevates OMS under the TOA (and, in turn, within the MISO
tariff) to permanent committee status. It provides a regular communication opportunity
to the Board, and, importantly, clearly gives the responsibility to OMS to provide its
input into the MISO stakeholder procedures for transmission planning, resource
adequacy, and transmission cost allocation. OMS has the discretion as to how and what
extent it participates, but the change does mean that non-participation by OMS will have
implications for the weight accorded OMS input (or lack of input) in the MISO
stakeholder process.
2
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Exhibit No. MISO-3
Transmission Planning Process:
Modify the MISO tariff and the Transmission Planning Business Practices Manual (BPM) to
codify in additional detail the process and expectations for MISO and the OMS Committee:
1. Opening of the Planning Year: OMS shall have the opportunity to review and raise
concerns to the System Planning Committee of the Board of Directors during the annual
consideration of the planning principles and objectives for the planning year. OMS’s opportunity
will be embodied in MISO’s tariff.
Comment: This provision, to be embodied in the MISO tariff, allows OMS to address
with the MISO Board, the annual re-evaluation of strategic concepts, such as planning
principles, planning objectives, and models. The point of the input is more properly
identified as the System Planning Committee, which is the Board’s specific venue for
oversight of the framework of transmission planning.
2. Opening and During the Planning Year: OMS shall have the opportunity, during the
MISO Transmission Expansion Plan scope development phase, to request that MISO staff add
specific additional scope elements to be addressed based on any specific additional state
jurisdictional needs or requirements. MISO shall identify the date of the opening of each planning
year and notify OMS and each member of OMS that it has 45 days from the date of the notice to
identify documented state statutory requirements, concerns, or needs that MISO must consider in the
planning year. MISO will adjust its MISO expansion plan scope as appropriate to reflect those
proposals and review the revised scope with OMS, TOs, and other stakeholders to ensure a complete
and accurate scope and schedule is achieved.
Comment: Carried forward from the July 6 proposal, this provision, to be placed in the
BPM, further details the OMS opportunity to establish the “scope elements” in the first
Scoping Phase of MISO’s five-stage planning process. The last sentence is intended to
recognize MISO’s scheduling and completion discretion, which might be needed for
urgent projects or projects taking more than one planning cycle.
3. Opening and During the Planning Year: a) OMS shall have the opportunity to present
specific modeling inputs, without limitation, providing appropriate justification is received for the
3
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-3
proposed inputs, to MISO for consideration by MISO staff during the Business Case Development
stage. During this stage, OMS (or its staff working groups) may request use of specific modeling,
inputs, or assumptions as to be part of the MTEP or carried along as supplemental analysis, providing
this additional analytical request is not unduly burdensome on the planning process. If the request
appears unduly burdensome on MISO and the planning process, MISO has the obligation to negotiate
in good faith a scope of work that will meet OMS’s analytical needs at a reasonable cost. OMS (or
its staff working groups) may also request, and shall receive from MISO staff as promptly as
reasonably possible given analysis timelines and result availability, (a) pricing zone-by-pricing zone
cost analyses, and (b) state-by-state, or local resource zone-by-local resource zone, as appropriate,
project or project portfolio costs and benefit analyses with respect to any project or project portfolio
where the cost allocation is premised in whole or in part on economics, but not including projects
proposed strictly for reliability purposes. This is not to be construed as requiring costs and benefits
analysis on the individual elements of a proposed portfolio of projects. The analyses furnished shall
be of a similar quality to those furnished to transmission owning stakeholders (within whatever
limitations may exist due to Critical Energy Infrastructure Information confidentiality requirements).
Such analyses shall conform to applicable engineering, economic or other planning standards or
practices delineated in NERC standards and the MISO Energy Markets Tariff and Business Practices
Manuals. When MISO is developing the future scenarios for use in the upcoming analysis cycle,
MISO will explicitly request submission of all final suggestions of inputs and requested analyses,
after which the future scenarios will be considered closed for the given year.
b) When the Business Case Development stage of planning begins, MISO will call for
submission of all final proposals and alternatives within 45 days, after which the set of proposals for
a given year is considered “closed,” although further optimization and refinement will continue in the
normal course to seek to improve the business case for the proposed facilities.
4
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-3
Comment: This provision defines the principal OMS opportunity during the Business
Case Development stage to secure information that OMS wants for its own analyses of
the projects under consideration. MISO is obliged to respond to reasonable requests and
negotiate with OMS where information requests might create a burden. MISO is
specifically obliged to provide certain, highly useful project cost information for
comparison and analysis. The last sentence obliges MISO to establish a “last call” as to
future scenarios for a planning cycle in order to establish the cycle’s planning limits
based on this key component for transmission planning.
4. During Planning Year Processes: OMS shall have the opportunity during the planning
year to raise concerns to MISO staff about general or specific MTEP issues. MISO will timely and
substantively respond to concerns raised by OMS. MISO’s response may be rebutted by OMS and,
in that situation, OMS may elect to have all relevant documentation on the disputed issue or concern
submitted to the Planning Advisory Committee and, if requested to the System Planning Committee
of the MISO Board of Directors, for consideration along with the draft MTEP
Comment: This proposal carried forward from the July 6 proposal is about addressing
immediate stakeholder concerns or issues in a given planning year. This “objection”
process is intended to provide immediate corrections in order to ensure OMS, MISO and
stakeholder resources are used effectively on a current basis.
5. Close of Planning Year Process - Substantive: a) Prior to the PAC meeting(s) where the
PAC will consider a motion regarding sending the MTEP to the Board, OMS shall have the
opportunity, providing OMS members and/or their designated staff has participated consistently
through the process, and at its discretion, to request reconsideration by MISO staff of any project
receiving regional cost allocation (other than for BRP projects below 345 kV), if a project or
alternative had not been vetted through the Business Case Development stage or, after a request for
updated projected costs by OMS, its projected cost for MTEP approval has increased by 25 percent
or more since the project was evaluated in the Business Case Development phase. OMS shall supply
to MISO staff a statement of its reasons for requesting such reconsideration. Before forwarding the
MTEP to the Board, MISO shall provide to OMS, and thereafter to the MISO Board of Directors for
5
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-3
its MTEP consideration, a “substantive and meaningful” response to the concerns raised by OMS.
OMS’s opportunity will be embodied in MISO’s tariff.
b) Additionally, at the conclusion of the planning year process, but prior to the plans being
considered by the MISO Board of Directors, the OMS shall have the opportunity to assess the
planning process and the outcomes, concurrent with the PAC review process. Specifically, this
assessment should review and raise any concerns regarding the process, models, inputs, and
assumptions used in the planning process. The assessment shall be provided directly to the PAC,
MISO staff, and the MISO System Planning Committee of the Board of Directors.
Comment: The first paragraph is the “yellow light” procedure to be used in the rare
circumstance where a new project was not vetted earlier or a project’s cost increased by
more than 25 percent since the Business Case Development phase. If OMS has
“participated consistently through the process,” so as to minimize the yellow light to the
rarest situations, MISO will oblige itself to a “substantive and meaningful” response to
OMS objections before the MTEP is forwarded to the Board, along with all OMS
concerns and the MISO response.
The second part of this item is restored at MISO’s suggestion to provide a
retrospective assessment of the overall process, taking up more systemic issues or
concerns that OMS has regarding the process, models, inputs, and assumptions used in
the planning process.
6. OMS Voting - Majority Needed to Act in Planning, Supermajority to Exercise Close of
Planning Year: With the exception of the proposal found at paragraph 5(a), OMS can exercise any of
the planning input opportunities set forth above by a simple majority of members present and voting
or by a delegation to OMS staff exercised by the OMS Board in the same manner. As to the
authority found at paragraph 5(a), it may be exercised by 66% of the OMS voting members.
Comment: This item identifies the OMS majority needed for use of the “yellow light” to
be exercised in No. 5(a) above. The supermajority vote is 66% of the voting members.
This is not a matter determined by MISO or for its tariff or BPM, but is OMS’s
commitment in its governance.
7. OMS Funding: OMS shall be adequately funded, to allow it to adequately participate in the
planning functions, either through in-kind provision of services by MISO or if necessary through
6
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-3
direct provision of funds to enable the hiring of staff and/or third party assistance. OMS’s ability to
receive such assistance, if necessary, will be embodied in MISO’s tariff.
Comment: This provision is simply re-worded from the July 6 proposal. It ensures OMS
with a tariff-supported ability to receive adequate resources to participate in the planning
process as embodied in this proposal. OMS would be recognized in the tariff as the
funded collective state entity, but budget matters would not be included in the tariff.
This proposal was adopted by the OMS Board of Directors on August 16, 2012. The
Manitoba Public Utilities Board abstained from voting on this proposal. The Illinois
Commerce Commission requested leave to add a separate statement of its concerns.
7
Exhibit No. MISO-4. Approximate Geographical Location of the 24 MISO Pricing Zones
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-5. Multi-Transmission Owner Pricing Zone Gross Transmission Plant Break-Down
No.
[1]
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Multiple Transmission
Owner Pricing Zone
[3]
Yes
Share of Gross Transmission
Plant in Pricing Zone for
Primary Transmission Owner
[4]
97.43%
No
Yes
100.00%
94.27%
No
Yes
100.00%
83.80%
No
No
Yes
100.00%
100.00%
91.09%
No
Yes
100.00%
98.52%
No
Yes
100.00%
84.69%
Yes
75.22%
No
Yes
100.00%
89.72%
No
Yes
100.00%
75.93%
No
No
100.00%
100.00%
No
Yes
100.00%
93.68%
No
Yes
100.0%
97.03%
No
100.0%
Pricing Zone
[2]
ITC Midw est
ITCM
SMMPA
Mountian Lake
Windom
Tipton
GRE
ATC System
Ameren IL
Ameren IL
* PPI
ATXI
Ameren MO
Duke Energy Indiana
DEI
WVPA
IMPA
CWLD
CWLP
GRE
GRE
SMMPA
Elk River
* Willmar
HUC
NSP
Hoosier Energy
ITC
International
MPPA
Indianapolis P&L
MI Joint Zone (includes
METC
Michigan Joint Sub-Zone
MPPA
Wolverine
MSCPA
Traverse City
Grand Haven
Zeeland
Minnesota Pow er
MP (AC facilities)
GRE
MDU
Northern States
NSP
SMMPA
NWEC
CMMPA - Agency
Blue Earth
Delano
GRE
NIPS
Otter Tail
OTP
MRET
GRE
SIPC
SMMPA
SMMPA
Vectren (SIGECO)
MidAmerican
MEC
* MEAN
* Waverly
* Indianola
CFU
Atlantic
IPPA
Eldridge
Pella
Montezuma
Tipton
Muscatine
Dairyland
DPC
NWEC
Big Rivers
MISO Total
Allocated Gross
Trans. Plant
[5]
$1,469,863,912
$1,432,119,000
$17,418,870
$449,034
$524,400
$0
$19,352,608
$3,643,828,009
$980,934,905
$924,733,094
$3,030,811
$53,171,000
$746,874,380
$1,188,872,297
$996,260,688
$109,483,196
$83,128,413
$32,312,865
$76,066,437
$393,182,970
$358,154,389
$7,293,632
$474,277
$12,797,449
$8,488,483
$5,974,740
$226,421,581
$1,497,864,944
$1,475,685,000
$22,179,944
$238,762,106
$1,363,522,740
$1,154,814,000
$208,708,740
$29,104,581
$149,623,381
$8,884,696
$12,666,327
$896,530
$7,533,225
$359,924,301
$270,717,906
$89,206,395
$154,774,316
$2,726,514,460
$2,446,249,553
$43,027,221
$4,127,610
$0
$2,312,215
$2,738,706
$228,059,155
$770,378,886
$313,546,332
$238,061,362
$37,879,330
$37,605,640
$83,395,542
$30,734,199
$30,734,199
$383,906,677
$796,324,355
$745,972,324
$10,437,188
$3,453,085
$4,635,258
$14,900,932
$5,821,926
$2,937,218
$828,891
$6,503,282
$626,186
$208,065
$12,000,630
$362,448,448
$351,694,537
$10,753,911
$230,469,307
$18,291,633,339
Notes:
1) * = NITS customer who who owns transmission facilities but is not considered a MISO Transmission Owner.
2) Source: Attachment O as of 10/1/2012
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-6. Potential Transmission Lines Identified
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-7. MISO’s Transmission Cost Allocation Hierarchy Provisions
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
HYPOTHETICAL TRANSMISSION PROPOSAL REQUEST
East – West 345 kV Transmission Project
MTEP Project ID: XYZ
Project Overview
1. Project Description
REPLACE WITH PROJECT IMAGE
The proposed East - West 345 kV Transmission Project consists of the following facilities:
•
•
•
Expansion of the existing East Substation to include a second 345-138 kV, 448 MVA
transformer and a new 345 kV transmission line terminal.
Construction of a new West Substation consisting of three 345 kV terminal positions
by tapping into the existing North-South 345 kV transmission line approximately 75
miles to the west of East Substation.
Construction of a new 345 kV transmission line from the existing East Substation to
the proposed West Substation.
This project was approved in the MTEP18 planning cycle as a Market Efficiency Project.
The entire project is located within the State of ABC. The proposed 345 kV West Substation
and the proposed 345 kV East-West transmission line are facilities believed to be eligible for
competitive bidding through this Transmission Proposal Request. Final eligibility will be
based upon the final route selection, as approved by any applicable State authorities.
1
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
2. Overview of 345 kV East – West Transmission Line Facility
REPLACE WITH PROJECT IMAGE, IF
APPLICABLE
The proposed 345 kV East – West transmission line should be designed as a single-circuit
345 kV three-phase AC transmission line with a normal rating of at least 1,100 MVA and an
emergency rating of at least 1,700 MVA. The portion of the transmission line to the west of
Interstate 99 should be constructed using double circuit structures to accommodate a future
345 kV circuit from West Substation to the nearby metropolitan area, and the circuit should
be installed on the north side of the structures if a vertical configuration, or as the top circuit
if a double-circuit H-frame or similar flat configuration. The proposed in-service date for the
345 kV East – West transmission line is June 1, 2025.
3. Overview of 345 kV West Transmission Substation Facility
REPLACE WITH PROJECT IMAGE, IF
APPLICABLE
The proposed 345 kV West transmission substation has a proposed in-service date of June
1, 2025 and should be designed as a three terminal 345 kV switching substation to
terminate three 345 kV overhead transmission circuits as follows:
•
Each of the three transmission circuit terminals should be designed with normal
ratings of at least 1,100 MVA for summer and winter seasons and long-term
emergency ratings of at least 1,700 MVA for summer and winter seasons.
•
One transmission circuit terminal will terminate the southern end of the proposed
West to North transmission circuit, one transmission circuit terminal will terminate
the northern end of the proposed West to South transmission circuit, and one
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
transmission circuit terminal will terminate the west end of the proposed East to
West transmission circuit.
•
The proposed West to North and West to South transmission circuits will be created
by installing in-and-out taps into the proposed West Transmission Substation Facility
from the existing South to North 345 kV transmission line.
•
The proposed West Transmission Substation Facility should be designed to
accommodate two future transmission circuits in either a i) breaker-and-a-half or ii)
double-breaker ultimate arrangement.
The proposed West Transmission Substation Facility cannot use a straight bus
based on a projected violation of the NERC TPL Category C1 standard four years
after the in-service date of the West Transmission Substation Facility under a
contingency outage of the straight bus during peak demand conditions.
•
•
•
The proposed West Transmission Substation Facility may use a ring bus
configuration as long as the ring bus is designed to remain closed for a planned
maintenance outage of a transmission circuit or its associated protective relays.
This requirement is driven by a projected violation of the NERC TPL Category B
standard when the future fourth transmission circuit is added at the substation. This
standard violation occurs when i) one of the transmission circuits terminating at the
West Transmission Substation Facility is out for planned maintenance during
demand levels and system conditions where planned maintenance is typically
performed; ii) this outage requires the ring bus to be open (i.e., both circuit breakers
and associated disconnects protecting the transmission circuit subject to the
planned maintenance outage are in an open position to facilitate the planned
outage); and iii) a forced outage occurs on the opposite transmission circuit
resulting in the opening of all four circuits that terminate at West Transmission
Substation Facility. To ensure the ring bus is designated to remain closed under
this conditions, the following two requirements must be satisfied:
o
Each transmission circuit terminating at the West Transmission Substation
Facility must contain a gang operated switch located outside of the ring that
can be opened and tagged to facilitate a transmission circuit outage with the
ring bus closed.
o
Each transmission circuit that terminates at the West Transmission
Substation Facility must contain redundant protective relay schemes to
facilitate continued and complete bus protection for all sections of the closed
ring bus when one of the transmission circuit relay schemes (and associated
transmission circuit) is out of service for routine testing and maintenance.
A breaker-and-a-half bus configuration is not applicable to three-position buses and
thus is not applicable to the West Substation Transmission Facility at this time.
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
•
A double breaker / double bus configuration may be used with six circuit breakers
and there would be no requirement for switches on each transmission circuit.
However, there would continue to be a requirement for redundant protective relay
schemes on the West-North transmission circuit and the West-South transmission
circuit to maintain compatibility with the existing redundant protective relay schemes
currently in service on this line.
•
The primary and backup transmission line relay schemes associated with the West
to North transmission circuit and the West to South transmission circuit must be
directional comparison carrier blocking relay schemes using power line carrier over
the middle phase of each circuit to initiate carrier blocking. Furthermore, West
Substation must be designed to receive breaker failure transfer trip signals via
power line carrier from both the North Substation and South Substation and initiate
the correct breaker tripping in response to these breaker failure trip signals. Finally,
breaker failure relay schemes at West Substation must use power line carrier to
send transfer trip signals to North Substation and/or South Substation to initiative
remote tripping when appropriate. Both the West to North Transmission Circuit and
the West to South Transmission Circuit must contain high speed and time delayed
reclosing, and must be capable of being configured as either the lead or lag
reclosing terminal for delayed reclosing, where lead reclosing occurs on a hot busdead line condition and lag reclosing occurs on a hot bus – hot line condition subject
to supervision by a synchronism check relay or relay element. More information is
outlined in Attachment D – Protection Requirements of this Transmission Proposal
Request regarding communication system parameters (type of modulation,
frequencies, etc.), detailed protective relay scheme requirements, and relay setting
requirements . All protective relay settings and options must be coordinated with the
existing Transmission Owners and, when system stability is an issue, with the
Transmission Provider prior to placing the West Transmission Substation Facility in
service.
•
For the West to East transmission circuit, a line differential relay scheme or a
permissive underreaching transfer trip relay scheme can be used, and the
requirements of such schemes to be compatible with the protective relay standards
of the Transmission Owner that owns East Substation can be found in Attachment D
–Protection Requirements of this Transmission Proposal Request. Differential relay
schemes will require two fiber optic shield wires on the West-East New
Transmission Line Facility to serve as primary and backup communications
channels per the standards outlined in Attachment D – Protection Requirements.
The fiber optic shield wires must also facilitate transfer trip signals to and from East
Substation to implement breaker failure protection requirements as further described
in Attachment D – Protection Requirements. If a permissive underreaching transfer
trip relay scheme is used, two redundant microwave communications channels must
be used to facilitate transfer tripping the East Substation terminal from the West
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
Substation terminal, transfer tripping the West Substation terminal from the East
Substation terminal, facilitating breaker failure transfer tripping signals from the East
Substation Terminal to the West Substation Terminal, and faciliate breaker failure
transfer tripping signals from the West Substation terminal to the East Substation
Terminal, all as further detailed in Attachment D – Protection Requirements.
Attachment D – Protection Requirements also includes details on required reclosing
schemes and settings for the West-East transmission circuit. All protective relay
settings and options must be coordinated with the existing Transmission Owners
and, when system stability is an issue, with the Transmission Provider prior to
placing the West Transmission Substation Facility in service.
•
If a ring bus configuration is used, all circuit breakers, circuit breaker disconnects,
current transformers (including associated secondary circuits and elements reflected
to the primary side), bus conductors, bus connectors, equipment leads and other
series load carrying equipment within the ring bus must be rated equal to 3,000 A
under normal conditions and 4,000 A under emergency conditions, unless the ring
bus is designed so that the West-North transmission circuit position will not be
adjacent to the West-South transmission circuit position when the fourth circuit is
added. This requirement is driven by projected loads above 3,000 A into and out of
the substation under certain contingencies when the fourth circuit is added. Any
section of the ring bus that will eventually be used as one of the main buses in the
ultimate future breaker-and-a-half or double-breaker five position bus must be rated
at 4,500 A.
•
If a double breaker / double bus configuration is used, all circuit breakers, circuit
breaker disconnects, current transformers (including associated secondary circuits
and elements reflected to the primary side), bus conductors, bus connectors
equipment leads and other series load carrying equipment in series with any circuit
breaker must be rated equal to the 2,000 A under normal conditions and 3,000 A
under emergency conditions. In addition, each of the two buses in the double bus /
double breaker scheme must be rated at 4,500 A to provide for future expansion of
the West Substation to an ultimate five position bus.
5
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
Information Request
All New Transmission Project Proposals received to install and own the New Transmission Line
Facility and the New Substation Facility will be evaluated based on consideration of the
information described below.
1. General
1.1. Agreements and Commitments
All New Transmission Proposals must meet the qualifications listed below to be considered
in the developer evaluation section described in Section VIII.G of the MISO Tariff.
1.1.1. ISO Agreement. The New Transmission Proposal Applicant must agree to
execute the ISO Agreement upon completing construction and prior to energization
of the New Transmission Line Facilities covered by this Transmission Proposal
Request unless the New Transmission Proposal Applicant is already a
Transmission Owner.
1.1.2. NERC Registrations. The New Transmission Proposal Applicant must agree to
register with NERC as the transmission owner (TO), transmission operators (TOP)
and transmission planner (TP) if selected to develop the New Transmission
Facilities associated with this Transmission Proposal Request. Registration must
occur prior to the in-service date of such New Transmission Facilities.
1.1.3. Balancing Authority Responsibilities. Unless the New Transmission Proposal
Applicant is already a Local Balancing Authority (LBA), the New Transmission
Proposal Applicant must agree to either i) contract with an interconnecting Local
Balancing Authority (LBA) to include the New Transmission Facilities associated
with this Transmission Proposal Request within the boundaries of the LBA and
demonstrate to the satisfaction of the Transmission Provider and per agreement by
the LBA that all applicable LBA-related tasks associated with proposed New
Transmission Facilities specified within this Transmission Proposal Request that
are delegated to the LBA by the Balancing Authority Agreement will be carried out
either by the LBA or the Selected Transmission developer or ii) register with NERC
as a Balancing Authority for the New Transmission Facilities, execute the Balancing
Authority Agreement and perform all tasks associated with the New Transmission
Facilities covered by this Transmission Proposal Request that have been delegated
to an LBA by the Balancing Authority Agreement.
1.1.4. Interconnecting Transmission Owner Standards and Criteria. The New
Transmission Proposal Applicant must comply with and adhere to all standards and
criteria regarding interconnection of transmission facilities published by each
incumbent Transmission Owner to which the New Transmission Facilities
6
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
associated with this Transmission Proposal Request will interconnect. These
standards and criteria are included in Attachment C of this Transmission Proposal
Request for each incumbent Transmission Owner with transmission facilities that
will directly interconnect to the New Transmission Facilities covered by this
Transmission Proposal Request.
1.1.5. Financial Plan. A business plan documenting the strategies and processes that
will be used to finance the Open Transmission Project covered by this
Transmission Proposal Request including credit ratings applicable to the New
Transmission Proposal Applicant or an affiliated organization if such information is
available.
1.2. Cost
All New Transmission Proposals must provide data for each of the categories below to be
considered in the developer evaluation section described in Section VIII.G of the MISO
Tariff.
1.2.1. Estimated 40-Year Annual Revenue Requirements
Consideration will be given to the estimated annual revenue requirements,
provided in year of occurrence dollars, for the first 40 years of the project’s inservice life to be calculated in accordance with Attachment MM of the Tariff
for Multi-Value Projects and Attachment GG of the Tariff for Market Efficiency
Projects. Note that for consistency between proposals for components of the
calculation that use an inflation rate the following rate of X.X% should be
used.
1.2.2. Estimated Capital Cost
Consideration will be given to the estimated total capital cost of project by
facility, provided in in-service year dollars, including estimates for
contingencies and overhead. Note that for consistency between proposals
for components of the calculation that use an inflation rate the following rate
of X.X% should be used.
1.2.3. Components of Estimated Annual Revenue Requirements
Consideration will be given to the supporting detail on the annual allocation
factors used to estimate the annual revenue requirements requested in
Section 1.2.1, including operations and maintenance, general and common
depreciation expense, taxes other than income taxes, income taxes, and
return.
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
1.3. Planning Process Participation
Consideration will be given to the knowledge the New Transmission Proposal
Applicant has regarding the local transmission system, as well as the New
Transmission Proposal Applicant’s participation in the Transmission Provider’s
Attachment FF planning process. This participation may include performance of
planning studies by the New Transmission Proposal Applicant regarding the
Transmission Issue(s) being addressed by this Open Transmission Project as long as
study assumptions, study methodologies and study results were shared with
stakeholders during the planning process. This participation may also include
submission of project or project/portfolio ideas into the planning process to address the
Transmission Issue(s) being addressed by the Open Transmission Project, including
proposal of the actual Open Transmission Project. Local transmission system
knowledge may be substantiated through demonstration of relevant studies, operating
experience, or other data.
1.4. Project Implementation Capabilities
All New Transmission Proposal Applicants must be able to become qualified (i.e. able,
authorized and/or committed to becoming able and authorized) to implement
transmission projects within the relevant state(s). New Transmission Proposal
Applicants must submit information regarding their planned strategies, processes,
procedures, policies and methods to implement the Open Transmission Project. New
Transmission Project Applicants are encouraged to also submit information regarding
past experience in implementing transmission line projects and/or transmission
substation projects. All New Transmission Proposals must provide data for each of the
categories below to be considered in the developer evaluation section described in
Section VIII.G of the MISO Tariff.
Information submitted by the New Transmission Proposal Applicant regarding project
implementation capabilities should include the following general areas:
•
•
•
•
•
•
•
•
•
•
•
Project Management
Transmission Line Routing Evaluation
Substation Site Evaluation
New Transmission Facility Regulatory Permitting
Right-of-way and Land Acquisition
Substation Engineering and Surveying
Transmission Line Engineering and Surveying
Material Procurement
Transmission Line Construction and Commissioning
Substation Construction and Commissioning
Project Implementation Safety Record and Programs
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
1.5. Operations, Maintenance, Repair, and Replacement Capabilities
All New Transmission Proposal Applicants must be able to become qualified (i.e.
able, authorized and/or committed to becoming able and authorized) to operate and
maintain transmission facilities within the impacted state(s). New Transmission
Proposal Applicants must submit information regarding their planned strategies,
processes, procedures, policies and methods to operate, maintain, repair, and
replace the New Transmission Facilities covered by this Transmission Proposal
Request. New Transmission Project Applicants are encouraged to also submit
information regarding past experience in performing transmission facility operations,
maintenance, repair, and replacement. All New Transmission Proposals must
provide data for each of the categories below to be considered in the developer
evaluation section described in Section VIII.G of the MISO Tariff.
Information submitted by the New Transmission Proposal Applicant regarding
operations, maintenance, repair, and replacement capabilities should include the
following general areas: Real-time Operations and Monitoring
•
•
•
•
•
•
•
Forced Outage Response
Switching
Emergency Repair and Testing
Spare Parts, Equipment and Structures
Preventative and/or Predictive Maintenance and Testing
Real-time Operations, Monitoring and Control
Operations and Maintenance Safety Record and Programs
2. Quality of High Level New Transmission Line Facility Design
All New Transmission Proposals must provide data for each of the applicable categories
below to be considered in the developer evaluation section described in Section VIII.G of the
Transmission Provider Tariff.
2.1. Estimated Route Length
Consideration will be given to the estimated route length including, but not limited to,
compliance with Applicable Laws and Regulations related to siting, route length,
regulatory risk, use of existing corridors and consideration given by New Transmission
Proposal Applicant to major route impacts.
2.2. Proposed Conductor and Thermal Rating Methodology
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
Consideration will be given to the proposed conductor including, but not limited to, the
proposed bundling configuration, proposed conductor type, proposed conductor size,
thermal rating methodology and thermal rating methodology input assumptions.
2.3. Proposed Lightning Protection and Grounding Methods
Consideration will be given to proposed default lightning protection methods including,
but not limited to, methods used, shielding angles if shield wires are used and/or
arrester specifications and locations if surge arresters are used.
2.4. Proposed Grounding Methods
Consideration will be given to proposed default grounding methods including, but not
limited to, type of grounding used and proposed structure grounding resistance values.
2.5. Proposed Structure Design Attributes
Consideration will be given to the proposed default structure design attributes
applicable to tangent, running angle, in-line dead-end and angle dead-end structures
including, but not limited to, structure design (lattice, monopole, H-frame, selfsupporting vs. guyed, etc.), structure design calculation assumptions, materials used,
anticipated useful life span, maintenance requirements, aesthetics and future flexibility.
2.6. General Line Design
Consideration will be given to the general line design proposal including, but not limited
to, average and maximum span length, average and maximum length between deadend structures, estimated positive and zero sequence impedance, estimated shunt
susceptance, insulator type and specifications and proposed methods to mitigate
impacts of conductor galloping and Aeolian vibration.
10
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
3. Quality of High Level New Substation Facility Design
All New Transmission Proposals must provide data for each of the applicable categories
below to be considered in the developer evaluation section described in Section VIII.G of the
Transmission Provider Tariff.
3.1. Proposed One-Line Diagram and Station Layout
Consideration will be given to the proposed one-line diagram and bus configuration
including, but not limited to, the ability to accommodate planned maintenance, impacts
of planned maintenance on topology, impact of planned maintenance on facility loading
limits and potential exposure to major contingencies. Consideration will be given to the
ability to facilitate connection of future facilities into the bus including additional branch
terminals, new voltage levels and/or shunt equipment.
3.2. Proposed Protection, Monitoring and Control Schemes
Consideration will be given to the proposed protective relaying schemes for
transmission circuits, bus sections (if applicable) and breaker failure schemes. This
consideration may include, but is not limited to, scheme type, technology, flexibility,
redundancy and when necessary, consistency with protective relay schemes at remote
substations. It also may include the level of proposed metering, telemetering and
remote equipment monitoring and alarms including proposed on-line monitoring
equipment for circuit breakers and protection and control equipment.
3.3. Proposed Lightning Protection Methods
Consideration will be given to proposed lightning protection methods including, but not
limited to, methods used as well as arrester locations, types and specifications within
the substation.
3.4. Proposed Circuit Breaker Specifications
Consideration will be given to proposed circuit breaker specifications including, but not
limited to, continuous current rating, momentary current rating, interrupting rating,
maximum design kV, Basic Impulse Level (BIL), interrupting time, interrupter type,
mechanism type, independent pole operation capability and use of dual trip coils.
3.5. Proposed Air Break Switch and Disconnect Specifications
Consideration will be given to proposed air break switch and disconnect specifications
including, but not limited to, continuous current rating, momentary current rating,
maximum design kV, Basic Impulse Level (BIL), and mechanism type.
11
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
3.6. Proposed Wave Trap Specifications if Applicable
If wave traps are required by the protection systems, consideration will be given to
proposed wave trap specifications including, but not limited to, continuous current
ratings, momentary current rating, maximum design kV and Basic Impulse Level (BIL).
3.7. Proposed Normal and Emergency Equipment Loading Ratings
Consideration will be given to the proposed normal and emergency load ratings of
station equipment such as circuit breakers, disconnect switches, wave traps, bus
sections, risers, jumpers, connectors, current transformers, current transformer
secondary equipment and other series equipment that could impact line terminal
ratings or station power transfer ratings. Consideration will also be given to rating
methodologies and associated input assumptions when ratings exceed nameplate
values. Rating methodologies should comply with interconnection requirements of
interconnecting Transmission Owners.
3.8. Proposed Miscellaneous Voltage Ratings
Consideration will be given to proposed maximum design kV and Basic Impulse Level
(BIL) ratings of instrument transformers, wave traps and station insulators.
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
Attachment A
1.1. Terms
All New Transmission Proposal Applicants must submit New Transmission Proposals
that are signed by a corporate officer or equivalent official of the New Transmission
Proposal Applicant who must certify in writing that he/she has the authority to act on
behalf of the proponent in such a manner. Additionally, all New Transmission
Proposal Applicants must submit a fully executed Binding Proposal Agreement with
each New Transmission Proposal. [see Attachment B]
1.1.1. Withdrawal and Amendment of New Transmission Proposals
Any amendment of a New Transmission Proposal must comply with
requirements for proposal submission described in Section VIII.C of the MISO
Open Access Transmission, Energy, and Operating Reserve Markets Tariff
(“MISO Tariff”) and any amendment must be submitted to the Transmission
Provider before 5:00 p.m. EST on the New Transmission Proposal due date.
Any withdrawal or amendment must be signed by a corporate officer or
equivalent official of the New Transmission Proposal Applicant who must
certify in writing that he/she has the authority to act on behalf of the New
Transmission Proposal Applicant in such a manner.
1.1.2. Expiration of New Transmission Proposals
A New Transmission Proposal shall expire the earlier of: (1) the time
Transmission Provider notifies the New Transmission Proposal Applicant that
its New Transmission Proposal has been rejected; (2) at midnight EST on the
date by which the Transmission Provider has selected and publically posted
the selected Qualified Transmission Developer for the full project described in
the Transmission Proposal Request; or (3) such other time as stated in the
Transmission Proposal Request.
13
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
Attachment B
Binding Proposal Agreement
Proposal Due Date: <month> <day><year>
In consideration for submitting a New Transmission Proposal as part of the [PROJECT
NAME] (“Project”) Transmission Proposal Request, ___________________________
(“New Transmission Proposal Applicant”) agrees to be bound by the contents of this
New Transmission Proposal Request and the terms of the MISO Open Access
Transmission, Energy, and Operating Reserve Markets Tariff (“MISO Tariff”) and
Applicable Laws and Regulations. These terms include the obligation to construct the
Project, as described in Section VIII.F of the MISO Tariff.
If the New Transmission Proposal is selected by Transmission Provider, the New
Transmission Proposal Applicant agrees to execute the ISO Agreement upon the New
Transmission Facilities being placed in service.
The submission of this Binding Proposal Agreement to Transmission Provider shall
constitute the New Transmission Proposal Applicant’s acknowledgment and acceptance
of all the terms, conditions and requirements of this Transmission Proposal Request
and the MISO Tariff.
The undersigned represents and warrants that he/she has the authority to act on behalf
of, and to bind, the New Transmission Proposal Applicant to perform the terms and
conditions and otherwise comply with all obligations stated herein.
Signature of Corporate Officer or Equivalent Official: ____________________________
Name of Corporate Officer or Equivalent Official (print):__________________________
Title of Corporate Officer or Equivalent Official (print): ___________________________
Date Signed: ______________________
This Binding Proposal Agreement must be submitted to Transmission Provider at the
address provided below by 11:59 EST on [proposal due date]:
ADDRESS INFORMATION
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Exhibit No. MISO-8. Hypothetical Transmission Proposal Request
Attachment C
Interconnection and Standards and Requirements of Interconnecting
Transmission Owners
Attachment D
System Protection Requirements
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FERC rendition of the electronically filed tariff records in Docket No. ER13-00187-000
Filing Data:
CID: C001344
Filing Title: MISO OATT Order No. 1000 Compliance Filing (Part 1 of 2)
Company Filing Identifier: 640
Type of Filing Code: 80
Associated Filing Identifier:
Tariff Title: FERC Electric Tariff
Tariff ID: 9
Payment Confirmation:
Suspension Motion: N
Tariff Record Data:
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.49a, Binding Proposal Agreement, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5359
Tariff Record Collation Value: 71305936 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
An agreement that must be signed by an officer or equivalent official of a New
Transmission Proposal Applicant with the authority to bind the latter; that must be
submitted with each New Transmission Proposal; and that binds the New Transmission
Proposal Applicant to the terms of the New Transmission Proposal and the Transmission
Proposal Request, and the applicable requirements of this Tariff. The Binding Proposal
Agreement shall be included as an appendix to the Transmission Proposal Request.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.109a, Cure Period, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5360
Tariff Record Collation Value: 152118768 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
A period of time, equal to ten (10) business days, allowed for a New Transmission
Proposal Applicant to correct deficiencies identified by the Transmission Provider in a
previously submitted New Transmission Proposal. The Cure Period commences upon
notification of deficiencies in the New Transmission Proposal by the Transmission
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Provider.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.419, Midwest ISO Transmission Expansion Plan (MTEP):, 1.0.0, A
Record Narative Name:
Tariff Record ID: 2716
Tariff Record Collation Value: 549051888 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: CHANGE
Record Content Type: 1
Associated Filing Identifier:
A long range plan used to identify expansions or enhancements to the Transmission
System to: i) support efficiency in bulk power markets; ii) facilitate compliance with
documented federal and state energy laws, regulatory mandates, and regulatory
obligations; and iii) maintain reliability. The MTEP is developed biennially or more
frequently, and subject to review and approval by the Transmission Provider Board. The
MTEP shall address Transmission Issues including, but not necessarily limited to: i)
Transmission Issues identified from Facilities Studies; ii) Transmission Issues associated
with Generator Interconnection Projects; iii) Transmission Issues identified by the
Transmission Owners; iv) Transmission Issues identified by the Transmission Provider
working in collaboration with Transmission Owners, their state and local regulatory
commissions and other stakeholders; and v) the transmission planning obligations of a
Transmission Owner and/or the Transmission Provider, imposed by federal or state
law(s), regulations, or regulatory authorities. The MTEP shall also consider the planning
needs and drivers of adjacent regional transmission organizations (“RTOs”) and other
transmission planning regions to develop long-term inter-regional plans for the benefit of
the combined regions, as and to the extent provided for in joint agreements between the
Transmission Provider and other RTOs, and/or in their respective tariffs.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.454a, New Substation Facility, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5358
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Tariff Record Collation Value: 593024568
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
Tariff Record Parent Identifier: 2261
A transmission substation that does not yet exist and that is proposed within a specific
Open Transmission Project as an electrical substation to be implemented, owned,
operated, maintained, and restored by a Selected Transmission Developer, containing
equipment or components classified as transmission plant. New Substation Facilities do
not include upgrades, modifications and/or expansions to existing substations owned by
Transmission Owners that contain equipment or components classified as transmission
plant, where such upgrades, modifications and/or expansions include but are not limited
to: i) expanding or upgrading facilities within the substation footprint, ii) expanding the
substation footprint within the current site boundaries or iii) procuring additional land
adjacent to or near the existing substation site and expanding the substation footprint into
or adding substation facilities on the additional land. New Substations Facilities also do
not include newly constructed transmission substations where all transmission lines
terminating at such substation are owned by an incumbent Transmission Owner as further
described in Section VIII.C of Attachment FF of the Tariff.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.455a, New Transmission Facility, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5353
Tariff Record Collation Value: 594212496 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
A New Transmission Line Facility or New Substation Facility.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.455b, New Transmission Line Facility, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5354
Tariff Record Collation Value: 594212992 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
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Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
An entire transmission line or section thereof, containing one or more transmission
circuits, that does not exist prior to the construction of an associated Open Transmission
Project as a facility classified as overhead or underground transmission line plant, and
that is proposed within an associated Open Transmission Project to be implemented,
owned, operated and maintained by a Selected Transmission Developer. New
Transmission Line Facilities do not include upgrades, modifications and/or expansions to
existing transmission facilities, as further described in this Section VIII.C of Attachment
FF of the Tariff.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.455c, New Transmission Proposal, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5355
Tariff Record Collation Value: 594213488 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
A proposal to construct, implement, own, operate, maintain, repair, and restore all New
Transmission Facilities associated with an Open Transmission Project, in response to a
Transmission Proposal Request. Each proposal is considered to be a firm offer of the
New Transmission Proposal Applicant to, at a minimum, perform the following acts if
the proposal is selected: (i) construct, own, operate, maintain, repair and restore the New
Transmission Facility(ies) within the scope of the Open Transmission Project in
accordance with the Binding Proposal Agreement, as well as applicable laws, regulations
and standards; (ii) execute the ISO Agreement; (iii) register with the North American
Electric Reliability Corporation (NERC) as the transmission owner (TO), transmission
operator (TOP), transmission planner (TP), and if applicable, the Local Balancing
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Authority (LBA) for all New Transmission Facilities associated with the Open
Transmission Project; and (iv) either execute the Balancing Authority Agreement and
assume the role of LBA for all New Transmission Facilities associated with the Open
Transmission Project or contract with an interconnecting LBA and demonstrate to the
satisfaction of the Transmission Provider and per agreement by the LBA that applicable
LBA-related tasks associated with the proposed New Transmission Facilities that are
delegated to an LBA by the Balancing Authority Agreement will be carried out either by
the LBA or the Selected Transmission Developer as required and accepted by FERC.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.455d, New Transmission Proposal Applicant, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5356
Tariff Record Collation Value: 594213984 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
An entity that submits a New Transmission Proposal in response to a Transmission
Proposal Request.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.463c, Non-owner Member, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5361
Tariff Record Collation Value: 604611206 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
Non-owner Member as defined in the ISO Agreement.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.474a, OMS Committee, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5378
Tariff Record Collation Value: 617980976 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
20121025-5070 FERC PDF (Unofficial) 10/25/2012 1:41:22 PM
Record Content Type: 1
Associated Filing Identifier:
OMS Committee shall be the committee that is composed of members of the
Organization of MISO States, established pursuant to the bylaws of the Organization of
MISO States, having the responsibilities and rights defined in Section I.B of Attachment
FF of the Tariff and associated Business Practices Manual. The OMS Committee has the
opportunity to provide input into the transmission planning, resource adequacy, and
transmission cost allocation approach and processes, and may report periodically to the
Transmission Provider Board. To enable it to exercise the authority described herein, the
OMS Committee will be adequately supported by the Transmission Provider either
through reasonable in-kind services or through the provisions of reasonable funding.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.477a, Open Transmission Project, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5362
Tariff Record Collation Value: 621546248 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
A Market Efficiency Project or Multi-Value Project contained in MTEP Appendix A that
has been approved by the Transmission Provider Board and may contain one or more
New Transmission Facilities, subject to Section VIII.A of Attachment FF of this Tariff.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.528a, Qualified Transmission Developer, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5363
Tariff Record Collation Value: 686909568 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
A New Transmission Proposal Applicant that meets the minimum requirements outlined
in a Transmission Proposal Request and Section VIII of Attachment FF of the Tariff to
construct, implement, own, operate, maintain, repair, and restore New Transmission
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Facilities.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.599a, Selected Transmission Developer, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5364
Tariff Record Collation Value: 783171912 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
The Qualified Transmission Developer selected by the Transmission Provider or the
applicable state(s) to construct, implement, own, operate, maintain, repair and restore one
or more New Transmission Facilities, pursuant to Attachment FF of this Tariff.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.671b, Transmission Proposal Request, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5357
Tariff Record Collation Value: 874680560 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
An invitation, including associated requirements, posted by the Transmission Provider on
its website, to submit a New Transmission Proposal.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.679, Transmission System:, 2.0.0, A
Record Narative Name:
Tariff Record ID: 2997
Tariff Record Collation Value: 884187456 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: CHANGE
Record Content Type: 1
Associated Filing Identifier:
The transmission facilities owned or controlled by Transmission Owners that have
conveyed functional control to the Transmission Provider, and are used to provide
Transmission Service under Module B of this Tariff. The Transmission System includes
transmission facilities owned or controlled by Transmission Owners, the functional
control of which has been transferred to the Transmission Provider subject to
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Commission approval under Section 203 of the Federal Power Act. In addition, the
Transmission System includes other transmission facilities owned or controlled by the
Transmission Owner that are booked to transmission accounts and are not controlled or
operated by the Transmission Provider but are facilities that the Transmission Owners, by
way of the Agency Agreement, have allowed the Transmission Provider to use in
providing service under this Tariff. While not part of the Transmission System, service
over Distribution Facilities is available through the execution of a Service Agreement
pursuant to Schedule 11 of this Tariff. The term Transmission System shall include the
Transmission System (Michigan).
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
1.692a, Variance Analysis, 0.0.0, A
Record Narative Name:
Tariff Record ID: 5365
Tariff Record Collation Value: 899637464 Tariff Record Parent Identifier: 2261
Proposed Date: 9998-12-31
Priority Order: 500
Record Change Type: NEW
Record Content Type: 1
Associated Filing Identifier:
Additional analysis performed by the Transmission Provider planning staff on an
approved Open Transmission Project regarding its scope and schedule when certain
circumstances or events significantly affect the Open Transmission Project. Additional
analysis performed by the Transmission Provider planning staff regarding the Selected
Transmission Developer when certain circumstances or events significantly affect the
Selected Transmission Developer.
Record Content Description, Tariff Record Title, Record Version Number, Option Code:
ATTACHMENT FF, Transmission Expansion Planning Protocol, 8.0.0, A
Record Narative Name:
Tariff Record ID: 3906
Tariff Record Collation Value: 2122525264 Tariff Record Parent Identifier: 3866
Proposed Date: 9998-12-31
Priority Order: 600
Record Change Type: CHANGE
Record Content Type: 1
Associated Filing Identifier:
ATTACHMENT FF
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TRANSMISSION EXPANSION PLANNING PROTOCOL
I.
Transmission Expansion Plan - Purpose and Scope, Definition and Role of
OMS Committee: This Attachment FF describes the process to be used by the
Transmission Provider to develop the Midwest ISO Transmission Expansion Plan
(“MTEP”), subject to review and approval by the Transmission Provider Board. The
provisions of this Attachment FF are consistent with the applicable provisions of
Appendix B of the ISO Agreement and this Tariff. For purposes of this Attachment FF,
all references to Transmission Owner(s) will include ITC(s). The costs incurred by the
Transmission Provider in the performance of data collection, analyses and review, and in
the development of the MTEP report, costs incurred under Section I.B of this Attachment
FF, and costs incurred under Section I.C of this Attachment FF shall be recovered from
all Transmission Customers under Schedule 10 of the Tariff.
A.
Enrollment Process: The MTEP is developed to facilitate the timely and
orderly expansion of and/or modification to the Transmission System to maintain
reliability, promote efficiency in bulk power markets and facilitate compliance with
applicable Federal and state laws, regulatory mandates and regulatory obligations. Any
transmission provider that wishes to enroll in the Transmission Provider planning process
for purposes of Order No. 1000 compliance must become a Transmission Owner, by
signing the ISO Agreement, and by, within a reasonable period of time: (1) turning over
functional control of its transmission facilities to the Transmission Provider; and (2)
taking service under this Tariff for all its load that is physically located within the
geographic area comprising the Transmission System. All Transmission Owners enrolled
in the Transmission Provider’s transmission planning region are listed in either (1)
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Attachment FF-4 of this Tariff, for Transmission Owners without a separately filed local
planning process or (2) Attachment FF-5 of this Tariff, for Transmission Owners with a
separately filed local planning process.
B.
OMS Committee Input to MTEP Process: To the extent not otherwise
specifically addressed in other portions of this Attachment FF, with respect to the MTEP
process, the OMS Committee may provide input to the Transmission Provider planning
staff and the System Planning Committee of the Transmission Provider Board, as
appropriate, regarding the following:
1.
At the start of a planning cycle, the OMS Committee may suggest to the
Transmission Provider Board modifications to the Transmission
Provider’s planning principles and planning objectives for that planning
cycle;
2.
At the start of a planning cycle, the OMS Committee may suggest
additional scope elements in the MTEP;
3.
Modeling inputs or assumptions used in the development of the MTEP
and related appropriate cost/benefit analyses with respect to certain
projects that are not proposed strictly for reliability; and
4.
Concerns about general or specific issues with the MTEP process as they
arise during the planning year.
Furthermore, at the end of the MTEP development process, but before the MTEP is
submitted to the Transmission Provider Board for its review, the OMS Committee may
submit a reconsideration request to the Transmission Provider planning staff, which shall
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respond prior to submitting the final MTEP report to the Transmission Provider Board.
This reconsideration request can be made only with respect to Network Upgrades eligible
to receive regional cost allocation under Attachment FF if such projects: (1) will be
recommended to the Transmission Provider Board for MTEP Appendix A approval, but
have not been considered through the complete MTEP process or (2) will have a change
in project cost of twenty-five percent (25%) or greater between the final Subregional
Planning Meeting in the current planning year and the project being submitted to the
Transmission Provider Board for approval. The Transmission Provider shall consider
such a reconsideration request only if it is endorsed by the OMS acting by a vote of sixtysix percent (66%) or more of the OMS members.
At the end of each MTEP cycle, the OMS Committee may submit its assessment of the
MTEP process to the Planning Advisory Committee, Transmission Provider, and the
System Planning Committee of the Transmission Provider Board. Upon receipt of any
such assessment from the OMS Committee, the Transmission Provider planning staff
shall provide an appropriate response in a reasonably timely manner.
The manner in which the OMS Committee shall provide its assessment shall be set forth
in the Transmission Planning Business Practices Manual procedures. The general
procedures adopted with respect to the OMS Committee input into the MTEP shall
remain unchanged until June 1, 2015, unless otherwise mutually agreed to by the
Transmission Provider and the OMS Committee. Changes to the Transmission Planning
Business Practices Manual procedures which describe OMS Committee input into the
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MTEP process may not be adopted with less than sixty (60) days’ notice to the OMS
Committee unless the OMS Committee consents to such earlier adoption. At the end of
the two year period the Transmission Provider, the OMS, and other stakeholders will
assess the success of the input procedures and provide suggestions for improvement.
C.
Development of the MTEP: The Transmission Provider, working in
collaboration with representatives of the Transmission Owners, OMS, and the Planning
Advisory Committee, shall develop the MTEP, consistent with Good Utility Practice and
taking into consideration long-range planning horizons, as appropriate. The
Transmission Provider shall develop the MTEP for expected use patterns and analyze the
performance of the Transmission System in meeting both reliability needs and the needs
of the competitive bulk power market, under a wide variety of contingency conditions.
The MTEP will give full consideration to the needs of all Market Participants, will
include consideration of demand-side options, and will identify expansions or
enhancements needed to i) support competition and efficiency in bulk power markets; ii)
comply with Applicable Laws and Regulations; and iii) maintain reliability. This
analysis and planning process shall integrate into the development of the MTEP among
other things:
(i) the Transmission Issues identified from Facilities Studies carried out in
connection with specific transmission service requests; (ii) Transmission Issues
associated with generator interconnection service; (iii) the Transmission Issues,
including proposed transmission projects, identified by the Transmission Owners
in connection with their planning analyses in accordance with local planning
process described in Section I.B.1.a to this Attachment FF and the coordination
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processes of Section I.B.1.b., or developed by Transmission Owners utilizing
their own FERC-approved local transmission planning process described in
Section I.B.2, as applicable, to provide reliable power supply to their connected
load customers and to expand trading opportunities, better integrate the grid and
alleviate congestion; (iv) the transmission planning obligations of a Transmission
Owner, imposed by federal or state law(s) or regulatory authorities, which can no
longer be performed solely by the Transmission Owner following transfer of
functional control of its transmission facilities to the Transmission Provider; (v)
plans and analyses developed by the Transmission Provider to provide for a
reliable Transmission System and to expand trading opportunities, better integrate
the grid and alleviate congestion; (vi) the identification, evaluation, and analysis
of expansions to enable the Transmission System to fully support the
simultaneous feasibility of all State 1A ARRs; (vii) the inputs provided by the
Planning Advisory Committee; (viii) the inputs, if any, provided by the state and
local regulatory authorities having jurisdiction over any of the Transmission
Owners; and (ix) the inputs of the OMS Committee.
1.
Planning Cycle and Milestones: The ISO Agreement requires that
a regional transmission plan be developed biennially or more frequently. An
MTEP planning cycle is established for each calendar year. The development of
the MTEP for a planning cycle with a given calendar year designation begins on
June 1 of the year prior to the MTEP calendar year designation and ends with the
approval of the final MTEP report by the Transmission Provider Board. This
approval typically occurs at the Transmission Provider Board Meeting in
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December of the MTEP designated year. For example, the development of the
MTEP14 transmission plan will commence on June 1 of 2013 and typically end
with approval in December 2014. The development of the MTEP will follow
specified process steps that are detailed, including process diagrams, in the
Transmission Provider’s Transmission Planning Business Practices Manual
(“TPBPM”). The TPBPM shall be posted on the website of the Transmission
Provider.
a.
Planning Functions: The planning process includes the following
functions which are described in detail in the TPBPM:
i.
Model Development;
ii.
Generator Interconnection Planning;
iii.
Transmission Service Planning;
iv.
Cyclical Regional Expansion Planning activities;
v.
Coordinated System Plans with other RTOs/regions;
vi.
System Support Resource (“SSR”) Studies for unit decommissioning;
vii.
Transmission-to-Transmission Interconnections;
viii.
Load Interconnections; and
ix.
Focus Studies. These are studies initiated during the
cyclical baseline planning process that cannot be delayed
until the next planning cycle (for example, NERC/FERC
directives, or near-term critical operational issues).
Each of these planning functions may develop system expansions that are taken
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into consideration in developing the entirety of the MTEP.
b.
Planning Cycle: The regional planning process is performed through a
continuous series of planning cycles, with each cycle typically addressing
Transmission Issues through a rolling planning horizon. Each cycle commences
with regional model development, and identification of potential expansions from
the local planning processes of the Transmission Owners, and concludes with
recommendations to the Transmission Provider Board of Directors of
recommended solutions to identified Transmission Issues. Transmission Owner
plans developed through local planning processes described in Section I.B.1.a are
included in the beginning of each regional planning cycle as potential alternatives
to local Transmission Issues identified by the Transmission Owners.
The regional planning process evaluates, with stakeholder input throughout the
cycle, the local plans of the Transmission Owners, as one input to the
development of the regional plan. Key milestones in the typical MTEP
development process are listed below and requirements and timelines for data
submittal, review, and comment at each of these milestone points are described in
the TPBPM:
i.
Model development;
ii.
Testing models against applicable planning criteria;
iii.
Development of possible solutions to identified
Transmission Issues;
iv.
Selection of preferred solution;
v.
Determination of funding and cost responsibility; and
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vi.
Monitoring progress on solution implementation.
The Transmission Provider shall address each of these milestones throughout the
planning cycle through Sub-regional Planning Meetings, Planning Subcommittee and
Planning Advisory Committee meetings.
2.
Stakeholders Input in Planning Process: The Transmission Provider shall
facilitate discussions with its Transmission Customers, Transmission Owners,
OMS Committee, and other stakeholders about the Transmission Issues and
solutions involving both transferred and non-transferred facilities, as described in
Section I.B.1 of this Attachment FF.
These discussions will take place at Sub-regional Planning Meetings and at
regularly scheduled meetings of the Transmission Provider’s Planning
Subcommittee, at locations provided by the Transmission Provider and with
communication capabilities for those participants unable to have in person
representation at these meetings. Once the MTEP report for a specific planning
cycle has been completed but prior to recommendation to the Transmission
Provider Board for approval, the Transmission Provider shall seek feedback on
the proposed MTEP, including Network Upgrades recommended for approval,
from the Transmission Provider’s stakeholders and the OMS Committee.
a.
Planning Advisory Committee (“PAC”): The Planning Advisory
Committee is a standing committee reporting to the Transmission
Provider’s Advisory Committee, and functions subject to the Stakeholder
Governance Guide developed by the Stakeholder Governance Working
Group, as approved by the Advisory Committee. The PAC is responsible
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for addressing planning policy issues of importance to stakeholders and
within the responsibilities of the Transmission Provider. The PAC charter
is maintained on the Transmission Provider’s website.
b.
Planning Subcommittee (“PS”): The Planning Subcommittee is a
standing stakeholder-chaired subcommittee of the Planning Advisory
Committee, and functions subject to the Stakeholder Governance Guide
developed by the Stakeholder Governance Working Group, as approved
by the Advisory Committee. Planning Subcommittee membership is open
to interested parties, including, but not limited too: transmission delivery
service and interconnection service customers, marketers, developers,
Transmission Owners, state and local regulatory authorities, federal
regulatory staff, other Market Participants, and all interested parties. The
charter for the committee is developed by stakeholders and is maintained
on the Transmission Provider’s website. The Transmission Provider will
seek guidance from Transmission Owners, state and local regulatory
authorities, and other stakeholders through the Planning Subcommittee
and/or the Planning Advisory Committee prior to the beginning of each
new planning cycle. Guidance will include the scope of planning studies
to be undertaken, the development of future scenarios to be modeled and
analyzed in long-term planning studies, and the development of suitable
models and assumptions to support such studies. The Transmission
Provider will also seek guidance from Transmission Owners, state and
local regulatory authorities, and other stakeholders through the Planning
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Subcommittee and/or the Planning Advisory Committee prior to
implementing changes or revisions to the scope, models, and assumptions
during the planning cycle. The Planning Subcommittee and/or the
Planning Advisory Committee may form working groups at the discretion
of stakeholders to perform specific tasks supporting the planning
processes, such as model development and detail review of study results
and draft plan reports.
c.
Sub-regional Planning Meetings (“SPMs”): The Transmission
Provider shall utilize SPMs to provide opportunity for Transmission
Owners, state and local regulatory authorities, and other stakeholders to
provide input to the planning process, and to carry out the tasks of
coordinating transmission plans among the Transmission Owners. Input
and planned coordination may occur through the use of existing subregional planning groups (“SPGs”) where they exist, or through the
establishment of new sub-regional meeting forums. One or more SPMs
will be used or established for each of the three regional Planning Subregions of the Transmission Provider. Planning Sub-regions shall be
defined based upon the Transmission Provider Planning Sub-regions:
West, Central, and East as defined in Attachment FF-3.
i)
SPM Participants: Participants at an SPM will consist of
representatives of the Transmission Owners operating within the
associated Planning Sub-region that integrate their local planning
processes with the regional process, representatives from state and
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local regulatory authorities, and any other parties interested in or
impacted by the planning process. For those Transmission Owners
engaged in local planning under their own FERC approved local
planning processes, such Transmission Owners shall participate in
the SPM in order to coordinate their planning activities.
Neighboring transmission-owning utilities and regulatory
participants are eligible and encouraged to participate in the SPM
to promote joint planning between the Transmission Provider and
neighboring transmission systems.
ii)
SPM Guidelines. The Sub-regional Planning Meeting
participants shall:
(a)
Make recommendations for a coordinated sub-
regional Plan, after considering sub-regional and regional
needs and alternatives, for the ensuing ten years, for all
transmission facilities in the sub-region;
(b)
Review and comment on proposed Transmission
Owners plans identified in local planning processes
described in Section I.B.1.a. of this Attachment FF, for
additions and modifications to the sub-regional
transmission system, as potential solutions to identify
Transmission Issues and review the transmission plans
developed by those Transmission Owners that have their
own FERC-approved local planning process (described in
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Section I.B.2) to ensure coordination of the projects set
forth in such plans with the potential regional planning
solutions developed in the SPM process consistent with the
requirements of Appendix B of the Transmission Owners’
Agreement;
(c)
Form technical study task forces as required to carry
out the sub-regional planning responsibilities;
(d)
Encourage non-Transmission Provider member
participation to improve understanding by the SPM
participants, the Planning Subcommittee, and the
Transmission Provider staff of facility changes outside the
Transmission Provider Region to ensure the impact of such
changes are considered in the planning studies;
(f)
Promote other stakeholder (i.e., environmental
agencies, and load and generation developers) involvement
in development of the sub-regional plans.
(g)
Recommend to the Planning Subcommittee
proposed sub-regional plans to be included in the MTEP.
In addition, the transmission projects developed by any
Transmission Owner or Owners utilizing the provisions of
their own FERC-approved local planning process shall be
submitted for inclusion in the regional MTEP after being
evaluated by the Transmission Provider in the regional
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evaluation of SPMs in accordance with Appendix B of the
Transmission Owners’ Agreement in determining the
Transmission Provider’s recommendation for inclusion in
the MTEP.
(h)
Reflect, as desired, minority opinions to the
Transmission Provider or the Planning Subcommittee.
i)
SPM Frequency, Location and Agenda:
SPMs should meet at least two times per year or as
otherwise provided for in the TPBPM, to provide
input in the planning process, review plans and
recommend changes, if any, needed to address
stakeholder needs and to coordinate proposed plans.
Meetings involving CEII or confidential materials
shall be handled under Section I.A.12 of this
Attachment FF.
3.
Meeting Notifications: Notice shall be provided by way of email exploder
lists distribution by the Transmission Provider of all SPMs, Planning
Subcommittee, and Planning Advisory Committee meetings. These email
exploder lists are established and maintained by the Transmission Provider and it
is the responsibility of stakeholders to have registered as described on the
Transmission Provider website. Meeting dates, times, locations, and materials
will also be posted on the meeting calendar page of the Transmission Provider’s
website. Meeting notification guidelines are set forth in the stakeholder
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developed Stakeholder Governance Guidelines.
4.
Other Meeting Schedules: Planning Subcommittee meetings are regularly
scheduled meetings that occur no less than bimonthly. Annual meeting schedules
and objectives are developed at the December meeting each year for the
subsequent year. Planning Advisory Committee meetings are scheduled as per
the PAC Charter.
5.
Planning Criteria: The Transmission Provider shall evaluate the system to
address Transmission Issues in a manner consistent with the ISO Agreement and
this Attachment FF. Projects included in the MTEP may be based upon any
applicable planning criteria, including accepted NERC reliability standards and
reliability standards adopted by Regional Entities, local planning reliability or
economic planning criteria of the Transmission Owner, or required by State or
local authorities, and any economic or other planning criteria or metrics defined in
this Attachment FF. Transmission Owners are required to annually provide
updated copies of local planning criteria for posting on the Transmission
Provider’s website.
The Transmission Provider will post on its website an explanation of which
transmission needs driven by public policy requirements will be evaluated for
potential solutions in the local or regional transmission planning process, as well
as an explanation of why other suggested potential transmission needs will not be
evaluated.
6.
Planning Analysis Methods: Planning analyses performed by the
Transmission Provider will test the Transmission System under a wide variety of
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conditions as described in Section II and using standard industry applications to
model steady state power flow, angular and voltage stability, short-circuit, and
economic parameters, as determined appropriate by the Transmission Provider to
be compliant with applicable criteria and this Tariff.
7.
Planning Models: The Transmission Provider shall collaborate with
Transmission Owners, other transmission providers, Transmission Customers, and
other stakeholders to develop appropriate planning models that reflect expected
system conditions for the planning horizon. The planning models shall reflect the
projected Load growth of existing Network Customers and other transmission
service and interconnection commitments. The models shall include any
transmission projects identified in Service Agreements or Interconnection
Agreements that are entered into in association with requests for transmission
delivery service or interconnection service, as determined in Facilities Studies
associated with such requests. Load forecasts applied to models will consider the
forecast Load of Network Customers reported to the Transmission Provider in
accordance with the requirements of Module B and Module E of this Tariff, and
the Business Practices Manuals of the Transmission Provider. Models will be
posted on an FTP site maintained by the Transmission Provider and accessible to
stakeholders with security measures as provided for in the TPBPM. The
Transmission Provider will provide an opportunity for stakeholders to review and
comment on the posted models before commencing planning studies.
The schedules for such reviews are maintained in the TPBPM. Stakeholders shall
be afforded opportunities to provide input on Load projections from Tariff
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reporting requirements or from Transmission Owner forecasts. After the base line
forecast and model are established, the Transmission Provider and/or
Transmission Owners may adjust the forecast as necessary on an ad hoc basis
throughout the planning year to address customer requests for new Load
interconnections arising from on-going dialogue with existing and prospective
customers.
8.
Planning Assumptions: Each MTEP report shall list in detail the planning
assumptions upon which the analyses are based. In general, planning analyses
will be based on the following:
a.
Planning Horizons: The MTEP will identify Transmission Issues
for a minimum planning horizon of five years and a maximum planning
horizon of twenty years.
b.
Load: Load demand will generally be modeled by the
Transmission Provider as the most probable (“50/50”) coincident Load
projection for each Transmission Owner’s service territory, for the season
under study. Specific studies may model alternative Load probabilities or
peak Load for areas within a Transmission Owner’s service territory as
dictated by operational and planning experience and/or local planning
criteria, but in any case shall be treated consistently in the planning for
native Load and transmission access requests.
c.
Generation: Planning models of five years or longer will model
generation, taking into consideration applicable planning reserve
requirements, that are: (i) existing and expected to be in existence in the
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planning horizon; (ii) not existing but with executed interconnection
agreements; and (iii) additional generation as determined with stakeholder
input, as necessary to adequately and efficiently meet demand forecasted
through the planning horizon and to facilitate compliance with statutory or
regulatory mandates. The Transmission Provider shall apply a scenario
analysis to determine alternative future generation portfolio possibilities.
Generation portfolio development for planning model purposes will be
developed with input from the Planning Advisory Committee and its
subcommittees, working groups, and task forces. Point-To-Point
Transmission Service and Network Integration Transmission Service
customers will have an opportunity to guide new generation portfolio
development that is reflective of customer future resource plans.
d.
Demand Response Resources: Planning solutions will be based
upon the best available information regarding the expected amount and
location of Load that can be effectively and efficiently reduced by demand
response or energy efficiency programs, as well as the amount of behindthe-meter generation that can reliably be expected to produce Energy that
could impact planning solutions. The Transmission Provider shall
perform and report on sensitivity analyses that indicate the effectiveness of
potential demand response as alternative planning solutions, to the extent
that appropriate methodology for such analyses is developed with
stakeholders and documented in the TPBPM.
e.
Topology: Each planning study will use the best known topology
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based upon the most recently approved MTEP. Planning studies will
include all projects approved by the Transmission Provider Board, and
shall identify, as appropriate, and as detailed in the TPBPM, any system
needs already identified in the most recent approved MTEP.
9.
Evaluation of Alternatives: When the planning analyses, based on the
foregoing principles, identifies Transmission Issues, the Transmission Provider
will consider the inputs from stakeholders derived from the SPM processes, the
inputs from the Planning Subcommittee and the Planning Advisory Committee,
the plans of any Transmission Owner with its own FERC-approved local planning
process, and the MTEP aggregate system analyses against applicable planning
criteria, in determining the solutions to be included in the MTEP and
recommended to the Transmission Provider Board for implementation.
10.
Facility Design: Facility design and system configuration (such as
conductor sizes, transformer design, bus configuration, protection schemes) are
selected by the Transmission Owner, and must be consistently applied by the
Transmission Owner for comparable system service conditions. Comparable
application of system design does not preclude the consideration or selection of
advanced or alternative transmission technology. For New Transmission
Facilities associated with Open Transmission Projects, the Transmission Provider
may provide limitations or requirements regarding facility design when necessary
due to a planning driver or to ensure compatibility with existing transmission
facilities to which the New Transmission Facilities will interconnect as further
described in Section VIII.D of this Attachment FF.
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11.
Status of Recommended Facilities: Upon solicitation from the
Transmission Provider and upon reaching pre-designated milestones in the project
implementation process, the responsible Transmission Owner or Selected
Transmission Developer shall report the status of all projects recommended for
implementation in the MTEP. Status reports shall, at a minimum, include: (i)
changes to the schedule and to the estimated project cost; (ii) an explanation of
the causes of, or reasons for, any such changes; and (iii) changes in project status
(i.e., under construction, in service, or withdrawn). The Transmission Provider
shall report such progress to the Transmission Provider Board on a quarterly
basis, or as otherwise directed by the Transmission Provider Board.
Status of Developer Qualifications: Upon solicitation from the Transmission
Provider and upon reaching pre-designated milestones in the project
implementation process, Selected Transmission Developers shall report the
following: (i) changes to the developer qualifications, as defined in the Binding
Proposal Agreement, including changes in the developer constructing the project;
(ii) an explanation of the causes of, or reasons for, such changes; and (iii) an
assessment of the impact of the changes on the project. The Transmission
Provider shall report such changes and any impact to the Transmission Provider
Board on a quarterly basis, or as otherwise directed by the Transmission Provider
Board.
12.
Treatment of Critical Energy Infrastructure Information (“CEII”) and
Confidential Data: The Transmission Provider shall utilize a Non-Disclosure and
Confidentiality Agreement (“NDA”) to address sharing of CEII transmission
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planning information. FTP sites containing such information will require such
agreements to be executed in order to obtain access to those sites. Stakeholder
meetings at which CEII may be available shall be noticed to email exploders and
shall require execution of NDAs prior to participation in such meetings. In the
alternative, such meetings will be structured to have separate discussion of issues
involving CEII data only with participants that agree to execute the NDA.
Confidential information related to economic (e.g., congestion) studies, as well as
CEII, is clearly sensitive information which must remain confidential. The
Transmission Provider shall use generic, publicly available, cost information from
industry sources in the economic studies to prevent the accidental release of
confidential information. This approach will promote an open planning process
because the results of economic studies are available to all interested parties.
13.
Resolution of Stakeholder Input: The Transmission Provider shall solicit
input and comments from all stakeholders, including Transmission Owners,
during and after stakeholder planning meetings, and will use reasonable efforts to
reply to comments that the Transmission Provider does not elect to implement,
together with reasons for such actions. The Transmission Provider shall develop
a process for the documentation and resolution of stakeholder issues raised in the
planning process, including but not limited to issues related to planning criteria.
14.
Dispute resolution: Consistent with Attachment HH of this Tariff, the
Transmission Provider shall resolve disputes concerning MTEP issues. The first
step will be for designated representatives of the affected parties to work together
to resolve the relevant issues in a manner that is acceptable to all parties. If that
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step is unsuccessful, each affected party shall designate an officer who shall
review disputes involving them that their designated representatives are unable to
resolve. The applicable officers of the parties involved in such dispute shall work
together to resolve the disputes so referred in a manner that meets the interests of
such parties, either until such agreement is reached, or until an impasse is
declared by any party to such dispute. If such officers are unable to satisfactorily
resolve the issues, the matter shall be referred to mediation. Parties that are not
satisfied with the dispute resolution procedures may only file a complaint with the
Commission during the negotiation or mediation steps.
If a matter remains unresolved, the affected parties may pursue arbitration.
D.
Project Coordination: In the course of the MTEP process, the
Transmission Provider shall seek out opportunities to coordinate or consolidate, where
possible, individually defined transmission projects into more comprehensive costeffective developments subject to the limitations imposed by prior commitments and
lead-time constraints. The Transmission Provider shall coordinate with Transmission
Owners, and shall consider the input from the SPMs, Planning Subcommittee, and
Planning Advisory Committee to develop expansion plans to meet the needs of the
system. This multi-party collaborative process will allow for all projects with regional
and inter-regional impact to be analyzed for their combined effects on the Transmission
System. Moreover, this collaborative process is designed to ensure that the MTEP
address Transmission Issues within the applicable planning horizon in the most efficient
and cost effective manner, while giving consideration to the inputs from all stakeholders.
In addition to the requirements of this Attachment FF, there may be state or local
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procedural requirements applicable to the planning or siting of transmission facilities by
the Transmission Owners. A current list of those requirements can be found on the
Transmission Provider’s website.
1.
Transmission Owners Electing to Integrate their Local Planning Processes
into the Transmission Provider’s Processes: Some Transmission Owners have
agreed to integrate internal planning process with the Transmission Provider’s
open and coordinated planning processes for all of their transmission facilities to
comply with Order 890 Planning Principles instead of filing a separate
Attachment K. Through this election, the local planning for all transmission
facilities of these Transmission Owners, regardless of whether the facilities are
ultimately transferred to the functional control of the Transmission Provider, shall
be integrated with and included in the regional planning processes of the
Transmission Provider. These regional planning processes, as provided for in this
Attachment FF and in additional detail in the TPBPM, ensure that the planning
decisions for all such facilities are made in an open and transparent environment.
This planning environment provides opportunity for input from, and review by,
stakeholders of the Open Access Transmission Tariff services throughout the
planning process, and is in accordance with the Planning Principles of the Order
890 Final Rule. The open and transparent planning provisions of this Attachment
FF shall not preclude interaction between stakeholders and Transmission Owners
prior to the submittal of proposed projects to the regional planning process.
Transmission Owners integrating local planning processes into the regional
planning processes are listed in Attachment FF-4. Such Transmission Owners
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shall be responsible for providing the Transmission Provider with sufficient
information regarding all planning activities to enable the Transmission Provider
to adequately review and incorporate all of the Transmission Owner’s
transmission facilities into the regional planning process of the Transmission
Provider, as described in Sections I.B.1.a. and I.B.1.b. of this Attachment FF.
The foregoing Transmission Owners will utilize the planning stakeholder forums
of the Transmission Provider to demonstrate the need for, identify the alternatives
to, and report the status of non-transferred transmission facilities using the same
open, transparent and coordinated planning process provided by the Transmission
Provider for transferred facilities as described in this Attachment FF.
a.
Local Planning Processes of Transmission Owners: In accordance
with the ISO Agreement, each Transmission Owner engages in local system
planning in order to carry out its responsibility for meeting its respective
transmission needs in collaboration with the Transmission Provider subject to the
requirements of applicable state law or regulatory authority. In meeting its
responsibilities under the ISO Agreement, the Transmission Owners may, as
appropriate, develop and propose plans involving modifications to any of the
Transmission Owner’s transmission facilities which are part of the Transmission
System. The Transmission Owners shall include the following specific local
planning steps in order to develop plans for potential inclusion in the regional
plan, in accordance with the annual regional planning process as described in
Section I.B.1.b. of this Attachment FF, and in accordance with the regional
planning principles of Section I.A of this Attachment. In addition to the local
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planning steps below, Transmission Owners shall adhere to any applicable state or
local regulatory planning processes.
i.
Define local study area and study horizon;
ii.
Develop appropriate power system models;
a)
Utilize existing NERC or Transmission Provider cases to
model external systems;
b)
Insert detailed model of Transmission Owner system if
required;
c)
Insert updated detailed models of neighboring system
models if required; and
d)
iii.
Verify model topology and generation.
Update loads (spatial and magnitude) in study area;
a)
Review historical MW and MVAR data to develop growth
trends;
b)
Obtain Load forecasts from customers in study area; and
c)
Obtain input from local distribution planners in the study
area.
iv.
Perform contingency analysis using applicable Transmission
Owner planning criteria;
v.
Identify any violations to planning criteria for each of study period;
vi.
Develop alternative solutions to the criteria violations and test
against the planning criteria;
a)
Obtain cost estimates for each alternative and perform
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economic analyses; and
b)
Determine non-cost attributes of each alternative such as
operating flexibility, robustness, among others.
vii.
Select alternative based on cost and non-cost attributes;
viii.
Submit proposed solution and list of alternatives and assumptions
to the Transmission Provider;
ix.
Participate in stakeholder evaluations and discussions as a part of
annual regional plan development process;
x.
Perform additional analysis as required based on feedback from
stakeholder groups (SPM/PS) in the regional planning process;
xi.
Submit results of additional analysis (if performed) to the
Transmission Provider for further discussion with stakeholders (SPM/PS);
xii.
Consider regional planning process results, including stakeholder
feedback on needs, proposed solutions, and alternatives, in determining
whether or not to proceed with implementation of Transmission Owner
proposed expansions; and
xiii.
Post the planning criteria and assumptions, and power flow models
used in development of each Transmission Owner’s current local planning
proposal in accordance with Section I.B.1.b below. To the extent that the
Transmission Owner uses the Midwest ISO MTEP models in developing
its list of newly proposed projects, the Transmission Owner shall indicate
as per Section I.B.1.b. below, the associated MTEP model used.
The Transmission Provider will maintain a link to applicable MTEP
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models on its website together with instructions for accessing such models
consistent with CEII criteria and suitable non-disclosure agreements. In
the event that the Transmission Owner applies its own power flow models
in developing its proposed local plans, the Transmission Owner shall
provide such models to the Transmission Provider for posting, or shall
provide to the Transmission Provider a link to the location of such
Transmission Owner model(s) and to instructions for accessing such
models consistent with the Transmission Owner’s CEII and non-disclosure
requirements. Transmission Provider shall post on its website links to
such postings on Transmission Owner’s website.
b.
Integration of Local Planning Processes of Transmission Owners:
Transmission Owners listed on Attachment FF-4 as integrating local planning
processes with those of the Transmission Provider, shall integrate proposals for
transmission expansions into the regional planning process as follows. Each
Transmission Owner shall submit its proposals for transmission plans to the
Transmission Provider prior to the start of each regional planning cycle. Each
Transmission Owner’s local plan, which consists of a list of proposed projects,
shall be made available on the Transmission Provider’s website for review by the
PAC, the PS, and the SPM participants, subject to CEII and the confidentiality
provisions in this Attachment FF. Such local plans shall be posted by September
15 each year in order to provide time for written comments by stakeholders. In
addition to the list of proposed projects, each Transmission Owner submitting
newly proposed projects by September 15 in any MTEP annual cycle shall
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provide to the Transmission Provider by June 1 of the same year identification of
any Midwest ISO base power flow model used by the Transmission Owner in
support of the identification of the list of proposed projects to be subsequently
posted in September, or in the event that the Transmission Owner uses a nonMidwest ISO base power flow model in support of the identification of the list of
proposed projects the Transmission Owner shall provide to the Transmission
Provider such base power flow model or a link to the power flow model and
assumptions used.
Each Transmission Owner’s local planning model and associated assumptions
shall be accessible on or through a link on the Transmission Provider’s website
for review, subject to CEII and the confidentiality provisions in this Attachment
FF and consistent with section I.B.1.a. In the event that the Transmission Owner
uses a non-Midwest ISO base power flow model, the Transmission Owner shall
provide for posting updates if there are significant changes in the model by July
15, August 15, and September 15 of each year. Comments by stakeholders on the
local planning models and assumptions that are provided to the Transmission
Provider SPM Planning Contact by July 1, or August 1 or September 1 with
respect to updates, shall be forwarded to the applicable Transmission Owner by
July 8, August 8, or September 8, respectively. The Transmission Provider shall
address any unresolved stakeholder issues through the SPM process.
Each Transmission Owner shall also provide to the Transmission Provider by
June 1 of each year any updates to the posted transmission planning criteria, or a
notification that the posted documents have not changed. In the event a
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Transmission Owner has additional significant updates to the posted transmission
planning criteria, the Transmission Owner shall provide such updates for posting
by July 15, August 15, and September 15 of each year.
The Transmission Provider shall post on its website the lists of newly proposed
projects, criteria and assumptions, and supporting base power flow models or
links to supporting base power flow models, as provided by the Transmission
Owners. Initial comments by stakeholders to the proposed projects should be
provided to the Transmission Provider SPM Planning Contact 45 days after the
posting of local plans otherwise comments may be made pursuant to Section
I.A.2.c.ii. The Transmission Provider SPM Planning Contact shall be identified
on the Transmission Provider’s web site page devoted to Expansion Planning.
The Transmission Provider shall provide to the applicable Transmission Owner
within five working days of receipt, a copy of all stakeholder comments received
within 45 days of the posted information regarding Transmission Owner planning
criteria and assumptions, models applied, and list of proposed projects. The
Transmission Provider shall address any unresolved stakeholder issues through
the SPM process. Each Transmission Owner must participate in SPMs in the
respective Planning sub-region as indicated in the Transmission Providers
meeting schedule. Such SPMs shall provide input to and review of the results of
the needs assessments and adequacy of plans proposed by the Transmission
Owners, or by stakeholders to the planning process, or by the Transmission
Provider, to best meet the needs of the sub-region.
Transmission Owners identified in Attachment FF-4, must submit to the
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Transmission Provider, on an annual basis and at a time to be determined by the
Transmission Provider, which shall be prior to the beginning of each regional
planning cycle, all proposed transmission plans for both transferred and nontransferred transmission facilities. The submitted projects of such Transmission
Owners shall be considered potential alternatives to system needs identified, and
as such must be submitted when initially identified as a potential system solution,
in order to permit the evaluation of such projects along with other potential
alternatives that may be proposed by stakeholders or the Transmission Provider,
in the SPM processes. Such alternatives may include transmission, generation,
and demand-side resources. The Transmission Provider will review and evaluate
such alternatives on a comparable basis and select the most appropriate solution.
Comparability includes the ability of the Transmission Provider to obtain
contractual assurances that the selected solution will be implemented by the
required in-service dates. Contractual commitments associated with the
construction of an MTEP Appendix A approved project by Midwest ISO
Transmission Owner(s) and/or Selected Transmission Developer(s) are provided
for by the ISO Agreement, this Tariff, and the Binding Proposal Agreement.
Contractual commitments associated with generation solutions require that a
generator interconnection agreement be filed with the Commission pursuant to
Attachment X of this Tariff by the time the alternative transmission solution
would need to be committed to in order to ensure installation on the required need
date. Contractual commitments associated with demand-side resource solutions
require demonstration to the Transmission Provider of an executed contract
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between LSE and End-Use Customers. Such demand-side contracts must be in
place by the time that the transmission solution would otherwise need to be
committed to in order to ensure a timely solution to the identified planning need,
and must be of a sufficient duration such that a reliable solution can be assured
through the planning horizon. Notwithstanding the provisions of Section VII of
the ISO Agreement regarding the Transmission Provider review of Transmission
Owner plans, no proposed project of a Transmission Owner that has elected to
integrate their local planning processes into the Transmission Provider’s
processes, as indicated on Attachment FF-4, shall be recommended in the MTEP
for implementation until completion of the annual needs analysis carried out in
the annual MTEP cycle, as described in Section I. A. of this Attachment FF,
except as provided for in Section I.B.1.c. of this Attachment FF.
c.
Out-of-Cycle Review of Transmission Owner Plans: In the event that a
Transmission Owner determines that system conditions warrant the urgent
development of system enhancements that would be jeopardized unless the
Transmission Provider performs an expedited review of the impacts of the project,
Transmission Provider shall use a streamlined approval process for reviewing and
approving projects proposed by the Transmission Owners so that decisions will be
provided to the Owner within thirty (30) days of the projects submittal to the
Midwest ISO unless a longer review period is mutually agreed upon.
2.
Transmission Owners Filing Separate Attachment K: Some Transmission
Owners as listed on the last page of Attachment FF-4 have developed individual open,
local planning processes for their facilities, that comply with the Planning Principles of
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the Order 890 Final Rule. These Transmission Owners have an Attachment K that
describes how the Transmission Owner will comply with the Order No. 890 Planning
Principles for all transmission facilities that they plan for, regardless of whether those
facilities are ultimately transferred to the functional control of the Transmission Provider.
With the exception of Sections I.B.1.a and I.B.1.b., the provisions of this Attachment FF
remain applicable to all Transmission Owners notwithstanding the filing by any
Transmission Owner of an Attachment K pursuant to the Order 890 Final Rule.
E.
Joint Regional Planning Coordination: The MTEP shall be developed in
accordance with the principles of interregional coordination through collaboration with
representatives from adjacent transmission providers, their designated regional planning
organizations, or regional transmission organizations, as provided for in this Attachment
FF, or as otherwise provided for in existing joint agreements between the Transmission
Provider and other regional entities that engage in planning activities. The Transmission
Provider has joint operating and coordination agreements with MAPPCOR, as contractor
for Mid-Continent Area Power Pool (“MAPP”), the PJM Interconnection (“PJM”),
Southwest Power Pool (“SPP”), Tennessee Valley Authority (“TVA”), and Manitoba
Hydro (Manitoba). Because TVA is non-jurisdictional, that agreement has not been
submitted for Commission approval, but is available on the Transmission Provider’s
public website.
1.
Initial Contact: The Transmission Provider will initiate a meeting with
representatives of adjacent transmission providers, their designated regional
planning organizations, or regional transmission organizations with which
existing joint agreements are not already established with the Transmission
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Provider (“Regional Planning Coordination Entities” or “RPCEs”), in order to
establish a Joint Planning Committee.
2.
Joint Planning Committee. The Transmission Provider shall offer to form
a Joint Planning Committee (“JPC”) with the RPCE. The JPC shall be comprised
of representatives of the Transmission Provider and the RPCE in numbers and
functions to be identified from time to time. The JPC may combine with or
participate in similarly established joint planning committees amongst multiple
RPCEs or established under joint agreements to which the Transmission Provider
is a signatory, for the purpose of providing for broader and more effective interregional planning coordination. The JPC shall have a Chairman. The Chairman
shall be responsible for: the scheduling of meetings; the preparation of agendas
for meetings; the production of minutes of meetings; and for chairing JPC
meetings. The Chairmanship shall rotate amongst the Transmission Provider and
the RPCEs on a mutually agreed to schedule, with each party responsible for the
Chairmanship for no more than one planning study cycle in succession. The JPC
shall coordinate planning of the systems of the Transmission Provider and the
RPCEs, including the following:
a.
Coordinate the development of common power system analysis models to
perform coordinated system planning studies including power flow analyses and
stability analyses. For studies of interconnections in close electrical proximity at
the boundaries among the systems of the Transmission Provider and the RPCEs
the JPC or its designated working group will coordinate the performance of a
detailed review of the appropriateness of applicable power system models.
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b.
Conduct, on a regular basis, a Coordinated Regional Transmission
Planning Study (CRTPS), as set forth in Section 8.3.4.
c.
Coordinate planning activities under this Section 8, including the
exchange of data and developing necessary report and study protocols.
d.
Maintain an Internet site and e-mail or other electronic lists for the
communication of information related to the coordinated planning process. Such
sites and lists may be integrated with those existing for the purpose of
communicating the open and transparent planning processes of the Transmission
Provider.
e.
Meet at least semi-annually to review and coordinate transmission
planning activities.
f.
Establish working groups as necessary to address specific issues, such as
the review and development of the regional plans of the RPCE and the
Transmission Provider, and localized seams issues.
g.
Establish a schedule for the rotation of responsibility for data
management, coordination of analysis activities, report preparation, and other
activities.
3.
Data and Information Exchange. The Transmission Provider shall make available
to each RPCE the following planning data and information. Unless otherwise indicated,
such data and information shall be provided annually. The Transmission Provider shall
provide such data in accordance with the applicable CEII policy, and maintain data and
information received from each RPCE in accordance with their applicable confidentiality
policies.
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a.
Data required for the development of power flow cases, and stability
cases, incorporating up to a ten year load forecasts as may be requested, including
all critical assumptions that are used in the development of these cases.
b.
Fully detailed planning models (up to the next ten (10) years as requested)
on an annual basis and updates as necessary to perform coordinated studies that
reflect system enhancement changes or other changes.
c.
The regional plan documents, any long-term or short-term reliability
assessment documents, and any operating assessment reports produced by the
Transmission Provider and the RPCE.
d.
The status of expansion studies, system impact studies and generation
interconnection studies, such that the Transmission Provider and the RPCE have
knowledge that a commitment has been made to a system enhancement as a result
of any such studies.
e.
Transmission system maps for the Transmission Provider and the RPCE
bulk transmission systems and lower voltage transmission system maps that are
relevant to the coordination of planning between or among the systems.
f.
Contingency lists for use in load flow and stability analyses, including lists
of all contingency events required by applicable NERC or Regional Entity
planning standards, as well as breaker diagrams for the portions of the
Transmission Provider and the RPCE transmission systems that are relevant to the
coordination of planning between or among the systems. Breaker diagrams to be
provided on an as requested basis.
g.
The timing of each planned enhancement, including estimated completion
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dates, and indications of the likelihood that a system enhancement will be
completed and whether the system enhancement should be included in system
expansion studies, system impact studies and generation interconnection studies,
and as requested the status of related applications for regulatory approval. This
information shall be provided at the completion of each planning cycle of the
Transmission Provider, and more frequently as necessary to indicate changes in
status that may be important to the RPCE system.
h.
Quarterly identification of interconnection requests that have been
received and any long-term firm transmission services that have been approved,
that may impact the operation of the Transmission Provider or the RPCE system.
i.
Quarterly, the status of all interconnection requests that have been
identified.
j.
Information regarding long-term firm transmission services on all
interfaces relevant to the coordination of planning between or among the systems.
k.
Load flow data initially will be exchanged in PSS/E format. To the extent
practical, the maintenance and exchange of power system modeling data will be
implemented through databases. When feasible, transmission maps and breaker
diagrams will be provided in an electronic format agreed upon by the
Transmission Provider and the RPCE. Formats for the exchange of other data
will be agreed upon by the Transmission Provider and the RPCE.
4.
Coordinated System Planning. The Transmission Provider shall agree to
coordinate with the RPCEs studies required to assure the reliable, efficient, and effective
operation of the transmission system. Results of such coordinated studies will be
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included in the Coordinated System Plan. The Transmission Provider shall agree to
conduct with the RPCEs such coordinated planning as set forth below
a.
Single Entity Planning. The Transmission Provider shall engage in such
transmission planning activities, including expansion plans, system impact
studies, and generator interconnection studies, as necessary to fulfill its
obligations under the Tariff. Such planning shall conform to applicable reliability
requirements of NERC, applicable regional reliability councils, and any successor
organizations thereto.
Such planning shall also conform to any and all applicable requirements of
Federal or State regulatory authorities. The Transmission Provider will prepare a
regional transmission planning report that documents the procedures,
methodologies, and business rules utilized in preparing and completing the report.
The Transmission Provider shall agree to share the transmission planning reports
and assessments with each RPCE, as well as any information that arises in the
performance of its individual planning activities as is necessary or appropriate for
effective coordination among the Transmission Provider and the RPCEs on an
ongoing basis. The Transmission Provider shall provide such information to the
RPCEs in accordance with the applicable CEII policy and shall maintain such
information received from the RPCEs in accordance with their applicable
confidentiality policies.
b.
Analysis of Interconnection Requests. In accordance with the procedures
under which the Transmission Provider provides interconnection service, the
Transmission Provider will agree to coordinate with each RPCE the conduct of
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any studies required in determining the impact of a request for generator or
merchant transmission interconnection. Results of such coordinated studies will
be included in the impacts reported to the interconnection customers as
appropriate. Coordination of studies shall include the following:
i.
When the Transmission Provider receives a request under its
interconnection procedures for interconnection, it will determine
whether the interconnection potentially impacts the system of a
RPCE. In that event, the Transmission Provider will notify the
RPCE and convey the information provided in the interconnection
queue posting. The Transmission Provider will provide the study
agreement to the interconnection customer in accordance with
applicable procedures.
ii.
If the RPCE determines that it may be materially impacted by an
interconnection on the Transmission Provider System, the RPCE
may request participation in the applicable interconnection studies.
The Transmission Provider will coordinate with the RPCE with
respect to the nature of studies to be performed to test the impacts
of the interconnection on the RPCE System, and who will perform
the studies. The Transmission Provider will strive to minimize the
costs associated with the coordinated study process undertaken by
agreement with the RPCE.
iii.
Any coordinated studies associated with requests for
interconnection to the Transmission Provider’s system will be
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performed in accordance with the study timeline requirements and
scope of the applicable generation interconnection procedures of
the Transmission Provider.
iv.
The RPCE may participate in the coordinated study either by
taking responsibility for performance of studies of its system, if
deemed reasonable by the Transmission Provider, or by providing
input to the studies to be performed by the Transmission Provider.
The study cost estimates indicated in the study agreement between
the Transmission Provider and the interconnection customer, will
reflect the costs, and the associated roles of the study participants
including the RPCE. The Transmission Provider will review the
cost estimates and scope submitted by all participants for
reasonableness, based on expected levels of participation, and
responsibilities in the study. If the RPCE agrees to perform any
aspects of the study, the RPCE must comply with the timelines and
schedule of the Transmission Provider’s interconnection
procedures.
v.
The Transmission Provider will collect from the interconnection
customer the costs incurred by the RPCE associated with the
performance of such studies and forward collected amounts, no
later than thirty (30) days after receipt thereof, to the RPCE. Upon
the reasonable request of the RPCE, the Transmission Provider
will make their books and records available to the requestor
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pertaining to such requests for collection and receipt of collected
amounts.
vi.
The Transmission Provider will report the combined list of any
transmission infrastructure improvements on either the RPCE
and/or the Transmission Provider’s system required as a result of
the proposed interconnection.
vii.
Construction and cost responsibility associated with any
transmission infrastructure improvements required as a result of
the proposed interconnection shall be accomplished under the
terms of the applicable OATT, Transmission Service Guidelines,
controlling agreements, and consistent with applicable Federal or
State regulatory policy and applicable law.
viii.
Each transmission provider will maintain separate interconnection
queues. The JPC will maintain a composite listing of
interconnection requests for all interconnection projects that have
been identified as potentially impacting the systems of the
Transmission Provider and coordinating RPCEs. The JPC will
post this listing on the Internet site maintained for the
communication of information related to the coordinated system
planning process.
c.
Analysis of Long-Term Firm Transmission Service Requests. In
accordance with applicable procedures under which the Transmission Provider
provides long-term firm transmission service, the Transmission Provider will
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coordinate the conduct of any studies required to determine the impact of a
request for such service. Results of such coordinated studies will be included in
the impacts reported to the transmission service customers as appropriate.
Coordination of studies will include the following:
i.
The Transmission Provider will coordinate the calculation of ATC
values associated with the service, based on contingencies on their
systems that may be impacted by the granting of the service.
ii.
When the Transmission Provider receives a request for long-term
firm transmission service, it will determine whether the request
potentially impacts the system of the RPCE. If the Transmission
Provider determines that the RPCE system is potentially impacted,
and that the RPCE would not receive a transmission service
request to complete the service path, the transmission provider will
notify the RPCE and convey the information provided in the
posting.
iii.
If the RPCE determines that its system may be materially impacted
by granting the service, it may contact the Transmission Provider
and request participation in the applicable studies. The
Transmission Provider will coordinate with the RPCE with respect
to the nature of studies to be performed to test the impacts of the
requested service on the RPCE system, and will strive to minimize
the costs associated with the coordinated study process. The JPC
will develop screening procedures to assist in the identification of
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service requests that may impact systems of the JPC members
other than the transmission provider receiving the request.
iv.
Any coordinated studies for request on the transmission Provider’s
system will be performed in accordance with the study timeline
and scope requirements of the applicable transmission service
procedures of the Transmission Provider.
v.
The RPCE may participate in the coordinated study either by
taking responsibility for performance of studies of its system, if
deemed reasonable by the Transmission Provider or by providing
input to the studies to be performed by the Transmission Provider.
The study cost estimates indicated in the study agreement between
the Transmission Provider and the transmission service customer
will reflect the costs and the associated roles of the study
participants. The Transmission Provider will review the cost
estimates and scope submitted by all participants for
reasonableness, based on expected levels of participation and
responsibilities in the study.
vi.
The Transmission Provider will collect from the transmission
service customer, and forward to the RPCE, the costs incurred by
the RPCE with the performance of such studies.
vii.
The Transmission Provider receiving the request will identify any
transmission infrastructure improvements required as a result of
the transmission service request.
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viii.
Construction and cost responsibility associated with any
transmission infrastructure improvements required as a result of
the transmission service request shall be accomplished under the
terms of the applicable OATT, Transmission Service Guidelines,
controlling agreements, and consistent with applicable Federal or
State regulatory policy and applicable law.
d.
Coordinated Regional Transmission Planning Study: The Transmission
Provider agrees to participate in the conduct of a periodic Coordinated Regional
Transmission Planning Study (CRTPS). The CRTPS shall have as input the
results of ongoing analyses of requests for interconnection and ongoing analyses
of requests for long-term firm transmission service. The Parties shall coordinate
in the analyses of these ongoing service requests in accordance with Sections
8.3.2 and 8.3.3. The results of the CRTPS shall be an integral part of the
expansion plans of each Party. Construction of upgrades on the Transmission
System of the Transmission Provider that are identified as necessary in the
CRTSP shall be under the terms of the Owners Agreement of the Transmission
Provider, applicable to the construction of upgrades identified in the expansion
planning process. Coordination of studies required for the development of the
Coordinated System Plan will include the following:
i.
Every three years, the Transmission Provider shall participate in
the performance of a CRTPS. Sensitivity analyses will be
performed, as required, during the off years based on a review by
the JPC of discrete reliability problems or operability issues that
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arise due to changing system conditions.
ii.
The CRTPS shall identify all reliability and expansion issues, and
shall propose potential resolutions to be considered by The
Transmission Provider and the coordinating RPCEs.
iii.
As a result of participation in the CRTPS, except as provided for in
Section II. A. 1., the Transmission Provider is not obligated in any
way to construct, finance, operate, or otherwise support any
transmission infrastructure improvements or other transmissionrelated projects identified in the CRTPS. Any decision to proceed
with any transmission infrastructure improvements or other
transmission-related projects identified in the CRTPS shall be
based on the applicable reliability, operational and economic
planning criteria established for the Transmission Provider as
applicable to the development of the MTEP and set forth in this
Attachment FF.
iv.
As a result of participation in the CRTPS, the RPCEs are not
entitled to any rights to financial compensation due to the impact
of the transmission plans of the Transmission Provider upon the
RPCE system, including but not limited to its decisions whether or
not to construct any transmission infrastructure improvements or
other transmission-related projects identified in the CRTPS.
v.
The JPC will develop the scope and procedure for the CRTPS.
The scope of the CRTPSs performed over time will include
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evaluations of the transmission systems against reliability criteria,
operational performance criteria, and economic performance
criteria applicable to the Transmission Provider and the RPCEs.
vi.
In the conduct of the CRTPS, the Transmission Provider and the
coordinating RPCEs will use planning models that are developed
in accordance with the procedures to be established by the JPC.
Exchange of power flow models will be in a format that is
acceptable to the coordinating parties.
vii.
Stakeholder Review Processes. The Transmission Provider, in
coordination with coordinating RPCEs shall review the scope and
results of the CRTPS with impacted stakeholders, and shall modify
the study scope as deemed appropriate by the Transmission
Provider in agreement with the coordinating RPCEs, after
receiving stakeholder input. Such reviews will utilize the existing
planning stakeholder forums of the coordinating parties including
as applicable joint Sub Regional Planning Meetings.
II.
Development Process for MTEP Projects: The Transmission Provider will
develop the MTEP biennially or more frequently. The MTEP will identify expansion
projects for inclusion in the MTEP according to the factors set forth in Appendix B of the
ISO Agreement and Section I.A. of this Attachment FF. For purposes of assigning cost
responsibility, expansion projects in the MTEP shall be categorized pursuant to the
following criteria.
A.
Reliability Needs: Reliability projects are identified either in the
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periodically performed Baseline Reliability Study, or in Facilities Studies associated with
the request processes for new transmission access. Transmission access includes requests
for both new transmission delivery service and new generation interconnection service.
1.
Baseline Reliability Projects: Baseline Reliability Projects are
Network Upgrades identified in the base case as required to ensure that the
Transmission System is in compliance with applicable national Electric
Reliability Organization (“ERO”) reliability standards and reliability
standards adopted by Regional Reliability Organizations and applicable
within the Transmission Provider Region. Baseline Reliability Projects
include projects that are needed to maintain reliability while
accommodating the ongoing needs of existing Market Participants and
Transmission Customers. Baseline Reliability Projects may consist of a
number of individual facilities that in the judgment of the Transmission
Provider constitute a single project for cost allocation purposes.
The Transmission Provider shall collaborate with Transmission Owning
members, other transmission providers, Transmission Customers, and
other stakeholders to develop appropriate planning models that reflect
expected system conditions for the planning horizon. The planning
models shall reflect the projected load growth of existing network
customers and other transmission service and interconnection
commitments, and shall include any transmission projects identified in
Service Agreements or interconnection agreements that are entered into in
association with requests for transmission delivery service or transmission
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interconnection service, as determined in Facilities Studies associated with
such requests. The Transmission Provider shall test the MTEP for
adequacy and security based on commonly applicable national Electric
Reliability Organization (“ERO”) standards, and under likely and possible
dispatch patterns of actual and projected Generation Resources within the
Transmission System and of external resources, including dispatch
reflective of Long-Term Transmission Rights of Transmission Customers,
and shall produce an efficient expansion plan that includes all Baseline
Reliability Projects determined by the Transmission Provider to be
necessary through the planning horizon of the MTEP. The Transmission
Provider shall obtain the approval of the Transmission Provider Board, as
set forth in Section VI, for each MTEP published.
2.
New Transmission Access Projects: New Transmission Access
Projects are defined for the purposes of Attachment FF as Network
Upgrades identified in Facilities Studies and agreements pursuant to
requests for transmission delivery service or transmission interconnection
service under the Tariff. New Transmission Access Projects include
projects that are needed to maintain reliability while accommodating the
incremental needs associated with requests for new transmission or
interconnection service, as determined in Facilities Studies associated with
such requests. New Transmission Access Projects may consist of a
number of individual facilities, which in the judgment of the Transmission
Provider constitute a single project for cost allocation purposes. New
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Transmission Access Projects are either Generation Interconnection
Projects
or Transmission Delivery Service Projects as defined in Sections II.A.2.a.
and II.A.2.b. The Transmission Provider shall consider the Baseline
Reliability Projects already determined to be needed in the most current
MTEP, as well as any other base-case needs not associated with the
request for new service that may be identified during the impact study
process when determining the need for New Transmission Access
Projects. Any identified base-case needs determined in the impact study
process that are not a part of the Baseline Reliability Projects already
identified in the most current MTEP shall become new Baseline
Reliability Projects and shall be included in the next MTEP. New
Transmission Access Projects identified in Facilities Studies and
agreements pursuant to requests for transmission delivery service or
transmission interconnection service under this Tariff shall be included in
the next MTEP.
a.
Generation Interconnection Projects: Generation
Interconnection Projects are New Transmission Access Projects
that are associated with interconnection of new, or increase in
generating capacity of existing, generation under Attachments X to
this Tariff.
b.
Transmission Delivery Service Projects: Transmission
Delivery Service Projects are New Transmission Access Projects
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that are needed to provide for requests for new Point-To-Point
Transmission Service, or requests under Module B of the Tariff for
Network Service or a new designation of a Network Resource(s).
B.
Market Efficiency Projects: Market Efficiency Projects are Network Upgrades:
(i) that are proposed by the Transmission Provider, Transmission Owner(s), ITC(s),
Market Participant(s), or regulatory authorities; (ii) that are found to be eligible for
inclusion in the MTEP or are approved pursuant to Appendix B, Section VII of the ISO
Agreement after June 16, 2005, applying the factors set forth in Section I.A. of this
Attachment FF; (iii) that have a Project Cost of $5 million or more; (iv) that involve
facilities with voltages of 345 kV or higher1; and that may include any lower voltage
facilities of 100kV or above that collectively constitute less than fifty percent (50%) of
the combined project cost, and without which the 345 kV or higher facilities could not
deliver sufficient benefit to meet the required benefit-to-cost ratio threshold for the
project as established in Section II.B.1.e, or that otherwise are needed to relieve
applicable reliability criteria violations that are projected to occur as a direct result of the
development of the 345 kV or higher facilities of the project; (v) that are not determined
to be Multi Value Projects; and (vi) that are found to have regional benefits under the
criteria set forth in Section II.B.1 of this Attachment FF.
1.
Criteria to Determine Whether a Project Should be Included as a Market
Efficiency Project: The Transmission Provider shall employ multiple future
scenarios and multi-year analysis including sensitivity analyses guided by input
from the Planning Advisory Committee to evaluate the anticipated benefits of a
proposed Market Efficiency Project in order to determine if such a project meets
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the criteria for inclusion in the regional plan as a Market Efficiency Project
eligible for regional cost sharing. Sensitivity analyses shall include, among other
factors, consideration of: (i) variations in amount, type, and location of future
generation supplies as dictated by future scenarios developed with stakeholder
input and guidance; (ii) alternative transmission proposals; (iii) impacts of
variations in load growth; and (iv) effects of demand response resources on
transmission benefits.
1
Transformer voltage is defined by the voltage of the low-side of the
transformer for these purposes.
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The Transmission Provider shall perform this inclusion analysis as follows:
a.
The Transmission Provider shall utilize a weighted futures, no loss
(“WFNL”) metric to analyze the anticipated annual economic benefits of
construction of a proposed Market Efficiency Project to Transmission Customers
in each of the Local Resource Zones, as defined in Attachment WW, based upon
adjusted production cost (“APC”) savings. APC savings will be calculated as the
difference in total production cost of the Resources in each Local Resource Zone
adjusted for import costs and export revenues with and without the proposed
Market Efficiency Project as part of the Transmission System. The WFNL metric
for each Local Resource Zone shall be calculated using the weighted APC savings
determined for each future scenario included in the analysis.
i.
The WFNL metric shall utilize the future scenarios determined and
identified by the Transmission Provider through the planning process,
with input from all stakeholders. The weights applied to the results of
each future scenario shall also be determined by the Transmission
Provider with input from all stakeholders.
b.
Project benefit evaluations will include benefits for the first 20 years of
project life after the projected in-service date, with a maximum planning horizon
of 25 years from the approval year. The annual benefit for a proposed Market
Efficiency Project shall be determined as the sum of the WFNL values for each
Local Resource Zone, as defined in Attachment WW. The total project benefit
shall be determined by calculating the present value of annual benefits for the
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multiple year scenarios and multi-year evaluations.
c.
The costs applied in the benefit to cost ratio shall be the present value,
over the same period for which the project benefits are determined, of the annual
Network Upgrade Charges for the project as determined in accordance with the
formula in Attachment GG.
d.
The present value calculation for both the annual benefits and annual costs
will apply a discount rate representing the after-tax weighted average cost of
capital of the Transmission Owners that make up the Transmission Provider
Transmission System.
e.
The Transmission Provider shall employ a benefit to cost ratio test to
evaluate a proposed Market Efficiency Project. Only projects that meet a benefit
to cost ratio of 1.25 or greater shall be included in the MTEP as a Market
Efficiency Project and be eligible for regional cost sharing.
f.
The benefits of the project used to determine the associated cost
allocations as a percentage of project cost shall be determined one time at the time
that the project is presented to the Transmission Provider Board for approval.
Estimated Project Cost will be used to estimate the benefit to cost ratio and the
eligibility for cost sharing at the time of project approval. To the extent that the
Commission approves the collection of costs in rates for Construction Work in
Progress (“CWIP”) for a constructing Transmission Owner, costs will be
allocated and collected prior to completion of the project.
g.
The aforementioned Market Efficiency Project inclusion criteria shall be
used for the exclusive purpose of determining whether projects are eligible for
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regional cost sharing in accordance with Section III.A.2.f below. These criteria
shall not affect the existing criteria set forth in Appendix B of the ISO Agreement
for determining whether projects are eligible for inclusion in the MTEP. Moreover,
the costs of projects included in the MTEP, but not eligible for regional cost
sharing, shall continue to be eligible for inclusion in the calculation of Transmission
Owner revenue requirements under Attachment O of this Tariff.
C.
Multi Value Projects: A Multi Value Project is one or more Network
Upgrades that address a common set of Transmission Issues and satisfy the conditions
listed in Sections II.C.1, II.C.2., and II.C.3 of Attachment FF. All Network Upgrades
associated with a Multi Value Project including any lower voltage facilities that may be
needed to relieve applicable reliability criteria violations that are projected to occur as a
direct result of the development of the Multi Value Project; may be cost shared per Section
III.A.2.g of Attachment FF except for i) any Network Upgrade cost associated with
constructing an underground or underwater transmission line above and beyond the cost of
a feasible alternative overhead transmission line that provides comparable regional
benefits, and ii) any DC transmission line and associated terminal equipment when
scheduling and dispatch of the DC transmission line is not turned over to the Transmission
Provider's markets, real-time control of the DC transmission line is not turned over to the
Transmission Provider's automatic generation control system and/or the DC transmission
line is operated in a manner that requires specific users to subscribe for DC transmission
service.
1.
A Multi Value Project must be evaluated as part of a Portfolio of projects, as
designated in the transmission expansion planning process, whose benefits
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are spread broadly across the footprint.
2.
A Multi Value Project must meet one of the three criteria outlined below:
a.
Criterion 1. A Multi Value Project must be developed through the
transmission expansion planning process for the purpose of enabling
the Transmission System to reliably and economically deliver
energy in support of documented energy policy mandates or laws
that have been enacted or adopted through state or federal legislation
or regulatory requirement that directly or indirectly govern the
minimum or maximum amount of energy that can be generated by
specific types of generation. The MVP must be shown to enable the
transmission system to deliver such energy in a manner that is more
reliable and/or more economic than it otherwise would be without
the transmission upgrade.
b.
Criterion 2. A Multi Value Project must provide multiple types of
economic value across multiple pricing zones with a Total MVP
Benefit-to-Cost ratio of 1.0 or higher where the Total MVP Benefit to-Cost ratio is described in Section II.C.7 of this Attachment FF.
The reduction of production costs and the associated reduction of
LMPs resulting from a transmission congestion relief project are not
additive and are considered a single type of economic value.
c.
Criterion 3. A Multi Value Project must address at least one
Transmission Issue associated with a projected violation of a NERC
or Regional Entity standard and at least one economic-based
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Transmission Issue that provides economic value across multiple
pricing zones. The project must generate total financially
quantifiable benefits, including quantifiable reliability benefits, in
excess of the total project costs based on the definition of financial
benefits and Project Costs provided in Section II.C.7 of Attachment
FF.
3.
All of the following conditions must be satisfied in order for a project to be
classified as a Multi Value Project:
a.
Facilities associated with the transmission project must not be in
service, under construction, or approved for construction by the
Transmission Provider Board prior to July 16, 2010 or the date a
Transmission Owner becomes a signatory member of the ISO
Agreement, whichever is later. This section II.C.3.a shall not
preclude the Multi Value Project classification of an Open
Transmission Project that makes a Selected Transmission Developer
eligible to become a Transmission Owner.
b.
The transmission project must be evaluated through the
Transmission Provider's transmission planning process and approved
for construction by the Transmission Provider Board prior to the
start of construction, where construction does not include
preliminary site and route selection activities.
c.
The transmission project must not contain any transmission facilities
listed in Attachment FF-1 of this Tariff.
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d.
The total capital cost of the transmission project must be greater than
or equal to $20,000,000.00.
e.
The transmission project must include, but not necessarily be limited
to, the construction or improvement of transmission facilities
operating at voltages above 100 kV. A transformer is considered to
operate above 100 kV when at least two sets of transformer
terminals operate at voltages above 100 kV.
f.
Network Upgrades driven solely by an Interconnection Request, as
defined in Attachment X of the Tariff, or a Transmission Service
request will not be considered Multi Value Projects.
4.
Any transmission project that qualifies as a Multi-Value Project shall
be classified as an MVP irrespective of whether such project is also a
Baseline Reliability Project and/or Market Efficiency Project.
5.
The specific types of economic value provided by a Multi Value
Project include the following:
a.
Production cost savings where production costs include
generator startup, hourly generator no-load, generator energy
and generator Operating Reserve costs. Production cost
savings can be realized through reductions in both
transmission congestion and transmission energy losses.
Productions cost savings can also be realized through
reductions in Operating Reserve requirements within Reserve
Zones and, in some cases, reductions in overall Operating
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Reserve requirements for the Transmission Provider.
b.
Capacity losses savings where capacity losses represent the
amount of capacity required to serve transmission losses
during the system peak hour including associated planning
reserve.
c.
Capacity savings due to reductions in the overall Planning
Reserve Margins resulting from transmission expansion.
d.
Long-term cost savings realized by Transmission Customers
by accelerating a long-term project start date in lieu of
implementing a short-term project in the interim and/or longterm cost savings realized by Transmission Customers by
deferring or eliminating the need to perform one or more
projects in the future.
e.
Any other financially quantifiable benefit to Transmission
Customers resulting from an enhancement to the
Transmission System and related to the provisions of
Transmission Service.
6.
Any project to facilitate like-for-like capital replacements of plant
originally installed as part of a Multi Value Project where replacement is
due to aging, failure, damage or relocation requirements where such
replacement is not the result of negligence by the constructing Transmission
Owner will be treated as a Multi Value Project. The minimum project cost
limitation for Multi Value Projects described in Section II.C.3.d of
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Attachment FF will not apply to the like for- like capital replacement
projects described in this Section.
7.
The following Total MVP Benefit-to-Cost Ratio will be applied to
any Multi Value Project justified solely on the basis of Sections II.C.2.b or
II.C.2.c of this Attachment FF to ensure such project qualifies as a Multi
Value Project:
Total MVP Benefit-to-Cost Ratio = financial benefits / Project
Costs.
For the purpose of this calculation, Financial Benefits will be set equal to
the present value of all financially quantifiable benefits provided by the
project projected for the first 20 years of the project's life and Project Costs
will be set equal to the present value of the annual revenue requirements
projected for the first 20 years of the project's life.
8.
The aforementioned Multi Value Project inclusion criteria shall be
used for the exclusive purpose of determining whether projects are eligible
for regional cost sharing in accordance with Section III.A.2.g below. These
criteria shall not affect the existing criteria set forth in Appendix B of the
ISO Agreement for determining whether projects are eligible for inclusion
in the MTEP. Moreover, the costs of projects included in the MTEP, but
not eligible for regional cost sharing, shall continue to be eligible for
inclusion in the calculation of Transmission Owner revenue requirements
under Attachment O of this Tariff.
III.
Designation of Cost Responsibility for MTEP Projects: Based on the planning
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analysis performed by the Transmission Provider, which shall take into consideration all
appropriate input from Market Participants or external entities, including, but not limited
to, any indications of a willingness to bear cost responsibility for an enhancement or
expansion, the recommended MTEP shall, for any enhancement or expansion that is
included in the plan, designate: (i) the Market Participant(s) in one or more pricing zones
that will bear cost responsibility for such enhancement or expansion, as and to the extent
provided by any applicable provision of the Tariff, including Attachments N, X, or any
applicable cost allocation method ordered by the Commission; or, (ii) in the event and to
the extent that no provision of the Tariff so assigns cost responsibility, the Market
Participant(s) or Transmission Customer(s) in one or more pricing zones from which the
cost of such enhancements or expansions shall be recovered through charges established
pursuant to Attachment GG of this Tariff, or as otherwise provided for under this
Attachment FF.
Any designation under clause (ii) of the preceding sentence shall be determined as
provided for in Section III.A and III.B of this Attachment FF. For all such designations,
the Transmission Provider shall calculate the cost allocation impacts to each pricing zone.
The results will be reviewed for unintended consequences by the Transmission Provider
and the Tariff Working Group and any such identified consequences shall be reported to
the Planning Advisory Committee, and the OMS.
A.
Allocation of Costs Within the Transmission Provider Region
1.
Default Cost Allocation: Except as otherwise provided for in this Attachment FF,
or by any other applicable provision of this Tariff and consistent with the ISO
Agreement, the responsibility for Network Upgrades included in the approved
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MTEP will be addressed in accordance with the provisions of the ISO Agreement.
2.
Cost Allocation: The Transmission Provider will designate and assign cost
responsibility on a regional, and sub-regional basis for Network Upgrades
identified in the MTEP subject to the grand-fathered project provisions of
Section III.A.2.b.
a.
Market Participant’s Option to Fund: Notwithstanding the
Transmission Provider’s assignment of cost responsibility
for a project included in the MTEP, one or more Market
Participants may elect to assume cost responsibility for any
or all costs of a Network Upgrade that is included in the
MTEP. Provided however, in the event the Market
Participant is also a Transmission Owner such election of
the option to fund must be made on a consistent, nondiscriminatory basis.
b.
Grandfathered Projects: The cost allocation provisions of
this Attachment FF shall not be applicable to transmission
projects identified in Attachment FF-1, which is based on
the list of projects designated as Planned Projects in the
MTEP approved by the Transmission Provider Board on
June 16, 2005 (MTEP 05) and some additions of proposed
projects that the Transmission Provider has determined to
be in the advanced stages of planning.
c.
Baseline Reliability Projects: Costs of Baseline Reliability
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Projects shall be recovered pursuant to Attachment O of
this Tariff by the Transmission Owner(s) and/or ITC(s)
developing such projects, subject to the requirements of the
ISO Agreement.
d.
Generation Interconnection Projects: Costs of Generation
Interconnection Projects that are not determined by the
Transmission Provider to be Baseline Reliability Projects,
Market Efficiency Projects, or Multi-Value Projects, and
the Network Upgrade costs associated with advancing a
Baseline Reliability Project, Market Efficiency Project, or
Multi-Value Project associated with a generator
interconnection will be paid for by the Interconnection
Customer(s) in accordance with Attachment X.
For Generator Interconnection Projects interconnecting to
the American Transmission Company LLC transmission
system, such costs will be subject to the provision of
Attachment FF - ATCLLC.
1)
For Network Upgrades to facilities in voltage
classes at or above 345 kV, the Interconnection
Customer shall be repaid 10 percent of the costs of
the Generation Interconnection Project funded by
the Interconnection Customer once Commercial
Operation is achieved. The Transmission Owner(s)
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constructing the Generation Interconnection Project
will repay 10% of the Generation Interconnection
Project costs associated with Network Upgrade
facilities in a voltage class of 345 kV or greater to
the Interconnection Customer under repayment
terms consistent with the schedules and other terms
of Attachment X.
The 10% of the Project Cost associated with
Network Upgrade facilities of voltage class 345 kV
or above and repaid to the Interconnection
Customer shall be allocated on a system-wide basis
and recovered pursuant to Attachment GG of this
Tariff.
2)
An Interconnection Customer may be required to
contribute to the cost of Shared Network Upgrades,
as defined in Attachment X to the Tariff, that are
funded by another Interconnection Customer as a
Generator Interconnection Project pursuant to
Attachment X.
Each Interconnection Customer with one or
more Shared Network Upgrade(s) identified in
Appendix A of its Generator Interconnection
Agreement shall make a one-time payment under
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Schedule 26-B to the Transmission Provider in
accordance with the terms in the Generator
Interconnection Agreement. The one-time payment
will reflect the cost of the Shared Network Upgrade
assigned to the Interconnection Customer as
determined by the Transmission Provider.
All revenue collected by the Transmission
Provider through Schedule 26-B shall be distributed
to the appropriate Interconnection Customer(s).
3)
The Interconnection Customer shall be entitled,
pursuant to Section 46 of this Tariff, to any
Financial Transmission Rights or other rights to the
extent provided for under this Tariff, for any
Network Upgrade costs funded by or charged to the
Interconnection Customer and not subject to
repayment under the provisions of this Section
III.A.2.d. In the event that a Generator
Interconnection Project defers or displaces a
Baseline Reliability Project, the costs of the
Generator Interconnection Project up to the costs of
the deferred or displaced Baseline Reliability
Project shall be allocated consistent with the cost
allocation for the Baseline Reliability Project.
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4)
International Transmission/Michigan Electric
Transmission Company/ITC Midwest LLC:
(a)
For those Generator Interconnection Projects
for which International Transmission Company,
Michigan Electric Transmission Company, LLC, or
ITC Midwest LLC (“International” or “METC” or
“ITC Midwest”) as Transmission Owners will be a
signatory to the interconnection agreement under
the terms of Attachment X of this Tariff or any
successor provision of the Tariff executed by the
parties after the effective date of this Attachment FF
Section III.A.2.d.4, this Attachment FF Section
III.A.2.d.4 shall apply, except that, where ITC
Midwest is the Transmission Owner, the
Interconnection Customer may elect to have another
approved methodology under Attachment FF
Section III.A.2.d apply.
(b)
Generation Interconnection Projects: The
cost of Network Upgrades for Generation
Interconnection Projects that are not determined by
the Transmission Provider to be Baseline Reliability
Projects shall be reimbursed by the Transmission
Owner as provided in this Section III.A.2.d.4. All
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costs of Network Upgrades for Generation
Interconnection Projects will initially be paid by the
Interconnection Customer in accordance with the
terms of the Interconnection Agreement entered into
pursuant to Attachment X of this Tariff. To the
extent the Interconnection Customer demonstrates
at the time of Commercial Operation of the
Generating Facility one of the following:
i.
Generating Facility has been designated
as a Network Resource in accordance
with the Tariff, or
ii.
Contractual commitment has been
entered into with a Network Customer
for capacity, or in the case of an
Intermittent Resource, for energy, from
the Generating Facility for a period of
one (1) year or longer.
The Interconnection Customer will receive up to
one hundred percent (100%) reimbursement of
reimbursable costs within ninety (90) days of the
Commercial Operation Date, such reimbursement
prorated by the percentage of the Generating
Facility capacity or annual available energy output
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contracted for and as demonstrated to the
satisfaction of the Transmission Provider.
If the Interconnection Customer is unable to
demonstrate to the satisfaction of the Transmission
Provider at the time of Commercial Operation of the
Generating Facility that the Generating Facility has
met the repayment obligations set forth in
Attachment FF Sections III.A.2.d.4.b.i. or
III.A.2.d.4.b.ii. the Interconnection Customer shall
be directly assigned 100% of the costs of the
Generation Interconnection Project. The
Transmission Owner may effect this direct
assignment of costs by either foregoing any
repayment of costs funded by the Interconnection
Customer, or by electing to repay 100% of the costs
under repayment terms consistent with the
schedules and other terms of Attachment X.
The Interconnection Customer shall be entitled,
pursuant to Section 46 of this Tariff, to any
Financial Transmission Rights or other rights to the
extent provided for under this Tariff, for any
Network Upgrade costs funded by or charged to the
Interconnection Customer and not subject to
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repayment under the provisions of this Attachment
FF Section III.A.2.d.4. In the event that a Generator
Interconnection Project defers or displaces a
Baseline Reliability Project, the costs of the
Generator Interconnection Project up to the costs of
the deferred or displaced Baseline Reliability
Project shall be allocated consistent with the cost
allocation for the Baseline Reliability Project.
(c)
For all amounts to be reimbursed by a
Transmission Owner to an Interconnection
Customer in accordance with this Attachment FF
Section III.A.2.d.4, the Transmission Owner will
reimburse the sums received from the
Interconnection Customer in cash together with any
applicable interest, in accordance with the terms of
the Interconnection Agreement.
(d)
Allocation of Generator Interconnection
Reimbursement. For all amounts reimbursed by a
Transmission Owner to an Interconnection
Customer under this Attachment FF Section
III.A.2.d.4, fifty percent (50%) of the
reimbursement will be allocated consistent with the
allocations under this Attachment FF Sections
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III.A.2.c.i and III.A.2.c.ii, except that such costs
associated with Generation Interconnection Projects
of less than 100 kV voltage class shall also be
allocated consistent with Section III.A.2.c.i. The
remaining fifty percent (50%) of the reimbursement
will not be subject to any regional or sub-regional
cost allocation, but will be recovered by that
Transmission Owner under its Attachment O
transmission rate formula under this Tariff.
e.
Transmission Delivery Service Projects: Costs of
Transmission Delivery Service Projects shall be assigned
and recovered in accordance with Attachment N of this
Tariff.
f.
Market Efficiency Projects: Costs of Market Efficiency
Projects shall be allocated as follows:
i)
Twenty percent (20%) of the Project Cost of the
Market Efficiency Project shall be allocated on a
system-wide basis to all Transmission Customers and
recovered through a system-wide rate.
ii)
Eighty percent (80%) of the costs of the Market
Efficiency Projects shall be allocated to all
Transmission Customers in each of the Local
Resource Zones, as defined in Attachment WW. The
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cost allocated to each Local Resource Zone shall be
based on the relative benefit determined for each
Local Resource Zone that has a positive present value
of annual benefits over the evaluation period using
the methodology for project benefit determination of
Section II.B.1.
iii)
Excessive Funding or Requirements: The
Transmission Provider shall seek to identify and
manage the development of, as a part of the planning
process for Market Efficiency Projects, portfolios of
projects that tend to provide benefits throughout each
Local Resource Zone, as defined in Attachment WW,
over the planning horizon. The Transmission
Provider shall analyze on an annual basis whether the
project portfolios developed in accordance with this
goal and the criteria in Section III. A.2.f
unintentionally result in unjust or unreasonable
annual capital funding requirements for any
Transmission Owner or rate increases for
Transmission Customers in designated pricing zones;
or otherwise result in undue discrimination between
the Transmission Customers, Transmission Owners,
or any Market Participants; any such identified
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consequences shall be reported to the Planning
Advisory Committee and to the Organization of
MISO States. After discussing such assessments with
the aforementioned stakeholder bodies, and taking
into consideration the cumulative experience in
applying this Attachment FF, the Transmission
Provider will make a determination as to whether
Tariff modifications are required, and if so file such
modifications.
g.
Multi Value Projects: Costs of Multi Value Projects will be
allocated as follows:
i)
One-hundred percent (100%) of the annual revenue
requirements of the Multi Value Projects shall be
allocated on a system-wide basis to Transmission
Customers that withdraw energy, including External
Transactions sinking outside the Transmission
Provider's region, and recovered through an MVP
Usage Charge pursuant to Attachment MM.
h.
Treatment of Projects that meet both Baseline Reliability
Project Criteria and/or New Transmission Access Project
Criteria, and the Market Efficiency Project Criteria: If the
Transmission Provider determines that a project designated
as a Market Efficiency Project also meets the criteria to be
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designated as a Baseline Reliability Project and/or a New
Transmission Access Project, the cost of such project shall
be allocated in accordance with the Market Efficiency
Project allocation procedures.
i.
Other Projects: Unless otherwise agreed upon pursuant to
Section III.A.2.a. of this Attachment FF, the costs of
Network Upgrades that are included in the MTEP, but do
not qualify as Baseline Reliability Projects, New
Transmission Access Projects, Market Efficiency Projects
or Multi-Value Projects, shall be eligible for recovery
pursuant to Attachment O of this Tariff by the
Transmission Owner(s) and/or ITC(s) paying the costs of
such project, subject to the requirements of the ISO
Agreement.
j.
Withdrawal from Midwest ISO: A Transmission Owner
that withdraws from the Midwest ISO as a Transmission
Owner shall remain responsible for all financial obligations
incurred pursuant to this Attachment FF while a Member of
the Midwest ISO and payments applicable to time periods
prior to the effective date of such withdrawal shall be
honored by the Midwest ISO and the withdrawing Member.
k.
New Transmission Owners: A new Transmission Owner
joining the Midwest ISO will be responsible for the
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following financial obligations:
a.
New Transmission Owners will not be responsible
for any portion of Baseline Reliability Projects,
Generator Interconnection Projects, Transmission
Delivery Service Projects, or Market Efficiency
Projects that were approved prior to their entry date.
b.
For Multi-Value Projects approved prior to the new
Transmission Owner’s entry date, the load
interconnected to the Transmission Owner’s
Transmission System will be responsible for onehundred percent (100%) of the MVP usage charge
described in Attachment MM for the years
following the Transmission Owner’s entry date
applied to the Monthly Net Actual Energy
Withdrawals for Load interconnected to the
Transmission Owner’s Transmission System.
l.
Only a Transmission Owner shall be
authorized to construct and/or own transmission
facilities associated with a Baseline Reliability
Project, Market Efficiency Project and/or Multi
Value Project. For projects jointly developed
between Transmission Owners and other parties the
portion constructed and owned by a Transmission
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Owner may qualify as a Baseline Reliability
Project, Market Efficiency Project and/or Multi
Value Project.
IV.
Merchant Transmission Project Data Requirements: A proposed merchant
transmission developer assumes all financial risk and funding requirements for
developing its transmission project(s) and constructing the proposed transmission
facility(ies). In order for a proposed merchant transmission developer’s facility to be
interconnected to the Transmission System, it is first necessary for the impacted
Transmission Owner and the Transmission Provider to analyze the reliability and
operational impact of the proposed new merchant transmission facility(ies) on the
Transmission System to determine if the new merchant transmission facilities can be
reliably supported by the Transmission System, and if not, what Network Upgrades
funded by the merchant transmission developer would be required to reliably support the
proposed merchant transmission facility(ies). In order to perform the required reliability
and operational analyses, the merchant transmission developer must provide the
following data to the Transmission Provider:
(1)
Each transmission circuit and substation, including new facilities, associated
with the merchant transmission proposal;
(2)
Nominal operating voltage level in kV and voltage characteristics (i.e., AC
or DC) for each transmission circuit associated with the merchant transmission
proposal;
(3)
Typical and maximum MW power flow schedules, in each direction, for all
proposed DC transmission circuits associated with the merchant transmission
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proposal;
(4)
Normal and emergency summer and winter load ratings for each
transmission circuit associated with the merchant transmission proposal;
(5)
Maximum allowable positive sequence impedance for each AC transmission
circuit associated with the merchant transmission proposal, when applicable;
(6)
List of all transmission buses associated with the merchant transmission
proposal, including nominal operating voltage level in kV, voltage characteristics,
and terminating transmission branches and shunts;
(7)
Proposed substation one-line diagrams for all new substations associated
with the merchant transmission proposal, including circuit breaker and bus
configuration details;
(8)
Load ratings, winding connections, impedances, tap data, and any other
relevant information for load carrying equipment and facilities associated with the
merchant transmission proposal, as applicable;
(9)
Modeling files to model proposed facilities and relevant new contingencies
in power flow, stability, short-circuit and other relevant study models; and
(10)
Any other data determined pertinent to the study by the Transmission
Provider and/or interconnecting Transmission Owners for the specific merchant
transmission facility proposal.
V.
Designation of Entities to Construct, Implement, Own, Operate, Maintain,
Repair, Restore, and/or Finance MTEP Projects: With the exception of Open
Transmission Projects, for each project included in the recommended MTEP Appendix A
and prior to approval by the Transmission Provider Board, the plan shall designate one or
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more Transmission Owners to construct, own, operate, maintain, repair, restore, and
finance the recommended project, based on the planning analysis performed by the
Transmission Provider and based on other input from participants, including, but not
limited to, any indications of a willingness to bear cost responsibility for the project; and
applicable provisions of the ISO Agreement. Regarding Open Transmission Projects, upon
the determination of the Selected Transmission Developer for such projects, as set forth in
Section VIII of this Attachment FF, the Transmission Provider shall update the approved
MTEP Appendix A by identifying the Selected Transmission Developer for each Open
Transmission Project. Should the facilities from such Open Transmission Projects not be
approved by state regulatory authorities as New Transmission Facilities, but instead as
upgrades to existing transmission facilities, as defined in Section VIII.C of this Attachment
FF, the Transmission Provider shall update MTEP Appendix A by designating the
appropriate Transmission Owner(s) to construct, own, operate, maintain, repair, restore,
and finance such facilities in accordance with the ISO Agreement.
VI.
Implementation of the MTEP:
A.
If the Transmission Provider and any Transmission Owner’s planning
representatives, or other designated entity(ies), cannot reach agreement on any element of
the MTEP, the dispute may be resolved through the dispute resolution procedures
provided in the Tariff, or in any applicable joint operating agreement, or by the
Commission or state regulatory authorities, where appropriate. The MTEP shall have as
one of its goals the satisfaction of all regulatory requirements as specified in Appendix B
or Article IV, Section I, Paragraph C of the ISO Agreement.
B.
The Transmission Provider shall present the MTEP, along with a summary
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of relevant alternative projects that were not selected, to the Transmission Provider Board
for approval on a biennial basis, or more frequently if needed. The proposed MTEP shall
include specific projects already approved as a result of the Transmission Provider
entering into Service Agreements with Transmission Customers where such agreements
provide for identification of needed transmission construction, timetable, cost, and
Transmission Owner or other parties’ construction responsibilities.
C.
Approval of the MTEP by the Transmission Provider Board certifies it as
the Transmission Provider plan for meeting the transmission needs of all stakeholders
subject to any required approvals by federal or state regulatory authorities. The
Transmission Provider shall provide a copy of the MTEP to all applicable federal and
state regulatory authorities. The affected Transmission Owner(s), Selected Transmission
Developer(s), or other designated entity(ies), shall make a good faith effort to design,
certify, and build the designated facilities to fulfill the approved MTEP. However, in the
event that an MTEP Appendix A project approved by the Transmission Provider Board
or the selection of the Selected Transmission Developer is being challenged through the
dispute resolution procedures under this Tariff or in court proceedings, the obligation of
the Transmission Owners, or other designated entity(ies), to build that specific project
(subject to required approvals) is waived until the approved project emerges from the
dispute resolution procedures. The Transmission Provider Board shall allow the
Transmission Owners, or other designated entity(ies), to optimize the final design of
specific facilities and their in-service dates if necessary to accommodate changing
conditions, provided that such changes comport with the approved MTEP and provided
that any such changes are accepted by the Transmission Provider through the
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reevaluation process described in Section VI of this Attachment FF, as necessary. Any
disagreements concerning such matters shall be subject to the dispute resolution
procedures of this Tariff.
D.
The Transmission Provider shall assist the affected Owner(s), Selected
Transmission Developer(s), or other designated entity(ies), in justifying the need for, and
obtaining certification of, any facilities required by the approved MTEP by preparing and
presenting testimony in any proceedings before state or federal courts, regulatory
authorities, or other agencies as may be required. The Transmission Provider shall
publish annually, and distribute to all Members and all appropriate state regulatory
authorities, a five-to-ten-year planning report of forecasted transmission requirements.
Annual reports and planning reports shall be available to the general public upon request.
VII.
Multi-Value Project Costs and Benefits Review and Reporting
A.
Frequency and Reporting of Multi-Value Project Review: Every three
(3) years, as provided below and in the Business Practices Manual for
Transmission Planning, the Transmission Provider shall conduct a review of the
cumulative costs and benefits associated with MVPs, and shall disseminate the
results of such reviews to its stakeholders. The Transmission Provider shall use
the review process and results to identify potential modifications to the MVP
methodology and its implementation for projects to be approved at a future date.
1.
Triennial Full MVP Review: Beginning with the MTEP for 2014 (“MTEP
14”), and every third year thereafter, the Transmission Provider shall
conduct a full MVP review, as provided in section VII.B of this
Attachment FF.
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2.
Annual Limited MVP Review: Beginning with the MTEP for 2015
(“MTEP 15”), and each year thereafter when there is no full MVP review,
the Transmission Provider shall conduct a limited MVP review, as
provided in section VII.C of this Attachment FF.
3.
Calculation of Costs and Benefits: The reviews shall calculate costs and
benefits on a forward-looking basis over both twenty (20)-year and forty
(40)-year periods. The costs calculation shall use updated project costs
and in-service dates provided in the latest MTEP quarterly status report,
and the benefits calculation shall use updated future scenarios from the
latest MTEP planning cycle. The results of the costs and benefits
calculation shall be provided for each Local Resource Zone as defined in
Module E. If the Local Resource Zones as defined in accordance with
Module E for Resource Adequacy purposes are modified, the
Transmission Provider, working with stakeholders, may define different
Local Resource Zones for purposes of reporting the results of the review.
The definition of different Local Resource Zones in connection with
reporting the results of the review will be detailed in the Business
Practices Manual for Transmission Planning.
4.
Dissemination of the Results of the Full and Limited MVP Reviews:
Within a reasonable time after completion of each MVP review, the
Transmission Provider shall disseminate the results of and supporting
analysis for the MVP review through: (a) publication in the MTEP; (b)
posting on the appropriate section of the Transmission Provider’s public
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website; and (c) presentation to the appropriate stakeholder committees.
B.
Scope of Full Multi-Value Project Review: Each full MVP review shall
at a minimum include the following:
1.
Quantitative Benefits: Analysis of the quantifiable economic benefits
resulting from the addition of MVPs, including, but not limited to:
a.
Congestion and Fuel Savings: Savings from increased access to
lower cost Resources;
b.
Decreased Operating Reserves: Savings associated with lower
Operating Reserve requirements;
c.
Decreased System Planning Reserve Margin: Savings associated
with deferred generation investment due to a reduction in the
system-wide Planning Reserve Margin; and
d.
Decreased Transmission Line Losses: Savings associated with
deferred generation investment due to a reduction in the Capacity
required to serve transmission losses during peak hours, to the
extent that MVPs reduce such losses.
2.
Public Policy and Other Qualitative Benefits: Analysis of the public
policy and other qualitative benefits accruing from MVPs, such as newly
interconnected wind units; and an increase in the percentage of the
Transmission Provider’s Energy needs being supplied by wind and/or
other renewable resources, and wind curtailments.
3.
Historical Data: Provision, beginning with the MTEP for 2017 (“MTEP
17”), and based on the historical data available to the Transmission
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Provider for the five (5) prior years, of information on certain additional
market trend metrics including, but not limited to:
a. Congestion costs;
b. Energy prices;
c. Fuel costs;
d. Planning Reserve Margin requirements;
e. Number of newly interconnected Resources, by Resource type; and
f. The share of the Transmission Provider’s Energy supplied, by
Resource type.
C.
Scope of Limited Multi-Value Project Review: Each limited MVP
review shall at a minimum include the items described in Sections VII.B.1.a and VII.B.3
of this Attachment FF, based on the latest available data for the current year, in
preparation for the next full MVP review.
VIII. Transmission Developer Selection
A.
State or Local Rights of First Refusal. The Transmission Provider shall
comply with any Applicable Laws and Regulations granting a right of first refusal to a
Transmission Owner. The Transmission Owner will be assigned any transmission project
within the scope, and in accordance with the terms, of any Applicable Laws and
Regulations granting such a right of first refusal. These Applicable Laws and
Regulations include, but are not limited to, those granting a right of first refusal to the
incumbent Transmission Owner(s) or governing the use of existing developed and
undeveloped right of way held by an incumbent utility.
B.
State Selection of Qualified Transmission Developers. In the absence
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of any Applicable Laws and Regulations granting a right of first refusal, a state with the
authority to do so may elect to determine the Selected Transmission Developer(s) from
the Qualified Transmission Developers who have submitted Transmission Proposals for
any Open Transmission Projects, or portion of such Open Transmission Projects that are
physically located within such state’s boundaries, in accordance with applicable state
criteria and procedures. Prior to the Transmission Provider Board’s approval of Open
Transmission Project(s) for inclusion in Appendix A of the MTEP, states may identify
any potential Open Transmission Projects within its state boundaries for which it will
determine the Selected Transmission Developer. States that elect to determine the
Selected Transmission Developer may request additional state-specific data or
qualification criteria related to the specific potential Open Transmission Project (s), for
which the state has indicated that it will determine the Selected Transmission Developer
to be included in the corresponding Transmission Proposal Request(s) prior to the
Transmission Provider Board’s approval of potential Open Transmission Project(s) for
inclusion in Appendix A of the MTEP.
Upon receipt of a New Transmission Proposal, the Transmission Provider will
review the New Transmission Proposal to ensure all qualifications and requirements from
the Transmission Proposal Request, including state-specific qualifications, have been
satisfied. Should the New Transmission Proposal not satisfy one or more of the
requirements or qualifications outlined in this Tariff and/or specified in the Transmission
Proposal Request, the Transmission Provider will notify the New Transmission Proposal
Applicant and initiate a Cure Period as described in Section VIII.F of this Tariff. Within
five (5) business days following the completion of this Cure Period, Transmission
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Provider will submit all applicable New Transmission Proposals, including any whose
deficiencies have been cured, to the appropriate state(s) for their consideration, subject to
execution of appropriate Non-Disclosure Agreements.
If, for any reason, a state is unable or declines to determine the Selected
Transmission Developer within the time period defined in Section VIII.G, the
Transmission Provider will assume responsibility for determining the Selected
Transmission Developer. In this event, the Transmission Provider will, pursuant to the
evaluation process outlined in Section VIII.G of this Attachment FF: i) evaluate each
New Transmission Proposal submitted by a Qualified Transmission Developer; ii) select
one of the New Transmission Proposals for implementation and; iii) post the Selected
Transmission Developer on its website within 180 calendar days of the notification from
a state that it is unable or declines to select a developer, or the lapse of the 180 calendar
day timeframe defined in Section VIII.G of this Attachment FF, not to exceed 450
calendar days from posting of the Transmission Proposal Request.
C.
Upgrades to Existing Transmission Facilities. A Transmission Owner
shall have the right to develop, own and operate any upgrade to a transmission facility
owned by the Transmission Owner, in accordance with this Tariff and the ISO
Agreement.
1.1
Upgrades to Existing Transmission Lines. Upgrades to existing
transmission line facilities include any expansion, replacement or
modification, for any purpose, made to existing transmission line facilities
that are classified as transmission plant and owned by one or more
Transmission Owners, for reasons including, but not limited to:
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(a)
increasing the load capability of the transmission line or an
associated circuit;
(b)
increasing the nominal operating voltage of the transmission line
or an associated circuit;
(c)
installing additional plant on an existing overhead or underground
transmission line facility, such as, but not limited to:
i.
plant associated with an additional circuit installed on spare
structure positions;
ii.
additional structures to increase a sag limit or for other
purposes;
iii.
a sectionalizing switch installed on an existing transmission
line circuit regardless of whether or not it is installed on an
existing structure; and
iv.
any other plant additions to existing transmission line
facilities.
(d)
relocating the existing transmission line, or any portion thereof, for
any purpose;
(e)
replacing an entire existing transmission line facility with a new
transmission line facility on the same right-of-way or on a different
right-of-way if the replacement is driven by a relocation request or
requirement;
(f)
replacing one or more existing components of any existing
transmission line facility, such as, but not limited to:
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i.
replacing existing conductors with higher capacity
conductors or better performing conductors;
ii.
replacing single-circuit structures with multi circuit
structures;
iii.
replacing insulators rated at a specific voltage with
insulators rated at a higher voltage;
iv.
replacing aging or defective components associated with
the existing transmission line;
(g)
improving the performance or characteristics of the existing
transmission line for any reason;
(h)
converting an existing overhead transmission line to an
underground transmission line on the same right-of-way and/or
converting an existing underground transmission line to an
overhead transmission on the same right-of-way;
(i)
improving land and land rights booked under the Commission’s
Uniform System of Accounts, Account Nos. 105, 350, and/or 380;
or
(j)
any other modifications to existing transmission facilities.
1.1.1
Combination of Upgrades and New Facilities. If a proposed
transmission project includes a combination of new transmission
line sections and upgrades to existing transmission line sections,
and the new transmission line sections are less than twenty (20)
contiguous miles in total length, construction of the new
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transmission line sections will be considered a transmission
upgrade for the purpose of retaining a right of first refusal. In
either event, upgrades made to the existing transmission line
sections will be considered transmission upgrades for the purpose
of retaining a right of first refusal.
1.2
Upgrades to Existing Substations. Upgrades to existing
substations include any expansions, replacements or modifications
made, in part or in whole, to any existing substation or portion
thereof that is owned by one or more Transmission Owners, and
where some or all of the plant within the existing substation is
classified as transmission plant. These upgrades include, but are
not limited to:
(a)
replacing facilities and/or equipment within an existing
substation footprint;
(b)
installing additional plant within an existing substation
footprint;
(c)
modifying facilities and/or equipment within an existing
substation footprint;
(d)
expanding an existing substation footprint within the
existing substation site boundaries and installing additional plant
within the expanded area; and
(e)
acquiring additional land adjacent to or near the existing
substation in conjunction with installation of additional plant
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within the boundaries of this additional land, including facilities to
interconnect such plant to the existing substation plant.
1.2.1
Construction of a new substation facility at the common junction
point(s) of a transmission line containing more than two terminals or
along an existing two terminal transmission line, where such transmission
line facilities are owned by an incumbent Transmission Owner, for the
purpose of implementing: i) transmission line protection system upgrades;
ii) improving operational flexibility; iii) improving customer service
reliability indices (e.g., reducing SAIFI, CAIDI, SAIDI, etc.); iv)
increasing the load capability of the transmission line; v) improving
transmission voltages and reactive power management; vi) mitigating the
economic and/or reliability impact of contingencies; and vii) any other
purpose other than facilitating the interconnection of a New Transmission
Line Facility will be considered a transmission upgrade for the purpose of
retaining a right of first refusal. Furthermore, construction of a new
substation for the purpose of interconnecting two or more existing
transmission circuits where all such existing transmission circuits are
owned by incumbent Transmission Owner(s) will be considered a
transmission upgrade for the purpose of retaining a right of first refusal.
Examples of newly constructed substations that will be considered
transmission upgrades for the purpose of retaining a right of first refusal
include, but are not limited to, i) circuit breaker substations installed along
an existing two-terminal transmission line to improve operational
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flexibility or customer service reliability via automatic sectionalizing; ii)
series capacitor substations installed within an existing transmission line
to increase load capability; iii) circuit breaker switching substations
installed at the common junction point of a three-terminal line to improve
loading and protection capabilities of protective relay systems; and iv)
newly constructed switching substation to interconnect two existing
transmission circuits at the point where they physically cross each other
where such existing transmission circuits are owned by the same
Transmission Owner. Examples of new substation facilities that would
not be considered transmission upgrades for the purpose of retaining a
right of first refusal include, but are not limited to, i) a New Substation
Facility proposed to interconnect three New Transmission Line Facilities;
ii) a New Substation Facility proposed to facilitate connecting a 345 kV
New Transmission Line Facility to the midpoint of an existing 345 kV
transmission circuit owned by an incumbent Transmission Owner; and iii)
a 765-345 kV New Substation Facility constructed to interconnect a 765
kV New Transmission Line Facility with an existing double circuit 345
kV transmission line, where such 345 kV double circuit transmission line
is owned by incumbent Transmission Owner(s).
D.
Data Submission
1.
Determination of Projects Not Subject to a Right of First
Refusal. Upon the Transmission Provider Board’s approval of
transmission projects for inclusion in Appendix A of the MTEP, the
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Transmission Provider will develop a separate Transmission Proposal
Request for each Open Transmission Project. These Transmission
Proposal Request(s) will be posted on the Transmission Provider website
within thirty (30) calendar days of the date the Transmission Provider
Board approved the Open Transmission Project for inclusion in Appendix
A of the MTEP.
2.
Transmission Proposal Requests
a.
Transmission Proposal Request Deposit. The New
Transmission Proposal Applicant will submit a deposit per
proposal equal to one percent (1%) of the projected project cost,
not to exceed $500,000. The Transmission Provider shall track all
time and expenses specifically associated with the evaluation
process identified in this Section VIII of Attachment FF and the
Transmission Proposal Request deposits will be applied to the cost
of evaluating the New Transmission Proposals. Any remaining
funds shall be refundable on a pro rata basis to each New
Transmission Proposal Applicant within thirty (30) days following
the designation of the Selected Transmission Developer. No
interest will be paid on any deposit funds held by the Transmission
Provider during this time.
b.
Minimum Contents of Transmission Proposal Requests.
The Transmission Proposal Request will specify i) each New
Transmission Line Facility and/or each New Substation Facility
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associated with the Open Transmission Project that should be
included in the New Transmission Proposal; ii) the date by which
the New Transmission Proposal must be submitted to the
Transmission Provider, which shall not exceed 180 calendar days
from the posting of the Transmission Proposal Request; and iii) a
list of the current transmission facility interconnection standards
and requirements established by the Transmission Owner(s) to
which the New Transmission Line Facilities and/or New
Substation Facilities will interconnect.
i.
Furthermore, where it involves one or more New
Transmission Line Facilities, the Transmission
Proposal Request will specify for each New
Transmission Line Facility, at a minimum:
(1)
Expected in-service date;
(2)
Implementation schedule indicating the
required steps to develop and construct the
Open Transmission Project, including, but
not limited to, all required regulatory
approvals;
(3)
Nominal operating voltage level in kV and
voltage characteristics (i.e., three-phase AC,
bipolar DC, etc.) for each transmission
circuit;
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(4)
Terminating substations and buses for each
transmission circuit;
(5)
Minimum required normal and emergency
load ratings for both summer and winter
seasons for each transmission circuit; and
(6)
Maximum allowable positive sequence
impedance for each transmission circuit
when determined applicable by planning
studies performed by the Transmission
Provider.
ii.
Where it involves one or more New Substation
Facilities, the Transmission Proposal Request will
specify for each New Substation Facility, at a
minimum, the following information:
(1)
Expected in-service date;
(2)
Implementation schedule indicating the
required steps to develop and construct the
Open Transmission Project, including, but
not limited to, all required regulatory
approvals;
(3)
List of all transmission buses within the
New Substation Facility, including nominal
operating voltage level in kV and voltage
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characteristics;
(4)
List of all major equipment and facilities
within the New Substation Facility and
associated terminating buses including
power transformers, voltage regulators,
phase angle regulators, series reactors, series
capacitors, shunt reactors, shunt capacitors,
static VAR compensators, DC converters,
transmission line circuit terminals, generator
terminals, and loads;
(5)
Limitations on and/or requirements for bus
configurations when determined applicable
by planning studies performed by the
Transmission Provider including required
load ratings of circuit breakers, disconnects,
bus sections and other load carrying
equipment under alternative bus
configurations;
(6)
Required load ratings for all load carrying
equipment and facilities identified in item
(4) above;
(7)
Winding connection and tap requirements
for power transformers, voltage regulators,
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phase angle regulators and load tap changers
when determined necessary by planning
studies performed by the Transmission
Provider;
(8)
Impedance requirements for power
transformers, phase angle regulators, series
reactors and series capacitors when
determined necessary by planning studies
performed by the Transmission Provider;
and
(9)
Limitations on and/or requirements for
protection systems when determined
applicable by a planning driver or
Applicable Reliability Standard or in order
to ensure a compatible interconnection with
existing protection systems associated with
existing transmission facilities to which the
New Transmission Facilities will
interconnect.
c.
Other Requirements of Transmission Proposal
Requests. The Transmission Provider reserves the right to specify
in Transmission Proposal Requests, if deemed necessary and/or
appropriate, additional information for any specific New
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Transmission Line Facilities and/or New Substation Facilities.
3.
Contents of New Transmission Proposals. New Transmission Proposal
Applicants that submit a New Transmission Proposal in response to a
Transmission Proposal Request must submit all data required by the
Transmission Proposal Request, including, but not limited to:
(1) Documentation of satisfaction of general requirements for
Qualified Transmission Developers;
(2) Cost estimate data for each proposed New Transmission Line
Facility and/or New Substation Facility;
(3) Reasonably descriptive facility design proposals for each New
Substation Facility and/or New Transmission Line Facility
included in the Open Transmission Project;
(4) Documentation of project implementation capabilities;
(5) Documentation of operations, maintenance, repair, and
replacement capabilities;
(6) Modeling data files for all proposed New Transmission Line
Facilities and/or New Substation Facilities included in the Open
Transmission Project; and
(7) Descriptions of relevant partnerships or agreements (if applicable).
4.
General Requirements for Qualified Transmission Developers. The
general requirements applicable to Qualified Transmission Developers
include, but are not limited to:
(1)
Agreement to execute the ISO Agreement if designated as the
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Selected Transmission Developer in the evaluation process to
develop, own and operate New Substation Facilities and/or New
Transmission Line Facilities after the facilities have been
constructed but prior to energization of such New Transmission
Facilities, unless New Transmission Proposal Applicant is already
a Transmission Owner;
(2)
Agreement to comply with all Applicable Laws and Regulations,
codes, and standards governing the engineering, design,
construction, operation, and maintenance of transmission facilities
including, but not limited to, federal laws, state laws, local laws,
state and local building codes, federal regulatory requirements,
state and local regulatory requirements, state and local licensing
authorities, the National Electric Safety Code, the National
Electric Code, Applicable Reliability Standards, and Good Utility
Practice;
(3)
Agreement to register with NERC as the transmission owner
(TO), transmission operator (TOP) and transmission planner (TP),
as defined by NERC, for all transmission facilities which the
Selected Transmission Developer will own that are to be part of
the Transmission System;
(4)
Agreement to either i) contract with the interconnecting Local
Balancing Authority (LBA) to include the New Transmission
Facilities within the boundaries of the LBA and demonstrate to the
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satisfaction of the Transmission Provider and per agreement by
the LBA that applicable LBA-related tasks associated with the
proposed New Transmission Facilities that are delegated to an
LBA by the Balancing Authority Agreement will be carried out
either by the LBA or the Selected Transmission Developer; or ii)
execute the Balancing Authority Agreement, register with NERC
as a Balancing Authority (BA), and be designated as the Local
Balancing Authority for the proposed New Transmission
Facilities, unless the New Transmission Proposal Applicant is
already registered with NERC as a BA and designated as an LBA
for one or more of the existing facilities that interconnect directly
with the New Transmission Facilities associated with the Open
Transmission Project in question;
(5)
Agreement to comply with the FERC Form 715 Part 4 TRPC,
Transmission Planning Criteria and Guidelines on file with FERC
and established by each incumbent Transmission Owner whose
existing transmission facilities will interconnect directly with the
New Transmission Line Facilities and/or New Substation
Facilities;
(6)
Agreement to comply with current requirements and standards
regarding the interconnection of transmission facilities published
by each Transmission Owner to which New Transmission Line
Facilities and/or New Substation Facilities will interconnect
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including, but not limited to, those standards and requirements
required for compliance with the applicable NERC Facilities
Design, Connections, and Maintenance (“FAC”) reliability
standards; and
(7) Submission of a business plan outlining the strategy and process
to obtain project financing and/or credit rating information
applicable to the entity’s organization from Standard and Poor’s,
Moody’s, or Fitch.
5.
Cost Estimates. Proposed cost estimate data must be based on the
reasonably descriptive facility design proposals submitted in the New
Transmission Proposal and will include, at a minimum:
(1)
Estimated project cost for each proposed New Transmission
Line Facility and/or New Substation Facility; and
(2)
Estimated annual revenue requirements for the first 40 years
the facilities included in the New Transmission Proposal will
be in service.
6.
Reasonably Descriptive Facility Design Proposals. Reasonably
descriptive facility design proposals must be submitted for each New
Transmission Line Facility and/or New Substation Facility included in the
Open Transmission Project. Reasonably descriptive facility design
proposals represent descriptions of the core attributes and features of a
design, not the detailed engineering and design calculations and
documents.
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a.
Reasonably Descriptive Facility Design Proposals for New
Transmission Facilities. For each New Transmission Line
Facility, reasonably descriptive facility design proposals must
include, at a minimum:
(1) Estimated length of New Transmission Line Facility in
miles and basis for estimate;
(2) Proposed conductor type, size, and, if applicable, bundling
configuration;
(3) Proposed default or typical structure design attribute(s)
(e.g., steel vs. wood vs. aluminum vs. concrete, monopole
vs. H-frame vs. lattice, single circuit vs. double circuit, selfsupporting vs. guyed, structural calculation assumptions,
etc.) to be used for tangent, running angle, in-line dead-end,
and angle dead-end structures when feasible and/or for the
majority of the New Transmission Line Facility;
(4) Estimated positive sequence line impedance and piequivalent shunt susceptance;
(5) Calculated normal and emergency seasonal thermal loading
ratings, including basis for calculations;
(6) Proposed type of lightning protection system to be used
when feasible and/or for the majority of the New
Transmission Line Facility (e.g., shield wires vs. surge
arresters, etc.) and key attributes (e.g., shielding angle,
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arrester location and type, etc.);
(7) Proposed grounding method to be used when feasible
and/or for the majority of the New Transmission Line
Facility (e.g., ground rods only, counterpoise, etc.) and key
attributes (e.g., targeted structure footing grounding
resistance, etc.);
(8) Proposed method to address or mitigate adverse impacts of
galloping conductors and/or Aeolian vibration, if any (e.g.,
Stockbridge dampers, special conductors, etc.);
(9) Continuous rating of any load carrying switchgear installed
on the New Transmission Line Facility; and
(10)
Assumed communications systems to be used for
the New Transmission Line Facility to facilitate protective
relaying (e.g., fiber optic, power line carrier, microwave,
etc.).
b.
Reasonably Descriptive Facility Design Proposals for New
Substation Facilities. For New Substation Facilities, reasonably
descriptive facility design proposals must include, at a minimum:
(1)
Detailed one-line diagram;
(2)
Proposed protection systems including protection
schemes, any anticipated interaction with existing/other
facilities and conceptual protection system design
(including backup protection systems, if applicable).
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Remote system monitoring capability shall be described
with major features listed (redundancy, monitored
parameters, etc.);
(3)
Detailed specifications for proposed power
transformers;
(4)
Description of other substation equipment items,
including load ratings, voltage ratings, fault interrupting
ratings, tap data, and impedances as applicable, where
other substation equipment includes, but is not limited
to, bus sections, circuit breakers, circuit switchers,
switches, disconnects, regulating transformers, station
service transformers, series and shunt capacitors, series
and shunt reactors, static VAR compensators, DC
conversion equipment, instrument transformers
(metering and relaying), wave traps, and surge
arresters;
(5)
Proposed line terminal ratings and basis for calculation,
including limiting element;
(6)
Basis for load rating calculations on any equipment
where nameplate continuous ratings are not used; and
(7)
Description of the communication system for remote
monitoring, control and data acquisition facilities,
including monitoring and control points.
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Any specific Transmission Proposal Request may
require submission of additional facility design data
when deemed necessary by the Transmission Provider.
Any New Transmission Proposal may also include
additional facility data, including but not limited to,
optional facility design data listed in the Business
Practices Manual for Transmission Planning, which
may be considered by the Transmission Provider in the
evaluation and selection of New Transmission
Proposals.
7.
Project Implementation Capabilities. Documentation of project
implementation capabilities required in a New Transmission Proposal
must include documented processes and methods to be used by the entity
to perform:
(1)
Project management;
(2) Routing evaluation studies for New Transmission Line Facilities, if
applicable;
(3)
Site evaluation studies for New Substation Facilities, if
applicable;
(4)
Regulatory permitting;
(5) Right-of-way acquisition for New Transmission Line Facilities, if
applicable;
(6)
Land acquisition for New Substation Facilities, if applicable;
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(7) Engineering and surveying required for New Transmission Line
Facilities and/or New Substation Facilities;
(8) Material procurement for New Transmission Line Facilities and/or
New Substation Facilities;
(9) Construction of New Transmission Line Facilities and/or New
Substation Facilities; and
(10)
Commissioning of New Transmission Line Facilities and/or
New Substation Facilities.
Any specific Transmission Proposal Request may require submission of
additional data related to the policies, processes, methods, capabilities,
experience, and past performance of New Transmission Proposal
Applicants regarding project implementation when deemed necessary by
the Transmission Provider.
Any New Transmission Proposal may also include additional information
regarding project implementation capabilities, including but not limited to,
existing capabilities and past experience regarding project implementation,
which may be considered by the Transmission Provider in the evaluation
and selection of New Transmission Proposals.
8.
Operations, Maintenance, Repair, and Replacement Capabilities.
Documentation of operations, maintenance, repair, and replacement
capabilities required in a New Transmission Proposal must include
documented processes and methods to be used by the New Transmission
Proposal Applicant to perform the following as applicable depending on
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types of facilities included in the Open Transmission Project:
(1)
Forced outage response for transmission line circuits;
(2)
Forced outage response for substations;
(3)
Switching for transmission line circuits;
(4)
Switching for substations;
(5)
Transmission line emergency repair;
(6)
Substation emergency repair and testing;
(7) Transmission line preventative and/or predictive maintenance,
including vegetation management;
(8) Substation preventative and/or predictive maintenance including
equipment testing;
(9) Maintenance and management of spare parts, spare structures,
and/or spare equipment inventories for substations and/or
transmission lines, as applicable, including description of any
agreements to share spare equipment, spare parts, and/or spare
structures with other transmission entities;
(10)
Real-time operations monitoring and control capabilities, if
the Open Transmission Project contains one or more New
Substation Facilities; and
(11)
Major facility replacements or rebuilds required as a result
of catastrophic destruction or natural aging through normal wear
and tear, including financial strategy to facilitate timely
replacements and/or rebuilds.
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Any specific Transmission Proposal Request may require submission of
additional data related to the policies, processes, methods, capabilities,
experience, and past performance of entities regarding operations,
maintenance, repair, and replacement when deemed necessary by the
Transmission Provider.
Additional information regarding operations, maintenance, repair, and
replacement capabilities may also be included in any New Transmission
Proposal, including but not limited to, existing capabilities and past
experience regarding operations, maintenance, repair and replacement,
which may be considered by the Transmission Provider in the evaluation
and selection of New Transmission Proposals.
9.
Transmission Provider Planning Process Participation
Documentation. While not required, should a New Transmission
Proposal Applicant participate in the Transmission Provider planning
process and desire to have such participation considered in the evaluation
as described in Section VIII.G of this Attachment FF, the New
Transmission Proposal Applicant should include in its New Transmission
Proposal documentation regarding relevant planning studies performed by
the New Transmission Proposal Applicant and results supplied to the
Transmission Provider planning process, as well as documentation on past
transmission project ideas submitted by the New Transmission Proposal
Applicant to the Transmission Provider to address the same Transmission
Issues being addressed by the Open Transmission Project for which the
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New Transmission Proposal is being submitted.
10.
Modeling Data. Modeling data files submitted with the New
Transmission Proposal must meet the requirements outlined in the
Business Practices Manual for Transmission Planning, including, at a
minimum, data files necessary:
(1) To model New Transmission Line Facilities and/or New
Substation Facilities in power flow and short-circuit models and
(2) To model new contingencies associated with New Transmission
Lines Facilities and/or New Substation Facilities.
11.
Period for Submission of New Transmission Proposals. New
Transmission Proposals must be submitted within 180 calendar days from
the date the Transmission Proposal Request is posted, or within the time
period specified in the Transmission Proposal Request, whichever comes
first. If the due date falls on a federal holiday, Saturday, or Sunday, the
New Transmission Proposals will be due on the next business day. Two
copies of the New Transmission Proposal in hard copy form must be
delivered to the address specified in the Transmission Proposal Request no
later than 5:00 PM EPT on the due date and one electronic copy of the
New Transmission Proposal must be e-mailed to the e-mail address
specified in the Transmission Proposal Request no later than 5:00 PM EPT
on the due date. Any inquiries by New Transmission Proposal Applicants
regarding a Transmission Proposal Request prior to submission of a New
Transmission Proposal should be made directly with the contacts listed in
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the Transmission Proposal Request and not to the interconnecting
incumbent Transmission Owners.
12.
Additional Data Requests. If, during the evaluation of New
Transmission Proposals, the Transmission Provider determines that
additional information is required to evaluate the Qualified Transmission
Developers, the Transmission Provider will request, in writing, the
additional data from all Qualified Transmission Developers, along with
the timeframe that this data must be submitted within. If the additional
data is not submitted within the specified timeframe, the New
Transmission Proposal will not be evaluated or considered further. This
timeframe will not be less than ten (10) business days from when the
Transmission Provider issues the additional data request. This data
request will not extend the evaluation timeframe defined in Section
VIII.G.
13.
Confidential Treatment of New Transmission Proposals. All
information submitted with the New Transmission Proposal will be
considered Confidential Information and will not be publicly posted or
shared with any individual, except employees of the Transmission
Provider, applicable state parties who have elected to choose the Selected
Transmission developers, as specified in Section VIII.A of this
Attachment FF, and/or contractors of the Transmission Provider that have
executed an appropriate non-disclosure agreement.
E.
Developer Qualifications. Any New Transmission Proposal Applicant
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may submit a New Transmission Proposal, but must meet the minimum qualifications
required for a Qualified Transmission Developer in order for the Transmission Provider
to accept and consider the New Transmission Proposal. A New Transmission Proposal
Applicant must either be a Transmission Owner as defined in this Tariff or a Non-owner
Member as defined in the ISO Agreement at the time the Transmission Proposal Request
is posted, and must maintain such status throughout the entire process of evaluation and
selection of New Transmission Proposals and project implementation, provided that a
Non-owner Member must become a Transmission Owner. To be eligible to be
considered a Qualified Transmission Developer, a New Transmission Proposal Applicant
that submits a New Transmission Proposal must include therein all the agreements
specified in Section VIII.D of this Attachment FF. Furthermore, a New Transmission
Proposal Applicant will not be considered a Qualified Transmission Developer if all
required data specified in the Transmission Proposal Request, including, but not limited
to, the required data outlined in Section VIII.D of this Attachment FF, is not included in
the New Transmission Proposal as required by Sections VIII.D and VIII.F of this
Attachment FF.
F.
Cure Period. Immediately after the date New Transmission Proposals are
due, the Transmission Provider will review each New Transmission Proposal to ensure
all qualifications and data requirements have been satisfied by each respective New
Transmission Proposal Applicant. Should a New Transmission Proposal fail to satisfy
one or more of the qualifications or data requirements specified in this Tariff and/or in
the Transmission Proposal Request, the Transmission Provider will, within ten (10)
business days, via e-mail notify the submitting New Transmission Proposal Applicant,
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through the contact person designated in the New Transmission Proposal, of any
deficiency, and that New Transmission Proposal Applicant will have a single Cure Period
of ten (10) business days from this notice to revise and resubmit the New Transmission
Proposal to address the deficiency, except that if the New Transmission Proposal
Applicant is neither a Non-owner Member nor a Transmission Owner on the date the
Transmission Proposal Request was posted or ceases to become a Non-owner Member or
Transmission Owner after the date the Transmission Proposal Request was posted, that
New Transmission Proposal Applicant shall not be designated a Qualified Transmission
Developer and the New Transmission Proposal will not be evaluated or considered
further. If a revised New Transmission Proposal is submitted after the Cure Period has
elapsed, or continues to have one or more deficiencies with regard to qualifications or
data requirements, the New Transmission Proposal Applicant shall not be designated a
Qualified Transmission Provider and the New Transmission Proposal will not be
evaluated or considered further. The Transmission Provider will provide a written
explanation identifying why the New Transmission Proposal Applicant has been
disqualified.
G.
Evaluation
1.
Steps of Evaluation and Selection Process. Upon receipt of all
New Transmission Proposals, sufficient in form and substance, by
the due date specified in the Transmission Proposal Request, and
upon completion of the process outlined in Section VIII.F of this
Attachment FF, notwithstanding the authority of states to elect to
choose the Selected Transmission Developer within 360 days of
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the Transmission Proposal Request, the Transmission Provider
will:
(1)
Evaluate each New Transmission Proposal submitted
by a Qualified Transmission Developer;
(2)
Select one of the New Transmission Proposals for
implementation based on application of the evaluation
criteria below; and
(3)
Post the name of the Selected Transmission Developer
on its website within 180 calendar days of the due date
for the submission of New Transmission Proposals for
the selection of the developer either by a competent
state regulatory authority that chooses to make the
selection, or by the Transmission Provider, or within
450 calendar days from the posting of the Transmission
Proposal Request if a state initially elects to perform an
evaluation of the New Transmission Proposals
submitted for an Open Transmission Project and then
the Transmission Provider assumes responsibility for
performing evaluation as outlined in Section VIII.B of
this Attachment FF.
2.
General Criteria. In evaluating each New Transmission Proposal,
the Transmission Provider will consider the following general
aspects of the proposal:
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(1) Cost and reasonably descriptive facility design quality;
(2) Project implementation capabilities;
(3) Operations, maintenance, repair, and replacement
capabilities; and
(4) Transmission Provider planning process participation.
3.
Cost and Reasonably Descriptive Facility Design. When
considering cost and reasonably descriptive facility design quality,
the Transmission Provider shall evaluate, at a minimum:
(1) Estimated project cost for each proposed New
Transmission Line Facility and/or New Substation Facility;
(2) Estimated annual revenue requirements for all New
Transmission Facilities included in the New Transmission
Proposal;
(3) Cost estimate rigor, which shall include financial
assumptions and supporting information to clearly
demonstrate a thorough analysis in support of the cost
estimate;
(4) Reasonably descriptive facility design quality; and
(5) Reasonably descriptive facility design rigor, which shall
include facility studies performed and other specific
supporting data that clearly documents and supports
consideration and attention given to the proposed
reasonably descriptive facility designs.
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4.
Project Implementation Capabilities. When considering project
implementation capabilities, the Transmission Provider shall
evaluate, at a minimum, existing or planned capabilities and
processes regarding:
(1)
Project management;
(2)
Route and site evaluation;
(3)
Land acquisition;
(4)
Engineering and surveying;
(5)
Material procurement;
(6)
Facility construction;
(7)
Final facility commissioning; and
(8)
Previous applicable experience and demonstrated
ability.
5.
Operations, Maintenance, Repair, and Replacement
Capabilities. When considering operations, maintenance, repair
and replacement capabilities, the Transmission Provider shall
evaluate, at a minimum, existing or planned capabilities and
processes regarding the following, as applicable, based on the
types of facilities included in the Transmission Proposal Request:
(1)
Forced outage response;
(2)
Switching;
(3)
Emergency repair and testing;
(4)
Spare parts;
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(5)
Preventative and/or predictive maintenance and testing;
(6)
Real-time operations monitoring and control; and
(7) Major facility replacement capabilities, including ongoing
financial capabilities to restore facilities after catastrophic
outages.
6.
Transmission Provider Planning Process Participation. When
considering transmission provider planning process participation,
the Transmission Provider will consider relevant planning studies
conducted by the Qualified Transmission Developer and the
associated results supplied to the Transmission Provider planning
process, as well as transmission project ideas submitted in the past
by the Qualified Transmission Developer as potential solutions to
address the same Transmission Issues addressed by the Open
Transmission Project.
7.
General Criteria Weighting. In evaluating each New
Transmission Proposal, the Transmission Provider will apply the
following weighting to each New Transmission Facility criteria
evaluated:
a.
New Transmission Line Facilities. The following weights
will be applied to New Transmission Line Facility criteria:
(1)
Cost and reasonably descriptive facility design
quality: 30%
(2)
Project implementation capabilities: 35%
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(3)
Operations, maintenance, repair, and replacement
capabilities: 30%
(4)
Transmission Provider planning process
participations: 5%
b.
New Substation Facilities. The following weights will be
applied to New Substation Facility criteria:
(1)
Cost and reasonably descriptive facility design
quality: 30%
(2)
Project implementation capabilities: 30%
(3)
Operations, maintenance, repair, and replacement
capabilities: 35%
(4)
Transmission Provider planning process
participations: 5%
8.
Evaluation and Selection. Specific methods used to evaluate
various aspects of a New Transmission Proposal shall be described
in the Business Practices Manual for Transmission Planning. This
evaluation will be conducted by Transmission Provider planning
staff and/or independent consultants competent in the areas of
finance, transmission facility design, transmission project
implementation, and transmission operations, maintenance, repair,
and replacement. The Transmission Provider planning staff, and
any independent consultants, will be overseen by an executive
oversight committee consisting of three or more executive staff of
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the Transmission Provider, including at least one officer, and the
final designation of the Selected Transmission Developer will rest
with this committee. The committee shall possess certain specific
expertise necessary for evaluation of New Transmission Proposals,
such as, but not limited to, transmission construction, engineering,
project management, financing, state regulatory, and operations.
Within thirty (30) calendar days of the designation of the Selected
Transmission Developer, the Transmission Provider will provide a
report in which it explains the basis for designating the Selected
Transmission Developer for each Open Transmission Project. Any
disputes regarding the developer selection will be referred to the
Dispute Resolution Process under Attachment HH of this Tariff.
The Selected Transmission Developer will assume the responsibility
and obligation to construct the facilities it is selected to construct. If
the Selected Transmission Developer is financially incapable of
carrying out its construction responsibilities, alternate construction
arrangements shall be identified. Depending on the specific
circumstances, such alternate arrangements shall include
solicitation of Transmission Owners to take on financial and/or
construction responsibilities. If the delay in construction may
adversely affect the Transmission System reliability, the
Transmission Provider shall coordinate with and support the
affected Transmission Owner(s) regarding any mitigation measures
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that may be required by Applicable Reliability Standards.
However, in the event that an MTEP Appendix A Open
Transmission Project approved by the Transmission Provider
Board or selection of the designated Selected Transmission
Developer to construct the approved project is being challenged
through the Dispute Resolution process under Attachment HH of
this Tariff or a court proceeding, the obligation of the Selected
Transmission Developer to build the specific Open Transmission
Project (subject to required approvals) is waived until the Open
Transmission Project or Selected Transmission Developer emerges
from the Dispute Resolution process or court proceedings as an
approved project with a Selected Transmission Developer
designated to construct, implement, own, operate, maintain, repair,
restore, and/or finance the recommended Open Transmission
Project.
9.
Recourse if No New Transmission Proposals are Received. If
no New Transmission Proposals are received from Qualified
Transmission Developers, the Open Transmission Project will be
assigned to the applicable Transmission Owner(s), as defined
below:
(1) Ownership and the responsibility to construct facilities which are
connected to a single Transmission Owner’s system belong to that
Transmission Owner; (2) Ownership and the responsibilities to
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construct facilities which are connected between two (2) or more
Transmission Owners’ facilities belong equally to each
Transmission Owner, unless such Transmission Owners otherwise
agree; and (3) Ownership and the responsibility to construct
facilities which are connected between a Transmission Owner(s)’
system and a system or systems that are not part of the Transmission
Provider belong to such Transmission Owner(s) unless the
Transmission Owner(s) and the non-Transmission Provider party or
parties otherwise agree.
IX.
Reevaluation. After Transmission Provider Board MTEP Appendix A approval,
certain circumstances or events may significantly affect such an Open Transmission
Project in a manner and to a degree that would require the Transmission Provider to
perform Variance Analysis. Such circumstances or events may include, but are not
limited to: material schedule delays, cost increases, or changes to the Selected
Transmission Developer’s qualifications, as compared to the schedule, cost estimates,
and qualifications represented in the New Transmission Project Proposal and/or MTEP
Appendix A, as applicable. The Variance Analysis shall consider, among other things:
(i) causes of, or reasons for, any such circumstance or event; (ii) impacts, including
potential reliability impacts of a delay in the Open Transmission Project, canceling the
Open Transmission Project, or replacing the Selected Transmission Developer; (iii)
mitigation measures and responsibilities; and (iv) solutions, and the timetable for the
implementation of such solutions. This process will begin at assignment of an Open
Transmission Project and end when construction begins.
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A.
Grounds for Variance Analysis
The following factors shall trigger the Transmission Provider’s Variance
Analysis for an Open Transmission Project. The Variance Analysis will focus on
the materiality of the changes identified and determine the need for full
reevaluation.
1.
Cost Increases
Any project cost increase which reduces the benefit-cost ratio of an
economically-driven Open Transmission Project to less than the
required benefit-to-cost threshold, as defined in Section II.B.1.e or
Section II.C.7 of this Attachment FF of the Tariff.
2.
Schedule Delays
A reported or otherwise identified delay of 6 months or more from
the in-service date established in MTEP Appendix A and agreed
upon in the accepted New Transmission Proposal and Binding
Proposal Agreement of any assigned Open Transmission Project.
This analysis may also be based upon failure to obtain necessary
regulatory approvals; failure to execute necessary agreements; or
failure to take the actions described in the Selected Transmission
Developer’s accepted New Transmission Proposal.
3.
Deviation From Selected Transmission Developer
Qualifications
Material changes in the condition and characteristics of the
Selected Transmission Developer, as described in its accepted New
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Transmission Proposal.
Material changes in this subsection may include, but are not
limited to, any delegation or assignment not described in the New
Transmission Proposal of project responsibilities to another entity,
including affiliates, or a partner that is either previously
undisclosed, or disclosed but assigned to or designated for different
responsibilities or failure to conform to the terms described in the
Selected Transmission Developer’s accepted New Transmission
Proposal.
B.
Project Reevaluation
If required by the results of the above-described additional analysis, the
Transmission Provider shall perform a reevaluation of the Open Transmission
Project and/or Selected Transmission Developer, including, but not limited to:
1.
Cost Increases
As applicable and necessary based upon the Variance Analysis, the
Transmission Provider shall use the Open Transmission Project’s
current cost estimate to perform an analysis and determine if said
Open Transmission Project’s currently estimated benefit is
sufficient to justify its continued construction.
2.
Schedule Delays
As necessary based upon the Variance Analysis, the Transmission
Provider shall perform an analysis to determine if the delay in the
achievement of any significant schedule milestone(s) (including,
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but not limited to, failure to obtain necessary regulatory approvals)
will delay the applicable Open Transmission Project’s in-service
date, and if so, whether such delay poses risks of adverse impacts
on Transmission System reliability, and what mitigation measures
and plan should be implemented.
3.
Deviation From Selected Transmission Developer
Qualifications
As necessary based upon the Variance Analysis, the Transmission
Provider shall perform an analysis to determine if the Selected
Transmission Developer remains qualified to construct, implement,
operate, maintain, and/or restore the Open Transmission Project.
C.
Reevaluation Outcomes
Based on all the required analysis described in subparagraphs a and b of
this section, the Transmission Provider may decide to (i) make no change to the
Open Transmission Project; (ii) reassign the Open Transmission Project to a
different Qualified Transmission Developer; (iii) cancel the Open Transmission
Project (iv) implement a reliability mitigation plan, in coordination with the
affected Transmission Owner(s); or (v) such other remedy or solution as may be
appropriate under the circumstances, including a suitable combination of two or
more of the foregoing courses of action.
1.
Reassignment
If a Selected Transmission Developer is found to no longer be a
Qualified Transmission Developer, the applicable Open
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Transmission Project may be reassigned. Open Transmission
Projects will be offered to the applicable Transmission Owner, as
defined below:
(1) Ownership and the responsibility to construct facilities which are
connected to a single Transmission Owner’s system belong to that
Transmission Owner; (2) Ownership and the responsibilities to
construct facilities which are connected between two (2) or more
Owners’ facilities belong equally to each Transmission Owner,
unless such Transmission Owners otherwise agree; and (3)
Ownership and the responsibility to construct facilities which are
connected between a Transmission Owner(s)’ system and a system
or systems that are not part of the Transmission Provider belong to
such Transmission Owner(s) unless the Transmission Owner(s) and
the non-Transmission Provider party or parties otherwise agree.
If the applicable Transmission Owner(s) decline to construct the
Open Transmission Project, it will be reassigned, as applicable,
through the developer evaluation process, as described in Section
VIII.F.
2.
Project Cancellation
Following reevaluation, the Transmission Provider may cancel
economically-driven Open Transmission Projects if (1) cost
increases reduce the benefit-cost ratio to the point where the
currently estimated cost exceed previously defined benefits; and
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(2) reliability and/or public policy benefits (if any), are insufficient
to justify continuation and completion of the project.
3.
Reliability Mitigation Plan
If the Transmission Provider’s analysis determines that
Transmission System reliability may be adversely affected by the
delay of an assigned Open Transmission Project, the Transmission
Provider shall coordinate with and support the affected
Transmission Owner(s) regarding any mitigation measures that
may be required by Applicable Reliability Standards. The
mitigation measures may include, without limitation, any one or
combination of the following components: i) an updated
implementation plan of the Selected Transmission Developer to
meet the required in-service date; ii) an operating procedure; or iii)
an alternative project to mitigate the reliability violation.
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Document Content(s)
Transmittal Letter for Order No. 1000 Compliance Filing.PDF...........1-63
Tab A - Redlined Version of Tariff Sheets.PDF.........................64-185
Tab B - Clean Version of Tariff Sheets.PDF............................186-306
Tab C - Testimony of Jennifer Curran.PDF..............................307-375
FERC GENERATED TARIFF FILING.RTF......................................376-502