UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Midwest Independent Transmission
)
Docket No. ER11-1844-000
System Operator, Inc.
)
PROTEST OF THE
NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.
In accordance with Rule 211 of the Commission’s Rules of Practice and Procedure1 and
with the Commission’s November 4, 2010 Notice of Extension of Time, the New York
Independent System Operator, Inc. (“NYISO”) respectfully submits this Protest against the
application of Midwest Independent Transmission System Operator, Inc. (“Midwest ISO”) and
International Transmission Company d/b/a ITC Transmission (“ITC”) proposing revisions to the
Midwest ISO’s tariffs “to allocate and recover the cost of the ITC Phase Angle Regulating
Transformers at Bunce Creek on the Michigan-Ontario border among the Midwest ISO,
[NYISO], and PJM Interconnection, L.L.C. (“PJM”).”2 In this Protest the NYISO refers to the
joint Midwest ISO/ITC pleading as the “Application” and to the Midwest ISO and ITC
collectively as the “Applicants.”
The Application seeks to impose costs associated with Phase Angle Regulators that ITC
has constructed at its Bunce Creek station on a transmission line connecting Michigan and
Ontario (“Replacement PARs”) on ratepayers in New York and PJM. The Replacement PARs
would replace an earlier PAR that failed shortly after it was placed in-service in 2003. The
activation and effective operation of the Replacement PARs would restore control functionality
that was supposed to have been in place for at least the last seven years, and that was expected to
provide substantial benefits to Detroit Edison Company’s (“Detroit Edison’s”) and ITC’s
1 18 CFR Part 35.
2 Application at 1.
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Michigan customers. For the reasons set forth below, the cost allocation sought by the
Applicants is unprecedented, unjustified, and would be unjust and unreasonable. The
Applicants’ request should therefore be rejected.
I.
Executive Summary
The Commission should reject the Applicants’ ex post proposal to allocate the cost of
transmission facilities that ITC has been in the process of constructing since 20063 to consumers
in New York. The Application is patently deficient and inconsistent with Commission precedent
for numerous reasons including, but not limited to, the following:
A.
The Cost Allocation Proposal Is Not Consistent With Commission Precedent
•
“Postage Stamp” Versus “License Plate” Rate Design. Under a postage-stamp rate
design, the costs of transmission facilities are spread broadly among identified
beneficiaries of those facilities, including customers in geographic areas outside of the
zone where the facilities are located.4 By contrast, “[u]nder a license-plate (or zonal) rate
design, a customer pays the embedded cost of transmission facilities that are located in
the same zone as the customer. A customer does not pay for other transmission facilities
outside of the zone, even if the customer engages in transactions that rely on those
zones.”5
o As explained below, the Midwest ISO Board of Directors has approved recovery
of the cost of the Replacement PARs from ITC’s customers under a license plate
rate within the Midwest ISO footprint. The Application does not propose to
disturb the use of a license plate cost recovery mechanism within the Midwest
ISO. Instead the Application proposes to recover approximately half of the cost
of constructing and operating the Replacement PARs from ratepayers in New
York and PJM, using what amounts to an unprecedented, multi-regional, postage
stamp rate.
•
The Commission Has Repeatedly Rejected Proposals to Adopt Postage Stamp Rates for
Existing Facilities. For the entire seven year period that the Replacement PARs have
been in development, the Commission’s policy has been to allocate the costs of existing
3 See Request of ITC to Amend Presidential Permit, submitted to the United States Department of Energy (“DOE”)
in Docket No. PP-230-3 at 5 (2009). Available on the DOE’s web site at:
4 See American Electric Power Service Corp. v. Midwest Independent Transmission System Operator, Inc., et al.,
125 FERC ¶ 61,341 at n.10 (2008).
5 PJM Interconnection, L.L.C., 130 FERC ¶ 61,052 at n.3 (2010).
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transmission facilities to the relevant transmission owner’s customers, even though, in
many cases, such facilities provide benefits to ratepayers in other geographic locations.
This policy is founded on equitable considerations and concern for economic and
administrative efficiency. The Commission has repeatedly rejected efforts by
transmission developers to reallocate costs of existing transmission facilities, such as the
Replacement PARs, through the use of “postage stamp rates,” and has required instead
that the costs of such facilities continue to be recovered through “license plate rates” from
the transmission owner’s customers.6
•
The Commission Has Previously Rejected Ex Post Efforts to Reallocate Sunk
Transmission Costs. In the limited instances in which the Commission has permitted
transmission costs to be allocated broadly to designated beneficiaries within a given
region, the Commission has been careful to place constraints on the applicability of such
mechanisms. The Commission has only permitted the use of postage stamp rates on a
prospective basis, where the facilities to which such postage stamp rates apply are
constructed after the rates are accepted by the Commission.7 Postage stamp rates are not
available for existing facilities that were constructed prior to the establishment of the rate.
Furthermore, the Commission has repeatedly insisted that postage stamp rates apply only
to facilities that are planned pursuant to an organized, regional process in which all
ratepayers who might have to bear the costs of such facilities have both (1) notice that
they might be expected to pay for such facilities, and (2) an opportunity to participate
fully in the planning of such facilities.8
•
The Replacement PARs Are Existing Facilities for Which Postage Stamp Rates Are Not
Available. The Commission has made clear that where a transmission developer has
proceeded to undertake substantial planning or construction of transmission facilities
under a license plate rate mechanism - as ITC has done here - it will not be permitted
later to reallocate the costs of those facilities on a postage stamp basis.9 Given that ITC’s
facilities were planned and constructed under a license plate rate mechanism, the after-
the-fact, expanded cost allocation now sought by Applicants is prohibited.
•
ITC Planned and Constructed the Original Bunce Creek Par and the Replacement PARs
for the Benefit of its Ratepayers, and to Satisfy Michigan’s Retail Access Statute; Not to
Provide Broader Regional Benefits. The history of the Bunce Creek PARs, as evidenced
by public statements by ITC and its predecessor-in-interest, Detroit Edison, highlights
that the original Bunce Creek PAR was constructed to benefit ITC’s ratepayers, and to
satisfy requirements of Michigan’s retail access statute. The benefits to ITC ratepayers
included the control of parallel path flows between Michigan and Ontario, and the
6 See American Electric Power Service Corp. v. Midwest Independent Transmission System Operator, Inc., et al.,
122 FERC ¶ 61,083 at P 31, order on rehearing, 125 FERC ¶ 61,341 (2008); PJM Interconnection, L.L.C., Opinion
No. 494, 119 FERC ¶ 61,063 (2007), order on reh'g, Opinion No. 494-A, 122 FERC P 61,082 (2008).
7 See Opinion No. 494, 119 FERC ¶ 61,063 at P 53.
8 See American Electric Power Service Corp. v. Midwest Independent Transmission System Operator, Inc., et al.,
122 FERC ¶ 61,083 at P 99.
9 See Opinion No. 494, 119 FERC ¶ 61,063 at P 53.
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increase of transmission capacity in Michigan. Statements made by ITC before it
embarked on its attempt to re-allocate the cost of the Replacement PARs to New York
ratepayers make clear that the Replacement PARs are intended to serve the same
purposes as the original Bunce Creek PAR. ITC did not seek authority to recover the
cost of constructing or operating the original Bunce Creek PAR from New York.
•
The Replacement PARs Were Not Planned and Constructed in Accordance With the
Kind of Regional Process That Is A Prerequisite to Regional Cost Allocation. To the
extent that the NYISO and New York ratepayers have had any discussions with ITC, the
Midwest ISO, or any other entity regarding the Replacement PARs, those discussions
have been informal communications, largely at the operational (as opposed to joint
system planning) level, and have not been part of the type of formalized, regional
planning process that is a prerequisite to the cost allocation sought by the Applicants.10
Neither the NYISO nor New York ratepayers have been brought into, or been asked to
participate in, the design, planning, or installation process for the Replacement PARs, and
have had absolutely no say over the nature or amount of the PARs expenditures incurred
by ITC. Applicants cannot demonstrate that either the original Bunce Creek PAR, or the
Replacement PARs were the subject of a regional planning process that included the New
York ratepayers that they propose to allocate a portion of the cost of the Replacement
PARs to in the Application.
o The draft Replacement PAR operating documents that the Midwest ISO submitted
to the Department of Energy,11 proposed Attachment SS-1 to the Midwest ISO’s
tariff, and a recently rejected Midwest ISO proposal addressing how the
Replacement PARs should be modeled in the NERC Interchange Distribution
Calculator (“IDC”) to determine available Transmission Line Loading Relief,12
provide additional evidence that the Midwest ISO and ITC have not involved the
NYISO in their planning efforts. Each of the identified documents contain
provisions that favor ITC and Midwest ISO interests and/or do not provide for
similar consideration of New York interests. If ITC and the Midwest ISO had
involved the NYISO in the preparation of these documents, the documents would
be more even-handed in their treatment of New York.
•
None of the Decisions Cited In The Application Authorize Ex Post Cost Allocation To
Non-Customers Located In Other Regions. Applicants cite a number of Commission and
court decisions in the hope that at least one of the cases they cite will resonate with the
Commission. None of the cases cited support the Applicants’ request. For example,
10 In the 1998-1999 timeframe studies were apparently performed to ensure that the operation of the
Ontario/Michigan PARs, including the original Bunce Creek PAR, would not significantly harm neighboring
systems.
11 The “Operating Instructions” that the Midwest ISO proposed to the Department of Energy in Docket No. PP-230-
4 are included as an attachment to Attachment A to this Protest.
12 Both the Midwest ISO’s presentation to the IDC Working Group and the NYISO’s responsive presentation raising
its concerns with the Midwest ISO’s proposal are included as Attachments B and C to this Protest. The IDC
Working Group did not approve the Midwest ISO’s proposed method of modeling the Ontario/Michigan PARs.
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Ameren Service Co.13 involves the proper application of existing Midwest ISO tariff
provisions and tariff rules to allocate costs between and among entities that voluntarily
elected to participate in the Midwest ISO, and to live by its market and cost allocation
rules.14 The Northern Indiana Public Service Co.15 case concerns a voluntarily
negotiated agreement that addressed the cost of the transmission upgrades.16 The
Midwest ISO-PJM Joint Operating Agreement is also an agreement that was negotiated
and entered into voluntarily by the two RTOs.17 The Western System Coordinating
Council (“WSCC”) decision addressed a dispute regarding how to allocate costs for a
regional effort to address loop flows between and among WSCC members.18 Further, the
court decisions cited by Applicants are not applicable, as none involved the issue of inter
regional cost allocation to non-customers. Thus, the precedent cited by the Applicants
does not support the proposal to reallocate the sunk cost of ITC’s Replacement PARs to
ratepayers located outside the Midwest ISO that were not participants in the planning of,
or the decision to build, the PARs.
•
The Proposal to Allocate the Cost of the Replacement PARs to New York and PJM
Customers Is Not Consistent With The Method Used To Allocate The Cost Of The
Replacement PARs Within the Midwest ISO Region. In the 2006 Midwest ISO Regional
Transmission Plan (“MTEP”), which incorporated the Replacement PARs as a project,
the Midwest ISO Board of Directors did not identify the “B3N Interconnection”
Replacement PAR project as a “Baseline Reliability Project” that was eligible for cost
sharing within the Midwest ISO region. Rather, the Midwest ISO Board determined that
the cost of the Replacement PARs was not eligible for cost sharing and needed to be
recovered from customers located in ITC’s traditional service territory.19 Although the
Midwest ISO is proposing to allocate the cost of the Replacement PARs to ratepayers in
13 Ameren Service Co., 125 FERC ¶ 61,161 (2008).
14 See Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 131
FERC ¶ 61,253 at P 141 (“One example of a voluntary cost recovery arrangement with a public utility is voluntary
membership in an RTO or ISO that makes an entity subject to the cost allocation provisions of the RTO’s or ISO’s
tariff.” [Citation Omitted]).
15 128 FERC ¶ 61,281 (2009).
16 See Application at 12-13.
17 See Application at 14. The NYISO does not attempt to address the application of this complex agreement
between Midwest ISO and PJM to the facts presented in this proceeding because it is not a party to the agreement
(or to any similar agreement with the Midwest ISO) and because PJM is already participating in this proceeding.
For a similar reason, the NYISO does not attempt to address the Midwest ISO’s pending Regional Expansion
Criteria and Benefits (“RCEB”) filing described on pages 14 and 15 of the Application. The NYISO is aware that
many PJM, and some Midwest ISO, members have protested the Midwest ISO’s proposal in Docket No. ER10-
1791, particularly with regard to its attempts to impose involuntary inter-regional cost recovery for “Multi Value
Projects.”
18 See Application at 13-14.
19 See MTEP06 Appendix A, Project ID Number 1308 (January 30, 2007), available on the Midwest ISO’s web site
at:
7d000a48324a/MTEP06_Report_020507.pdf?action=download&_property=Attachment
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New York, page 16 of the Application indicates that the Midwest ISO is not proposing to
allocate the cost of the Replacement PARs to Midwest ISO customers located outside the
“ITC pricing zone.” Page 9 of Mr. Grover’s Affidavit (Tab G of the Application) states
that costs recovered from PJM and NYISO will be “excluded from the ITC Transmission
Attachment O zonal revenue requirement to prevent double recovery.” This statement
strongly implies that the costs are not being recovered from any other Midwest ISO zone.
In its Application the Midwest ISO seeks permission to recover costs from New York
ratepayers that it is not proposing to recover from ratepayers within its own footprint that
reside outside ITC’s service territory.
B.
The Cost Allocation Proposal Is Not Consistent With The Cost Allocation
Rules Proposed In The Pending Transmission Planning And Cost Allocation
NOPR
•
The Commission’s Cost Allocation Proposal In The Transmission Planning And Cost
Allocation By Transmission Owning And Operating Public Utilities Notice Of Proposed
Rulemaking (“Transmission Planning NOPR”). In Docket No. RM10-23 the
Commission is considering adopting rules addressing cost allocation for transmission
facilities. The Application’s proposal to allocate costs to New York ratepayers directly
contradicts the cost allocation proposal in the Transmission Planning NOPR.
o
For intraregional facilities, the Transmission Planning NOPR proposes:
The allocation method for the cost of an intraregional facility must
allocate cost 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.
[Emphasis added.]20
o
For transmission facilities located in two or more regions, the Transmission
Planning NOPR proposes:
Costs allocated for an interregional facility must be assigned only
to transmission planning regions in which the facility is located.
Costs cannot be assigned involuntarily under this rule to a
transmission planning region in which that facility is not located.
[Emphasis added.]21
o
The Replacement PARs are located in Michigan, which is part of the Midwest
ISO’s service territory. The Midwest ISO is a member of both Reliability First
Corporation and the Midwest Reliability Organization. The New York ISO is
responsible for transmission planning in New York State and is a member of the
Northeast Power Coordinating Council, Inc. The New York ISO and Midwest
20 Transmission Planning NOPR at P 164(4).
21 Id. at P 174(4).
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ISO do not share a common border, they are separated by the Province of Ontario,
Canada and by PJM. The Commission’s proposal appropriately rejects efforts to
reallocate the cost of transmission facilities to entities outside the transmission
planning region(s) in which the facility is located unless a voluntary agreement is
reached.
o The Transmission Planning NOPR is also clear that costs associated with a project
that is not included in a region’s transmission plan “may not be recovered through
a transmission planning region’s cost allocation process.”22 Applicants should
not be allowed to impose the cost of the Replacement PARs on New York
customers when a developer that sought to allocate the costs of transmission
facilities physically located in New York would not be eligible to do so with
out
first participating in the NYISO’s established planning process
es.
C.
“Benefits” That The Ontario/Michigan PARs Are Expected To Provide
•
The Benefit The NYISO Expects Is The Removal Of Unscheduled Ontario And Midwest
ISO Power Flows From The New York State Transmission System. The Application
cites prior NYISO statements regarding expected benefits to New York at times when the
Ontario/Michigan PARs are able to better conform actual power flows to match
scheduled power flows at the Ontario/Michigan border. Given the emphasis that the
Applicants have placed on the NYISO’s statements about benefits, the NYISO considers
it necessary to clearly explain its position. The primary benefit that the NYISO
anticipated in its earlier pleadings was that, when the Ontario/Michigan PARs are able to
better conform actual power flows to scheduled power flows at the Ontario/Michigan
border, transmission service that is scheduled into, out-of or through the Midwest ISO
would actually flow over the Midwest ISO’s transmission facilities, not through New
York. When generation in Ontario is dispatched to serve load in PJM, the associated
transmission service is ordinarily scheduled through the Midwest ISO and the Midwest
ISO is paid to transmit the scheduled energy. However, nearly 40% of the power actually
flows over the New York State Transmission System as unscheduled, “clockwise” loop
flow, increasing costs to New York customers.23 The benefit that the NYISO referred to
in its prior pleadings is the removal of these unscheduled power flows from the New
York State Transmission System. From New York’s perspective, the described benefit is
actually the remedy of an existing detriment. The NYISO does not agree that New York
ratepayers should be required to pay for ITC and Midwest ISO to undertake measures to
better conform actual power flows to scheduled power flows at the Ontario/Michigan
border.
o The Broader Regional Markets Buy-Through of Congestion Solution Will Enable
New York To Charge Scheduling Entities For Unscheduled Power Flows That
Cause Congestion In New York. The proposed Broader Regional Markets Buy-
22 Transmission Planning NOPR at P 96.
23 When this occurs, customers in the Midwest ISO benefit from their use of the New York State Transmission
System because the Midwest ISO was paid to provide transmission service that was actually provided by New York.
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Through of Congestion solution to Lake Erie loop flow will permit the NYISO to
charge entities scheduling transmission service into, out-of or through the
Midwest ISO for the parallel path impacts of their unscheduled flows on the New
York State Transmission System.
•
The Replacement PARs Must Be Operated In Conjunction With The IESO/Hydro One’s
PARs To Better Conform Actual Power Flows To Scheduled Power Flows At The
Ontario/Michigan Border. The Application suggests that the Replacement PARs will
provide benefits to New York and PJM customers by better conforming actual power
flows to scheduled power flows at the Ontario/Michigan border. However, the
Replacement PARs, by themselves, are not capable of effectively conforming actual
power flows to scheduled power flows at the Ontario/Michigan border. There are four
transmission lines interconnecting Michigan and Ontario, three of which have PAR
control devices located in Ontario that have been in place since 2003, or earlier. The
Replacement PARs only affect power flows on one of the four transmission lines that
interconnect Michigan and Ontario. As ITC has previously recognized, the Replacement
PARs must be operated in coordination with the existing IESO/Hydro One PARs to
conform actual power flows to scheduled power flows at the Ontario/Michigan Border.24
The Applicants have not explained why it is appropriate to charge ratepayers in New
York and PJM for “benefits” that PARs that they do not own or operate, and did not pay
for, are needed to provide.
•
The Ontario/Michigan PARs Are Only One Component of the Solution To Lake Erie
Loop Flow. The Application takes some liberties in interpreting statements from the
NYISO’s prior pleadings with regard to the benefits that the four ISO/RTO region is
expected to receive at times when all four sets of Ontario/Michigan PARs are in place
and operating to better conform actual power flows to scheduled power flows.25 For
example, on page 6 of the Application ITC and MISO state that “there is agreement that
the New PARs are the optimal solution to the Lake Erie loop flow problem…” The
Applicants provide no support for this statement. In fact, the NYISO believes the
“optimal solution” is to integrate the operation of the Ontario/Michigan PARs into the
suite of market-based solutions to Lake Erie loop flow that the Midwest ISO,
Independent Electricity System Operator of Ontario (“IESO”), PJM and the NYISO are
working with their stakeholders to develop. The NYISO does not expect the
Ontario/Michigan PARs to “solve” the Lake Erie loop flow problem. The Broader
Regional Market improvements remain a vital component of the solution to Lake Erie
loop flow.
24 See n. 49 and n. 78, infra.
25 On their own, the Replacement PARs would have little impact on Lake Erie loop flow. The Replacement PARs
can only be effective in conforming actual power flows to scheduled power flows if they are operated in conjunction
with PARs located in Ontario.
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II.
Documents Submitted
1.
This Protest;
2.
A copy of the Midwest ISO’s Comments on ITC’s Request to Amend Presidential
Permit, submitted to the Department of Energy on March 12, 2009 in Docket No.
PP-230-4, including as Attachment A thereto the Midwest ISO’s proposed
Operating Instructions for the Ontario/Michigan PARs (“Attachment A”);
3.
A copy of the Midwest ISO’s October 5, 2010 presentation the NERC
Interchange Distribution Calculator Working Group titled Modeling MI-ONT
PARS in IDC (“Attachment B”)26; and
4.
A copy of the NYISO’s October 5, 2010 presentation to the NERC Interchange
Distribution Calculator Working Group titled Modeling MI-ONT PARS in IDC
and prepared in response to the Midwest ISO’s presentation (“Attachment C”).
III.
Protest
A.
Overview
The NYISO’s Answer first addresses the application of existing Commission precedent
to the cost reallocation proposal in the Application. As the NYISO explains in Section III.C of
this Protest, the NYISO is not aware of any Commission precedent that supports allocating the
cost of transmission facilities that have already been constructed to non-customers located in a
different planning region in the absence of a voluntary cost sharing agreement. Because there is
no precedent that is directly on-point, the discussion below considers the Application based on
the most closely analogous decisions that the NYISO identified, or that the Applicants identified
in the Application.
After addressing existing precedent, the NYISO briefly explains that the Applicants’
proposal is contrary to the Commission’s interregional transmission cost allocation proposal in
its Transmission Planning NOPR. Finally, the NYISO explains why the “benefits” New York
26 The Midwest ISO’s presentation to the IDC Working Group used materials that the Midwest ISO first presented
to the NERC Operating Reliability Subcommittee on September 22, 2010.
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expects to receive at times when the Ontario/Michigan PARs are operated to better conform
actual power flows to scheduled power flows at the Ontario/Michigan border do not justify the
Applicants’ proposal to allocate millions of dollars in transmission costs to New York ratepayers
on an annual basis.
B.
There is No Basis in Existing Commission Precedent for Granting the Cost
Allocation Remedy Sought by Applicants
1.
Even For Cost Allocation Within A Single Region, The Commission
Has Placed Strict Limits on Cost Sharing
The Commission’s default cost allocation mechanism within a region is the license plate
rate, which requires that the costs of a transmission provider’s facilities be paid for by that
transmission provider’s customers, irrespective of the benefits those facilities might provide to
customers on other interconnected systems. Although the Commission has expressed a desire to
move away from license plate rates, and toward postage stamp rates that might better reflect the
regional benefits that certain transmission facilities provide, it has repeatedly endorsed - for
reasons of equity and efficiency - the use of license plate rates in its efforts to facilitate the
development of ISOs and RTOs.27 In recent years, the Commission has gradually moved toward
the use of postage stamp rates, but only for facilities that are to be constructed in the future and
that are developed in accordance with a Commission-accepted regional joint planning process.28
Most significantly, the Commission’s movement toward limited postage stamp rates has been
accompanied by an insistence that license plate rates be retained for existing facilities.
27 See PJM Interconnection, L.L.C., 96 FERC ¶ 61,060 at 61,220 (2001); Cleco Power LLC, 103 FERC ¶ 61,272 at
P 28 (2003); Southwest Power Pool, Inc., 111 FERC ¶ 61,118 at P 35 (2005); Bonneville Power Administration,
112 FERC ¶ 61,012 at P 96 (2005).
28 See, e.g., PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ¶ 61,063 (2007), order on reh'g, Opinion No.
494-A, 122 FERC P 61,082 (2008); Midwest Independent Transmission System Operator, Inc., 114 FERC ¶ 61,106,
order on reh’g., 117 FERC ¶ 61,241 (2006).
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a.
The Commission has repeatedly rejected a shift to postage
stamp rates for existing facilities, particularly where they have
been constructed by individual transmission owners to benefit
their own customers
Recent Commission decisions addressing the allocations of transmission costs in PJM
and the Midwest ISO are directly applicable to the Applicants’ request. These decisions, which
have repeatedly rejected efforts to impose postage stamp rates for existing transmission facilities,
strongly undercut the proposal to reallocate the cost of the Replacement PARs to New York
ratepayers.
i.
Opinion No. 494
In Opinion No. 494, the Commission’s resolution of rate design issues in PJM, the
Commission affirmatively rejected a request to implement postage stamp rates for existing
facilities. Instead, the Commission required that license plate rates remain in effect for existing
transmission facilities, even though many of those facilities provide benefits to ratepayers
outside of their local zones.29
The Commission’s rationale for mandating the use of license plate rates for existing
facilities is premised on four core factors. The first is the fact that “existing facilities represent
sunk costs that were built primarily by individual utilities to serve their own internal needs and
were financed by those utilities.”30 The Commission explained that because “transmission
owners in PJM built their existing infrastructure primarily to accommodate the needs of their
own customers,”31 it is appropriate to require that those customers bear the costs of that
infrastructure. The Commission rejected arguments that ancillary beneficiaries should bear a
portion of the costs of such facilities, even if those benefits are a result of unanticipated or new
29 Opinion No. 494, 119 FERC ¶ 61,063 at P 49 (2007).
30 Id. at P 50.
31 Id. at P 51.
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uses of the system, because the “fact that the transmission system is used today in ways that
differ from when the facilities were first constructed does not, standing alone, provide a basis for
finding that a license plate rate design is no longer just and reasonable.”32
The second, related, factor revolves around the fact that the “sunk transmission costs in
question were not planned and constructed to maximize benefits on a region-wide basis”33 as
part of a region-wide planning process. Instead, as noted above, the transmission facilities w
ere
constructed by each individual transmission owner for the benefit of their own ratepayers. In the
absence of a region-wide planning process intended to maximize benefits on a regional basis, the
Commission held that it was just and reasonable for the costs of existing transmission facilities to
be recovered through license plate rates.
The third factor involves economic efficiency, and the provision of appropriate incentives
for construction of new transmission facilities. The Commission noted that “one of the goals in
allocating costs is to promote economic efficiency, [and] reallocation of the sunk costs of already
built facilities will not affect future investment decisions.”34 The Commission went on to
explain that:
the allocation of the sunk costs of existing transmission facilities has no
significant impact on investment decisions associated with new transmission
facilities. A reallocation of costs for existing facilities will not affect a
transmission owner's future decision about whether and where to build new
transmission facilities. Rather, it is the cost allocation method for new
transmission facilities that influences the incentive to invest.35
32 Id.
33 Id. at P 54.
34 Id. at P 53.
35 Id.
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The fourth factor is the fact that “[a]n abrupt shift away from license plate rates
would . . . result in inequities within PJM.”36 Specifically, the Commission was concerned that
the use of postage stamp rates for existing facilities would abruptly impose additional costs on
third parties that had no notice that such costs would be imposed on them, and that had no input
into whether, or how, such facilities should be constructed.37
Each of the factors listed above dictate against the Applicants’ cost sharing proposal.
First, as explained below, the original Bunce Creek PAR and the Replacement PARs were
constructed to benefit ITC’s customers and to satisfy Michigan regulatory requirements. Second,
the Replacement PARs were not planned and constructed to maximize benefits to the combined
Midwest ISO, PJM, IESO, NYISO region under a planning process that covered the region. As
explained below, the Replacement PARs were included in the 2006 MTEP, but they were not
determined to be eligible for broad postage stamp cost allocation within the Midwest ISO region.
Third, the cost of the Replacement PARs are sunk costs. Permitting ITC to reallocate the cost of
these completed transmission facilities is not necessary to incent ITC to construct them, or to
permit ITC to obtain the financing necessary to construct them. Finally, granting the Application
would abruptly impose additional costs on New York ratepayers that had no notice that such
costs would be imposed on them, and that had no input into whether, or how, such facilities
should be constructed.
ii.
AEP Complaint
The Commission reiterated these holdings in its rejection of a complaint by American
Electric Power (“AEP”) seeking the imposition of a postage stamp rate for existing facilities in
both PJM and the Midwest ISO. Similar to the arguments made by Applicants in this case, AEP
36 Id. at P 57.
37 Id.
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argued that its existing high voltage transmission facilities in the combined PJM/Midwest ISO
region provided substantial benefits to customers outside of AEP’s zones, and that those
customers therefore should bear a portion of the costs of those existing facilities.38
The Commission began its discussion by explaining why postage stamp rates are
permissible for future facilities, but not for existing facilities. The Commission first contrasted
the planning process that led to the construction of AEP’s existing facilities with the process
used to construct prospective facilities in PJM and the Midwest ISO. The Commission explained
that, unlike the process that led to the construction of AEP’s existing facilities, “Midwest ISO
and PJM plan the construction of new facilities based on each RTO's independent planning
process, which helps to ensure that new projects are necessary to meet the reliability and
economic needs of each RTO’s system as a whole.”39 Equally important, “[s]takeholders in each
RTO can participate in the RTO’s regional planning process and, thus, can be part of the
discussion that leads to the decision to build new facilities in which they will share the cost.”40
By “contrast, decisions to build existing facilities were not made as part of any regional planning
process.”41
The Commission also explained that “unlike existing facilities, the rate design for new
facilities has efficiency implications.”42 Specifically, “rate design for new facilities is important
because it provides incentives for construction and provides sufficient certainty, so that
38 See American Electric Power Service Corp. v. Midwest Independent Transmission System Operator, Inc., et al.,
122 FERC ¶ 61,083 at P 31, order on rehearing, 125 FERC ¶ 61,341 (2008).
39 Id. at P 96.
40 Id.
41 Id.
42 Id. at P 97.
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developers can obtain financing and the projects can be constructed.”43 By contrast,
“reallocating the cost of existing facilities would neither provide economic efficiencies nor
promote the goal of increasing necessary transmission investment.”44
The Commission then went on to address AEP’s arguments that its facilities were, in fact,
planned on a regional basis that justified a postage stamp rate, again, similar to the argument
raised in the Application and accompanying affidavits. In response to AEP’s argument that it “in
fact did coordinate the development of its [high-voltage] system with other utilities in the
region,” the Commission stated that “AEP has not shown that the level and type of coordination
it says occurred in the development of its existing high-voltage facilities is comparable to the
RTO regional planning processes currently in place.”45 The Commission noted that while
“AEP's facilities were likely not planned in isolation, there is no evidence in the record to show
that they were planned to address regional needs of either the Midwest ISO or PJM wholesale
market, and therefore they are not comparable to each RTO’s regional planning process.”46
The Commission also addressed the general argument that customers throughout PJM
and the Midwest ISO should pay for AEP’s existing high voltage facilities because they all
benefit from them. In particular, the Commission stated that “[w]e do not dispute that some of
AEP’s existing facilities provide benefits outside of their local zone, including for Midwest ISO
customers.”47 However, the Commission concluded that, “consistent with the Commission's
findings in Opinion No. 494, this fact by itself does not establish that the current license-plate
43 Id.
44 Id.
45 Id. at P 98.
46 Id.
47 Id. at P 133.
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rate design for existing facilities is unjust or unreasonable, nor does it provide justification for
reallocating the cost of existing facilities throughout the combined Midwest ISO/PJM region.”48
These decisions are the most recent Commission pronouncements on the permissibility of
reallocating sunk transmission costs outside the Order No. 890/Transmission Planning NOPR
context, and establish clearly that such costs, having been incurred pursuant to a license plate
rate cost allocation methodology, should not later be reallocated to unsuspecting third parties
under a postage stamp rate. Beginning in 2008, ITC identified the replacement of the Original
Bunce Creek PAR as a capital project to be included in ITC’s Attachment O rate - the license
plate rate in the Midwest ISO tariff for recovery of ITC’s transmission costs from ITC’s own
customers.49 There is no reason for the Commission to reach a different conclusion in this case.
b.
The Commission’s decisions limit postage stamp rates to
prospective transmission facilities constructed pursuant to an
organized regional planning process
Just as important as the Commission’s repeated rejection of the application of postage
stamp rates to existing facilities are the limited circumstances under which the Commission has
permitted the use of postage stamp rates. The Commission’s decisions establish two
fundamental prerequisites for the applicability of postage stamp rates - that they be applied to
facilities constructed after the relevant postage stamp methodology has been put into effect, and
48 Id.
49 ITC has included replacement of the Original B3N in its Attachment O as a capital project. See International
Transmission Company, ITC Partners in Business 2009 Attachment O at 9 (listing Midwest ISO Project ID #1308 -
B3N ITC-Hydro One Interconnection (Bunce Creek) as a 2009 Planned Capital Addition) and International
Transmission Company, ITCTransmission 2010 Attachment O at 10. ITC has also discussed the project in several
presentations as a replacement of the Original Bunce Creek PAR. See, e.g., International Transmission Company,
ITC Partners in Business Meeting Presentation at 21 (dated December 13, 2007 (describing it as a project to
“Replace the failed B3N phase shifting transformer at Bunce Creek with two phase shifting transformers to be
operated in series. Justification Includes - Replace failed equipment.”); Spring 2008 ITC Presentation at 9 (stating
that “[w]ith PARs on 3 of 4 interconnections, it will not be possible to achieve the goal of flow equal to schedule,
particularly when external transactions cause heavy flow conditions. The interconnection will be operated to control
flow to schedule as much as possible. This will be the case for Summer 2008. The B3N transformer will be
replaced by two (in series) phase angle regulating transformers which are expected to be delivered in late 2008 and
early 2009. Once operational, the interconnection flow can be optimally controlled to flow equals scheduled.”).
- 16 -
that they be constructed pursuant to a formal, system-wide planning methodology which takes
into consideration the needs of the entire region, and which permits all affected stakeholders to
participate meaningfully before they are allocated transmission upgrade costs.
i.
Prospective Transmission Facilities
As outlined above, one of the core lessons of Opinion No. 494 is that cost allocation for
existing transmission facilities is different from cost allocation for proposed/future transmission
facilities. Among the reasons for this is the need to encourage efficient construction and siting of
new transmission assets. As the Commission observed, the “reallocation of costs for existing
facilities will not affect a transmission owner’s future decision about whether and where to build
new transmission facilities.”50 Rather, “it is the cost allocation method for new transmission
facilities that influences the incentive to invest.”51
Another significant reason for the distinction between existing and proposed facilities is
the desire to avoid the inequitable result of unanticipated cost shifts to unsuspecting third party
transmission customers. The Commission has consistently sought to avoid the imposition of
additional costs on third parties that had no notice that such costs would be imposed on them, or
input into whether, or how, such facilities should be constructed.52
Largely for these reasons, the Commission has limited the applicability of postage stamp
rates to transmission facilities planned and constructed after the implementation of a postage
stamp cost allocation methodology.53 Postage stamp rates have not been available in
circumstances, like the ones present in this proceeding, where transmission facilities are
50 119 FERC ¶ 61,063 at P 53.
51 Id.
52 Id.
53 See 119 FERC ¶ 61,063 at PP 61-66 (emphasizing that the methodology requiring transmission costs to be paid by
all beneficiaries will apply to all “new” transmission facilities).
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constructed before a postage stamp rate method is adopted. Only by ensuring that postage stamp
rates apply on a prospective basis can the Commission ensure that it is truly providing the correct
incentives for the construction of new transmission facilities, and avoid inequitable cost shifts
that inevitably accompany the reallocation of sunk transmission costs.
The Commission’s decisions requiring license plate cost allocation for transmission
facilities is not limited to transmission facilities that have already been placed in service. In the
case of the Midwest ISO’s transmission facilities in particular, the Commission approved a cost
allocation approach that excluded from the newer, system-wide cost allocation mechanism
numerous transmission projects that had reached advanced stages in the planning process, but
that had not yet been constructed. The Commission rejected challenges to this determination
from developers of these excluded projects, noting that they had “moved forward with those
projects without any assurance that such projects would be candidates for regional cost-
sharing.”54 This holding underscores that the key issue is not whether the underlying
transmission facility has been placed into service, but instead whether the developer of that
facility has moved forward in its effort to construct that facility before a postage stamp rate was
put into effect. There is no postage stamp rate in place for allocating costs across the combined
Midwest ISO-PJM-NYISO region.
ii.
System-Wide Planning Process
The Commission’s second prerequisite to the adoption of a postage stamp rate is the use
of “a formal, Commission-approved, regional planning process where the needs of the region are
addressed and where all stakeholders are given an opportunity to participate.”55 In its orders on
54 117 FERC ¶ 61,241 at P 96.
55 122 FERC ¶ 61,083 at P 99. See also Opinion No. 494, 119 FERC ¶ 61,063 at P 84 (“facilities that are eligible for
postage-stamp treatment will be planned on a regional basis by a central grid operator, PJM, which considers the
reliability and economic interests of PJM as a whole.”).
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the AEP complaint the Commission found that “an important factor in allowing certain new
high-voltage facilities to be eligible for postage-stamp treatment is that those new facilities are
planned on a regional basis by a central grid operator, who considers the reliability and economic
interests of the RTO as a whole.”56
This factor directly affected the outcome of AEP’s complaint because AEP was unable to
prove that its existing facilities were constructed pursuant to such a process. As outlined above,
AEP provided documentation of collaborations between it and neighboring utilities, in an
attempt to satisfy this criterion. Nonetheless, the type of organized process needed to satisfy this
criterion is a highly centralized one that formally accounts for all the needs of the relevant
region, and that permits all affected stakeholders to participate on a prospective (pre-
construction) basis. AEP’s collaborations with its neighboring utilities was insufficient to carry
AEP’s burden of establishing that its existing facilities had been planned pursuant to the
necessary regional planning process. The Commission concluded that “[a]lthough AEP’s
facilities were likely not planned in isolation, there is no evidence in the record to show that they
were planned to address regional needs of either the Midwest ISO or PJM wholesale market, and
therefore they are not comparable to each RTO's regional planning process.”57
2.
The Application Does Not Demonstrate That the Prerequisites to the
Adoption of Regional Cost Sharing for the Replacement PARs are
Satisfied
All of the circumstances that the Commission relied on in rejecting postage stamp rates
for existing facilities in Opinion No. 494 and in the AEP case are present in this proceeding, and
none of the prerequisites to the application of a postage stamp rate have been satisfied.
56 122 FERC ¶ 61,083 at P 99.
57 Id.
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a.
The Replacement PARs are existing facilities for which the
type of cost allocation sought in the Application is not available
One of criteria for regional cost sharing is that the cost sharing mechanism be in place
before the underlying transmission assets are planned and constructed. Indeed, the Commission
has looked askance at the use of a postage stamp rate in circumstances where “[p]arties moved
forward with [their] projects without any assurance that such projects would be candidates for
regional cost sharing.”58 Thus, where there are existing facilities - that is, facilities that have
undergone either extensive planning or construction, the costs of which are expected to be
recovered under a license plate rate - the Commission prohibits a reallocation of such costs
pursuant to a postage stamp rate. The reasons for this, again, are to promote efficient
transmission development, and to prevent unfair cost shifts to unsuspecting third party
customers.
In this case, ITC moved forward with the planning and construction of the Replacement
PARs long before it began participating in the process that is currently in place to develop
broader regional market solutions to Lake Erie loop flow. Parties outside of the ITC zone had
absolutely no notice of any proposal by ITC or the Midwest ISO to allocate such costs to them
until after the underlying PARs were either nearly complete or completed.59 The Replacement
PARs are existing transmission facilities for which the type of broad cost allocation sought by
ITC is prohibited. The fact that the Replacement PARs have not yet entered service is
58 Midwest Independent Transmission System Operator, Inc., 117 FERC ¶ 61,241 at P 96 (2006).
59 ITC did not propose or request broader allocation of the cost of its PARs until more than eight years after ITC
initially proposed to construct the original Bunce Creek PAR. It was not until the NYISO brought the incidental
benefits these facilities could provide to other ratepayers to the Commission’s attention that ITC began requesting
broader allocation of the cost of its facilities. ITC first began making these arguments in pleadings seeking to
dissuade the NYISO and the Commission from involving themselves in the Department of Energy permitting
process for the Bunce Creek PARs. See, e.g., ITC’s Answer In Opposition to Request for Clarification at 3 (August
31, 2009).
- 20 -
irrelevant.60 Granting the Application would unfairly reallocate part of the costs of the
Replacement PARs to New York ratepayers, without ever giving them a chance to weigh in on
the planning or construction of those facilities, in contravention of established Commission
precedent. Furthermore, granting the cost allocation proposed in the Application would
constitute the very type of reallocation of sunk costs that the Commission has repeatedly
concluded would adversely affect efficient transmission construction decisions. The Application
should be rejected.
b.
ITC constructed the original Bunce Creek PAR and the
Replacement PARs in order to benefit its own ratepayers, and
to satisfy the requirements of the Michigan retail access
statute, and not to provide interregional benefits
As the Commission established in Opinion No. 494, broad cost allocation is not
warranted in circumstances where “existing facilities represent sunk costs that were built
primarily by individual utilities to serve their own internal needs and were financed by those
utilities.”61 It is for this reason that the Commission, in its rejection of the AEP complaint, held
that “[w]ithin the context of RTOs, examining the original basis for making an investment is a
reasonable component of a rate design analysis.”62
A review of the “original basis” for the PARs shows that they were designed and
constructed primarily for the benefit of ITC’s ratepayers and to achieve compliance with
Michigan’s electric retail access statute. The original Bunce Creek PAR was not designed
pursuant to the type of formalized, (inter)regional planning process necessary to justify an
60 As outlined above, the Commission’s decisions regarding the Midwest ISO cost allocations excluded from
postage stamp rates facilities that had not yet been constructed, but that had advanced substantially through the
planning process. See Midwest Independent Transmission System Operator, Inc., 117 FERC ¶ 61,241 at P 96.
61 Opinion No. 494, 119 FERC ¶ 61,063 at P 50.
62 125 FERC ¶ 61,341 at P 41.
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allocation of ITC’s costs to New York ratepayers. ITC conceded this in a pleading it submitted
to the Commission earlier this year.63
The construction of a PAR at Bunce Creek Station was originally proposed by Detroit
Edison - ITC’s predecessor-in-interest - in 2000. In its April 2000 application to amend its
Presidential Permit to allow the construction of the original Bunce Creek PAR, Detroit Edison
explained that the installation of the original Bunce Creek PAR would “provide enhanced control
over the inadvertent power flow between Michigan and Ontario, and by extension, around the
Great Lakes.”64
In December of 2000, the Michigan Public Service Commission (“MPSC”) initiated a
proceeding, requiring electric utilities serving more than 100,000 retail customers in Michigan,
to file a joint plan detailing measures to expand available transmission capability by at least 2000
MW, by June 5, 2002. The MPSC imposed this requirement to comply with Section 10v of
Michigan’s Customer Choice and Electric Reliability Act, 2000 PA 141 (“Section 10v”).65
In the resulting MPSC proceeding, Detroit Edison, and its then-subsidiary, ITC, filed a
Joint Report “detailing the actions required to achieve the 2000 MW expansion, including
identifying the facilities required.”66 The Joint Report identified seven projects that ITC would
63 See Motion for Leave to Answer and Answer of International Transmission Company d/b/a ITC Transmission,
Docket No. ER08-1281-000 (March 1, 2010) at 7 (acknowledging that no formalized planning process existed
“when the PARs were planned”).
64 The Detroit Edison Company, Presidential Permit Order No. P-221 at 2 (April 27, 2000) (“April 2000 Presidential
Permit”).
65 See In the Matter of the application of Indiana Michigan Power Co., d/b/a American Electric Power, for
approvals in connection with 2000 PA 141 Section 10v; In the matter of the application of International
Transmission Company and Great Lakes Energy Cooperative for approvals in Connection with 2000 PA 141
Section 10v, Brief of the Detroit Edison Co. at 1-2, MPSC Docket Nos. U-12780 and U-12781 (filed June 29, 2001)
(“Detroit Edison Brief”); see also, MPSC Docket Nos. U-12780 and U12781, ITC Testimony of T.W. Vitez at 16
(filed March 17, 2001).
66 Id. at 2.
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have to build, in order to meet the requirements of Section 10v.67 One of the projects ITC
identified was the addition of “a 675 MVA Phase Angle Regulator in the B3N interconnection
with Hydro One [i.e., the original Bunce Creek PAR].”68
In the Joint Report, ITC stated that it had installed the original Bunce Creek PAR which
was:
operating in concert with similar phase angle regulators added by Hydro One in
the L4D and L51D interconnections, as well as the existing phase angle regulator
in the J5D interconnection, [and] enables the control of 600-700 MW of parallel
path flow north of Lake Erie (Lake Erie circulation). As this circulating power
was using a significant portion of the International Transmission Company-
Ontario interface, the control of 600-700 MW of circulating power translates into
an increase in the firm commercial capability of that interface. In total, the
Hydro One to MECS path will realize an increase of 820 MW of firm
commercial capability from 2000 to 2002.69 (Emphasis added.)
The Joint Report indicated that ITC was “committed to constructing all of the identified projects”
which were required to comply with Section 10v.70 In a subsequent pleading with the MPSC,
DTE and ITC stated that “adding a 675 MVA phase angle regulator in the B3N interconnection
with Hydro One” was part of the projects “required to be completed on ITC’s system in order to
support the expansion by 2000 MW, of the firm commercial capability into the lower peninsula
of Michigan.”71 In July of 2002, the MPSC issued an order finding that the Joint Report
complied with state law and stated that the proposal “will achieve the required increase in
transmission capacity.”72
67 See MPSC Docket Nos. U-12780 and U12781, ITC Testimony of T.W. Vitez - Exhibit 2 “Joint Report” at 1 (filed
March 17, 2001) (The Joint Report was produced by ITC, along with Consumers Energy Company and Great Lakes
Energy Company) (“Joint Report”).
68 Detroit Edison Brief at 5.
69 Joint Report at 8.
70 Id. at 12.
71 Detroit Edison Brief at 1-2.
72 MPSC Docket Nos. U-12780 and U12781, Opinion and Order (issued July 23, 2002).
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In April of 2001, the Department of Energy issued a Presidential Permit to ITC,73
authorizing the construction of the original Bunce Creek PAR.74 The original Bunce Creek PAR
entered service in 2003, but failed in March of that year.75 Later, in April of 2003, the tower
supporting the Canadian side of the underlying transmission line (the Bunce Creek - Scott line)
collapsed due to inclement weather, causing the line itself to fail.76 In November of 2006, Hydro
One replaced the tower and restrung the Bunce Creek-Scott transmission line.77 In 2009 and
2010, ITC identified the replacement of the original Bunce Creek PAR as a capital project to be
included in ITC’s Attachment O rate - that is, the license plate rate in the Midwest ISO tariff for
recovery of ITC’s transmission costs from ITC’s own customers.78 Replacement of the original
Bunce Creek PAR was also listed in the 2006 Midwest ISO Transmission Expansion Plan as a
project recommended by the Midwest ISO to meet system needs, but not eligible for cost
73 ITC and Detroit Edison had restructured and applied to the DOE to rescind the Presidential Permit granted to
Detroit Edison and concurrently issue a new Presidential Permit to ITC for the same facilities. That request was
authorized on September 26, 2000 in Presidential Permit Order No. PP-230. See April 2001 Presidential Permit at 3.
74 See April 2001 Presidential Permit at 1.
75 International Transmission Company d/b/a ITCTransmission, Request of International Transmission Company
D/B/A ITCTransmission to Amend Presidential Permit at 5, DOE Docket No. PP-230-4 (filed January 5, 2009)
(“January 2009 Presidential Permit Application”); International Transmission Company, Partners in Business
Presentation at 8, Spring 2008 (“Spring 2008 ITC Presentation”).
76 See January 2009 Presidential Permit Application at 5 and Spring 2008 ITC Presentation at 8.
77 See Spring 2008 ITC Presentation at 8.
78 ITC has identified replacement of the original Bunce Creek PAR in its Attachment O presentations as a capital
project. See International Transmission Company, ITC Partners in Business 2009 Attachment O at 9 (listing
Midwest ISO Project ID #1308 - B3N ITC-Hydro One Interconnection (Bunce Creek) as a 2009 Planned Capital
Addition) and International Transmission Company, ITCTransmission 2010 Attachment O at 10. ITC has also
discussed the project in several presentations as a replacement of the original Bunce Creek PAR. See, e.g.,
International Transmission Company, ITC Partners in Business Meeting Presentation at 21 (dated December 13,
2007 (describing it as a project to “Replace the failed B3N phase shifting transformer at Bunce Creek with two
phase shifting transformers to be operated in series. Justification Includes - Replace failed equipment.”); Spring
2008 ITC Presentation at 9 (stating that “[w]ith PARs on 3 of 4 interconnections, it will not be possible to achieve
the goal of flow equal to schedule, particularly when external transactions cause heavy flow conditions. The
interconnection will be operated to control flow to schedule as much as possible. This will be the case for Summer
2008. The B3N transformer will be replaced by two (in series) phase angle regulating transformers which are
expected to be delivered in late 2008 and early 2009. Once operational, the interconnection flow can be optimally
controlled to flow equals scheduled.”).
- 24 -
sharing.79 As the Midwest ISO has established in its Regional Transmission Plan, projects that
are not eligible for cost sharing include those that are “under the threshold for regional cost
sharing, are driven by local area planning criteria … and are therefore not eligible for cost
sharing but should nevertheless be implemented with the costs recovered by the Transmission
Owner within the associated pricing zone.”80
On January 5, 2009, ITC filed an application to amend its Presidential Permit.
Specifically, ITC requested approval to place into service two 700 MVA phase shifting
transformers (the Replacement PARs) to replace the “previously authorized 675-MVA
transformer” (the original Bunce Creek PAR).81 ITC asserted that the original Bunce Creek
PAR’s “purpose was to help provide ‘enhanced control over the inadvertent power flow between
Michigan and Ontario and, by extension, around Lake Erie’, so that ‘under normal operating
conditions … the electrical flow on the Michigan-Ontario interface will match the Michigan-
Ontario scheduled transactions across the interface.’”82 Further, ITC stated that:
[i]n recognition of the failure of the original transformer … ITC chose a
differently designed unit and decided to replace the single failed unit with two
700-MVA units connected in series…. Since the two new transformers will
nominally have 15 degrees more shifting capability than the failed transformer,
they should be capable of providing some increased amount of control over
unscheduled electrical flows when necessary. However, the intended function
of the new units will be the same as the original unit was authorized to
provide in 2001 -- to control unscheduled flows so that actual flow matches
scheduled flow, to the maximum extent possible. In that sense, therefore, the
new units should perhaps best be viewed as replacement facilities providing
an already authorized service, rather than as new facilities providing a new
service.83
(Emphasis added.)
79 See Midwest ISO Transmission Expansion Plan - MTEP06 at 7 (revised February 2007); MTEP06 Appendix A,
Project ID Number 1308 (January 30, 2007).
80 Midwest ISO Transmission Expansion Plan - MTEP06 at 7.
81 January 2009 Presidential Permit Application at 5-6.
82 Id. at 5.
83 Id. at 6.
- 25 -
This history demonstrates that the original Bunce Creek PAR was constructed by Detroit
Edison with the needs of its own ratepayers in mind, and for the purpose of satisfying
Michigan’s electric retail access requirements. ITC’s presidential permit application emphasizes
that the replacement PARs were constructed for the same purposes as the original Bunce Creek
PAR. Thus, like the existing facilities in Opinion No. 494 and in the AEP complaint proceeding,
the Bunce Creek PARs were built for the benefit of ITC’s own ratepayers, and - in spite of any
ancillary benefits that those facilities might have for other areas around Lake Erie - not for the
benefit of the broader region.
c.
The Replacement PARs were not planned and constructed
pursuant to the type of formalized planning process that is a
prerequisite to the type of cost allocation proposed in the
Application
The history of the Replacement PARs outlined above belies the arguments throughout
Mr. Webb’s affidavit that they were somehow constructed pursuant to the type of regional
planning process required to justify the cost allocation that the Applicants now seek. The
specific requirement is that there be a “formal, Commission-approved, regional planning process
where the needs of the region are addressed and where all stakeholders are given an opportunity
to participate.”84 As outlined above, informal discussions or collaborations are not sufficient to
satisfy this criterion. Rather, a proponent of a broad cost allocation must demonstrate that a
formalized, regional planning process was in place at the time that the underlying facilities were
planned, that it considered the needs of the entire region, and that it permitted all affected
stakeholders to have a say over whether and, if so, how the relevant facilities will be constructed.
ITC did not propose to allocate costs associated with the original Bunce Creek PAR to
New York ratepayers. To the extent that the NYISO and New York ratepayers have had any
84 122 FERC ¶ 61,083 at P 99.
- 26 -
discussions with ITC, the Midwest ISO, or any other entity regarding the Replacement PARs,
those discussions have been informal and operational in nature, and have not been part of the
type of formalized, regional planning process that is a prerequisite to the cost allocation sought
by ITC. Neither the NYISO nor New York ratepayers have been brought into, or been permitted
to participate in, the design, planning, or installation process for the Bunce Creek PARs, and
have had no say regarding the nature or amount of the PARs expenditures incurred by ITC.
Furthermore, there has been no formalized process in place to encourage such participation, and
any discussions that the NYISO or New York ratepayers have had with other entities regarding
the original Bunce Creek PAR and the Replacement PARs have been only informal
communications, largely at the operational (as opposed to the planning) level.
This is borne out by the limited documentation that the Applicants cite in support of their
“regional planning” claims - a 1999 MAAC-ECAR-NPCC (MEN) study titled Michigan-
Ontario Phase Angle Regulator Study An Interregional Perspective (the “MEN study”) a joint
PJM-Midwest ISO report, and documentation of the Midwest ISO Board’s approval of the 2006
Midwest ISO Regional Transmission Plan (“MTEP”), which incorporated the Replacement
PARs as an MTEP project. The PJM-Midwest ISO report is not a formalized planning
document. Rather, as its terms make clear, it is a report on the existing status of loop flow
issues, and a description of operational measures being taken by PJM and the Midwest ISO to
address loop flows.85 In any case, the NYISO was not a sponsor of that study. The NYISO did
not participate in the MISO’s MTEP process, and notes that in the MTEP process the
Replacement PARs were not eligible for cost sharing within the Midwest ISO region. The 1999
85 See Investigation of Loop Flows Across Combined Midwest ISO and PJM Footprint, May 25, 2007 at 3-4 (stating
that the purpose of the initiative is “to provide details on plans and actions taken to address the problems of external
common/downloads/20070525-loop-flow-investigation-report.pdf).
- 27 -
MEN study focused on the expected impact of the Ontario/Michigan PARs including the original
Bunce Creek PAR. The MEN study estimated the impact that the operation of the
Ontario/Michigan PARs would have on interregional transfer capabilities and interregional
power flows under a series of operating scenarios. The study did not identify a significant risks
to the reliability of the interconnected system, so long as appropriate emergency procedures for
the Ontario/Michigan PARs operation were in place. The MEN study’s scope did not include
determining or assessing whether the original Bunce Creek PAR was appropriately designed, or
whether it was the best, most cost effective, or the most appropriate facility to construct.
The Application does not identify any formal multi-regional planning process that
resulted in the construction of the Replacement PARs, to which the NYISO was a party. The
Applicants cannot demonstrate that the Replacement PARs were the subject of a regional
planning process that included New York ratepayers. ITC and its predecessors planned and
constructed both the original Bunce Creek PAR and the Replacement PARs before it
commenced its opportunistic pursuit of cost contributions from New York and PJM.
The NYISO’s position that the PARs were not developed pursuant to a regional planning
process is bolstered by the terms and conditions that the Midwest ISO included in a draft set of
Ontario/Michigan PAR Operating Instructions that it submitted to the Department of Energy in
March of 2009. The draft Operating Instructions are included as an attachment to Attachment A
to this Protest. Proposed Sections 5.1(c) and (d) of the attached draft Operating Instructions
assigns a higher priority to relieving local congestion in Michigan and Ontario than to
conforming actual power flows to scheduled power flows at the Ontario/Michigan border.
Proposed Section 7.0 provides that the PAR settings will be determined once each hour “based
on a best estimate of the next hour target flow to meet the agreed upon schedule” and ramped at
- 28 -
the top of the hour. Section 7.0 also provides that the Midwest ISO and IESO will not move the
Ontario/Michigan PARs to correct actual power flows to match scheduled power flows in-hour
(without regard to the extent of the mismatch), unless the fact that the PARs are off schedule
creates a reliability concern, or causes local congestion in Michigan or Ontario.
Proposed Attachment SS that is included in Tab C to the Application is described on
pages 5-6 of Mr. Zwergel’s testimony. Mr. Zwergel explains:
The Midwest ISO has proposed additional Tariff language which states that if the
Midwest ISO determines that the normal operation of the Michigan-Ontario
PARs results in anomalous Midwest ISO market results, the Midwest ISO will
consult with the Midwest ISO's Independent Market Monitor (“IMM”), the
Independent Electricity System Operator (“IESO”) and other relevant Reliability
Coordinators (such as P JM Interconnection, LLC (“PJM”) and the New York
Independent System Operator (“NYISO”)) as appropriate to determine whether
the Midwest ISO should temporarily suspend normal operation of the Michigan-
Ontario PARs. ITC will not be consulted and will not play a role in the Midwest
ISO's determination of whether to suspend normal operation of the Michigan-
Ontario PARs pursuant to Schedule SS-1.
If the Midwest ISO determines that normal operation of the Michigan-Ontario PARs
needs to be suspended, the Midwest ISO will coordinate the change in Interface control
status with the IESO. [Emphasis added.]
Proposed Schedule SS-1 provides that when the Midwest ISO determines that the Midwest ISO’s
market is being adversely impacted by the operation of the PARs, the Midwest ISO will decide if
the operation of the PARs should be suspended, after consulting with the Midwest ISO IMM,
IESO, the NYISO and PJM. Proposed Schedule SS-1 only addresses Midwest ISO market
impact, and leaves ultimate decision-making authority entirely in the hands of the Midwest ISO.
The NYISO was not asked to opine on the one-sided provisions of this proposed rate schedule
(or on the Application, for that matter) before it was submitted to the Commission.
Attachment B to this Protest is the Midwest ISO’s presentation to the NERC IDC
Working Group. It proposes a change to the IDC’s PAR modeling method for the modeling of
- 29 -
the Ontario/Michigan PARs. Under the Midwest ISO’s proposal, the PARs would be treated as
“regulating” without regard to how closely actual power flows conform to scheduled power
flows at the Ontario/Michigan border, so long as all of the four PARs still have additional taps
available (see Slide #6). When the PARs are “regulating” the Midwest ISO proposed that the
Michigan/Ontario interface be modeled as an “open circuit.” In other words, as if the breakers
connecting Michigan and Ontario had been thrown open and the two control areas were no
longer directly interconnected. If this proposal is implemented, it would practically exempt all
transactions scheduled into, out-of or through the Midwest ISO from requests for reliability
curtailments using the NERC Transmission Line Loading Relief (“TLR”) process. The NYISO
would not be able to use the TLR process to remove transactions scheduled through the Midwest
ISO’s Control Area that are creating reliability concerns in New York, not even when actual
power flows at the Ontario/Michigan border diverge significantly from scheduled power flows.
Even when the PARs are not regulating, the Midwest ISO proposed to protect all transactions
scheduled across the Ontario/Michigan interface from possible TLR curtailment without regard
to the transactions’ transmission priority.
Attachment C to this Protest is the NYISO’s presentation to the NERC IDC Working
Group responding to the Midwest ISO presentation included as Attachment B. The NYISO’s
presentation explains a number of significant problems created by the Midwest ISO’s PAR
modeling proposal. The NERC IDC Working Group did not approve the Midwest ISO’s
proposal.
The Applicants have not involved the New York ISO in their efforts to plan and
implement the Ontario/Michigan PARs. Moreover, the documents that the NYISO has attached
to this Protest suggest that the Midwest ISO intends to use its authority to operate the
- 30 -
Ontario/Michigan PARs to benefit customers located within its footprint, not to provide broad
regional benefits.
Just as AEP was unable to satisfy its burden of demonstrating that its existing facilities
were planned and constructed pursuant to a formalized, region-wide planning process, the
Applicants have also failed to demonstrate that the Bunce Creek PARs were planned and
constructed pursuant to a formalized, region-wide planning process. The NYISO submits that
the Applicants have not and cannot identify a multi-region planning process that satisfies the
Commission’s joint planning prerequisite, because no such joint planning process occurred.
There was no process in place for the NYISO or New York ratepayers that are not also,
coincidentally, participants in the Midwest ISO’s markets, to have any say regarding the design,
planning, or construction of the Replacement PARs. In light of these circumstances, there is no
basis under applicable Commission orders for granting the cost allocation proposed in the
Application.
d.
The proposal to allocate the cost of the Replacement PARs to
New York and PJM ratepayers is not consistent with the
method used to allocate the cost of the replacement PARs
within the Midwest ISO region
In the 2006 MTEP, which incorporated the Replacement PARs as a project, the Midwest
ISO Board of Directors did not identify the “B3N Interconnection” Replacement PAR project as
a “Baseline Reliability Project” that was eligible for cost sharing within the Midwest ISO region.
Rather, the Midwest ISO Board determined that the cost of the Replacement PARs was not
eligible for cost sharing and needed to be recovered from customers located in ITC’s traditional
service territory.86 Although the Midwest ISO is proposing to allocate the cost of the
86 See MTEP06 Appendix A, Project ID Number 1308 (January 30, 2007), available on the Midwest ISO’s web site
at:
- 31 -
Replacement PARs to ratepayers in New York, page 16 of the Application indicates that the
Midwest ISO is not proposing to allocate the cost of the Replacement PARs to Midwest ISO
customers located outside the “ITC pricing zone.” Page 9 of Mr. Grover’s Affidavit (Tab G of
the Application) states that costs recovered from PJM and NYISO will be “excluded from the
ITC Transmission Attachment O zonal revenue requirement to prevent double recovery.” This
statement strongly implies that the costs are not being recovered from any other Midwest ISO
zone. In its Application the Midwest ISO seeks permission to recover costs from New York
ratepayers that it is not proposing to recover from ratepayers within its own footprint that reside
outside ITC’s service territory. The Application does not explain why it is appropriate to
narrowly target recovery of the proposed Midwest ISO share of the cost of the Replacement
PARs from only ITC’s customers, but it is appropriate to broadly allocate the cost of the
Replacement PARs to regions outside the Midwest ISO footprint.
e.
The Application does not distinguish its Replacement PARs
from other transmission facilities that provide extra-regional
benefits, the costs of which are recovered through license plate
rates
The Replacement PARs are similar to other existing transmission facilities that provide
benefits across a relatively broad geographic area. As the Commission stated with respect to
AEP’s existing facilities “[w]e do not dispute that some of AEP’s existing facilities provide
benefits outside of their local zone, including for Midwest ISO customers…. this fact by itself
does not establish that the current license-plate rate design for existing facilities is unjust or
unreasonable, nor does it provide justification for reallocating the cost of existing facilities
throughout the combined Midwest ISO/PJM region.”87 Unless the Applicants are able to show
7d000a48324a/MTEP06_Report_020507.pdf?action=download&_property=Attachment
87 122 FERC ¶ 61,083 at P 133.
- 32 -
that the Replacement PARs satisfy the criteria set forth in the Commission decisions outlined
above, the Application does not present a basis for a departure from the license plate rates that
currently apply to the Replacement PARs.
The Application does not distinguish the Replacement PARs from other existing
transmission facilities that provide benefits outside the region in which they are located, but
whose costs are recovered through license plate rates. It is not difficult to identify existing
transmission facilities that provide benefits to neighboring regions. For example, when
generation in Ontario is dispatched to serve load in PJM, the associated transmission service is
ordinarily scheduled through the Midwest ISO and the Midwest ISO is paid to deliver the
scheduled energy to PJM. However, over the past seven years nearly 40% of the power that
suppliers in Ontario have scheduled to flow through the Midwest ISO to sell to PJM, has actually
flowed through New York as unscheduled, “clockwise” loop flow. When this occurs, customers
in the Midwest ISO benefit from their unintended, but uncompensated use of the New York State
Transmission System because the Midwest ISO is paid to provide transmission service that is
actually provided by New York State transmission facilities.
The scenario described above (Ontario generation serving PJM and Midwest ISO loads)
occurred regularly in January of 2010. For the weeks of January 6, 2010 and January 13, 2010
the NYISO’s Day-Ahead modeling assumptions reflected an expectation that average hourly
loop flows would be 600 MW throughout the day. The Day-Ahead loop flow modeling
assumption the NYISO used for the month was never less than 500MW of clockwise loop
- 33 -
flow.88 A driver of this January 2010 clockwise Lake Erie loop flow was the sale of Ontario
generation to PJM and to the Midwest ISO.
The NYISO submits that there is no basis for distinguishing the Replacement PARs from
other existing transmission facilities that are capable of providing benefits outside the region in
which the facilities are located. To avoid the endless litigation that permitting ex post cost
allocation would create, Commission precedent only permits the cost of transmission facilities to
be allocated regionally on a prospective basis, and only when transmission facilities are planned
and developed pursuant to a process that provides all of the entities to which costs will be
allocated an opportunity to participate. The NYISO believes this approach is the correct
approach.
C.
None of the Decisions Cited in the Application Authorize Ex Post Cost
Allocation to Non-Customers
None of the cases cited by the Applicants’ support their proposal to reallocate the sunk
costs of ITC’s Replacement PARs to non-customers that are not located within (or even adjacent
to) the Midwest ISO’s footprint and that were not involved in the planning process that resulted
in the Replacement PARs’ construction. The cases all concern cost sharing under voluntary
agreements, or cost sharing among entities that are voluntarily members of a common Regional
Transmission Operator (“RTO”), Independent System Operator (“ISO”) or other regional
organization.
Ameren Service Co.,89 involved the allocation of certain costs among classes of Midwest
ISO market participants and does not address allocations to non-customers in another region.
That decision found that the Midwest ISO’s currently-effective Revenue Sufficiency Guarantee
88 Lake Erie loop flow information is available on the NYISO’s web site at:
89 125 FERC ¶ 61,161 (2008).
- 34 -
(“RSG”) cost allocation methodology, did not reflect the principles of cost causation because it
did not allocate costs to certain Midwest ISO market participants that were causing the costs.90
Northern Indiana Public Service Co.,91 concerned a voluntarily negotiated agreement for the
allocation of transmission upgrade costs among PJM, the Midwest ISO and certain other market
participants. Also, the Midwest ISO-PJM Joint Operating Agreement is negotiated agreement
entered into voluntarily by the two RTOs.92
The Commission decisions accepting a cost allocation proposal among the members of
the Western System Coordinating Council (“WSCC”)93 are also inapplicable. Those decisions,
which were issued in 1995 before ISOs and RTOs assumed responsibility for regional
planning,94 accepted a cost allocation proposal developed as part of a formalized, organized plan
to address parallel path flow issues. The process resulting in the cost allocation methodology
was one through which all WSCC members had input and through which those members had
attempted to come to a negotiated agreement regarding the cost allocation methodology, but for
which certain outstanding issues had to be resolved by the Commission. The Commission
acknowledged the voluntary nature of the proposal and noted that it “has consistently rejected
unilateral filings by single utilities proposing to impose charges, terms and conditions on a
neighboring utility that, according to the filing utility, is responsible for loop flows” and instead
90 Id. at PP 44, 105 (2008) (stating that “[t]he result of such a cost allocation is that certain market participants are
paying for [RSG] costs caused by other market participants
”) (emphasis added).
91 128 FERC ¶ 61,281 (2009).
92 Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and PJM
Interconnection, L.L.C. (Midwest Independent Transmission System Operator, Inc., Second Revised Rate Schedule
FERC No.5 at Section 9.4.3 (Sheet No. 58); PJM Interconnection, L.L.C. Second Revised Rate Schedule FERC No.
38).
93 The Western Electricity Coordinating Council is the successor to the WSCC “which was formed in 1967 by 40
electric power systems serving all or part of the 14 Western States and British Columbia, Canada”), see
94 Southern California Edison Co., et al., 70 FERC ¶ 61,087 (1995); 73 FERC ¶ 61,219 (1995).
- 35 -
“has required utilities, in the first instance, to work to resolve these highly complex issues among
themselves.”95
Further, the judicial precedent cited by Applicants does not provide a basis on which to
allocate costs to non-customers inter-regionally. The cases cited by the Applicants simply stand
for the well-established proposition that costs should be paid by customers who cause them and
that, in certain circumstances, costs may be allocated to customers who benefit from the
incurrence of costs that they did not cause. In KN Energy v FERC,96 the court found that the
Commission could order cost sharing among a natural gas pipeline’s sales and transportation
customers, even where only the sales customers caused the costs. The decision did not involve
entities that were not customers of the pipeline. Moreover, the court’s approval of cost
allocations to beneficiaries that did not cause them was rooted in the “extraordinary
circumstances” associated with the “take or pay crisis” of the time.97
Applicants’ reliance on Illinois Commerce Commission v. FERC,98 is similarly
misplaced. In that decision, the court denied the Commission’s proposal to allocate costs of
transmission facilities within PJM to certain PJM member entities, on the ground that the
Commission had not made an adequate showing of the benefits that those entities received. The
other decisions cited by Applicants do not support their contentions as they involve costs
allocations among members of an RTO or disputes regarding cost allocation proposals among a
95 Southern California Edison Co., et al., 70 FERC ¶ 61,087 at 61,250.
96 968 F.2d 1295 (D.C. Cir. 1992).
97 See also, American Electric Power Service Corp. v. Midwest Independent Transmission System Operator, Inc.
and PJM Interconnection, LLC, 125 FERC ¶ 61,341 at PP 66-67 (2008) (holding that KN Energy did not support the
reallocation of sunk costs of existing facilities because KN Energy involved “take or pay costs arising from clauses
in gas purchase contracts” that were “distinct” from the sunk costs of existing transmission facilities for which AEP
sought reallocation).
98 576 F.3d 470 (7th Cir. 2009).
- 36 -
transmission provider’s customers.99 There is thus no basis in Commission or judicial precedent
for Applicant’s proposal.
D.
The Cost Allocation Proposed in the Application Is Not Consistent With the
Interregional Cost Allocation Proposal Included In The Transmission
Planning NOPR
In Docket No. RM10-23 the Commission is considering adopting rules addressing cost
allocation for transmission facilities. The Application’s proposal to allocate costs to New York
ratepayers directly contradicts the Commission’s Transmission Planning NOPR. The NOPR
proposes the following rules for allocating the cost of transmission facilities located within a
single transmission planning region:
The allocation method for the cost of an intraregional facility must allocate cost
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.100
The Transmission Planning NOPR proposes the following rules for allocating the cost of
transmission facilities that are located in two or more transmission planning regions:
Costs allocated for an interregional facility must be assigned only to transmission
planning regions in which the facility is located. Costs cannot be assigned
involuntarily under this rule to a transmission planning region in which that
facility is not located.101
Regardless of whether the Replacement PARs are considered an intraregional facility or
(for sake of argument) a component of a multi-regional facility, the cost allocation proposal
99 Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 708 (D.C. Cir. 2000) (finding that a broader
cost sharing was not necessary as departing customers caused stranded costs); Pacific Gas & Elec. Co. v. FERC, 373
F.3d 1315, 1320-21 (D.C. Cir. 2004) (finding that the Commission had not justified the allocation of CalPX wind-up
activities costs based on the size of an entity’s CalPX account balance at a certain date); Midwest ISO Transmission
Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004) (finding that certain Midwest ISO Transmission Owners
were properly allocated Midwest ISO administrative costs); Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009)
(upholding the net energy for load cost methodology for NERC costs); Sithe Independence Power Partners, L.P. v.
FERC, 285 F.3d 1, 4-5 (D.C. Cir. 2002) (finding that rates must be based on a cost-causation principle and the
Commission failed to justify a cost allocation mechanism’s deviation from such principles).
100 Transmission Planning NOPR at P 164(4).
101 Id. at P 174(4).
- 37 -
included in the Commission’s Transmission Planning NOPR would not permit the Applicants to
allocate the cost of the Replacement PARs to New York, absent a voluntary cost sharing
agreement between the two regions. The Replacement PARs are located in Michigan, which is
part of the Midwest ISO’s service territory. The Midwest ISO is a member of both Reliability
First Corporation and the Midwest Reliability Organization. The New York ISO is responsible
for transmission planning in New York State and is a member of the Northeast Power
Coordinating Council, Inc. The New York ISO and Midwest ISO do not share a common
border, they are separated by the Province of Ontario, Canada and PJM. The Commission’s
proposal appropriately rejects efforts to reallocate the cost of transmission facilities to entities
outside the transmission planning region(s) in which the facility is located unless a voluntary
agreement is reached.
The Transmission Planning NOPR is also clear that costs associated with a project that is
not included in a region’s transmission plan “may not be recovered through a transmission
planning region’s cost allocation process.”102 The NYISO was never asked to include the
Replacement PARs in its Comprehensive System Planning Process documents, and the
Replacement PARs are, as would reasonably be expected, not included in any reliability or
economic plans in New York. Applicants should not be allowed to impose the cost of the
Replacement PARs on New York customers when a developer that sought to allocate the costs of
transmission facilities physically located in New York would not be eligible to do so without
first participating in the NYISO’s established planning processes.
102 Transmission Planning NOPR at P 96.
- 38 -
For the reasons explained in this Protest, the NYISO does not believe that it is
appropriate to allocate a portion of the cost of the Replacement PARs, on an ex post basis, to
consumers in New York.
E.
“Benefits” That The Ontario/Michigan PARs Are Expected To Provide to
New York
1.
The Benefit The NYISO Expects Is The Removal Of Unscheduled
Ontario And Midwest ISO Power Flows From The New York State
Transmission System
The Application cites prior NYISO statements regarding expected benefits to New York
at times when the Ontario/Michigan PARs are able to better conform actual power flows to
match scheduled power flows at the Ontario/Michigan border. Given the emphasis that the
Applicants have placed on the NYISO’s statements about benefits, the NYISO considers it
necessary to clearly explain its position. The primary benefit that the NYISO anticipated in its
earlier pleadings was that, when the Ontario/Michigan PARs are able to better conform actual
power flows to scheduled power flows at the Ontario/Michigan border, transmission service that
is scheduled into, out-of or through the Midwest ISO would actually flow over the Midwest
ISO’s transmission facilities, not through New York.
When generation in Ontario is dispatched to serve load in PJM, transmission service is
ordinarily scheduled through the Midwest ISO and the Midwest ISO is paid to transmit the
scheduled energy. However, nearly 40% of the power actually flows through New York as
unscheduled, “clockwise” loop flow, increasing costs to New York customers.103 The benefit
that the NYISO raised in its prior pleadings is the removal of these unscheduled power flows
from the New York State Transmission System. From New York’s perspective, the described
103 When this occurs, customers in the Midwest ISO benefit from their use of the New York State Transmission
System because the Midwest ISO was paid to provide transmission service that was actually provided by New York,
and because the Midwest ISO transmission system is less congested than it should be.
- 39 -
“benefit” is actually the remedy of an existing detriment. The NYISO does not agree that this
type of benefit justifies the Applicants’ proposed allocation of Replacement PAR costs to New
York. New York ratepayers should not be required to pay for ITC and Midwest ISO to
undertake measures to better conform actual power flows to scheduled power flows at the
Ontario/Michigan border.
As discussed in Section III.B.2.e of this Protest, above, the Midwest ISO benefits from its
unscheduled use of elements of the New York State Transmission System. Neither the NYISO
nor New York Transmission Owners have asked the Midwest ISO or its customers to pay for a
portion of the cost of constructing, operating or maintaining elements of the New York State
Transmission System that provide benefits to the Midwest ISO. However, it would be possible
for the NYISO and its Transmission Owners to “cherry pick” elements of the New York State
transmission system that provide benefits to the Midwest ISO and to submit a filing proposing to
allocate a portion of the cost of those facilities to ratepayers in Michigan and other Midwest ISO
states based on the “benefits” that elements of the New York State Transmission System provide.
The NYISO believes that the better option is to follow the Commission’s lead in the
Transmission Planning NOPR and limit cost allocation for extra-regional benefits to new
transmission facilities that are jointly planned to benefit both regions, and that are subject to
voluntary cost allocation agreements.
2.
The Broader Regional Markets Buy-Through of Congestion Solution
Will Enable New York To Charge Scheduling Entities For
Unscheduled Power Flows That Cause Congestion In New York
The proposed Broader Regional Markets Buy-Through of Congestion solution to Lake
Erie loop flow will permit the NYISO to charge entities scheduling transmission service through
the Midwest ISO for the parallel path impacts of their unscheduled flows on the New York State
- 40 -
Transmission System. This Broader Regional Markets solution will help protect New York
loads from congestion costs caused by unscheduled power flows and will provide “insurance”
against TLR-based transaction removal or curtailment to transactions that elect to pay for their
congestion impact on the New York State Transmission System. This proposed market solution
is capable of supplementing, or providing an alternative to the operation of the Ontario/Michigan
PARs.
3.
The Replacement PARs Must Be Operated In Conjunction With The
IESO/Hydro One’s PARs To Better Conform Actual Power Flows To
Scheduled Power Flows At The Ontario/Michigan Border
The Application suggests that the Replacement PARs will provide benefits to New York
and PJM by better conforming actual power flows to scheduled power flows at the
Ontario/Michigan border. However, the Replacement PARs, by themselves, are not capable of
conforming actual power flows to scheduled power flows at the Ontario/Michigan border. There
are four transmission lines interconnecting Michigan and Ontario, three of which have PAR
control devices located in Ontario that have been in place since 2003, or earlier. The
Replacement PARs only affect power flows on one of the four transmission lines that
interconnect Michigan and Ontario. The Replacement PARs must be operated in coordination
with the existing IESO/Hydro One PARs to better conform actual power flows to scheduled
power flows at the Ontario/Michigan Border. The Applicants have not explained why it is
appropriate to charge ratepayers in New York and PJM for “benefits” that PARs that they do not
own or operate, and did not pay for, provide.
4.
The Ontario/Michigan PARs Are Only One Component of the
Solution To Lake Erie Loop Flow
The Application takes liberties in interpreting statements from the NYISO’s prior
pleadings with regard to the benefits that the four ISO/RTO region is expected to receive at times
- 41 -
when all four sets of Ontario/Michigan PARs are in place and operating to better conform actual
power flows to scheduled power flows at the Ontario/Michigan border.104 For example, on page
6 of the Application ITC and MISO state that “there is agreement that the New PARs are the
optimal solution to the Lake Erie loop flow problem…” The Applicants provide no support for
this statement. In fact, the NYISO believes the “optimal solution” is to integrate the operation of
the Ontario/Michigan PARs into the suite of market-based solutions to Lake Erie loop flow that
the Midwest ISO, Independent Electricity System Operator of Ontario (“IESO”), PJM and the
NYISO are working with their stakeholders to develop. The NYISO does not expect the
Ontario/Michigan PARs to “solve” the Lake Erie loop flow problem. The Broader Regional
Market improvements remain a vital component of the solution to Lake Erie loop flow.
IV.
Communications
Communications and correspondence regarding this Protest should be directed to:
Rana Mukerji, Senior Vice President of Market Structures
Robert E. Fernandez, General Counsel
*Robert Pike, Director of Market Design
Raymond Stalter, Director of Regulatory Affairs
*Alex M. Schnell
New York Independent System Operator, Inc.
10 Krey Boulevard
Rensselaer, N.Y. 12144
Tel: (518) 356-8707
Fax: (518) 356-7678
rpike@nyiso.com
aschnell@nyiso.com
*Persons designated for receipt of service.
104 On their own, the Replacement PARs have little impact on Lake Erie loop flow. The Replacement PARs can
only be effective in reducing loop flow if they are operated in conjunction with PARs located in Ontario.
- 42 -
V.
Conclusion
WHEREFORE, for the foregoing reasons, the Commission should reject the Application.
Respectfully submitted,
/s/ Alex M. Schnell
Robert E. Fernandez, General Counsel
Alex M. Schnell
New York Independent System Operator, Inc.
10 Krey Boulevard
Rensselaer, New York 12144
November 17, 2010
- 43 -
Attachment A
Copy of the Midwest ISO’s Comments on ITC’s Request to Amend
Presidential Permit, submitted to the Department of Energy on March
12, 2009 in Docket No. PP-230-4, including as Attachment A thereto the
Midwest ISO’s proposed Operating Instructions for the
Ontario/Michigan PARs
Attachment B
Copy of the Midwest ISO’s October 5, 2010 presentation the NERC
Interchange Distribution Calculator Working Group titled
Modeling MI-ONT PARS in IDC
Presentation 1
10/14/2010
Modeling MI-ONT PARs in IDC
NERC ORS Meeting
September 22, 2010
Regulated Phase Shifters within
MISO
2 Parallel PARs between MH-ONT
WAUE-SPC
MP-ONT
1
10/14/2010
Current Modeling in IDC
MHOH
MPOH
SPWA
Future IDC Model
• MI-ONT Phase Shifters
- Expected to be controlled in Q4 of 2010
- Regulated operation of Interface by setting
phase shifter taps at the beginning of the hour
based on hour ahead forecast
» Objective is to have actual flow equal to scheduled flow
» Conditions can change in real-time and there may be some
circulation flow in real-time
- No intra-hour tap adjustments to address the
circulation flows
2
10/14/2010
Regulated Phase Shifters within
MISO
MH-ONT
WAUE-SPC
MP-ONT
MI-ONT
Changes in IDC Model
• Phase Shifter/Interface Status:
- Currently, IDC allows to set status of each of the 4 PARs
individually
- Change IDC to have a single status (flag) for an Interface that
resets all 4 PARs
• Regulate Mode:
- Tags with “MI-ONT” as POR/POD will 100% flow across the
interface or phase shifters
» Flow over the 4 PARs that form the interface will be based on the
pre-determined percentages and will not be updated over time
except during outage of one or more segments of PARs.
» Pseudo CAs will be used to determine impact on other FGs
- Tags not using “MI-ONT” as POR/POD and Market Flows (GTL)
will flow across the rest of the network (open circuit)
3
10/14/2010
Changes in IDC Model
• Non-Regulate Mode:
- Equivalent to max tap/min tap position
- Non-regulate status for each of the four PARs (Interface)
» One PAR will hit a max/min tap position while the other 3 will still have tap
range available (minimize the circul ation flow between the four PARs)
- Tags with “MI-ONT” as POR/POD will 100% flow across
the interface or phase shifters
- Tags not using “MI-ONT” as POR/POD and Market Flows
(GTL) will have some portion across the interface and the
remainder on the rest of the network (free flowing)
» Based on the impedance of PARs relative to the rest of the system
• By-Pass Mode:
- PARs are on neutral tap and not regulating
Examples
4
10/14/2010
Example for Regulating Mode
E-Tags:
1) MISO/NYIS; ALTE/MI-ONT (Source/Sink;
POR/POD)
2) MISO/NYIS; CIN/PJM (Source/Sink; POR/POD)
NYIS
ONT
ONT-MI
MI-ONT
ALTE
PJM
CIN
Example for Regulating Mode
(contd.)
• E-Tag 1 will be seen by IDC as flowing over Michigan-
Ontario phase shifters or Interface FG # 9084
• IDC will use pseudo CAs “MI-ONT” and “ONT-MI” to
calculate impact of E-Tag 1 on all FGs except Interface
FGs # 9084 and 9159
• IDC will calculate impact of E-Tag 2 on all the FGs as if
Michigan-Ontario Interface is open circuit
• MISO/PJM will calculate Market Flows by modeling
Michigan-Ontario Interface as open-circuit
- MISO/PJM Market Flows on IESO and NYIS FGs would be 0
5
10/14/2010
Example for Regulating Mode
(contd.)
• For TLR on FGs # 9084 and 9159 (very unlikely while in
Regulating Mode)
» E-Tag 1 will have 100% (or -100%) impact on the interface
flowgates
» All other Tags will have 0 % impact on the interface flowgates
• For TLR on any other flowgate in the system, IDC will
assume the interface is an open circuit and calculate
impacts of E-Tags and Market Flows (GTL) on the
congested flowgate accordingly
» E-Tag 1 using Pseudo CAs
» E-Tag 2 and Market Flows as if interface is an open circuit
Example for Non-Regulating Mode
E-Tags:
1) MISO/NYIS; ALTE/MI-ONT (Source/Sink; POR/POD)
2) MISO/NYIS; CIN/PJM (Source/Sink; POR/POD)
NYIS
ONT
ONT-MI
MI-ONT
ALTE
PJM
CIN
6
10/14/2010
Example for Non-Regulating Mode
(contd.)
• E-Tag 1 will be seen by IDC as flowing over Michigan-Ontario
phase shifters or Interface FG # 9084
• IDC will use pseudo CAs “MI-ONT” and “ONT-MI” to calculate
impact of E-Tag 1 on all FGs except Interface FGs # 9084
and 9159
» E-Tag 1 will have 100% impact on Interface FGs # 9084 and 9159
• IDC will calculate impact of E-Tag 2 on all the FGs as if
Michigan-Ontario Interface is free flowing
» Portion of E-Tag 2 will flow through the Interface and remaining will flow
through the rest of the network depending on impedance of PARs relative to
the AC system
• MISO/PJM will calculate Market Flows by modeling PARs at
max tap or min tap, where a portion will go through the
Interface and remaining through the rest of the network
Example for Non-Regulating Mode
(contd.)
• For TLR on FGs # 9084 or 9159, IDC will assume 100% of
impact from E-tag 1 on the congested flowgate and portion of
all other E-Tags and market flow through the interface
• For TLR on any other flowgate in the system, IDC will assume
the interface is a free flowing system and calculate impacts of
E-Tags and Market Flows (GTL) on the congested flowgate
accordingly
» E-Tag 1 using Pseudo CAs
» E-Tag 2 and Market Flows as if interface is free flowing
7
10/14/2010
Benefits of PAR Operations
• Assume PARs have ability to push back a maximum of
600 MW of parallel flow on the interface when fully
regulating.
• The following two scenarios demonstrate the ability of
the PARs to push back 600 MW when in regulate mode
and when in non-regulate mode:
Scenario 1-PARs in Regulate Mode
• Scheduled flow across interface
600 MW
• Potential parallel flows across interface
600 MW
• Potential total flow across interface (if not reg) 1200 MW
• Source of parallel flows:
- Tag impacts
300 MW
– Market flow impacts
300 MW
• PARs are in regulate mode pushing back 600 MW.
Actual flow across interface is 600 MW.
Scenario 1- Actual Interface Flow
ONT
MI
Actual Flow = 600 MW
8
10/14/2010
Scenario 1-IDC Modeled Interface Flow
MI-ONT
ONT-MI
ONT
Pseudo BA Flow = 600 MW
MI
Impedance Flow = 0 MW
Benefits of PAR Operations cont.
• IDC shows 100% of the 600 MW flowing across the
interface. Remaining tag impacts and market flow
impacts see this as an open interface.
• If TLR called, would have 600 MW impacts across the
interface based on pseudo BAs. The remaining 600 MW
of potential parallel flows at 0 MW (see an open
interface).
• If call TLR on an IESO or NYISO flowgate, MISO and
PJM market flows appear to be 0 MW and tag impacts
(other than the 600 MW) appear to be 0 MW.
9
10/14/2010
Benefits of PAR Operations cont.
Scenario 2-PARs in Non-Regulate Mode
• Scheduled flow across interface
600 MW
• Potential parallel flows across interface
625 MW
• Potential total flow across interface (if not reg) 1225 MW
• Source of parallel flows:
- Tag impacts
300 MW
– Market flow impacts
325 MW
• PARs are now in non-regulate mode but continue to
push back 600 MW. Actual flow across interface is 625
MW.
• IDC shows 100% of the 600 MW flowing across the
interface. The remaining tag impacts and market flow
impacts see this as a free flowing system based on the
impedance of the interface relative to the impedance of
the remainder of the AC system.
Scenario 2- Actual Interface Flow
ONT
MI
Actual Flow = 625 MW
10
10/14/2010
Scenario 2-IDC Modeled Interface Flow
ONT
MI-ONT
ONT-MI
Pseudo BA Flow = 600 MW
MI
Impedance Flow = 625 MW
Benefits of PAR Operations cont.
• A question has been raised on who should get the
benefits of the PARs pushing back 600 MW when fully
regulating (this is the difference between the actual
parallel flow and the IDC parallel flow when PARs has
status of non-regulate).
- In Scenario 2, the 600 MW of benefits are not being
assigned to anyone. This is why we see the large
difference between actual parallel flow and IDC parallel
flow.
- An alternate approach would assign the 600 MW of
benefit to the parties responsible for the PARs (IESO &
MISO). This alternative would remove up to 600 MW of
MISO market flows and IESO GTL flows from inclusion
in impacts subject to TLR curtailments. Since MISO is
recommending regional cost sharing of the PARs, this
alternative is not being pursued.
11
10/14/2010
Benefits of PAR Operations cont.
• Another question has been raised whether the 600 MW
scheduled across the interface should continue to
assume 100% flows across the interface when PAR is
fully regulating (PAR has status of non-regulate). The
current design of the IDC removes the pseudo BA
treatment and has the entire 600 MW use a response
factor based on the impedance of the interface relative to
the rest of the AC network to set the flow across the
interface. We have the following response to this
question:
- We agree this is the acceptable when the PAR status is
by-pass. This is effectively how the interface is operated
today.
- We do not agree it is acceptable when the PAR status is
non-regulate. The PARs continue to regulate at max tap
such that the actual flow consists of scheduled flow plus
some component of parallel flow
Benefits of PAR Operations cont.
- The schedules across the interface are from
reservations for transmission service purchased across
the interface as opposed to parallel flows from third
parties that have no rights on the interface.
- If the schedules across the interface were to get
combined with the rest of the tags and market flows,
these flows would go from 0 MW to 1081 MW (assuming
the impedance causes 80% of the scheduled flow to go
across the interface) after 1 MW of parallel flow appears
on the interface. This will cause volatility issues in the
IDC where all schedules get cut and all schedules are
reloaded when there is a 1 MW swing in parallel flows.
12
10/14/2010
Benefits of PAR Operations cont.
• Under this proposed treatment, all of the potential
parallel flows now appear as if flowing across the
interface. Although actual flows only increased 25 MW,
the IDC now shows 600 MW of scheduled flows across
the interface plus 625 MW of parallel flows across the
interface.
• If call TLR on an IESO or NYISO flowgate, MISO and
PJM market flow impacts appear to be 325 MW and tag
impacts (other than the 600 MW) appear to be 300 MW.
• Even though the actual flow across the interface only
increased 25 MW, the IDC shows the full amount of
parallel flows (625 MW) available to manage congestion
on IESO and NYISO flowgates.
Modeling MI-ONT PARs in IDC
Questions?
26
13
Attachment C
Copy of the NYISO’s October 5, 2010 presentation to the NERC
Interchange Distribution Calculator Working Group titled
Modeling MI-ONT PARS in IDC
Presentation 2
Modeling
MI-ONT PARs in IDC
IDC Working Group
Oct 5-7
David Mahlmann
Draft for Discussion
Draft for Discussion
Concerns with MISOs Proposal
NYISO cannot support the MISO proposal because it
Proposes to inflexibly pre-determine how system reliability
can be protected, that cannot and will not account for real-
time system conditions
Gives both firm and non-firm transactions scheduled at the
OH/MI interface an absolute priority over all other transactions
and GTL impacts, even when the PARs are not adequately
maintaining scheduled flow
Could adversely affect system reliability
MISO’s presentation explicitly recognizes that
implementing the method it proposes will result in
uncorrected Lake Erie circulation, but ignores the
potential reliability impact
2
1
Concerns with MISOs Proposal
The proposal will permit circulation that cannot be corrected
when MISO determines the PAR settings and declares the PARs
to be regulating at the top of the hour, even when
The PAR schedule that is determined for the hour fails to accurately
match flow to schedules over the interface
Real-time events like line outages, significant generator outages, or
dispatch/load variations occur
MISO-PJM implement significant quarter-hour transaction changes
A“counterflow”transactionthatwasprojectedtoprovidecounter
pressure when the fixed angle phase shift was calculated is removed
or curtailed
TLR actions that impact relative power angles across the
Interconnection are taken, causing flow across the fixed angle phase
shifters
3
Draft for Discussion
Issues with the MISO Proposal
Even when the top-of-the-hour determination
recognizes that the PARs are not regulating
MISO proposes to give both firm and non-firm transactions
scheduled at the OH/MI interface an absolute priority over all
other transactions and GTL impacts (they will not be available
in the IDC for removal/curtailment)
For example when the PARs are not regulating, NYISO will be
able to use the TLR process to remove firm MISO GTL
service, or MISO to PJM transactions to address a New York
constraint, but will have no ability to remove non-firm
transactions scheduled over the OH/MI interface
• Not even when the non-firm transaction has a larger impact on
the New York constraint than the firm GTL
• Non-firm transmission service over the OH/MI interface will be
more “firm” than firm transmission service that does not cross the
interface
4
2
Draft for Discussion
Reliability Risk Example
OH/MI PAR scheduled fixed for the hour and the PARs are
determined to be “regulating”
Top of hour
1000 MW actual
1000 MW Sched
+ 10 min
1000 MW actual
1000 MW Sched
+ 20 min
0 MW actual
1000 MW Sched
+ 30 min
-500 MW actual
1000 MW Sched
1500 MW change in actual flow since the top of the hour,
PARs are fixed and will not be moved to address subsequent
changes in system conditions
NYISO has no ability to TLR when PARs are declared
“regulating”
The NYISO requires the ability to apply TLR to all transactions
to preserve system reliability when circulation is observed
5
Draft for Discussion
NYISO Proposal – 2 Stage TLR 9
(1of2)
•
NYISO proposes to protect transactions scheduled over the
OH/MI PARs when transaction flows conform to schedules (plus
an agreed upon bandwidth), but to permit TLR actions to
remove unscheduled flows
•
Method of determining when PARs are not controlling should be
changed from a “taps at limit” flag to a “flow outside schedule
plus allowed bandwidth” flag.
6
3
Draft for Discussion
NYISO Proposal – 2 Stage TLR 9
(2of2)
A the time the TLR is initiated, and throughout the TLR process,
the IESO-MICH projected flows should be compared to the IESO-
MICH projected schedule
Whenever the IESO-MICH projected flows are outside the
schedule plus an agreed-upon bandwidth, ONT-MI PARs
modeled as non-controlling and all tr ansactions will be subject to
curtailment, as they are today
with the additional monitoring of the cumulative effect of the
curtailments on the IESO-MICH projected flows described below
If the requested relief has not been met when the projected IESO-
MICH flows are brought back within schedule plus bandwidth,
then
Pause the continued TLR computations,
Re-compute the shifts with ONT-MI PARs modeled as controlling
Continue the TLR calculations with the new shift factor until the
necessary relief is obtained
7
Draft for Discussion
Advantages of NYISO Proposal
Promotes system reliability with t ools to control circulation over a
wide range of system conditions
Provides uniform open access treatment when the MI-ONT flows
are uncontrolled, i.e. when portions of MI-ONT transactions are
circulating outside the ties.
Conforms with the intention to operate PARs once an hour
Shields MISO-IESO transactions from TLR curtailments when the
interface flow is on schedule.
8
4
The New York Independent System Operator (NYISO) is a not-for-profit
corporation that began operations in 1999. The NYISO operates New York’s
bulk electricity grid, administers the st ate’s wholesale electricity markets, and
provides comprehensive reliability planning for state’s bulk electricity system.
__________________________________________________________
5
CERTIFICATE OF SERVICE
I hereby certify that I have this day served the foregoing documents upon each person
designated on the official service list for the captioned proceeding, in accordance with Rule 2010
of the Commission's Rules of Practice and Procedure (18 C.F.R. § 385.2010).
Dated this 17th day of November, 2010, at Rensselaer, New York.
/s/ Alex M. Schnell
Alex M. Schnell
New York Independent System Operator, Inc.
10 Krey Boulevard
Rensselaer, New York 12144
Ph: 518-356-8707
