NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.

Alex M. Schnell

James H. Sweeney

New York Independent System Operator,
Inc.

10 Krey Boulevard

Rensselaer, NY 12144 (518) 356-6000

aschnell@nyiso.com
jsweeney@nyiso.com

Howard H. Shafferman Daniel R. Simon

Jack N. Semrani
Ballard Spahr LLP

1909 K Street, NW, 12th Floor Washington, DC 20006
(202) 661-2200

hhs@ballardspahr.com

simond@ballardspahr.com
semranij@ballardspahr.com

Attorneys for New York Independent System Operator, Inc.

October 16, 2012

DMEAST #15738748 v8

TABLE OF CONTENTS

Page

STATEMENT OF THE CASE....................................................1

THRESHOLD ISSUES........................................................17

I.Whether the Federal Power Act (“FPA”) and applicable Commission policies

thereunder permit the Midwest Independent Transmission System Operator, Inc. (“MISO”)

and the International Transmission Company d/b/a ITCTransmission (“ITC”) to make, and

the Commission to approve, the October 20, 2010 filing (as amended on January 31,

2012)?......................................................................17

A.Section 205 Filings Must Be Premised on a Customer or Other Contractual

Relationship with the Entities to Which the Rate Will Be Charged..............17

B.None of the Cases Cited by Joint Applicants Provide Any Basis for Assessing Costs to

the NYISO or its Customers............................................23

C.The Joint Application Violates the Commission’s Cost Allocation Policies That

Preceded Those Reflected in Order No. 1000...............................28

D.The Joint Application Is Deficient Under the Commission’s Regulations.........29

II.Whether the Joint Operating Agreement between MISO and PJM Interconnection,

L.L.C. (“PJM”) precludes allocation of costs associated with the ITC PARs to PJM?........30

III. Whether there are any other customer or contractual relationships or interregional

plans, or lack thereof, that are relevant to the proposed cost allocation?...................32

A.There Is No Customer or Contractual Relationship Between the NYISO or the

NYISO’s Customers and MISO or ITC...................................32

B.The Original PAR and the Replacement PARs Were Built Pursuant to Pre-Existing

Contract Obligations, and to Serve the Transactional/Economic Interests of Michigan

and Ontario Utilities and their Electricity Customers.........................34

1.The Original PAR and the Replacement PARs Were Built Pursuant to Pre-Existing

Contract Obligations..................................................34

2.The Original PAR and the Replacement PARs Were Built to Serve the

Transactional/Economic Interests of Michigan and Ontario Utilities and their

Electricity Customers.................................................36

C.The MISO-IESO Operating Instruction Permits MISO and IESO to Favor Their Own

Customers and Interests, Over the NYISO’s and PJM’s Customers and Interests...43

D.Neither the Original PAR nor the Replacement PARs Were Planned Jointly with

NYISO and PJM.....................................................44

RATE ISSUES...............................................................47

IV. Whether the allocation of the costs of the ITC PARs to NYISO and PJM, and the level

of such allocations, is just, reasonable and not unduly discriminatory or preferential under

the Federal Power Act and the applicable Commission policies, orders and precedent

DMEAST #15738748 v8i

thereunder (including but not limited to the policies, if applicable, contained in Order No.

1000)?......................................................................47

A.Acceptance of the Joint Application’s Proposal to Charge NYISO and PJM Would

Violate Applicable Commission Precedent.................................47

1.Introduction to Postage Stamp and License Plate Rate Terminology, and the Difference

Between “Zones” and “Regions”........................................47

2.Even For Cost Allocation Within A Single ISO/RTO Region, The Commission Has

Placed Strict Limits on Cost Sharing.....................................49

3.The Application Does Not Demonstrate That the Prerequisites to the Adoption of

Regional Cost Sharing for the Replacement PARs are Satisfied................62

B.Acceptance of the Joint Application’s Proposal to Charge NYISO and PJM Would

Violate the Policies Expressed in Order Nos. 1000 and 1000-A................67

C.The Joint Application Improperly Shifts Costs Caused by IESO and Its Customers to

NYISO and PJM, Resulting in Undue Discrimination........................69

D.It Is Not Just and Reasonable, and Is Unduly Discriminatory, to Charge NYISO and its

Customers for the Costs of the Replacement PARs When MISO Customers Outside

the ITC Zone Are Not Being Charged....................................74

E.The MISO-IESO Operating Instruction and MISO Tariff Provide Undue Operating

Preferences to MISO, IESO and Their Customers...........................77

1.The Operating Instruction..............................................77

2.Attachment SS-1.....................................................80

3.Proposal to continue charging NYISO and PJM while MI/ON PAR operations are

suspended..........................................................82

F.NYISO and PJM and Their Customers Were Not Given the Opportunity to Participate

in Deciding Whether to Construct the PARs or Whether to Pursue Other Options In

Relation to Lake Erie Loop Flow........................................82

V. Whether any allocation of costs of the ITC PARs to NYISO and PJM and their

customers (or others) is appropriate based on cost causation/incurrence and/or beneficiary
pays principles or on other considerations, and if so, is the proposed cost allocation roughly
commensurate with (a) the extent to which NYISO and PJM and their customers (or MISO,
IESO or others) caused ITC to incur the costs of the installation and operation of the ITC
PARs (and, to the extent relevant, the reasons for which Detroit Edison/ITC incurred costs
for installation of the original PAR); and/or (b) the extent to which NYISO and PJM and
their customers (or MISO, IESO or others) will benefit from (or be harmed by) the

installation and operation of the ITC PARs?........................................83

A.MISO Has Stated that the Replacement PARs Are a Reliability Project and, As Such,

Must be Allocated Based On Cost Causation, Not Potential Benefits............84

B.Even if Benefits Were Deemed Relevant for the Cost Allocation, MISO and ITC Have

Not Submitted Evidence Demonstrating that New York Customers Receive Any

Benefit from the Operation of the Replacement PARs........................84

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C.To the Extent that Benefits are Relevant, Control by the MI/ON PARs of

Counterclockwise Loop Flow Does Not Benefit, and May Harm, NYISO and Its

Customers..........................................................86

D.ITC and Its Customers Obtain Transactional and Reliability Benefits That Have Not

Been Accounted For in the Joint Application, and That Are Not Available to NYISO

or PJM Customers....................................................88

1.Transactional Benefits.................................................88

2.Reliability Benefits...................................................89

E.The MI/ON PARs Do Not Provide Unique Benefits Justifying Allocation of the Costs

of the Replacement PARs to NYISO and PJM..............................91

F.It Would Not Be Appropriate to Allocate Costs of the Replacement PARs to the

NYISO or its Customers Based on Cost Causation Principles.................101

VI. What is the extent of the contributions to loop flows of MISO, IESO, NYISO and PJM

and others, and do they represent a basis for MISO/ITC to allocate the costs of the ITC

PARs to PJM and NYISO?.....................................................105

A.MISO and ITC Have Not Presented Evidence of the NYISO’s Actual Contribution to

Lake Erie Loop Flow.................................................105

B.It is Unjust and Unreasonable, and Unduly Discriminatory, to Require NYISO and Its

Customers to Pay for a Share of Replacement PARs Costs that Are “Caused” by IESO

.................................................................................................................................... 106

VII. Whether the MISO/ITC DFAX study provides an adequate basis for the proposed cost

allocation?..................................................................106

A.The DFAX Analysis Is Fundamentally Flawed.............................106

1.MISO’s DFAX Analysis Should Have Included All 8,760 Hours of the Year.....106

2.MISO’s DFAX Should Have Used the Load Duration Curve for each RTO, Instead of

Using a Single, Aggregate Load Duration Curve...........................110

3.Contributions to Flows over the Four Circuits that Comprise the MI/ON Interface

Should Not be Netted Against Each Other when Determining an ISO or RTO’s

Contribution to the MI/ON Interface Flows...............................113

4.DFAX Analysis Does Not Consider the Economics of Dispatch...............116

5.The DFAX Analysis Should Have Associated Cost Allocation with Flow Participation

Solely on the B3N Circuit.............................................119

6.Cumulative Impact on DFAX Analysis of Only Considering Flows Over the B3N

Circuit and Using Each RTO’s Load Duration Curve.......................121

7.Other Regional Contributors to Lake Erie Loop Flow.......................122

B.The DFAX Analysis and Associated Cost Allocation Proposal Were Developed in a

Result-Oriented Fashion that Should Be Rejected..........................123

MISCELLANEOUS ISSUES...................................................125

VIII.Whether the filing creates a service obligation of MISO and ITC to NYISO or PJM or

their customers and, if so, what is the nature of the obligation?.........................125

IX. Whether and to what extent will the PARs control Lake Erie loop flow, including
whether, if any of the ITC PARs (or the Hydro One PARs) are unavailable, bypassed, or
not being operated in a manner that is consistent with the Presidential Permit issued to ITC
by the Department of Energy, NYISO or PJM or their customers nonetheless should be

required to pay the charges at issue in this proceeding?...............................127

A.MISO’s and ITC’s Claim that the MI/ON PARs Will Remove 600 MW of Loop Flow

(Almost) All the Time is Vastly Overstated...............................127

1.MISO’s and ITC’s Claimed Operating Effectiveness Ignores the Fact that the MI/ON

PARs are Operated to Achieve a +/-200MW Control Band...................130

2.The Joint Applicants’ Expectations Regarding MI/ON PAR Operating Effectiveness

Do Not Account for PAR Outages......................................132

B.The MI/ON PARs Are Not Providing the Loop Flow Control Promised in the Joint

Application........................................................134

1.Wes Yeomans’ Direct Testimony.......................................134

2.Introduction to Exhibit NYI-66.........................................134

3.Review of MISO’s Exhibit NYI-66 Data—Tabulation of Operating Data Covering

April 5, 2012 to July 18, 2012..........................................137

4.Interpretation of Exhibit NYI-66 Data for Specific Operating Days.............141

5.Response to Joint Applicants’ Argument that the Operation of the PARs from April 5,

2012 to July 18, 2012 is Not Indicative of Expected Future Efficacy...........144

C.MISO’s and IESO’s Failure to Timely Set the “Regulated/Non-Regulated” Flag in the

NERC Interchange Distribution Calculator Can Delay or Prevent NYISO’s Ability to

Use TLR to Resolve Reliability Issues at Times When the MI/ON PARs Are Not

Successfully Mitigating Unscheduled Power Flows.........................147

D.The MI/ON PARs Outage History, Including Recent Problems with Hydro One’s L4D

PAR..............................................................150

E.ITC and MISO Have Indicated a Lack of Commitment to Operate the MI/ON PARs In

the Manner Called For in the Operating Instruction and in Representations to the DOE
.................................................................................................................................... 153

X. Whether, if the costs of the ITC PARs are allocated to PJM, the cost responsibility
assigned to PJM by MISO’s January 2012 testimony, which increases PJM’s allocation

above the amount allocated by the Joint Application, may be imposed on PJM?...........154

XI. Whether, if the costs of the ITC PARs are allocated to PJM or NYISO, PJM or

NYISO is responsible (respectively) for paying MISO in the case of a PJM or NYISO

customer’s failure to pay PARs-related charges?....................................155

XII. CONCLUSION..........................................................155

APPENDIX: STATEMENT OF CASE, AND PROPOSED FINDINGS OF FACT AND CONCLUSIONS OF LAW

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TABLE OF AUTHORITIES

Page(s)

FEDERAL CASES

Ameren Servs. Co. v. Midwest Indep. Transmission Sys. Operator, Inc.

121 FERC ¶ 61,205 (2007) (“Ameren”).........................................71

Ameren Servs. Co. v. Midwest Indep. Transmission Sys. Operator, Inc., 125 FERC

¶ 61,162 (2008)............................................................71

American Electric Power Service Corp. v. Midwest Independent Transmission System

Operator, Inc., et al., 49 FERC ¶ 61,377 (“AEP I”), (1986).........................27

American Electric Power Service Corp. v. Midwest Independent Transmission System

Operator, Inc., et al., 122 FERC ¶ 61,083 (2008) ("AEP II")... 52, 53, 54, 56, 61, 62, 64, 69

Bonneville Power Administration,

112 FERC ¶ 61,012 (2005)...................................................49

Cleco Power LLC, et al.,

103 FERC ¶ 61,272 (2003)...................................................49

Cleveland v. Federal Power Comm'n,

525 F.2d 845 (D.C. Cir. 1976)................................................19

Commonwealth Edison Co.,

129 FERC ¶ 61,298 (2009), order on reh’g, 132 FERC ¶ 61,268 (2010)............21, 22

Cranberry Pipeline Corp.,

112 FERC ¶ 61,268 (2005)...................................................29

FPC v. Sierra Pac. Power Co.,

350 U.S. 348, 76 S. Ct. 368, 100 L. Ed. 388 (1956)................................19

Illinois Commerce Commission v. Federal Energy Regulatory Commission, 576 F.3d 470

(7th Cir. 2009) (“ICC”)...................................................26, 27

In re Permian Basin Area Rate Cases,

390 U.S. 747 (1968)...............................................18, 19, 21, 28

Indiana Michigan Power Co. and Ohio Power Co.,

64 FERC ¶ 61,184 (1993)....................................................25

ITC Holdings Corp., et al.,

102 FERC ¶ 61,182 (2003)...................................................29

Midwest Independent Transmission System Operator, Inc.,

114 FERC ¶ 61,106, order on reh’g., 117 FERC ¶ 61,241 (2006).....................48

Midwest Independent Transmission System Operator, Inc.,

117 FERC ¶ 61,241 (2006) (“MISO”)....................................58, 59, 62

Midwest Independent Transmission System Operator, Inc.,

Order on Initial Decision, 131 FERC ¶ 61,173 (2010) (“Green Mountain”)....... 19, 21, 27

Midwest ISO Transmission Owners v. Federal Energy Regulatory Commission, 373 F.3d

1361 (D.C. Cir. 2004) (“MISO TOs”)...........................................26

Midwest Independent Transmission System Operator, Inc. v. PJM Interconnection, L.L.C.

135 FERC ¶ 61,243 (2011)...................................................81

Morgan Stanley Capital Group, Inc. v. Public Utility District No. 1 of Snohomish County,

Washington, 554 U.S. 527 (2008) (“Morgan Stanley”).............................28

New York Independent System Operator, Inc.,

124 FERC ¶ 61,174 (2008)...................................................38

New York Independent System Operator, Inc.,

125 FERC ¶ 61,184 (2008)...................................................38

Northern Indiana Public Service Co.,

128 FERC ¶ 61,281 (2009)................................................24, 25

PJM Interconnection, L.L.C.,

96 FERC ¶ 61,060 (2001)....................................................49

Richmond Power & Light v. FPC,

156 U.S. App. D.C. 315, 481 F.2d 490, cert. denied, 414 U.S. 1068, 94 S. Ct. 578, 38

L. Ed. 2d 473 (1973)........................................................19

Southern California Edison Company,

70 FERC ¶ 61,087 (1995), subsequent order approving loop flow plan, 73 FERC ¶

61,219 (1995) (“WSCC”)....................................................23

Southwest Power Pool, Inc.,

111 FERC ¶ 61,118 (2005)...................................................49

OTHER CASES

New York Independent System Operator, Inc. v. Federal Energy Regulatory Commission,

Case No. 12-1293 (2012)....................................................18

FEDERAL STATUTES

§ 205 of the Federal Power Act.........................................17, 22, 23, 27

§ 206 of the Federal Power Act..................................................22

REGULATIONS

18 C.F.R. § 35.5 (2012)............................3, 4, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16

Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided

by Public Utilities Under the Federal Power Act, 59 Fed. Reg. 55031 (November 3,

1994)....................................................................24

Opinion No. 494.............................48, 49, 50, 51, 55, 56, 57, 58, 61, 62, 63, 69

Opinion No. 494-A............................................................48

Order No. 1000..................................4, 18, 21, 26, 29, 31, 47, 65, 67, 68, 69

Order No. 1000-A...........................................18, 21, 27, 28, 65, 67, 68

Order No. 2000...............................................................48

Order No. 2000-A.............................................................48

Transmission Planning and Cost Allocation by Transmission Owners and Operating

Public Utilities, Notice of Proposed Rulemaking, 75 Fed. Reg. 37884 (2010)

(“Transmission NOPR”).....................................................67

OTHER AUTHORITIES

In the matter of the Commission's own motion, to consider the restructuring of the

electric utility industry,Case No. U-11290, Michigan Public Service Comm’n, 1997

Mich. PSC LEXIS 171; 177 P.U.R.4th 201(1997).................................41

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viii

NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.

To: Honorable Steven L. Sterner

Presiding Administrative Law Judge

The New York Independent System Operator, Inc. (“NYISO”) hereby submits its initial
brief. The brief is organized in the manner specified in the Joint Statement of Issues filed in this
proceeding.

STATEMENT OF THE CASE1

1.Introduction

The Joint Application presents an unprecedented, unsupported and unsupportable attempt by a transmission owner (ITCTransmission or “ITC”) and its regional transmission organization (the Midwest Independent Transmission System Operator, Inc. or “MISO”) to charge New York and PJM customers millions of dollars each year for phase angle regulators (“PARs”) built in Michigan by the transmission owner.

The newly constructed facilities (the “Replacement PARs”) replace a PAR that was

constructed in 2002 by ITC’s predecessor in interest, Detroit Edison (the “Original PAR”). The
Original PAR became an ITC asset, then failed and burned up in March 2003. Detroit Edison or
ITC had never asked or proposed that NYISO or PJM share in the cost of the Original PAR.
Within MISO, the costs of the Original PAR would have been allocated solely to Detroit

1 Proposed findings of fact and conclusions of law are provided in the Appendix to this initial brief.

Edison’s local transmission customers, but were never collected due to the failure of that asset. When the Replacement PARs were approved within MISO’s regional planning process, their costs were again allocated solely to the ITC zone within MISO, on the basis that the PARs were simply a replacement of existing facilities. By contrast, the costs of baseline reliability projects approved in the MISO regional planning process are spread across all zones.2

Despite the narrow allocation of costs of the Replacement PARs within MISO, MISO and
ITC now propose in the Joint Application to spread these costs outside MISO, to PJM and
NYISO. NYISO is not directly interconnected with MISO. Neither NYISO nor PJM consented
to these charges, and NYISO and PJM did not participate in the planning of, or the decision to
build or design, the Replacement PARs (or the Original PAR). NYISO and PJM had no
opportunity to consider alternatives to the ITC facilities. NYISO and PJM were not parties to the
1998 and 2007 agreements pursuant to which Detroit Edison and ITC committed to Canadian
utilities to build the Original PAR and the Replacement PARs, respectively, at their own
expense.3

The Joint Application presents, as observed during the hearings, a charge in “search of a customer.”4 The Presiding Judge should call off that search, and reject the Joint Application in its entirety, for the numerous reasons summarized below.

2. The Joint Application violates the Federal Power Act

As a threshold legal matter, the Federal Power Act requires a public utility to have a

contractual or customer relationship with an entity in order to impose charges on that entity,5 but

2 Tr. 305:9-306:9.

3 Initial brief at § III.B.1.

4 Tr. 121:19.

5 Initial brief at § I.A.

neither MISO nor ITC has a customer or contractual relationship with the NYISO or its customers.6

3.The Joint Application does not satisfy the requirements of the Commission’s

regulations

The Joint Application is also deficient under the Commission’s regulations, as it fails to include required support for the rate of return and the depreciation rate.7 The Commission’s regulations call for rejection of filings that do not meet stated requirements.8
4. The Joint Application contravenes Commission precedent

The Joint Application squarely contravenes applicable Commission precedent. A series
of Commission orders, including those relating to transmission facilities in PJM and MISO, have
prohibited broad reallocation of the sunk costs of existing transmission facilities. The costs of
the Original PAR were to be allocated solely to Detroit Edison transmission customers. These
are the original “existing facilities” to which the prohibition of subsequent cost reallocation
applies.

When the Replacement PARs were approved in 2006, they were specifically

denominated in the MISO planning process and, in correspondence, by ITC itself as

replacements for existing facilities. In the MISO’s planning process the costs of the

Replacement PARs were allocated solely to the ITC zone within MISO, consistent with

Commission precedent prohibiting the broad reallocation of costs of existing facilities. ITC

agreed in the 2007 Facilities Agreement with Hydro One to build the Replacement PARs at

ITC’s own expense. ITC had essentially completed the construction of its Replacement PARs by
2009. The cossts ITC had incurred were “sunk costs” of “existing facilities” for purposes of the

6 Id. at § III.A.

7 Id. at § I.D.

8 18 C.F.R. § 35.5 (2012).

Commission’s governing cost allocation precedent. Only after the construction of the

Replacement PARs was essentially complete did ITC (with MISO’s complicity) seek a broader
allocation of those costs, culminating in the filing of the Joint Application.
The pertinent Commission orders reflect that reallocation of transmission facility costs (to spread them beyond the customers of the utility actually building the facility) is not
acceptable for existing facilities, and that broad allocation is acceptable only where the facilities
were prospectively planned in an open process that included the customers or stakeholders to
whom the costs are proposed to be allocated.9 The costs of the Replacement PARs are sunk
costs of existing facilities that were planned without any request for input from PJM or NYISO.
At this late hour, MISO and ITC now seek to reallocate the cost of the replacement PARs beyond
the ITC customer base to which those costs have been allocated since 2006.10 This attempt to
reallocate the cost of previously planned and constructed facilities violates Commission
precedent, and should be rejected outright.

5.The Joint Application’s proposed cost allocation also contravenes the policies

reflected in Order No. 1000

Order No. 1000’s Cost Allocation Principle 4 (which the Commission had proposed

before the Joint Application was filed) carries forward the principles that underlie the

Commission’s precedent described above, by requiring the costs of an facility to be constructed
within a region to be allocated solely within that region unless another external entity or region
voluntarily agrees to assume a portion of the costs.11 The Joint Application violates the
principle, because it proposes to allocate a portion of the costs of facilities located within MISO

9 Id. at § IV.A.

10 Id.

11 Id. at § IV.B.

(the Replacement PARs) to NYISO and PJM, neither of which has voluntarily agreed to assume a portion of the PARs’ costs.

6.The charges in the Joint Application are unjust, unreasonable and unduly

discriminatory

If the Joint Application is not rejected on threshold legal and policy grounds, it should be rejected because the facts show that the charges proposed in the Joint Application are unjust and unreasonable, and unduly discriminatory to the NYISO, including for the following reasons
explained further below:

• The Joint Application provides no studies or other quantification of “benefits”

they assert NYISO and PJM will receive from the Replacement PARs.

•The Replacement PARs (and the Original PAR) were built for the benefit of

Detroit Edison and ITC customers.

• The provisions under which MISO and the Independent Electricity System

Operator of Ontario (“IESO”) will operate the Ontario and Michigan PARs,

including the Replacement PARs (collectively, the “MI/ON PARs”), as well as
the proposed MISO tariff provisions, permit MISO and IESO to favor their own
customers and interests over NYISO’s and PJM’s customers and interests.

• The Joint Application discriminates against NYISO and PJM customers by failing

to propose allocation of charges to IESO customers, and by charging NYISO and PJM customers while MISO customers located outside the ITC transmission zone are not being charged.

• Control by the MI/ON PARs of counterclockwise Lake Erie loop flow does not

benefit, and may harm, NYISO and its customers. Lake Erie loop flow has been
counterclockwise on average for 2012 so far, and MISO’s DFAX cost allocation
analysis suggests projectedMISO’s DFAX cost allocation analysis suggests that
Lake Erie loop flow will continue to occur in a counterclockwise direction into
the mid-term future.

• The Joint Applicants submitted no studies or analyses to support their repeated

claim that the MI/ON PARs will control 600 MW of Lake Erie loop flow, and

actual MI/ON PAR performance data for the period since the Replacement PARs were placed in service reveal that the claim is vastly overstated.

• The outage history of the MI/ON PARs indicates a significant risk that the control

of Lake Erie loop flow will be provided only intermittently.

•Unlike the rest of the MISO tariff that charges rates for defined services, the tariff

provisions filed with the Joint Application propose charges to NYISO and PJM

for unspecified services (essentially, for “nothing”) and the collection of a rate for nothing is unduly discriminatory to those entities and their customers.

• Besides seeking to charge NYISO and PJM customers for an undefined service,

the MISO tariff provisions fail to establish any sort of performance standard or

any service obligation of MISO or ITC to the customers that will receive the non-
service.

• Data supplied by MISO indicates that MISO and IESO are failing to set the

MI/ON PARs-related “flag” in the Interchange Distribution Calculator properly,
precluding NYISO and PJM and other regions from using transmission loading
relief (“TLR”) to call for curtailment of transactions to protect reliability at times
when the MI/ON PARs are not successfully mitigating Lake Erie loop flow.

• The Joint Applicants submitted no evidence of any actual contribution of NYISO

to Lake Erie loop flow, and instead submitted a fundamentally flawed DFAX analysis that uses hypothetical data to estimate NYISO’s expected future contribution to Lake Erie loop flow.

• The rebuttal testimony of the Joint Applicants moves away from a “benefits”

theory of cost allocation to a cost causation theory, but the Joint Applicants have
not submitted studies showing that Lake Erie loop flow causes reliability issues.
The only specific reliability issues identified in the record as a reason for
construction of the replacement PARs are those reliability concerns identified in
MTEP06. All of the MTEP06 reliability concerns occur on ITC’s system.

•The Joint Applicants have not shown that loop flow caused any of the ITC system

reliability issues identified in the MTEP06 report.

• MISO and IESO have indicated a potential lack of commitment to operate the

MI/ON PARs in the manner called for in the Operating Instruction and in representations to the U.S. Department of Energy (“DOE”).

These issues are discussed below.

a.The Joint Application provides no studies or other quantification of

“benefits” they assert NYISO and PJM will receive from the Replacement

PARs.

The unjust and unreasonable nature of the proposed charges is revealed, most

fundamentally, by the Joint Applicants’ failure to provide studies, analyses and other evidence
that support their assertion that NYISO and PJM should pay for the costs of the Replacement

PARs because they and their customers “benefit” from operation of the MI/ON PARs.12 For

example, the Joint Applicants have not introduced any studies quantifying economic benefits or identifying specific reliability benefits to NYISO or PJM from the operation of the MI/ON
PARS. On the other hand, the record shows that the Replacement PARs make a broad array of transactional and reliability benefits available to ITC and its customers.13
Instead of submitting evidence to support their contentions, the Joint Applicants make generalized assertions of benefit to NYISO and PJM, while admitting they performed no studies to demonstrate or quantify the benefits.14

b.The Replacement PARs (and the Original PAR) were built for the benefit of

Detroit Edison and ITC customers.

The pertinent contractual, testimonial, and regulatory materials confirm that Detroit
Edison and ITC elected, and bound themselves by contract, to construct and pay for, the
Replacement PARs in order to better serve the transactional, economic and reliability needs of
the utilities and their customers.15 These needs included greater import capability into the
Detroit Edison/ITC system to facilitate trading between Detroit Edison/ITC and Ontario, and
between Detroit Edison/ITC and the South, and the need to reduce interruption in Ontario-
Michigan trading from curtailments across the electrical interface between Michigan and Ontario (the “MI/ON Interface”). Expected reliability benefits to the ITC service territory were
identified in the MISO’s MTEP06 report.

12 Id. at § V.B.

13 Id. at § V.D.

14 Id. at § V.B.

15 Id. at § III.B.

c.The provisions under which MISO and IESO will operate the MI/ON PARs,

including the Replacement PARs, and the proposed MISO tariff provisions, permit MISO and IESO to favor their own customers and interests over NYISO and PJM customers and interests.

The Operating Instruction under which MISO and IESO are operating the MI/ON PARs
(and to which NYISO and PJM are not parties) is unduly discriminatory as it permits MISO and
IESO to favor their own customers and interests over NYISO’s and PJM’s customers and
interests.16 First, neither NYISO nor PJM has a direct say in how MISO and IESO will operate
the MI/ON PARs. Second, several provisions of the Operating Instruction require, or at least
permit, MISO and IESO to operate the MI/ON PARs in a manner that favors themselves in
MISO or IESO emergencies when they are acting to prevent a possible emergency, but does not
provide for similar assistance in the event NYISO or PJM are seeking to prevent an emergency.
Third, the Operating Instruction also permits MISO and IESO to suspend normal operation of the
MI/ON PARs to protect MISO and/or IESO customers in the event of unexpected operational or
market outcomes in their regions, but does not provide corresponding protection for NYISO or
PJM customers in the event of unexpected operational or market outcomes in the NYISO or PJM
regions.

In a similar vein, proposed Attachment SS-1 to the MISO tariff allows MISO to

temporarily suspend normal operations of the MI/ON PARs in the event of anomalous MISO market results related to the MI/ON PARs. As confirmed by MISO witness Zwergel,
Attachment SS-1 does not provide for similar potential suspension of the MI/ON PARs for anomalous market results in the NYISO or PJM markets.

16 Id. at §§ III.C, IV.E.

d.The Joint Application discriminates against NYISO and PJM customers by

failing to propose allocation of charges to IESO customers, and by charging NYISO and PJM customer while MISO customer located outside the ITC transmission zone are not being charged.

Joint Applicants argue that it would be unjust and unreasonable to require one set of

market participants to pay for costs that are caused by other market participants. However, the
Joint Applicants proposed cost allocation method patently violates the principles that the Joint
Applicants espouse. MISO’s DFAX analysis indicates that the IESO region’s generation-to-load
flows are the single largest contributing factor to Lake Erie loop flows, and that IESO’s
generation-to-load contribution causes more than half (55%) of all Lake Erie loop flow.
Nonetheless, MISO and ITC are not proposing to require IESO or its customers to bear any of
the costs that the MISO’s DFAX analysis indicates that the IESO region causes. To the contrary,
MISO and ITC propose to required NYISO’s and PJM’s customers (as well as ITC customers) to
pay for costs that are caused by IESO. The Joint Applicants’ attempted justification cannot
withstand scrutiny. It would be unduly discriminatory to shift costs “caused” by IESO (under the
Joint Applicants’ DFAX study and theory) and its customers to NYISO and PJM.17
The Joint Applicants also violate their espoused cost allocation principles by proposing not to assign any share of the cost of Replacement PARs to MISO customers outside the ITC zone, despite the fact that MISO’s DFAX study indicates that MISO areas and customers located outside ITC’s region contribute to Lake Erie loop flows.18 This proposal is also unduly
discriminatory to NYISO and PJM.

17 Id. at § IV.C.

18 Id. at § IV.D.

e.Control by the MI/ON PARs of counterclockwise Lake Erie loop flow does

not benefit, and may harm, NYISO and its customers. Lake Erie loop flow has been counterclockwise on average for 2012 so far, and MISO’s DFAX cost allocation analysis suggests that Lake Erie loop flow will continue to occur in a counterclockwise direction into the mid-term future.

It is unjust and unreasonable to assign costs of the Replacement PARs to New York when it may be harmed, not benefited, by the operation of the MI/ON PARs.19 New York can be
harmed by the operation of the MI/ON PARs when (x) the MI/ON PARs are operated to reduce
counterclockwise loop flows, and (y) components of the New York State Transmission System
that are substantially affected by unscheduled Lake Erie power flows are constrained, or would
become constrained in the absence of counter-clockwise Lake Erie loop flow.   As the data
MISO provided in Exhibit NYI-66 indicates, Lake Erie loop flow has predominantly flowed in a counter-clockwise direction in 2012.   Counterclockwise Lake Erie loop flow tends to relieve
transmission congestion in New York.   Exhibit NYI-66 shows that, in 2012, the MI/ON PARs
have operated to block counterclockwise Lake Erie loop flow.   In addition, MISO’s DFAX
analysis projects that generator-to-load contributions to Lake Erie loop flows will continue to
tend to be counterclockwise into the mid-term future.

f. The Joint Applicants submitted no studies or analyses to support their

repeated claim that the MI/ON PARs will control 600 MW of Lake Erie loop
flow, and actual MI/ON PAR performance data for the period since the
Replacement PARs were placed in service reveal that the claim is vastly
overstated.

The Joint Application and the MISO and ITC supporting testimonies repeatedly state that
the MI/ON PARs are expected to fully mitigate Lake Erie loop flows approximately 74% of the
time, and reduce them by approximately 600 MW the remainder of the time.20 However, the
Joint Applicants have not submitted any evidence supporting that claim, and actual MI/ON PAR

19 Id. at § V.C.

20 Id. at § IX.A.

operating data provided by MISO shows that the MI/ON PARs have not effectively conformed actual power flows to scheduled power flows. In fact, the data shows that the operation of the MI/ON PARs frequently increased Lake Erie loop flow. Beyond this, the Operating Instruction does not require MISO and IESO to take additional PAR actions to reduce Lake Erie loop flow when it falls within the +/- 200 MW “control band.” It is clearly unjust and unreasonable to charge NYISO and PJM for control that does not meet claimed capabilities.

g. The outage history of the MI/ON PARs indicates a significant risk that the

control of Lake Erie loop flow will be provided only intermittently.

Since the Replacement PARs were placed into service, several outages of the MI/ON

PARs have occurred.21 Most notably, at least one PAR was out of service on 71 of the first 104
days the MI/ON PARs were in operation. Of particular concern is the viability of the L4D PAR
on the Hydro One system, which has gone out of service repeatedly due to gassing, which in the
worst case, can cause an explosion. When fewer than all four of the circuits that comprise the
MI/ON Interface as PAR controlled, very little Lake Erie loop flow can be achieved. Thus, the
frequent recent MI/ON PAR outages suggest that only intermittent control of loop flow can be
expected. This highlights, again, the unjust and unreasonable nature of charging NYISO and
PJM for a “non-service” that is not tied to the availability of the MI/ON PARs.

h. Unlike the rest of the MISO tariff that charges rates for defined services, the

tariff provisions filed with the Joint Application propose charges to NYISO and PJM for unspecified services (essentially, for “nothing”) and the
collection of a rate for nothing is unduly discriminatory to those entities and their customers.

At the hearing, ITC witness Grover admitted that MISO’s proposed Schedule 36 and

Attachment SS contain no description of the service that the NYISO’s customers will receive in

21 Id. at § IX.B.

return for their payments.22 It is unduly discriminatory to NYISO and its customers to be

charged a rate for unspecified service (essentially, for “nothing”), when MISO’s own customers only pay for services that are specified in MISO’s tariffs.

i. Besides seeking to charge NYISO and PJM customers for an undefined

service, the MISO tariff provisions fail to establish any sort of performance standard or any service obligation of MISO or ITC to the customers that will receive the non-service.

It is unjust and unreasonable enough to propose a charge for an undefined service, but even more unjust and unreasonable to impose a charge when there is no service obligation or performance standard to determine if the service is being provided adequately. Yet this is precisely what the Joint Applicants propose to do in this proceeding.23

j. Data supplied by MISO indicates that MISO and IESO are failing to set the

MI/ON PARs-related “flag” in the Interchange Distribution Calculator

properly, precluding NYISO and PJM and other regions from using TLRs to call for curtailment of transactions to protect reliability at times when the MI/ON PARs are not successfully mitigating Lake Erie loop flow.

The data supplied by MISO (in Exhibit NYI-66) shows that IESO and MISO frequently
fail to set the MI/ON PARs-related “flag” in the NERC Interchange Distribution Calculator
(“IDC”) properly.24 In particular, in some hours the flag is being set to “regulate” when the
MI/ON PARs are not controlling loop flow within the +/- 200 MW control band, in violation of
the Operating Instruction. When the flag is set to “regulate,” this blocks the ability of NYISO
and PJM (and other control areas) to use TLRs to call for curtailment of transactions in order to
protect reliability. It is unjust and unreasonable for NYISO and PJM to be charged for costs of
the Replacement PARs when MISO’s and IESO’s failure to adequately implement their

22 Id. at § VIII.

23 Id.

24 Id. at § IX.C.

operating responsibilities can contribute to an inability to address reliability problems arising in New York or in PJM.

k. The Joint Applicants submitted no evidence of any actual contribution of

NYISO to Lake Erie loop flow, and instead submitted a fundamentally flawed DFAX analysis that uses hypothetical data to estimate NYISO’s expected future contribution to Lake Erie loop flow.

The Joint Applicants provided no evidence of the NYISO’s actual contribution to Lake Erie loop flow,25 even though this is the centerpiece of the Joint Applicants’ cost allocation theory. Instead, they offer only a DFAX study showing the hypothetical 2015 contributions PJM, IESO, NYISO and MISO might make to Lake Erie loop flow.

The MISO’s study is flawed in every material respect,26 and was developed in a resultoriented fashion that merits rejection for that reason alone.27

First, MISO’s reliance on three representative load blocks to represent an entire year was
a gross over-simplification that produced inaccurate weighted participation percentages
penalizing the NYISO. The MISO should have conducted 8,760 DFAX runs for each region,
one DFAX run for every hour of the year, instead of using the three representative load blocks to
represent the entire year.28 Mr. Chatterjee admitted that performing 8,760 DFAX runs would be
the most accurate way to time normalize the DFAX analysis over an entire year.29
Second, MISO inappropriately relied on an aggregate load duration curve for MISO,
NYISO and PJM. 30 The MISO should have used each region’s individual load duration curve to
perform the DFAX analysis over all 8,760 hours of the year to calculate each region’s individual

25 Id. at § VI.A.

26 Id. at § VII.A.

27 Id. at § VII.B.

28 Id. at § VII.A.1.

29 Id. at § VII.A.1 citing Tr. 400:15-21.

30 Id. at § VII.A.2.

participation over the MI/ON Interface. According to Mr. Chatterjee, the MISO is not opposed
to using individual region’s load duration curves for the DFAX analysis.
Third, MISO’s unilateral decision to permit directional contributions to the flow
participation over the four circuits that comprise the MI/ON Interface to offset each other is
inappropriate and inconsistent with other decisions that MISO made with regard to netting of
contributions in the DFAX study.31 Netting participation across the four circuits reduced
MISO’s flow participation significantly more than any other region. As a result, netting
participation appears to be one way that MISO tailored the DFAX analysis to produce results
favorable to its own interests.

Fourth, the MISO DFAX study is not reflective of real-world electric power system

operation practices. MISO does not account for any economic impacts of generation dispatch in its hypothetical DFAX analysis.32 On cross-examination Mr. Chatterjee acknowledged that, in contrast to the DFAX analysis, RTOs do not “serve their load by uniformly ramping up all of the generation in their control area.”33 All RTOs dispatch generation throughout their entire system to achieve a least cost economic solution.

Fifth, it was not appropriate to base the DFAX analysis on the contribution to flows on all four of the circuits that comprise the MI/ON Interface.34 MISO should have calculated the
generation-to-load flow participation over only the B3N circuit, on which the Replacement PARs are located. The Replacement PARs on the B3N circuit are the only facilities that are being cost allocated in this proceeding.

31 Id. at § VII.A.3.

32 Id. at § VII.A.4.

33 Id. at § VII.A.4 citing Tr. 440:5-8.

34 Id. at § VII.A.5.

Sixth, MISO failed to consider in its DFAX analysis the cumulative Lake Erie loop flow contribution from regions other than MISO, NYISO, PJM and IESO.35 The multitude of small “contributors” illustrates that if regions are permitted to assess charges to each other on the basis of asserted “benefits” in the absence of regional agreements, this “chain reaction” and ensuing litigation will have no logical stopping place.

l. The rebuttal testimony of the Joint Applicants moves away from a “benefits”

theory of cost allocation to a cost causation theory, but the Joint Applicants
have not submitted studies showing that Lake Erie loop flow causes
reliability issues. The only specific reliability issues identified in the record
as a reason for the construction of the replacement PARs are reliability
concerns identified in MTEP06. All of the MTEP06 reliability concerns
occur on ITC’s system.

Despite the Joint Application’s “benefits” premise and the Joint Application’s multitude
of generically stated, unproven assertions of benefits provided by the Replacement PARs to
NYISO and PJM, the rebuttal testimony of a chief MISO witness states that benefits offered by
the Replacement PARs are irrelevant, because they should be cost allocated as a reliability
project that is allocated based on cost causation.36 It is unclear why the Joint Applicants have
shifted course, unless the weakness of the benefits assertions has become clearer in the period
since filing.

It would not be appropriate to allocate costs of the Replacement PARs to the NYISO or
its customers based on cost causation principles.37 If the standard is to be “cost causation,”
NYISO should not be paying for costs that MISO’s analysis shows they didn’t cause (e.g., costs
caused by IESO and its customers). More fundamentally, under the cost causation theory, ITC’s
incurrence of the costs of the Replacement PARs was “caused” by ITC’s unilateral decision to

35 Id. at § VII.A.7.

36 Id. at § V.A.

37 Id. at § V.F.

assume a contractual obligation to install the Replacement PARs in ITC’s 2007 Facilities

Agreement with Hydro One, in order to address the transactional and reliability needs of the ITC
system and customers. Accordingly, there is no basis for charging NYISO and its customers.

m. The Joint Applicants have not shown that loop flow caused any of the ITC

system reliability issues identified in the MTEP06 report.

To the extent the Joint Applicants argue that these needs were created by Lake Erie loop
flow, they have submitted no evidence showing that problems caused by Lake Erie loop flow
required ITC to restore the B3N circuit and construct the Replacement PARs. In particular,
MISO and ITC have each admitted that they never performed an assessment or identified
specific reliability criteria that are potentially violated by Lake Erie loop flow, and neither MISO
nor ITC submitted studies showing that Lake Erie loop flow causes reliability issues.
The only reliability issues noted in MISO’s 2006 regional plan (“MTEP06”) as being resolved by the Replacement PARs were those occurring on ITC’s own system, and MTEP06 attributes none of these issues to Lake Erie loop flow.38 These reliability issues, along with the desire to capture transactional benefits for ITC customers, and not the activities of the NYISO or its customers, caused the costs to be incurred to build the Replacement PARs.

n. MISO and IESO have indicated a potential lack of commitment to operate

the MI/ON PARs in the manner called for in the Operating Instruction and in representations to the DOE.

A September 9, 2011 e-mail from ITC to MISO provided as Exhibit No. NYT-35

indicates a potential lack of commitment by MISO and ITC (and perhaps IESO) to operating the
MI/ON PARs to achieve the +/-200mw bandwidth called for in the Operating Instruction and
that ITC, MISO and IESO presented to the DOE in the Presidential Permit proceeding. The e-
mail expresses great concern about the apparent volatility of the loop flow shown in August 2011

38 Id. at § V.D.2.

data, and states that ITC and MISO must absolutely ensure they have the flexibility to change the +/- 200 MW control band if it becomes onerous on MISO, ITC and IESO. This uncertainty is
yet another reason why it would be unjust and unreasonable to allocate Replacement PARs costs to NYISO and PJM.39

7.Conclusion

For the reasons summarized above, the Presiding Judge should reject the Joint Application in its entirety.

THRESHOLD ISSUES

I. WHETHER THE FEDERAL POWER ACT (“FPA”) AND APPLICABLE

COMMISSION POLICIES THEREUNDER PERMIT THE MIDWEST

INDEPENDENT TRANSMISSION SYSTEM OPERATOR, INC. (“MISO”) AND
THE INTERNATIONAL TRANSMISSION COMPANY D/B/A
ITCTRANSMISSION (“ITC”) TO MAKE, AND THE COMMISSION TO
APPROVE, THE OCTOBER 20, 2010 FILING (AS AMENDED ON JANUARY 31,
2012)?

A. Section 205 Filings Must Be Premised on a Customer or Other Contractual

Relationship with the Entities to Which the Rate Will Be Charged

Judicial and Commission precedent dictate that a Section 205 rate filing requires a

customer or other contractual relationship between the filing utility and the ratepayer. As

explained in Section III.A below, the NYISO and its customers (in their status as NYISO

customers) are in no sense customers of Midwest ISO or ITC, and neither NYISO nor any of its customers (except to the extent particular NYISO customers may also participate in the MISO’s markets) is a party to a contractual agreement by which it has consented to pay costs allocated to it by the Midwest ISO. Accordingly, the October 20, 2010 filing of MISO and ITC (the “Joint Applicants”) in this proceeding (the “Joint Application”) should be rejected.

39 Id. at § IX.E.

The NYISO presented its arguments regarding these matters to the Commission in the

rehearing request it submitted addressing the Commission order setting the filing for hearing and
accepting it subject to refund.40 The Commission has not, to date, ruled on this rehearing
request. In its Order No. 1000-A, the Commission rejected arguments that “the costs of new
transmission facilities can only be allocated within a preexisting contractual relationship,”41
reasoning that “[r]ather than contractual relationships, the benefits received by users of the
regional transmission grid provide a basis for how costs should be allocated.”42 The NYISO is
seeking review of this holding in the U.S. Court of Appeals for the District of Columbia
Circuit.43 As explained in its rehearing request of Order No. 1000, NYISO believes that the
Commission erred in this holding, because Order No. 1000’s extremely broad claims of the
Commission’s statutory authority exceed the Commission’s jurisdiction under the Federal Power
Act, and diverge from Commission precedent without a reasoned explanation.44 Rather than
restate its content here, the NYISO Rehearing Request is incorporated herein by reference, and
summarized briefly below.

As explained by the U.S. Supreme Court in In re Permian Basin Area Rate Cases

(“Permian Basin”), the requirement for a contractual relationship as the basis for a proposal to

charge an entity pursuant to tariff follows from the principle that “[t]he regulatory system created

40 See Midwest Independent Transmission System Operator, Inc. and International Transmission Company d/b/a
ITCTransmission, Request of New York Independent System Operator, Inc. for Expedited Reconsideration or
Rehearing, Request to Stay Proceedings and Motion to Shorten Response Period, Docket No. ER11-1844-001 at 5-

12 (January 21, 2011) (hereinafter “NYISO Rehearing Request”).

41 See Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000-A, 139 FERC ¶ 61,132 at P 564 (2012) (hereinafter “Order No. 1000-A”).

42 See Order No. 1000-A at P 565 (2012).

43 See New York Independent System Operator, Inc. v. Federal Energy Regulatory Commission, Case No. 12-1293 (Consolidated with Case Nos. 12-1232, 12-1233, 12-1250, 12-1276, 12-1279, 12-1280, 12-1285, 12-1290, 12-1292, 12-1294, 12-1296, 12-1299, 12-1300 and 12-1304) (2012).

44 See Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities,

Rehearing Request of New York Independent System Operator, Inc., Docket No. RM10-23-001 (August 22, 2011).

by the Act is premised on contractual agreements voluntarily devised by the regulated

companies….”45 If an entity does not take jurisdictional service as a customer from a utility

under a contractual relationship, or if there is no other voluntary contractual agreement (such as an RTO agreement) by which charges can be assessed to an entity by a utility, application of the Permian Basin principle means that the Federal Power Act’s “regulatory system” provides no authority for a utility to file for collection of a rate from the unrelated entity, and no authority under which the Commission may accept such a filing.

Consistent with Permian Basin, Commission precedent has long recognized that its rate-
related authority under the Federal Power Act requires the existence of contractual relationships
between a utility and its customers, and the Commission has rejected rate filings that contravene
this basic principle. Perhaps the most recent order reflecting this principle was issued in May
2010,46 when the Commission reversed a finding of an initial ALJ decision that the MISO could
collect Seams Elimination Charge/Cost Adjustment/Assignment (“SECA”) transmission-related
charges from a retail load-serving entity (Green Mountain) that was not a MISO transmission
customer or market participant, even though Green Mountain benefitted from the transmission
service that MISO provided to Green Mountain’s affiliate, BP Energy, which acted as an

intermediary for Green Mountain.

On rehearing, the Commission stood by its earlier rulings that the mere fact that Green
Mountain made retail sales cannot justify imposing SECA charges and that Green Mountain’s

45 In re Permian Basin Area Rate Cases, 390 U.S. 747, 822 (1968). Permian Basin addressed rate filings under the Natural Gas Act. However, “the provisions of the Federal Power Act relevant to [rate-revisions] are in all material respects substantially identical to the equivalent provisions of the Natural Gas Act.” FPC v. Sierra Pac. Power Co., 350 U.S. 348, 353, 76 S. Ct. 368, 371-372, 100 L. Ed. 388, 394 (1956); see also Permian Basin Area Rate Cases (Continental Oil Co. v. FPC), 390 U.S. at 821, 88 S. Ct. at 1388, 20 L. Ed. 2d at 366; Richmond Power & Light v. FPC, 156 U.S. App. D.C. 315, 317, 481 F.2d 490, 492, cert. denied, 414 U.S. 1068, 94 S. Ct. 578, 38 L. Ed. 2d 473 (1973); Cleveland v. Federal Power Comm'n, 525 F.2d 845, 855 (D.C. Cir. 1976).

46 See Midwest Independent Transmission System Operator, Inc., Order on Initial Decision, 131 FERC ¶ 61,173 (2010) (“Green Mountain”); on reh’g, 136 FERC ¶ 61,244 (2011) (“Green Mountain Rehearing”).

use of MISO transmission service to serve its retail load did not convert Green Mountain into a MISO customer on whose behalf MISO was authorized to file unexecuted transmission service agreements. The Order on Rehearing noted that “if the existence of retail sales were an
appropriate basis to assess SECA charges, then they should be assessed to all entities selling at retail and not merely Green Mountain,”47 and stated that, in the Order on Initial Decision, “the Commission disagreed with the Initial Decision’s finding that, even though Green Mountain did not directly contract with Midwest ISO, Green Mountain was ultimately responsible for
transmission charges, since the procurement of network transmission service was for the benefit of Green Mountain and was its financial responsibility.”48

The Green Mountain Order and Order on Rehearing are instructive and, if followed,

should determine the outcome of this proceeding. In the proceeding at bar, the Joint Applicants submitted proposed revisions to the MISO’s tariffs that permit the MISO to charge a portion of the cost of ITC’s Replacement PARs to entities with which MISO has no existing contractual or customer relationship. One of the bases for proposing the charges is an assertion that customers of NYISO and PJM Interconnection, L.L.C. (“PJM”) will “benefit” from the operation of the MI/ON PARs to control Lake Erie loop flow.49

Applied to this case, the Green Mountain orders dictate that the charges for the

Replacement PARs remain with ITC’s existing transmission service customers, rather than being spread to all entities that MISO and ITC allege will receive a sufficient (but unquantified) benefit from the operation of the MI/ON PARs.

47 Green Mountain Rehearing, at P 208 (emphasis added).

48 Id. at P 204 (emphasis added).

49 See, e.g., Midwest Independent Transmission System Operator, Inc. and International Transmission Company d/b/a ITCTransmission, Transmittal Letter, Docket No. ER11-1844-001 at 5-7 (October 20, 2010) (“Joint
Application Transmittal Letter”). But see discussion in Section V.A below, referencing the statements of MISO witness Chatterjee that benefits are irrelevant.

The Commission tries to distinguish the Green Mountain orders in Order No. 1000-A by
implying that the outcome of the Green Mountain proceeding turned solely on the requirements
of the MISO tariff. However, the Commission’s reasoning in the Green Mountain orders was
broader than the Commission admitted in Order No. 1000-A. In Green Mountain, the
Commission rejected MISO’s attempt to charge Green Mountain based on the fact that Green
Mountain’s ability to serve its retail loads was dependent on transmission service provided by the
MISO. The Green Mountain orders’ insistence that, in order to send a beneficiary a bill, the
beneficiary must be a customer that is actually taking a defined service under a regional tariff,
undermines the Commission’s effort to defend its legal conclusion in Order No. 1000.
The Commission’s decision in Commonwealth Edison Co. (“Commonwealth Edison”) reflected the principles announced by the Supreme Court in Permian Basin.50 In Commonwealth Edison, the Commission rejected the filing by Commonwealth Edison (“ComEd”) - a
transmission owner that had departed MISO - of a proposed rate schedule to ComEd’s own
tariff. The rate schedule proposed to assign to another utility (Ameren) credits accruing to
ComEd when ComEd took transmission service from MISO. The rate schedule provided that
Ameren could use the credits that ComEd accrued to offset the capital cost component of future
MISO administrative charges.

Section 4 of ComEd’s proposed rate schedule stated that the Commission’s acceptance
would “constitute direction to Midwest ISO to charge its administrative costs to [Ameren]
pursuant to Schedule 10-A of the Midwest ISO [Tariff], rather than under Schedule 10 of the
Midwest ISO [Tariff].”51 Protestors, including MISO, asserted that this new rate schedule would
have the effect of raising rates payable by other MISO transmission customers under a MISO

50 Commonwealth Edison Co., 129 FERC ¶ 61,298 (2009), order on reh’g, 132 FERC ¶ 61,268 (2010).

51 Id. at P 6.

rate schedule. In essence, ComEd’s proposed rate schedule would have imposed increased charges on entities with which ComEd had no direct contractual or customer relationship.
In its protest, the Midwest ISO stated:

ComEd cannot compel the modification of the Midwest ISO Tariff by filing a
Section 205 application to establish a new Rate Schedule under its own tariff.
…ComEd is not a transmission-owning member of the Midwest ISO and
therefore is not authorized to make filings that would affect the rates, terms, or
conditions of service under the Midwest ISO Tariff. Moreover, it is ultra vires the
scope of Section 205 for one utility to make a filing to compel the action of a non-
filing utility. …Because ComEd’s Section 205 Application contains provisions
that are not authorized under Section 205 of the FPA, the instant filing should be
rejected with prejudice.52

The Commission’s order summarily rejected Section 4 of ComEd’s proposed rate

schedule,53 acknowledging that only through Section 206 of the Federal Power Act could the Commission approve ComEd’s request to amend the tariff of another entity (i.e., MISO).54 Thus, the Commission in Commonwealth Edison implicitly agreed that it is ultra vires for one utility to make a filing under Section 205 to assign costs to non-customers.55

The “ultra vires” conduct protested by the Midwest ISO bears a strong resemblance to
the filing submitted by MISO/ITC in the instant proceeding. The Presiding Judge should find,
accordingly, that the Joint Application is improper under Section 205 of the Federal Power Act,
and reject it.

52 See Commonwealth Edison Co., Motion to Intervene and Protest of the Midwest Independent Transmission
System Operator, Inc., Docket Nos. ER10-209-000, et al., at 7-8 (November 24, 2009) (footnote omitted).

53 See Commonwealth Edison at P 27.

54 Id. (“Further, we reject section 4 of the proposed rate schedule, which states that our acceptance of the [ComEd] rate schedule shall constitute direction to the Midwest ISO to charge its administrative costs to Ameren pursuant to Schedule 10-A of the Midwest ISO Tariff…. In the meantime, ComEd and/or Ameren may exercise their rights
under section 206 of the Federal Power Act to seek to enforce the Midwest ISO Tariff, or amend it if necessary, to recognize the assignment.”).

55 Id. at P 17 (summarizing MISO’s protest).

B.None of the Cases Cited by Joint Applicants Provide Any Basis for Assessing

Costs to the NYISO or its Customers

The decisions of the Commission and the courts cited in the Joint Application Transmittal Letter56 and in the testimony of MISO witness Webb57 as supporting the authority to file tariff
revisions that purport to apply to non-customers, and assess charges in the absence of a customer or other contractual relationship, are readily distinguishable. Moreover, none of these decisions provides any basis for assessing the costs of ITC’s replacement phase-angle regulators (the
“Replacement PARs”) to the NYISO or to the NYISO’s customers. The cited cost allocation
orders addressing loop flows all involve the allocation of such costs within a contractually
bounded region such as the Midwest ISO or the Western Systems Coordinating Council
(“WSCC”). Most of the orders and proceedings cited were based on mutual agreement among
the participants regarding the charges to be assessed.

The WSCC order cited in the Joint Application Transmittal Letter58 addressed a filing,
accepted after a paper hearing, of a plan developed collaboratively by the signatories to the
WSCC Agreement to address a longstanding loop flow problem.59 The plan called for the use of
controllable devices owned by five of its member utilities, and included a cost allocation and
compensation methodology. The plan was approved by 57 of the 64 WSCC members. In noting
favorably the collaborative development and approval of the plan, the Commission contrasted
attempts to impose charges on neighbors through Section 205 filings: “The Commission has
consistently rejected unilateral filings by single utilities proposing to impose charges, terms and

56 Joint Application Transmittal Letter at 6-15.

57 Ex. MSO-Tab D at 30:9-19. Mr. Webb’s testimony was adopted by MISO witness Chatterjee on January 31,
2012.

58 Joint Application Transmittal Letter at 13.

59 See Southern California Edison Company, 70 FERC ¶ 61,087 (1995) (footnote omitted) (“WSCC”), subsequent order approving loop flow plan, 73 FERC ¶ 61,219 (1995).

conditions on a neighboring utility that, according to the filing utility, is responsible for loop

flows.”60 In contrast to the WSCC decision, MISO and ITC’s October 20, 2010 joint application to amend the MISO tariffs (the “Joint Application”) is a unilateral filing seeking to collect
charges from NYISO and PJM customers for facilities that (as explained in Section III.D of this brief) were not jointly planned with NYISO and PJM and which are not the subject of a cost
allocation agreement.

Underscoring the contrast between the Joint Application and the WSCC case, in WSCC
the Commission also stated that: “The Commission’s policy is that owners and controllers of
interstate transmission facilities attempt to resolve loop flow issues on a consensual, regional
basis.”61 ITC has admitted that it did not attempt to “attempt to resolve loop flow issues on a
consensual, regional basis” before it undertook the planning and construction of the Original
PAR or the Replacement PARs. In that context, WSCC referred to the Commission’s seminal

Transmission Pricing Policy Statement, which in turn made clear that loop flow cost allocation in
a broader inter-regional context is based on consent: “Of course, such individual utility pricing
may be appropriate if there are no objections to the loop flow solution from any affected
neighboring utilities or transmission customers.”62 Here, NYISO objects to being shouldered
with the costs of a single alleged “solution” (versus other potential solutions, as discussed in
Section IV.F of this brief) forced upon it without joint planning or consent.
The Joint Applicants’ citation63 of Northern Indiana Public Service Co.64 only
underscores the manner in which the Joint Application violates longstanding Commission policy

60 WSCC at p. 61,250.

61 Id. at pp. 61,241-2.

62 See Policy Statement, Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided
by Public Utilities Under the Federal Power Act, 59 Fed. Reg. 55031 at p. 55037, n.35 (November 3, 1994).

63 Joint Application Transmittal Letter at 12-13; Ex. MSO-Tab D at 30:9-19.

regarding unilateral filings against entities with no customer or contractual relationship.

Northern Indiana, as admitted in the testimony of MISO witness Webb,65 involved a negotiated
agreement to share the costs of upgrades designed to address loop flow. In contrast, in the
current proceeding, no negotiated agreement with NYISO exists, or was proposed by ITC (or
Detroit Edison) before it undertook the planning and construction of the Original PAR or the
Replacement PARs.

In Indiana Michigan Power Co. and Ohio Power Co.,66 the Commission rejected a

unilateral filing of charges by Indiana Michigan Power Company and Ohio Power Company

(both American Electric Power (“AEP”) companies) to collect charges from neighboring utilities
for their “nonscheduled use” of the filing utilities’ transmission systems via unauthorized power
flows.67 The filing consisted of proposed new schedules to the filing utilities’ interconnection
agreements with those neighboring utilities. In rejecting the filing, the Commission stated:

While the Commission has left open an option for utilities to seek compensation for unscheduled power flows if the problem cannot be resolved through mutual agreement, this was not intended as an alternative to a good faith attempt at working out the problem. Rather, it was intended as a last resort to address
situations that could not be resolved consensually.68

MISO and ITC are not proposing to charge the NYISO for the NYISO’s unscheduled use
of MISO’s transmission system. To the contrary, MISO’s DFAX analysis suggests that MISO’s
unscheduled use of the New York State Transmission System could reasonably be expected to
exceed NYISO’s unscheduled use of the MISO’s transmission system. MISO and ITC (and

64 128 FERC ¶ 61,281 (2009) (“Northern Indiana”).

65 Ex. MSO-Tab D at 30:16-19.

66 64 FERC ¶ 61,184 at p. 62,554 (1993) (“Indiana-Michigan”).

67 Id. at p. 62,554.

68 Indiana-Michigan at p. 62,543.

ITC’s predecessor, Detroit Edison) made no attempt to obtain pre-planning or pre-construction
consent of the NYISO or its customers to pay for the Original PAR or the Replacement PARs.
Nor do the judicial decisions offered to support the Joint Application suggest that the Commission possesses authority to file or accept charges to parties that are not in a
customer/supplier relationship or otherwise in privity of contract with the utility. Illinois
Commerce Commission v. Federal Energy Regulatory Commission (“ICC”)69 and Midwest ISO
Transmission Owners v. Federal Energy Regulatory Commission (“MISO TOs”)70 involved cost
allocation disputes within the boundaries of PJM and the Midwest ISO, respectively, among
entities that voluntarily became members/customers of those RTOs. As discussed in Section
III.A of this brief, the NYISO and its customers (except to the extent particular NYISO
customers may also participate in the MISO’s markets) are not customers of the Midwest ISO or
ITC, and therefore these decisions lend no support to the propriety of the Joint Application.
The Joint Application Transmittal Letter71 cites, as supportive of their filing, the
Transmission NOPR that became Order No. 1000.72 However, as discussed in Section IV.B of
this brief, application of the cost allocation principles contained in Order No. 1000 - which
forbid filings by one region to charge another region for new transmission facilities built within
the former’s region without the latter’s consent - in fact support rejection of the Joint
Application.

69 576 F.3d 470 (7th Cir. 2009).

70 373 F.3d 1361 (D.C. Cir. 2004).

71 Joint Application Transmittal Letter at pp. 10-12.

72 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, FERC Stats. and Regs. ¶ 31,323 (2011) (“Order No. 1000”), order on reh'g, Order No. 1000-A, 139 FERC ¶ 61,132 (2012) (“Order No. 1000-A”).

Finally, the Joint Application Transmittal Letter cites73 the then-pending filing of the MVP Proposal. However, the Multi Value Project (“MVP”) Proposal involved charges for transmission service to MISO customers. The instant proceeding does not involve transmission service charges to MISO customers.74

The cases cited by the Commission in Order No. 1000-A,75 in rejecting legal arguments
regarding whether the Federal Power Act requires a customer or contractual relationship as the
basis for a tariff filing, do not support the Joint Application. As discussed above in Section I.A
above, Green Mountain is inconsistent with Order No. 1000-A, and actually supports rejection of
the Joint Application. As noted above, ICC involved a cost allocation dispute within a single
RTO region, not between several distinct ISO/RTO regions, as is the case in the current
proceeding.

In Order No. 1000-A,76 the Commission denied that its position on its legal authority
under Section 205 of the Federal Power Act to assess charges against entities that are not
transmission customers or otherwise contractually responsible for paying the charges represents
a unexplained change in policy from that expressed in American Elec. Power Co.77 AEP I lends
no support to the Joint Application because, as stated in Order No. 1000-A, “[AEP I] does not
deal with planning and cost allocation for new transmission facilities and expresses no policy
with regard to these matters.”78 Moreover, Order No. 1000-A makes clear that AEP I’s
statements about the permissibility of a last-resort unilateral filing were made in the context of a

73 Joint Application Transmittal Letter at pp. 14-15.

74 See Ex. NYI-5, NYI-6, NYI-9.

75 Order No. 1000-A at PP 564-584.

76 Id. at PP 583-584.

77 49 FERC ¶ 61,377 at p. 62,381 (1986) (“AEP I”).

78 Order 1000-A at P 584.

rate to collect transmission charges for unscheduled use (through loop flow) of the filer’s system. As discussed above, that is not the context of the Joint Application.

The Commission also refers, in Order No. 1000-A,79 to the citation by the U.S. Supreme
Court in Morgan Stanley Capital Group, Inc. v. Public Utility District No. 1 of Snohomish
County, Washington (“Morgan Stanley”),80 of the Court’s holding in Permian Basin (discussed
in Section I.A. of this brief) that “[t]he regulatory system created by the [FPA] is premised on
contractual agreements voluntarily devised by the regulated companies.” The Commission
attempts to avoid, or negate the import of, the Supreme Court’s Permian Basin/Morgan Stanley
holding by arguing that “Morgan Stanley never stated that, by refusing to sign a contract, an
entity…can limit its obligation….”81 There are many things that the Supreme Court “never
stated” in Morgan Stanley, because the corresponding issues were not presented in that case.
However, even if one were to assume that the Commission’s basis for distinguishing Morgan
Stanley is valid, prior to Detroit Edison’s, ITC’s and MISO’s planning and construction of the
Original PAR or Replacement PARs, the NYISO and its customers were never presented a
contract that they could “refus[e] to sign.” Instead, MISO and ITC are asking the Commission to
require the NYISO and its customers to assume after-the-fact cost responsibility for transmission
facilities that were planned and constructed by others.

C. The Joint Application Violates the Commission’s Cost Allocation Policies

That Preceded Those Reflected in Order No. 1000

As discussed in Section IV.A of this initial brief, the Joint Application’s attempts to
impose on the NYISO and PJM a super-regional “postage stamp” rate, and to change the

79 Id. at P 567.

80 554 U.S. 527, 533 (2008).

81 Order No. 1000-A at P 567.

allocation of sunk costs, violate the Commission’s cost allocation policies that preceded those reflected in Order No. 1000.

D. The Joint Application Is Deficient Under the Commission’s Regulations
The Joint Application is deficient under Part 35 of the Commission’s regulations, and thus the Joint Applicants cannot meet their burden of proof under the Federal Power Act that the filing is just and reasonable. The deficiencies stem from a failure to provide any evidence, as required in Part 35, supporting key cost recovery elements of the filing.

These deficiencies were highlighted during cross-examination of ITC witness Grover by counsel for the New York Transmission Owners. Mr. Grover is ITC’s sole witness on rate
issues, and MISO did not offer a witness for this purpose - even though the rates are being
collected under MISO’s tariff.

In particular, the Joint Applicants have failed to provide information justifying the

justness and reasonableness of applying rates of return on equity and capital structure that were
established in 200382 to new customers for new types of charges.83 In cross-examination, Mr.
Grover admitted that the Joint Applicants had not provided any evidence in this proceeding that
the return on equity is still a just-and-reasonable rate under today’s capital markets,84 violating
Commission policy prohibiting the use of stale data to justify a rate of return.85 It is likely, in
today’s interest rate and capital markets environment that such a high rate of return overstates

ITC’s current costs. Section 35.13(h)(22) of the Commission’s regulations requires the submittal
of Statement AV, justifying rate of return through provision of current information regarding the

82 See ITC Holdings Corp., et al., 102 FERC ¶ 61,182 (2003).

83 Tr. 90:6-90:17.

84 Tr. 90:23-91:1.

85 Cranberry Pipeline Corp., 112 FERC ¶ 61,268 at P 25 (2005) (rejecting a pipeline’s proposed rate of return because it was based on “stale data” that was “more than three years old”).

capitalization of the utility, the cost of debt capital and preferred stock capital, the claimed rate of return on the common equity of the utility and the resulting overall rate of return requested. The Joint Applicants failed to include Statement AV as part of their filing, and therefore are not even in a position to meet their burden of proof for cost recovery.

Similarly, Joint Applicants have failed, as admitted by Mr. Grover,86 to justify the rate and time period for depreciation of the Replacement PARs. Section 35.13(h)(10) requires the provision of this information, through the inclusion of Statement AJ. Statement AJ was not included in the Joint Application.

The Joint Applicants cannot meet their burden of proof that the rates, terms and conditions of their filing are just and reasonable.

II. WHETHER THE JOINT OPERATING AGREEMENT BETWEEN MISO AND

PJM INTERCONNECTION, L.L.C. (“PJM”) PRECLUDES ALLOCATION OF COSTS ASSOCIATED WITH THE ITC PARS TO PJM?

The NYISO takes no position on this issue.

However, if it is determined that PJM cannot be charged for any of the costs of the

Replacement PARs due to the provisions of the Joint Operating Agreement (“JOA”) between
PJM and MISO, it becomes even clearer that it would be unjust and unreasonable, and unduly
discriminatory, to permit New York customers to be charged for a share of the costs of the
Replacement PARs. If this determination is made regarding the JOA, consider the
circumstances:

• In 2007 ITC entered into an agreement with Hydro One that obligated ITC to

construct, maintain and operate the Replacement PARs. ITC also assumed responsibility for its costs of complying with the agreement.87

86 Tr. 93:23-95:4.

87 Ex. NYI-49 at 10 (§ 6.1.1); and at 12 (§ 10.3).

•MISO and ITC seek to excuse IESO customers from sharing in any of the costs of

the Replacement PARs because the Commission lacks jurisdiction over those

entities, and because of investments Hydro One made in other PARs many years

ago.

•PJM customers would avoid cost responsibility because of the terms of the

PJM/MISO JOA.

• Customers of the MISO Transmission Owners, other than ITC’s customers, avoid

cost responsibility based on the terms of the MISO’s Tariff and MISO’s refusal to
re-allocate any portion of the cost of the Replacement PARs to other MISO load
areas that contribute to Lake Erie loop flow. Exhibit MSO-1B indicates that all
MISO load areas, not just ITC’s load area, contribute to Lake Erie loop flow.
Exhibit NYT-2, an e-mail from the MISO’s Gregory A. Troxell to ITC’s Thomas
Wrenbeck indicates that MISO is unwilling to charge MISO Transmission
Owners, other than ITC, or their customers, for any portion of the cost of ITC’s
Replacement PARs. MISO witnesses Mallinger and Chatterjee have both stated,
in their filed testimony and on cross-examination, that the MISO Transmission
Owners, other than ITC, and their customers, will benefit from the Replacement
PARs.88

• NYISO customers invested in PARs at the New York/PJM border, and at the New

York/Ontario border that assist with loop flow control (see Exhibit NYI-38, at

21:20-25:10), and are paying for NYISO’s implementation of various Broader

Regional Markets initiatives that are intended to reduce or address Lake Erie loop flow, but are not being given the same credit that MISO and ITC propose to
provide to Hydro One/IESO customers for Hydro One’s construction of the
Hydro One PARs at the MI/ON Interface.

• New York does not share a common border with ITC or MISO (the MISO and

NYISO regions are divided by the Province of Ontario), so NYISO has not

previously had reason to enter into a joint operating agreement with the MISO.
Nor had MISO sought an agreement with the NYISO addressing the joint
construction of transmission facilities prior to the submission of the Joint
Application.

• ITC and MISO seek to assign a share of the cost of the Replacement PARs to the

NYISO because NYISO is the only (distant) neighbor that MISO is not affirmatively precluded, by contract, from charging.

This set of facts makes it exceedingly clear why the Commission has repeatedly decided
(in Order No. 1000, and under prior precedent) that a formal, regional planning process with an

88 See Webb/Chatterjee testimony (Ex. MSO-Tab D at 13:1-7); Ex. MSO-1B (indicating that all MISO load areas contribute to Lake Erie loop flow); Ex. MSO-3 at 14:21-23; Tr. 561:2-5.

opportunity for stakeholders to have input is an absolute necessity before the cost of facilities can be imposed on a neighboring region. Here, ITC is seeking to spread the cost of its Replacement PARs to an area that had no say in the decision that ITC made to construct the Replacement
PARs. The failure of ITC to utilize a planning process that included entities that they intended to charge, or to negotiate a cost sharing agreement prior to undertaking contractual commitments to construct the PARs, dictates rejection of the Joint Application.

III. WHETHER THERE ARE ANY OTHER CUSTOMER OR CONTRACTUAL

RELATIONSHIPS OR INTERREGIONAL PLANS, OR LACK THEREOF, THAT ARE RELEVANT TO THE PROPOSED COST ALLOCATION?

A.There Is No Customer or Contractual Relationship Between the NYISO or

the NYISO’s Customers and MISO or ITC

MISO and ITC have not identified any customer or contractual relationship with either
NYISO or its customers that present a valid basis for assessing the NYISO or its customers
charges for the costs of the Replacement PARs. Section 1.652 of the MISO’s Open Access
Transmission, Energy and Operating Reserve Tariff (the “MISO Tariff”) defines who is a MISO
“Tariff Customer” as a “Market Participant, Transmission Customer or Coordination Customer.”
The NYISO is not a MISO Market Participant,89 Transmission Customer90 or Coordination
Customer,91 as each term is defined in the Midwest ISO Tariff. MISO has stated that NYISO is
not currently a Transmission Owner, Transmission Customer or Market Participant under the
MISO Tariff.92 MISO has also stated that it does not have any Tariff obligation to provide

89 The NYISO has not registered with, or been qualified by, the Midwest ISO as a Market Participant. See Midwest ISO Tariff at § 1.384.

90 The NYISO has not executed a transmission Service Agreement or requested the Midwest ISO to file with the Commission an unexecuted Service Agreement. See Midwest ISO Tariff at § 1.666.

91 The NYISO is not taking Coordination Services from the Midwest ISO under Module F of its tariff. See Midwest ISO Tariff at § 1.98.

92 See Ex. NYI-5.

reliable service to the NYISO, or to the NYISO customers that are paying for a portion of the cost of the Replacement PARs.93

In the hearing, ITC witness David Grover admitted that neither the NYISO nor the New
York Transmission Owners (“NYTOs”) are customers of ITC.94 Mr. Grover also stated that he
was unaware of any agreement by either the NYISO or the NYTOs to pay the rates proposed in
this proceeding.95 Neither MISO nor ITC introduced any evidence of either a customer or
contractual relationship between the MISO and the NYISO or the NYISO’s customers.
The absence of a customer or contractual relationship between the NYISO, or the
NYISO’s customers, and MISO or ITC is underscored by the specific disclaimer MISO and ITC
have made that the tariff revisions proposed in the Joint Application do not include any service
obligation to the NYISO, or to the NYISO’s customers. As noted above, MISO takes the
position that “NYISO is not a MISO Transmission Owner, Transmission Customer, or Market
Participant, and MISO does not have service obligations to NYISO related to these categories.”96
Similarly, MISO answered “no” to the NYISO’s question as to whether MISO and/or ITC would
be “subject to an obligation to provide reliable service to NYISO customers…that are not
otherwise MISO customers.”97

The NYTOs asked ITC in a data request to “describe what service obligation ITC would
have to the NYISO or any NYTO to the extent the NYISO or any NYTO is required to pay for
any portion of the Replacement PARs.”98 ITC responded: “As far as ITC knows, none.”99

93 See Ex. NYI-6.

94 Tr. 92:17-25.

95 Tr. 91:14-18.

96 See Ex. NYI-5.

97 See Ex. NYI-6.

98 See Ex. NYI-9.

As discussed in Section I.A of this brief, as a legal matter, the Federal Power Act forbids
a public utility to file a rate that imposes charges on entities that have no customer or contractual
relationship with the public utility. Because the MISO and ITC have no contractual or customer
relationship with the NYISO or its customers, the Commission should reject the Joint
Application.

B. The Original PAR and the Replacement PARs Were Built Pursuant to Pre-

Existing Contract Obligations, and to Serve the Transactional/Economic

Interests of Michigan and Ontario Utilities and their Electricity Customers

1.The Original PAR and the Replacement PARs Were Built Pursuant to

Pre-Existing Contract Obligations

The costs of the Original PAR and the Replacement PARs were incurred due to contract
obligations that Detroit Edison and ITC voluntarily assumed, and to serve the interests of
Michigan and Ontario utilities and their electricity customers. As explained in NYISO witness
Pike’s testimony,100 in 1998, Detroit Edison (ITC’s former parent company), Ontario Hydro (the
pertinent part of which is now Hydro One Networks Inc.) and Consumers Energy Company
entered into an Interconnection Facilities Expansion Agreement (the “1998 Facilities
Agreement”).101 In Section 3.2 of the 1998 Facilities Agreement Detroit Edison agreed, at its
own expense, to install and operate the Original PAR on the B3N transmission line that
interconnects Michigan and Ontario,102 and in Section 3.1, Ontario Hydro agreed to install and
operate a PAR on the Ontario side of each of the other three major transmission lines (J5D,
L51D and L4D) that comprise the Michigan/Ontario Interface or “MI/ON Interface.”103 The

99 Id.

100 Ex. NYI-46 at 3:20-4:15.

101 The 1998 Facilities Agreement is Ex. NYI-48. 102 Ex. NYI-48, at 2.

103 Ex. NYI-48 at 1-2.

three PARs constructed by Ontario Hydro (now Hydro One) are referred to herein as the “Hydro
One PARs.” Each of the Hydro One PARs is associated with a distinct transmission line, so
three of the four transmission lines at the MI/ON Interface are associated with Hydro One
PARs.104

Detroit Edison and Ontario Hydro agreed to construct the Original PAR and the Hydro
One PARs to prevent or control power flows that were interfering with scheduled transactions
between Michigan and Ontario.105 On cross-examination, ITC witness Capra agreed that the
interruption of scheduled transactions between Michigan and Ontario in 1998 was at a sufficient
level that it could reasonably be expected to have caused Detroit Edison to be willing to install
the Original PAR.106 Mr. Capra’s testimony also quotes from Detroit Edison’s request to the
Department of Energy for authorization to construct the Original PAR and other facilities at the
MI/ON Interface.107 That application explains that in 1998 over 8,500 MW of transactions

scheduled between Ontario Hydro and utilities in Michigan were curtailed via TLRs.

Section 3.7 of the 1998 Facilities Agreement states, “Hydro and Edison shall each be
responsible for the performance of operation and maintenance, extraordinary maintenance and
repair, which can include replacement, of the New Equipment and New Facilities [defined to
include the Original PAR] which are owned by them, including all costs associated
therewith.”108 A 2006 e-mail from ITC employee Vitez to MISO employee Webb states that the
replacement phase shifter at issue in this proceeding is essentially a “’replacement-in-kind’ type

104 Ex. NYI-46 at 4:7-9.

105 Ex. NYI-48 at 9.
106 Tr. 142:12-146:4.

107 Ex. ITC Tab F at 5:8-6:34.

108 Ex. NYI-48 at 3 (emphasis added).

project.”109 Similarly, an ITC data response indicates that the Replacement PARs project “was approved as a like for like replacement.”110

In 2007, ITC (successor to Detroit Edison) and Hydro One entered into a new

Interconnection Facilities Agreement (the “2007 Facilities Agreement”).111 In Section 10.3 of the 2007 Facilities Agreement ITC agreed to install two replacement PARs at Bunce Creek to replace the Original PAR, stating specifically: “[d]ue to the failure of the Phase Angle Regulator referenced in Subsection 10.2(a) above [i.e., the Original PAR], ITC agrees to install one or more Phase Angle Regulators with a combined total capacity of at least 645 MVA in the B3N
Interconnection terminal at its Bunce Creek Station.”112 Section 6.1.1 of the 2007 Facilities
Agreement states that each party shall bear their own costs of compliance with the Agreement, except as specifically provided therein.113 Thus, ITC entered into a contractual obligation to
construct the Replacement PARs at its own expense before it so much as suggested that New
York should pay for a portion of the cost of the Replacement PARs.

2. The Original PAR and the Replacement PARs Were Built to Serve

the Transactional/Economic Interests of Michigan and Ontario Utilities and their Electricity Customers

As confirmed in the review that follows of the pertinent contractual, testimonial, Detroit
Edison/ITC, and regulatory materials, ITC elected to construct, and pay for, the Replacement
PARs in order to better serve the transactional and economic needs of the utilities and their
customers.

109 Ex. NYI-53.
110 Ex. NYI-54.
111 Ex. NYI-49.

112 Ex. NYI-49 at 12.
113 Ex. NYI-49 at 10.

Contractual evidence is supplied in the 1998 Facilities Agreement between Detroit
Edison (predecessor in interest to ITC) and Ontario Hydro (predecessor in interest to Hydro
One). Schedule “A” to the 1998 Facilities Agreement, titled “Basic Principles of Ontario-
Michigan Phase Shifter Operation,” states that Ontario Hydro and Detroit Edison “intend to
improve reliability of bulk power supply by adding and modifying facilities … to control
circulating power flows that would otherwise interfere with the ability to carry out scheduled
transactions” and that the PARs would be “operated primarily to control power flow circulating
through the electrical systems of the parties in order to protect the parties’ respective
transmission facilities and to facilitate transactions between and among the parties.”114
ITC witness Capra’s testimony similarly recognizes that removal of obstacles to Ontario-Michigan trading was the fundamental reason that Ontario Hydro and Detroit Edison decided to install the Hydro One PARs and the Original PAR on the B3N circuit. Mr. Capra’s testimony states that “[t]he fundamental purpose of the joint Detroit Edison Company and Ontario Hydro proposal to add additional PARs on the interconnections between what was then the Detroit
Edison Company and Ontario Hydro was to improve the reliability of the bulk power system by
controlling circulating loop flows around Lake Erie that would otherwise interfere with the
ability to carry out scheduled transactions.”115 Mr. Capra’s testimony also quotes from Detroit
Edison’s request to the Department of Energy for permission to construct the Original PAR and
other facilities at the MI/ON Interface. The application states, as a premise for the filing, that in
1998 over 8,500 MW of transactions scheduled between Ontario Hydro and utilities in Michigan
were curtailed via TLR.116

114 Ex. NYI-48 at 9.

115 Ex. ITC Tab F at 4:21-5:3.
116 Ex. ITC Tab F at 6:12-6:16.

The application of TLR procedures to curtail transactions between Michigan and Ontario at the MI/ON Interface remain an obstacle to commerce between MISO and IESO today. As described in the testimony of NYISO witness Pike,

Over [the time period from January 1, 2009 through December 31, 2011], more than 1,900 transactions that were scheduled over the MI/ON Interface between Ontario and MISO were curtailed or removed via TLR actions. Those transactions represented more than 100,000 MW of scheduled interchange between Ontario and Michigan that was prevented or interrupted via TLR.117

The reduction of TLRs affecting transactions scheduled over the MI/ON Interface does
not provide benefits to New York. NYISO witness Pike reviewed transaction schedule data
stored in the NYISO’s Market Information System (“MIS”) for calendar year 2011 and
determined that only four-tenths of one percent of the NYISO’s total real-time scheduled
interchange sourced from, or sank in MISO.118 These are the only transactions that could
possibly have been scheduled across the MI/ON Interface.119 A portion of the NYISO/MISO
interchange Mr. Pike identified is scheduled through PJM’s Balancing Authority Area, not over
the MI/ON Interface, so the component of NYISO interchange that is scheduled over the MI/ON
Interface is a small fraction of one percent of the NYISO’s scheduled interchange with its
neighbors. Unlike MISO, ITC, IESO and Hydro One, the potential economic harm to NYISO
from TLRs of transactions scheduled across the MI/ON Interface is negligible.120
Corporate documents also confirm that the purpose of the MI/ON PARs is to facilitate economic trades between Ontario and Michigan. A November 12, 1998 internal Detroit Edison

117 Ex. NYI-46, at 10:6-10:10 (as corrected at hearing on September 12, 2012; Tr. 932:2-5), and the supporting information supplied in Ex. NYI-77.

118 See Ex. NYI-46 at 10:14-21.

119 The provisions of the NYISO tariff prohibiting circuitous scheduling would prevent other transactions from being scheduled to New York across the MI/ON PARs. See New York Independent System Operator, Inc., 124 FERC ¶ 61,174 (2008); New York Independent System Operator, Inc., 125 FERC ¶ 61,184 (2008).

120 Ex. NYI-46 at 10:14-11:5.

memorandum that describes the Original PAR as part of a project that is the “solution” to an
increase in Lake Erie loop flow that “has reduced our ability to import power from Ontario
Hydro….This project provides both a benefit in importing more power from OH through
increased capacity and by blocking the loop flow and the additional benefit of obtaining more
import capability on either the [MI/ON] or Southern Interface, therefore, providing operating
flexibility.”121 Hence, Detroit Edison recognized that the installation of the Original PAR would improve its ability to import power from Ontario, and its ability to import power into Michigan from the South. The circumstances under which New York might benefit from the operation of the Replacement PARs are more limited.122

In addition, the Detroit Edison memorandum lists eleven separate “major benefits” Detroit Edison expected to receive from the installation of the Original PAR:

1. A maximum increase in capacity of 1000 MW’s, or 500 MW of fixed capacity increase and ±500 MW’s of controllable. [Emphasis in original.]

2. A reduction in loss capacity of about $1.1M/yr and a reduction in energy losses of about $.8M/yr.

3. A reduction in TLR’s (from 25 to 7 for last year) - 18 TLR’s could be eliminated by this project.

4. An increase in revenue through additional power sales.

5. A reduction in our cost for transmission service (for example, transmission service through OH [i.e., Ontario Hydro] is lower than through AEP when open access occurs in OH on July 2000).

6. A reduction in the uncertainty in planning and scheduling power. Less

purchase power options are needed because more sources are available from the East and South.

7. If an emergency occurs, more resource options are available.

121 Ex. NYI-56 at 1.

122 See Section V.D of this initial brief.

8. The Operation and Facilities agreements with OH are nearly finalized and DE will realize 400 MW of QFW capacity increase from OH during emergencies; and receive favorable treatment of incremental capability from the South when phase shifters are blocking (if DE drops out of the this project, OH will undoubtedly operate phase shifters in full block during high LEC and therefore DE would have reduced capabilities from the South.). [Emphasis added.]

9. We have negotiated very favorable positions with respect to the cost of

facilities for DE (phase shifter at $.7M below next bidder, and autotransformer
$.5M below next bidder - re-bidding at a later date will increase these costs by
about $2M).

10. The market power concern for DE would be reduced by increasing the OHMI import capability up to 1000 MW.

11. During the transition period of open access, DE may be required to provide
back up, unless increased import capability allows customers access to external
markets.123

The memorandum indicates that one of the reasons Detroit Edison decided to construct the Original PAR was a concern about how Ontario Hydro would operate the PARs on the
MI/ON Interface if Detroit Edison declined to participate in the project by installing the Original PAR on the B3N circuit:

…OH would install the three phase shifters in the B3N, L51 and L4D,

respectively, and DE would be disadvantaged due to the reduction in import capability from the South….124

…if DE drops out of this project, OH will undoubtedly operate phase shifters in full block during high LEC and therefore DE would have reduced capabilities from the South…. 125

If Ontario Hydro constructed all of the PARs at its own expense, it was expected to

operate the PARs “in full block during high [Lake Erie Circulation],” to the detriment of Detroit
Edison. By agreeing to construct the Original PAR itself (rather than letting Ontario Hydro
construct the B3N PAR), Detroit Edison gained a say in the how the MI/ON PARs would be

123 Ex. NYI-56 at 2-3.

124 Ex. NYI-56 at 2.
125 Ex. NYI-56 at 3.

operated. Detroit Edison’s decision was based on the opportunity to increase capacity imports into Michigan either from the north (Ontario) or from the south. The Detroit Edison internal memorandum does not consider, discuss, or address expected or potential benefits to other Lake Erie control areas. Instead, the memorandum shows that Detroit Edison decided to construct the Original PAR to benefit itself, its service territory and its customers.

In addition to operational benefits, the memorandum reflects that Detroit Edison expected
to gain regulatory benefits from the construction of the MI/ON PARs. Item 10 of the
memorandum (quoted above) indicates that “market power concern for DE would be reduced by
increasing the OH-MI import capability up to 1000 MW.”126 In particular, the Michigan Public
Service Commission (“MPSC”) was concerned, in the context of its initiative to restructure the
Michigan electric utility industry, about Detroit Edison’s ability to exercise market power in its
service territory.127 The addition of 1000 MW of import capability was presumably expected to
reduce this concern by providing the opportunity for additional supply to compete to serve load
in Detroit Edison’s service territory.

That the construction of the Original PAR was intended to enhance Michigan power
supply through increased transactions with Ontario is verified through ITC’s submission of a
portion of a December 2000 “Joint Report” to the MPSC in Case No. U-12781.128 The purpose
of the Joint Report, filed by several Michigan utilities, was to describe how the utilities would
satisfy the requirements of a 2000 Michigan law to increase import capability from Ontario by
2000 MW. In the Joint Report, ITC stated that it had installed the Original PAR, which,

126 Ex. NYI-56 at 3.

127 See In the matter, on the Commission's own motion, to consider the restructuring of the electric utility industry,
Case No. U-11290, Michigan Public Service Comm’n, 1997 Mich. PSC LEXIS 171 at *62-*72; 177 P.U.R.4th
201(1997).

128 Ex. NYI-58.

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, 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 [Michigan] path will realize an increase of 820 MW of firm commercial capability from 2000 to 2002.129 [Emphasis added.]

Detroit Edison and ITC thus relied on the construction of the Original PAR to satisfy regulatory obligations to which they were subject in the State of Michigan. The NYISO’s customers do not gain any benefit from efforts related to the implementation of effective retail competition in the State of Michigan.

The evidence submitted in this proceeding makes it clear that ITC carefully considered whether the Replacement PARs would be beneficial to ITC, and considered alternatives to
constructing the Replacement PARs, before it entered into the 2007 Facilities Agreement.
Exhibits NYT-38 and NYI-60 illustrate the deliberations ITC and MISO engaged in before they decided to construct the Replacement PARs.

Exhibit NYT-38, an internal ITC e-mail from 2004 discusses economic considerations
that ITC employees Thomas Vitez and Richard Schultz were considering: “In short, if we
believe prevailing flow will be from West to East - Comed/AEP to PJM and Ontario imports,
then maybe B3N being permanently gone isn’t the worst thing. If interface limits East to West,
then B3N is probably the least expensive way to support needed ITC import capability.”130
Exhibit NYT-38 also identifies several alternatives to constructing the Replacement PARs that ITC’s employees considered. The exhibit recounts a discussion between Mr. Vitez (ITC) and a Hydro One employee about the possibility of converting the MI/ON Interface to

129 Ex. NYI-58 at 9.

130 Ex. NYT-38 at 2.

high voltage direct current (HVDC) control (“got the impression from him that Hydro One was
luke warm on HVDC at the interface - too expensive and the politics would be brutal”).131 The
e-mail also raises the possibility of installing a stronger tie between American Electric Power
(“AEP”) and ITC to reduce Lake Erie loop flow that is caused by Detroit Edison’s imports from
AEP. Exhibit NYT-38 states that approximately 15% of Detroit Edison’s imports from AEP (to
the south) enter ITC’s service territory over the MI/ON Interface.132 The potential solutions

discussed in NYT-38 are representative of the types of planning deliberations that the NYISO

and its stakeholders were not given the opportunity to participate in. As a result, the NYISO and its customers were not provided a comparable opportunity to evaluate alternatives and make a choice about whether the Replacement PARs would be a worthwhile investment for New York, when compared to possible alternatives.

C. The MISO-IESO Operating Instruction Permits MISO and IESO to Favor

Their Own Customers and Interests, Over the NYISO’s and PJM’s Customers and Interests

Another contract whose terms demonstrate that charging the NYISO or its customers for
a share of the costs of the Replacement PARs would be unjust and reasonable is the Operating
Instruction entered into by MISO and IESO for the operation of the MI/ON PARs.133 The
Operating Instruction was included with the final documentation that ITC submitted to DOE in
connection with its Presidential Permit proceeding addressing the addition of the Replacement
PARs. As discussed in Section IV.E.2 of this initial brief, the terms of the Operating Instruction
permit MISO and IESO to favor their own customers and interests, over the NYISO’s and PJM’s
customers and interests.

131 Ex. NYT-38 at 2.

132 Id.

133 The Operating Instruction is Ex. NYI-3 at 50-59.

D.Neither the Original PAR nor the Replacement PARs Were Planned Jointly

with NYISO and PJM

Neither the Original PAR nor the Replacement PARs were planned jointly with PJM and
NYISO.

Although the testimony of MISO witness Chatterjee states that the Original PAR “was
vetted through the joint planning structure that existed at the time,”134 Mr. Chatterjee does not
claim that planning process was an interregional planning process that included NYISO or PJM. The Joint Applicants have submitted no evidence of joint planning for the Original PAR, and can only assert that “Lake Erie Loop Flow was identified as an issue worthy of interregional
attention as early as 1999.”135 In that context, Mr. Chatterjee refers to the MAAC-ECAR-NPCC Study Committee’s “Michigan-Ontario Phase Angle Regulator Study: An Interregional
Perspective”136 (the “MEN Study”).137

However, as explained by NYISO witness Smith, a review of the MEN Study makes
clear that it is, in no sense, a multi-regional planning study to determine whether the Original
PAR (and the Hydro One PARs) were appropriately designed, or whether they were the best,
most cost effective, or the most appropriate facility to construct.138 Nor did the MEN Study
address any sort of allocation of the costs of the Original PAR among the regions that
participated in the study. Instead, the study was initiated “[i]n order to ensure continued reliable
operation of the interconnected regional systems”139 following the proposed installation of the

134 Ex. MSO-Tab D at 22:2-3.

135 Id. at 21:6-7.

136 Id. at 19:11-18.
137 Ex. NYI-44.

138 Ex. NYI-38 at 20:7-21:14. 139 Ex. NYI-44 at 39.

Original PAR. Section 4.3 of the MEN Study states that the procedure employed will be “to
study the impact on transfer capability of the new phase angle regulator transformers…”140
By contrast, a true interregional planning effort would have involved multiple utilities across the Lake Erie region seeking a joint solution, or a collaboration among the reliability councils to the same end. Instead, it is clear from the “Scope of Study” in Appendix D that the installation by Detroit Edison and Ontario Hydro of the Original PAR and the Hydro One PARs was considered a fait accompli: (i) the study proceeds from the fact that “In January 1999,
Detroit Edison and Ontario Hydro announced plans to modify the existing interconnection
facilities between Michigan and Ontario;”141 and (ii) the study recognized that those entities
were proceeding with those plans in the very near future by stating “[t]he incorporation of Phase
Angle regulators on all Michigan-Ontario Tie lines is intended to be complete by summer of the
year 2000.”142

Mr. Smith’s testimony that the MEN Study was not a joint planning study was not rebutted by the Joint Applicants.

In Exhibit MSO-Tab D MISO witness Chatterjee states that the Replacement PARs were
planned in the MISO’s Market Transmission Expansion Planning (“MTEP”) process.143 The
planning process to which Mr. Chatterjee refers (MTEP06) occurred wholly within the MISO
structure,144 and without participation by NYISO.145 MISO subsequently admitted that the
Replacement PARs were not jointly planned with NYISO or PJM. MISO’s planning process

140 Ex. NYI-44 at 16.

141 Ex. NYI-44 at 15.
142 Ex. NYI-44 at 39.

143 Ex. MSO-Tab D at 20:1-18. 144 Id. at 22:3-6.

145 Ex. NYI-45 at 1.

requires that all parties that are subject to an allocation of the costs of a transmission facility be
provided an opportunity to participate.146 In its response to data request NYISO/MISO 1-28,
MISO admitted that MISO never asked or invited the NYISO to discuss the design, costs or cost
allocation for the Replacement PARs (as part of MISO’s MTEP06 process, or otherwise).147
MISO also admitted that NYISO has never participated in MISO’s MTEP planning process.148
In an August 24, 2010 e-mail from MISO witness Chatterjee to other MISO personnel, Mr.
Chatterjee stated that “We did not do a coordinated study with PJM to approve the [Replacement
PARs] project.”149

Because the MI/ON PARs were not jointly planned with NYISO, PJM, NYISO’s

stakeholders or PJM’s stakeholders, NYISO and PJM had no say in the design or decision to

construct the Original PAR or the Replacement PARs. As discussed in Sections IV.A and IV.B of this brief, Commission precedent and policy (both pre- and post-Order No. 1000) preclude a utility or region from charging neighboring utilities or regions for the costs of facilities that were not jointly planned. Accordingly, the Joint Application should be rejected insofar as it seeks to charge NYISO, PJM, or their customers.

146 Ex. NYT-8 at l.

147 Ex. NYT-10 at 1.
148 Ex. NYI-45 at 1.
149 Ex. NYT-2 at 1.

RATE ISSUES

IV. WHETHER THE ALLOCATION OF THE COSTS OF THE ITC PARS TO

NYISO AND PJM, AND THE LEVEL OF SUCH ALLOCATIONS, IS JUST,

REASONABLE AND NOT UNDULY DISCRIMINATORY OR PREFERENTIAL
UNDER THE FEDERAL POWER ACT AND THE APPLICABLE COMMISSION
POLICIES, ORDERS AND PRECEDENT THEREUNDER (INCLUDING BUT
NOT LIMITED TO THE POLICIES, IF APPLICABLE, CONTAINED IN ORDER
NO. 1000)?

A. Acceptance of the Joint Application’s Proposal to Charge NYISO and PJM

Would Violate Applicable Commission Precedent

Commission precedent addressing “postage stamp” rates and recovery of “sunk”

transmission costs requires the rejection of MISO’s and ITC’s proposal to allocate to the NYISO
and PJM regions a share of the costs of ITC’s Replacement PARs. Costs ITC incurred to
construct the Replacement PARs are not eligible for allocation outside the ITC transmission zone
because the Replacement PARs were not constructed as part of an inter-regional planning
process that included NYISO, PJM or the stakeholders of these regional organizations. In
addition, it would be unjust, unreasonable, unduly discriminatory, unduly preferential and unduly
prejudicial to allocate the costs of the Replacement PARs using a license plate rate within the
MISO region, but using a super-regional postage stamp rate to allocate the costs of the same
facilities outside the MISO region.

1. Introduction to Postage Stamp and License Plate Rate Terminology,

and the Difference Between “Zones” and “Regions”

The Commission has described the fundamentals of license plate and postage stamp rates
in a number of orders. “Under 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 [transmission]
customer. A customer does not pay for other transmission facilities [located] outside of the zone,
even if the customer engages in transactions that rely on” facilities located outside the zone

where it is located, but within the same overall region.150 “The use of license-plate rates is

essentially the same as allocating existing system costs to the parties for whom the investment
was originally made.”151 “Consider that registering a car in one state, paying that state’s fees,
and obtaining a license plate from that state, allows that car to be driven on the roads and
highways of all other states.”152 Accordingly, the license plate rate each customer pays reflects the cost of existing transmission facilities within the zone (traditional utility service territory)
where it is located. The license-plate rate is also known as “zonal rate.”
Under a postage stamp rate design, all transmission service customers in a region pay a uniform rate per unit of service, based on the aggregated costs of all transmission facilities in the region153 regardless of the contractual origin or destination of the electricity transmitted. Under a postage stamp rate, every customer in the region pays the same average rate regardless of the cost caused or benefit derived from a particular transaction.

When used in the context of discussing license plate and postage stamp rates, a “region” represents the service territory of an ISO or RTO and a “zone” is, generally speaking, the
traditional transmission service territory of each transmission owner within a region.154

150 PJM Interconnection, L.L.C., Order On Rehearing And Compliance Filing, Opinion No. 494-A, 122 FERC ¶ 61,082 at n. 2 (2008) (“Opinion No. 494-A”).

151 Opinion No. 494-A at n. 28.

152 Regional Transmission Organizations, Order No. 2000 at n. 619, FERC Stats. & Regs. ¶ 31,089 (1999) (“Order No. 2000”), order on reh’g, Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 (2000), aff’d sub nom. Pub. Util. Dist. No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).

153 PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ¶ 61,063 at P 18 (2007) (“Opinion No. 494”), order on reh'g, Opinion No. 494-A, 122 FERC ¶ 61,082 (2008); see also Midwest Independent Transmission System
Operator, Inc., 114 FERC ¶ 61,106, order on reh’g., 117 FERC ¶ 61,241 (2006); Opinion No. 494-A, at n. 4;
Opinion No. 494, at n. 2; and American Electric Power Service Corp. v. Midwest Independent Transmission System Operator, Inc., et al., 122 FERC ¶ 61,083 at n. 30 (2008).

154 Opinion No. 494 at PP 1-3.

2.Even For Cost Allocation Within A Single ISO/RTO Region, The

Commission Has Placed Strict Limits on Cost Sharing

The Commission’s traditional default cost allocation mechanism within a single ISO or RTO 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 located outside the transmission provider’s zone. 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.155 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.156

a. The Commission has repeatedly rejected a shift to postage

stamp rates for existing transmission facilities, particularly where the facilities were constructed by individual
transmission owners to benefit their own customers

Commission decisions addressing the allocations of transmission costs in PJM and MISO
are directly applicable to the Joint Application. These decisions, which have repeatedly rejected
efforts to impose postage stamp rates for existing transmission facilities, strongly undercut the
proposal to reallocate a share of the costs of the Replacement PARs to the NYISO’s customers.

155 See PJM Interconnection, L.L.C., 96 FERC ¶ 61,060 at p. 61,220 (2001); Cleco Power LLC, et al., 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).

156 Opinion No. 494 at P 4.

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.157

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.”158 The Commission explained that because “transmission
owners in PJM built their existing infrastructure primarily to accommodate the needs of their
own customers,”159 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
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.”160
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”161 as part of a region-wide planning process. Instead, as noted above, the transmission facilities were

157 Opinion No. 494 at P 49.

158 Id. at P 50.

159 Id. at P 51.
160 Id.

161 Id. at P 54.

constructed by each individual transmission owner for the benefit of its 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 from the constructing transmission owner’s transmission
customers.

The third factor involves economic efficiency, and the provision of appropriate incentives
for construction of new transmission facilities. The Commission stated 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.”162 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.163

The fourth factor is the fact that “[a]n abrupt shift away from license plate rates

would . . . result in inequities within PJM.”164 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.165

Each of the factors listed above dictate against the Joint Applicants’ cost-sharing

proposal. First, as explained in Section III.B.2 of this initial brief, the Original PAR and the

162 Id. at P 53.

163 Id.

164 Id. at P 57.
165 Id.

Replacement PARs were constructed to benefit Ontario and Detroit Edison/ITC customers, and
to facilitate trading between Michigan and Ontario. Second, as explained in Section III.D of this
initial brief, the Replacement PARs were not planned and constructed to maximize benefits
across a combined MISO, PJM, IESO and NYISO region under a planning process that covered
a combined MISO, PJM, IESO and NYISO region. As explained in Section IV.A of this initial
brief, the Replacement PARs were included in the MTEP06, which is the planning process for
(only) the MISO region, but they were not determined to be eligible for broad postage stamp cost
allocation, even within the MISO region. Third, the costs of the Replacement PARs are sunk
costs: the construction of the Replacement PARs was nearly complete at the time the Joint
Application was submitted. 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.166 Similar to the arguments made by MISO and ITC in this
case, AEP argued that its existing high-voltage transmission facilities in the combined

166 See American Electric Power Service Corp. v. Midwest Independent Transmission System Operator, Inc., et al., 122 FERC ¶ 61,083 (“AEP II”), order on rehearing, 125 FERC ¶ 61,341 (2008).

PJM/Midwest ISO region provided substantial benefits to customers outside of AEP’s zones, and
that those customers should therefore bear a portion of the costs of AEP’s existing facilities.167
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 prospectively plan the construction of new 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.”168 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.”169 By “contrast, decisions to build [AEP’s] existing facilities were not made as
part of any regional planning process.”170 As Section III.D of this initial brief demonstrates, the
Original PAR and Replacement PARs were not planned in any joint planning process that
included the NYISO or PJM regions.

The Commission also explained that “reallocating the cost of existing facilities would

neither provide economic efficiencies nor promote the goal of increasing necessary transmission investment.”171

167 See AEP II at P 31. 168 Id. at P 96.

169 Id.

170 Id.
171 Id.

The Commission next addressed AEP’s arguments that its facilities were, in fact, planned
on a regional basis that justified a postage stamp rate. AEP’s arguments were similar to the
argument that MISO and ITC have made that the MEN Study172 somehow shows that the
Original PAR and Replacement PARs were the product of regional planning.173 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.”174 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.”175

The Commission also addressed the general argument that customers throughout PJM

and the MISO 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.”176

172 Ex. NYI-44.

173 As NYISO witness Zachary Smith explained in Exhibit NYI-38 (at 20:2-21:14), and as discussed in Section III.D
of this brief, the MEN Study referenced in the Joint Application was not a multi-regional planning study to
determine whether the Original PAR and the Hydro One PARs were necessary, appropriately designed, or whether
they were the best, most cost effective, or the most appropriate solution to construct. The MEN Study did not
discuss or address the allocation of the costs of the Original PAR among the regions that participated in the study.
The MEN study did not seek input from the New York Power Pool (predecessor to the NYISO) or PJM regarding
whether or not the MI/ON PARs should be constructed. Instead, the MEN study was initiated “[i]n order to ensure
continued reliable operation of the interconnected regional systems” following the proposed installation of the
Original PAR. Ex. NYI-44 at 39.

174 Id. at P 98.

175 Id.

176 AEP II at P 133.

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 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.”177

The testimony of MISO witness Chatterjee in Exhibit MSO-Tab D attempts to distinguish
the facts of AEP II from the circumstances presented in this proceeding,178 but fails to do so.
First, Mr. Chatterjee claims that the AEP II holding does not apply because Replacement PARs
were facilities not yet in service at the time the Joint Application was submitted, 179 suggesting
that the Replacement PARs are not “existing facilities” under the Commission’s cost allocation
rules. In Section IV.A.2.b.i of this initial brief, the NYISO explains that the Commission’s
determination is based on the developing utility’s reasonable cost allocation expectations at the
time a transmission facility is planned and constructed, not whether the developing utility
submitted a new and unexpected cost allocation proposal shortly before construction of the
transmission facility was completed.

Second, Mr. Chatterjee claims that, while the AEP facilities were constructed mainly to benefit AEP’s region, the Replacement PARs will address loop flows benefiting the combined control areas.180 However, as discussed in Section III.B of this initial brief, the evidence shows that the Original PAR and Replacement PARs were built to serve the interests of Michigan and Ontario utilities and their electricity customers.

177 Id.

178 Ex. MSO-Tab D at 24:13-27:12. 179 Id. at 25:13-26:3.

180 Id. at 26:4-8.

Finally, in an attempt to direct attention away from MISO’s and ITC’s failure to jointly
plan the Replacement PARs with the NYISO and PJM regions, Mr. Chatterjee asserts that while
the Commission found no evidence to show that the facilities at issue in AEP II were planned to
address regional needs of either the MISO or PJM wholesale markets and therefore the planning
was not comparable to each RTO’s regional planning process, there is ample evidence in the
record of this proceeding to support the MI/ON PARs’ ability to address Lake Erie loop flow.181
Mr. Chatterjee’s testimony attempts to dance around the joint planning requirement
because, as demonstrated in Section III.D of this initial brief, the Original PAR and Replacement
PARs were not planned jointly with PJM and NYISO. Setting aside the NYISO’s multiple
responses to MISO’s and ITC’s “benefit” allegations, the MI/ON PARs’ ability to reduce Lake
Erie loop flow is not even pertinent under the AEP II holding. In AEP II, the Commission
recognized that the transmission facilities that AEP was seeking to allocate to PJM and MISO
customers provided benefits to those customers, but concluded, “consistent with the
Commission's findings in Opinion No. 494, 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.”182 The Commission’s reasoning in AEP II should be followed in this
proceeding.

In sum, AEP II states that the costs of the Replacement PARs, 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. The MISO reached a similar conclusion

181 Id. at 26:9-27:12.

182 AEP II at P 133.

when ITC asked MISO to agree to re-allocate the cost of the PARs to other MISO customers.183 There is no reason for the Commission to reach a different conclusion with regard to the proposal to allocate a portion of the cost of the Replacement PARs outside the MISO region to the
NYISO’s customers.

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
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

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. The Commission observed that the “reallocation of costs for existing
facilities will not affect a transmission owner’s future decision about whether and where to build

183 See Section IV.A of this initial brief; Ex. NYI-2 at 1.

new transmission facilities.”184 Rather, “it is the cost allocation method for new transmission facilities that influences the incentive to invest.”185

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.186 As discussed in Section
III.D of this brief, this is exactly the situation in which the NYISO and its customers find
themselves. Neither the Original PAR nor the Replacement PARs were jointly planned with
NYISO and its customers.187

In Exhibit MSO-Tab D, MISO witness Chatterjee argues that the Replacement PARs
were not yet in service at the time the Joint Application was submitted, suggesting that the
Replacement PARs are not “existing facilities” because the instant proceeding was initiated
before the Replacement PARs began operating.188 However, the Commission’s decisions
requiring license plate cost allocation for transmission facilities are not limited to transmission
facilities that have already been placed in service. In the case of the MISO’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.189 The

184 Opinion No. 494 at P 53.

185 Id.

186 Id. at P 84.

187 Ex. NYT-10 at 1.

188 Exhibit MSO-Tab D at 25:13-26:3.

189 Midwest Independent Transmission System Operator, Inc., 117 FERC ¶ 61,241 at P 96 (2006) (“MISO”).

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.”190 The key issue is not whether the underlying transmission facility is already in service before a postage stamp cost allocation
method takes effect. The key is whether the developer of a transmission facility moved forward in its effort to develop and construct that facility without any assurance that the project would be a candidate for (inter)regional cost-sharing.191

There was no postage stamp rate in place for allocating costs across the combined

Midwest ISO-PJM-NYISO region in 1998,192 when Detroit Edison assumed a contractual

obligation to construct the Original PAR, or in 2007, when ITC assumed a contractual obligation to construct the Replacement PARs.193 As noted above, ITC has admitted that it did not ask the NYISO to contribute to the cost of the Replacement PARs until after it had already begun its efforts to construct the Replacement PARs.194

As discussed in Section IV.D of this initial brief, the Replacement PARs were approved
for construction in the MISO region’s transmission planning process in MTEP06. The costs of
the Replacement PARs did not qualify for region-wide cost sharing as a baseline reliability
project.195 Instead, the costs were allocated to ITC’s customers under a license plate rate design:
MISO’s Attachment O rate for the ITC zone.196 MISO treated the Replacement PARs as

190 Id.

191 Id. at PP 86, 96.
192 Ex. NYI-48.
193 Ex. NYI-49.
194 Ex. NYT-11 at 1.

195 Tr. 305:19-23; Ex. PJM-9 at 1 (Table 1.4-3 to the MTEP06 report).

196 Ex. NYI-51 at 19 (MTEP06 Appendix A at 19 (showing project ID 1308 as not having a “Y” (for “Yes”) in the last two columns for cost-sharing and postage-stamp)).

existing facilities for purposes of the MTEP planning process and for purposes of cost allocation
within MISO because the Replacement PARs are like for like replacements for the Original
PAR.197 MISO has repeatedly determined that, within the MISO region, the cost of the
Replacement PARs should not be reallocated to customers outside the ITC transmission zone.198
ITC did not propose or seek to allocate the costs of the Replacement PARs to customers located outside the MISO region in 2006. ITC first suggested to the Commission that NYISO and its customers should share in the costs of the PARs in August 2009,199 and did not approach NYISO about it until October or November of 2009.200 There was no postage stamp rate in
place for allocating costs across the combined MISO-PJM-NYISO region in 1998, when Detroit
Edison assumed a contractual obligation to construct the Original PAR,201 or in 2007, when ITC
assumed a contractual obligation to construct the Replacement PARs.202 ITC moved forward
with the construction of the Original PAR and the Replacement PARs without any assurance that
the Replacement PARs were candidates for multi-regional cost-sharing. The December 23, 2009
letter from ITC (included as Attachment E to the January 12, 2010 NYISO report on Broader
Regional Markets) that asks for contributions from NYISO and others explicitly states in the first
paragraph that ITC has already “installed new PARs.”203 In addition, as explained in Section
IV.D of this initial brief, it would be unduly discriminatory, unduly preferential, unduly
prejudicial, unjust and unreasonable to allow a license plate cost allocation method to be used to

197 See Ex. PJM-11 (data response to NYISO/ITC 1-14).

198 See, e.g., Ex. NYT-2 at 4.

199 See ITC’s Answer In Opposition to Request for Clarification, Docket No. ER08-1281-000 at 3 (August 31,
2009).

200 See Ex. S-4 at 13, 25-26. 201 Ex. NYI-48.

202 Ex. NYI-49.
203 Ex. S-4 at 25.

allocate the cost of the Replacement PARs within the MISO region, while applying a postage
stamp rate allocation method outside the MISO region for the same transmission facilities.

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.”204 In its orders on 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.”205

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. AEP’s
collaborations with its neighboring utilities were 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.”206

204 AEP II at P 99. See also Opinion No. 494 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.”).

205AEP II at P 99.
206 Id. at P 98.

3.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 II case are present in this proceeding,
and none of the prerequisites to the application of a postage stamp rate have been satisfied.

a. The Replacement PARs are existing facilities for which the

type of cost allocation sought in the Joint Application is not available

One of the criteria for regional cost sharing is that the regional cost sharing mechanism
be in place before the underlying transmission assets are planned and constructed. In the 2006
MISO order, the Commission addressed MISO’s proposed institution of its transmission
expansion cost allocation policy that allocated and recovered costs associated with new
transmission projects and system upgrades within the MISO region. One of the issues presented
was whether certain projects were appropriately being excluded from cost sharing. In finding the
MISO’s proposed “Excluded Projects List” appropriate (such that a postage stamp rate would not
apply to those projects), the Commission noted that the proponents of the excluded projects
“moved forward with [their] projects without any assurance that such projects would be
candidates for regional cost sharing.”207

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.

207 MISO at P 96.

ITC proposed and MISO approved the construction of the Replacement PARs in the

MTEP06.208 ITC signed a contract with Hydro One that obligated ITC to construct the

Replacement PARs, at its own expense, in 2007.209 The first of the two PARs was delivered in
October 2008, and the second was delivered in the fall of 2009.210 Both had been installed by
December 2009.211 ITC first suggested to the Commission in August 2009 that NYISO and its
customers should share in the costs of the Replacement PARs.212 ITC first asked the NYISO to
pay directly in October or November 2009.213 ITC’s request that the NYISO contribute occurred after the completion of the MISO’s planning process, after the construction of the Replacement
PARs was essentially complete, and over two years after ITC assumed a contractual obligation to construct the Replacement PARs.214

As shown in Section IV.A.1.a.ii of this initial brief, the Replacement PARs are existing
transmission facilities for which the type of broad cost allocation proposed by MISO and ITC is
prohibited. Applicable Commission precedent requires that MISO’s and ITC’s proposal to
allocate a portion of the cost of ITC’s Replacement PARs to the NYISO’s customers be rejected.

b. ITC constructed the Original 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

208 Ex. NYI-50 at 11, 19, NYI-51 at 7.

209 Ex. NYI-49 at 10, 12 (§§ 6.1.1 and 10.3). 210 Ex. S-3 at 6.

211 See Ex. S-4 at 25.

212 See ITC’s Answer In Opposition to Request for Clarification, Docket No. ER08-1281-000 at 3 (August 31,
2009).

213 See Ex. S-4 at 25.

214 The 2007 Facilities Agreement is Ex. NYI-49.

primarily by individual utilities to serve their own internal needs and were financed by those utilities.”215 It is for this reason that the Commission, in its rehearing order on 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.”216

As described in detail in Section III.B of this initial brief, a review of the “original basis” for both the Original and Replacement PARs shows that they were designed and constructed primarily for the benefit of Ontario and Detroit Edison/ITC customers. Accordingly, reallocation of the costs of these facilities to NYISO and PJM is inappropriate.

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 Joint Application

Under the Commission policy discussed above, 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.”217 Informal
discussions or collaborations are not sufficient to satisfy this criterion.218 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.219

215 Opinion No. 494 at P 50.

216 125 FERC ¶ 61,341 at P 41. 217 AEP II at P 99.

218 Id.

219 AEP II at P 99.

The Commission carried this policy forward into Order No. 1000 when it adopted Cost
Allocation Principle 4. Cost Allocation Principle 4 requires “The allocation method for the cost
of an intraregional facility must allocate costs solely within that transmission planning region
unless another entity outside the region or another transmission planning region voluntarily
agrees to assume a portion of those costs.”220 One of the chief rationales for this principle was
(as explained in Order No. 1000-A) that “[e]ntities outside of a region may not be capable of
being full participants in each and every region’s transmission planning process in which they
could potentially be allocated transmission costs. Unilateral allocation of costs to them thus
could undermine rather than promote the linking of cost allocation and transmission
planning.”221

As demonstrated in Section III.D of this initial brief, MISO and ITC have offered no evidence of the existence of a formalized, regional planning process that includes the MISO, NYISO and PJM regions, much less evidence that such a planning process was used to plan the Original or the Replacement PARs.

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 Joint Applicants have failed to demonstrate that the Replacement PARs were planned and constructed pursuant to a formalized, region-wide planning process. In light of these circumstances, there is no basis under applicable Commission orders for granting the cost allocation proposed by MISO and ITC in this proceeding.

benefits, the costs of which are recovered through license plate
rates

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. On pages 39 and 40 of Exhibit NYI-1, NYISO witness Yeomans identifies
six transmission security benefits that interconnected transmission facilities, including free
flowing transmission lines, provide to neighboring ISOs and RTOs. The benefits Mr. Yeomans
identifies are: (1) reduced post contingency power flows; (2) improved pre- and post-
contingency transmission voltage performance; (3) improved dynamic and steady state
transmission stability performance; (4) improved post-disturbance frequency response;

(5) opportunities for reserve sharing protocols; and (6) opportunities for emergency power

purchases. As Mr. Yeomans explains, none of the mutual transmission security benefits he

identifies require a PAR, are unique to a PAR-equipped interconnection, or are enhanced by the installation of a PAR.222

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 (or across multiple regions) 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

222 Exhibit NYI-1 at 40:5-6.

approach is the correct approach, and it bars allocation of costs of the Replacement PARs to NYISO and its customers.

B. Acceptance of the Joint Application’s Proposal to Charge NYISO and PJM

Would Violate the Policies Expressed in Order Nos. 1000 and 1000-A

The Joint Application’s attempt to allocate Replacement PARs costs to NYISO and PJM violates the policies expressed in Order Nos. 1000 and 1000-A. Regional Cost Allocation
Principle 4 articulated in Order No. 1000 states:

The allocation method for the cost of a transmission facility selected in a regional transmission plan must allocate costs solely within that transmission planning region unless another entity outside the region or another transmission planning region voluntarily agrees to assume a portion of those costs.223

Regional Cost Allocation Principle 4 is consistent with the cost-allocation principles included in the then-pending Notice of Proposed Rulemaking issued June 17, 2010, which formed the basis for the Commission’s subsequent Order No. 1000:

The allocation method for the cost of an intraregional facility must allocate costs solely within that transmission planning region unless another entity outside the region or another transmission planning region voluntarily agrees to assume a portion of those costs.224

Order No. 1000-A rejected rehearing requests (including a rehearing request filed by a group that included ITC) asking the Commission to allow transmission providers to accomplish exactly what the MISO/ITC Joint Application proposes: the ability to submit a filing “to allocate [unilaterally the] costs of a facility to a neighboring region that benefits from it.” The
Commission’s ruling on these rehearing requests is set forth below:

We affirm Regional and Interregional Cost Allocation Principle 4. Accordingly,
we deny the arguments of those petitioners that ask us to expand the scope of Cost
Allocation Principle 4 to permit a transmission planning region where a new

223 Order No. 1000 at P 657.

224 Transmission Planning and Cost Allocation by Transmission Owners and Operating Public Utilities, Notice of Proposed Rulemaking, 75 Fed. Reg. 37884, 37905 at P 164 (2010) (“Transmission NOPR”).

transmission facility is located to allocate costs of the facility unilaterally to a

neighboring region that benefits from it. Such arguments fail to take into account the relationship between the Commission’s cost allocation reforms and the other reforms contained in Order No. 1000 and the need to balance a number of factors to ensure that the reforms achieve the goal of improved planning and cost
allocation for transmission in interstate commerce.225

The Commission explained in Order No. 1000-A that this approach “follows directly
from the requirement of Order No. 890 that transmission planning be open and transparent,”
promoting “ a close link between transmission planning and cost allocation and helps to ensure
fairness, which ultimately promotes successful transmission planning.”226 The Commission
warned in Order No. 1000-A that “[e]ntities outside of a region may not be capable of being full
participants in each and every region’s transmission planning process in which they could
potentially be allocated transmission costs. Unilateral allocation of costs to them thus could
undermine rather than promote the linking of cost allocation and transmission planning.”227
Furthermore, Order Nos. 1000 and 1000-A acknowledged that, although the
Commission’s policy may allow some beneficiaries to avoid cost responsibility, it was
“important to balance the possibility that some beneficiaries could escape cost responsibility
against the larger goal of linking cost allocation with the transmission planning process for the
purpose of improving that process.”228 Thus, even if the Commission were to determine that the
NYISO receives some benefit from the Replacement PARs, Commission policy prohibits
MISO/ITC from allocating any resulting costs to a neighboring region like the NYISO, without
the NYISO’s consent.

225 Order No. 1000-A at P 707.
226 Order No. 1000-A at P 709.
227 Id.

228 Id. at P 710.

Regional Cost Allocation Principle 4, as articulated in Order No. 1000, aligns with prior Commission precedent such as its Opinion No. 494 and AEP II order, as discussed in detail in Section IV.A of this brief.

The Joint Application directly and unambiguously violates the policies expressed in

Regional Cost Allocation Principle 4 described in Order No. 1000, and affirmed in Order 1000-
A, by proposing to unilaterally allocate costs incurred for a transmission facility constructed in
one transmission planning region’s plan (i.e., MISO) - and located in that region - to another
planning region (i.e., NYISO) without the consent of the NYISO or its customers. The
Replacement PARs are located in the MISO. The MISO does not share a common border with
the NYISO. The NYISO has not - in the words of Regional Cost Allocation Principle 4 -
“voluntarily agree[d] to assume a portion of the costs” MISO and/or ITC have incurred for the
ITC PARs. The Joint Application thus should be rejected because it is inconsistent with
Commission policy.

C. The Joint Application Improperly Shifts Costs Caused by IESO and Its

Customers to NYISO and PJM, Resulting in Undue Discrimination

Joint Applicants argue that it would be unjust and unreasonable to require one set of

market participants to pay for costs that are caused by other market participants.229 MISO and
ITC claim that the goal of their cost allocation proposal is to make sure that “the cost burden”
accurately reflects the cost causation principle “by fairly allocating the cost of the New PARs to
the other regions that cause the loop flow issue.”230 MISO witness Chatterjee asserts that the
Commission has stated “that a cost allocation where certain market participants are required to

229 See Ex. MSO-Tab D at 29:9-16. MISO and ITC have not alleged or shown that NYISO or its customers are

MISO market participants. Rather, they have admitted that the NYISO and its customers are not MISO customers. See Ex. NYI-5 at 1.

230 Joint Application Transmittal Letter at 5.

pay for … costs caused by other market participants although both sets of market participants

engage in activities that cause the additional costs, is unjust and unreasonable.”231 MISO witness
Webb also asserts that “just and reasonable rates require that customers pay only those costs that
are attributable to them,”232 and reaches the conclusion in his adopted direct testimony that “a
cost allocation methodology that allocates costs to one set of market participants, but exempts
others engaged in the same cost causing behavior is unjust and unreasonable.”233
The Joint Applicants proposed cost allocation method patently violates the principles that they espouse. MISO’s DFAX analysis indicates that the IESO region’s generation-to-load flows are the single largest contributing factor to Lake Erie loop flows, and that IESO’s generation-to-
load contribution causes more than half (55%) of all Lake Erie loop flow.234 MISO witness
Chatterjee recognized at hearing that IESO is “part of the cost causation….”235 Nonetheless,
MISO and ITC are not proposing to require IESO or its customers to bear any of the costs that
the MISO’s DFAX analysis indicates that the IESO region causes; to the contrary, MISO and
ITC propose to required NYISO’s and PJM’s customers (as well as ITC customers) to pay for
costs that are caused by IESO. The proposal to charge NYISO and PJM customers for costs that
MISO has determined are caused by IESO and its customers is unjust, unreasonable and unduly
discriminatory to the NYISO and its customers.

A Commission order addressing circumstances similar to those presented in this

proceeding underscores that conclusion. In Ameren Servs. Co. v. Midwest Indep. Transmission

231 Ex. MSO-Tab D at 29:9-16.

232 Ex. MSO-Tab D at 31:20-32:1 citing Ameren Services Company, 125 FERC ¶ 61,161 at P 44 n.39 (2008) (citing Enron Power Marketing, Inc., 119 FERC ¶ 63,013 at P 157 (2007) (citing KN Energy, Inc. v. FERC, 968 F.2d
1295,1300 (D.C. Cir. 1992).

233 Ex. MSO-Tab D at 32:4-6.

234 Ex. NYT-1, at 17:11-13; see Ex. MSO-1B, IESO_Gen, Total Participation. 235 Tr. 343:2-4.

Sys. Operator, Inc.,236 the Commission held that a public utility may not exclude from cost

allocation a customer (or a class of customers) that caused the public utility to incur such costs in the first place. In Ameren, the Commission granted a complaint to require MISO to allocate
Revenue Sufficiency Guarantee (“RSG”) costs to virtual bidders because “the Commission
concluded that virtual supply offers can cause RSG costs to increase.”237 The Commission
affirmed on rehearing that failing to assess such costs to virtual bidders meant the rate MISO
assessed other customers was unduly discriminatory.238 Similarly, IESO contributes to the cost causation that created the need for the Replacement PARs. Rather than allocate to IESO the
costs it caused, MISO allocates those costs to the NYISO and PJM—the very type of
discrimination the Commission prohibited in Ameren.

The rationales offered by the Joint Applicants for charging NYISO and its customers for costs that they do not cause are that: (i) IESO is non-jurisdictional to the Commission (so an attempt by ITC and MISO to forcibly recover costs from Canadian customers that they have not agreed to pay is unlikely to succeed), and (ii) Hydro One customers paid the costs of the Hydro One PARs, so they should bear no obligation to pay any portion of the costs of the Replacement PARs. Both rationales should be rejected.

236 121 FERC ¶ 61,205 (2007) (“Ameren”). 237 Id. at P 81.

238 Ameren Servs. Co. v. Midwest Indep. Transmission Sys. Operator, Inc., 125 FERC ¶ 61,162 at P 24 (2008). The Commission explained:

We agree with the complainants that the critical issue is whether any virtual supply offer can cause Revenue

Sufficiency Guarantee costs or whether only virtual supply offers of certain market participants can cause Revenue Sufficiency Guarantee costs - i.e., whether the existing rate is unduly discriminatory. In the Order on Revenue
Sufficiency Guarantee Complaints, the Commission considered the evidence in the record of Docket No. ER04-691, as sponsored by complainants, to provide a sufficient basis to find that the existing rate is unduly discriminatory. Since the central claim in the Revenue Sufficiency Guarantee Complaints is undue discrimination, we do not
consider a zone of reasonableness to be the correct metric for determining if the Revenue Sufficiency Guarantee
charge is just and reasonable. We also do not find that a cost of service study would add guidance as to whether the current rate is unduly discriminatory. Accordingly, the assertion that virtual supply offers do not cause Revenue
Sufficiency Guarantee costs does not persuade us to grant rehearing.

In 1998 and in 2007 ITC’s predecessor Detroit Edison and ITC negotiated

interconnection agreements with Hydro One’s predecessor Ontario Hydro and Hydro One to

construct the MI/ON PARs, including the Hydro One PARs, the Original PAR and the

Replacement PARs. Detroit Edison’s agreements with Ontario Hydro assigned cost

responsibility for the Original PAR to Detroit Edison; ITC’s agreement with Hydro One assigned cost responsibility for the Replacement PAR(s) to ITC.239 The agreements assigned cost
responsibility for the L51D and L4D PARs to Ontario Hydro/Hydro One.240 Neither NYISO nor PJM, nor any of their customers, were invited to participate in the negotiation of the cost sharing agreements that ITC and Hydro One voluntarily entered into.

Because ITC voluntarily entered into a cost sharing agreement with Hydro One that
addressed cost responsibility for the Replacement PARs in 2007, ITC’s inability to recover a
portion of the cost of the Replacement PARs from customers in the IESO control area is a
problem that is properly assigned to ITC. Unless ITC is able to convince Hydro One or IESO to
agree to pay for a portion of the cost of ITC’s Replacement PARs, ITC should be required to
absorb the costs that MISO’s DFAX analysis indicates are caused by IESO and its customers,
consistent with the contractual obligations that Detroit Edison and ITC voluntarily assumed.
This is a risk that ITC took when it planned and began constructing the Replacement PARs
without having planned them jointly and sought voluntary agreements with IESO/Hydro One and
the other regions for cost support. MISO witness Chatterjee recognized at the hearing that ITC
and Hydro One could have attempted to negotiate an agreement to have IESO share in the
costs.241

239 See Ex. NYI-48 at 2 § 3.2 and NYI-49 at 12 § 10.3. See also Section III.B.1 of this initial brief.
240 Id.

241 Tr. 343:5-7.

With respect to the “crediting” argument, even assuming for purposes of argument that it
has merit, the Joint Applicants provided no evidence, in MISO witness Webb’s testimony or
otherwise, to show the costs of the Hydro One PARs or their proportionality to the share of
Replacement PARs costs that the DFAX method would assign to IESO’s customers. At hearing,
MISO witness Chatterjee specifically stated he had no knowledge regarding the amount of the
revenue requirement or investment for the Hydro One PARs or how Hydro One’s investment in
the Hydro One PARs compares to ITC’s revenue requirement for the Replacement PARs.242
Further, the “selectivity” of crediting IESO’s customers for their contribution to the costs of the Hydro One PARs alone should be rejected as unduly preferential and unduly
discriminatory. The Joint Applicants do not propose to give any credit to PJM and NYISO and
their customers for building PARs on their systems that also help control Lake Erie loop flow.
As demonstrated in the study performed by NYISO witness Smith that is described in Section
V.E of this initial brief, the PARs at PJM/New York border and other PARs in the Eastern
Interconnection tend to mitigate Lake Erie loop flows when they are being actively operated to
better control power flows.243 If the other PARs in the Eastern Interconnection were removed
from service, Lake Erie loop flow would be substantially higher than it is today.244 NYISO
witness Yeomans explained in testimony that the Replacement PARs do not provide unique
benefits that no other PARs can provide.245

In addition to denying NYISO and PJM a financial credit for the PARs they have

constructed, the Joint Applicants refused to give NYISO and PJM a financial credit for the costs

242 Tr. 345:24-346:8.

243 Ex. NYI-38 at 21:20-25:10. 244 Id., at 25:4-10.

245 Ex. NYI-1 at 40:10-18.

of designing and implementing the “Broader Regional Markets” initiatives246 that are designed to control or mitigate the effects of loop flow.247

For these reasons, if any Replacement PARs costs at all are permitted to be assigned to
NYISO, despite the myriad of reasons for which that should not occur, none of the costs that
MISO’s DFAX analysis indicates were caused by IESO should be reallocated to NYISO or its
customers.

D. It Is Not Just and Reasonable, and Is Unduly Discriminatory, to Charge

NYISO and its Customers for the Costs of the Replacement PARs When MISO Customers Outside the ITC Zone Are Not Being Charged

Joint Applicants argue that it would be unjust and unreasonable to require one set of

market participants to pay for costs that are caused by other market participants.248 MISO and
ITC claim that the goal of their cost allocation proposal is to make sure that “the cost burden”
accurately reflects the cost causation principle “by fairly allocating the cost of the New PARs to
the other regions that … cause the loop flow issue.”249 MISO witness Chatterjee asserts that the
Commission has stated “that a cost allocation where certain market participants are required to
pay for … costs caused by other market participants although both sets of market participants

engage in activities that cause the additional costs, is unjust and unreasonable.”250 MISO witness
Chatterjee also asserts that “just and reasonable rates require that customers pay only those costs

246 Tr. 351:22-352:1.

247 Ex. NYI-46 at 15:3-18:22.

248 See Ex. MSO-Tab D at 29:9-16. MISO and ITC have not alleged or shown that NYISO or its customers are

MISO market participants. Rather, they have admitted that the NYISO and its customers are not MISO customers. See Ex. NYI-5 at 1.

249 Joint Application Transmittal Letter at 5. 250 Ex. MSO-Tab D at 29:9-16.

that are attributable to them,”251 and reaches the conclusion in his adopted direct testimony that “a cost allocation methodology that allocates costs to one set of market participants, but exempts others engaged in the same cost causing behavior is unjust and unreasonable.”252

Contrary to the Joint Applicants’ cost causation and allocation theories, and the cost

responsibility determined by MISO’s DFAX study, the Joint Application does not propose to

assign any share of the cost of ITC’s Replacement PARs to MISO customers outside the ITC

zone, despite the fact that MISO’s DFAX study indicates that MISO areas and customers located outside ITC’s region contribute to Lake Erie loop flows.253 The Joint Applicants’ proposal to exempt all MISO Transmission Owners and customers that do not pay ITC’s zonal “Attachment O” rate from any responsibility for the cost of the MI/ON PARs, while at the same time asking NYISO and PJM customers to pay for a portion of the cost of the Replacement PARs, is unjust, unreasonable, unduly preferential, unduly prejudicial and unduly discriminatory.

In MTEP06, which incorporated the Replacement PARs into the MISO region’s planning
process as a MISO reliability project, the MISO 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, as confirmed by MISO witness
Chatterjee,254 the MISO 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

251 Ex. MSO-Tab D at 31:20-32:1 citing Ameren Services Company, 125 FERC ¶ 61,161 at P 44 n.39 (2008) (citing Enron Power Marketing, Inc., 119 FERC ¶ 63,013 at P 157 (2007) (citing KN Energy, Inc. v. FERC, 968 F.2d
1295,1300 (D.C. Cir. 1992).

252 Ex. MSO-Tab D at 32:4-6.

253 See Ex. MSO-1B identifying and calculating DFAX participation factors for 28 distinct MISO “Load Areas” (zones), only one of which (MISO_ITCT_Load) represents ITC’s Load Area.

254 Tr. 305:9-306:5.

service territory.255 The Joint Application Transmittal Letter confirmed that the Joint Applicants do not propose to allocate the cost of the Replacement PARs to MISO customers located outside the ITC pricing zone.256

The DFAX study (appropriately) does not limit its study of generation-to-load flows occurring within MISO to those occurring within the ITC zone. Instead, the DFAX study
includes and calculates participation factors for all MISO generation and loads, regardless of their location.257 MISO witness Mallinger admits that the “rest of MISO benefit[s] from the replacement PARs.”258

There is no cost-causation basis for exempting non-ITC MISO customers from cost

responsibility for the Replacement PARs. The Joint Applicants argue that costs caused by the
activities of one entity should not be paid by another. However, the Joint Applicants fail to
apply the cost allocation principles they espouse. For the reasons explained above, the Joint
Applicants’ proposal to exempt MISO customers that do not pay the ITC zonal rate from any
responsibility for the cost of the Replacement PARs, while at the same time charging customers
in the NYISO and PJM for a portion of the cost of the Replacement PARs, is unjust,
unreasonable, unduly preferential, unduly discriminatory, and should be rejected by the
Commission.

255 Ex. NYI-51 at 7, project 1308.

256 Joint Application Transmittal Letter at 16.

257 See Ex. MSO-1B identifying and calculating DFAX participation factors for 28 distinct MISO “Load Areas” (zones), only one of which (MISO_ITCT_Load) represents ITC’s Load Area.

258 Tr. 561:3-5.

E.The MISO-IESO Operating Instruction and MISO Tariff Provide Undue

Operating Preferences to MISO, IESO and Their Customers

The MISO-IESO Operating Instruction259 provides MISO and IESO nearly unlimited

discretion to suspend normal operation of the MI/ON PARs to address reliability concerns or

anomalous market results for the benefit of MISO and IESO customers; the same treatment is not available for reliability concerns or market anomalies that occur in the NYISO or PJM control areas. The Joint Application’s proposal to impose equal charges on entities that are not eligible or expected to receive equal benefits from the operation of the MI/ON PARs is unduly
preferential, unduly prejudicial and unduly discriminatory.

Proposed Attachment SS-1 to the MISO Tariff 260 would permit MISO to temporarily
suspend normal operation of the MI/ON PARs “in the event there are anomalous Midwest ISO
market results related to the PARs controlling the Michigan-Ontario Interface.” Proposed
Attachment SS-1 provides no such similar opportunity for the operation of the MI/ON PARs to
be suspended should NYISO or PJM encounter anomalies in their own markets that are affected
by, or related to the operation of the MI/ON PARs. Here again, the Joint Application’s proposal
to impose equal charges on entities that are not eligible or expected to receive equal benefits
from the operation of the MI/ON PARs is unduly preferential, unduly prejudicial and unduly
discriminatory.

These factors support the rejection of the Joint Application.

1.The Operating Instruction

The Operating Instruction is an agreement to which the NYISO is not a party. The

Operating Instruction was drafted and executed by MISO and IESO to provide a framework for

259 Ex. NYI-3 at 50-59.

260 Ex. MSO-Tab H (last page).

their coordinated operation of the MI/ON PARs. For the reasons set forth below and in the

testimony of NYISO witness Yeomans, the Operating Instruction reinforces MISO’s ability to
provide preferential treatment to MISO and IESO over the NYISO and PJM.261
First, neither the NYISO nor PJM has a direct say in how MISO will operate the
Replacement PARs or in how MISO and IESO will operate the MI/ON PARs. Section 1.0 of the
Operating Instruction states that MISO “will direct actions regarding the Michigan-Ontario
interconnection facilities in Michigan,” and that “MISO and IESO will jointly coordinate
operation of the Interconnection Facilities in accordance with this document regardless of the
location or the status at any time of any of the Interconnection Facilities.”262 Although the
Operating Instruction requires MISO and IESO to consult with the NYISO and PJM in a limited
number of circumstances, the ultimate decision-making authority rests with MISO and IESO in
every case.263

Second, several provisions of the Operating Instruction require, or at least permit, MISO
and IESO to operate the MI/ON PARs in a manner that favors themselves (and their own
customers) over the NYISO and PJM. For instance, Section 3.4.2 of the Operating Instruction
provides “[i]n order to prevent an emergency in MISO or Ontario, PARs may be adjusted such
that the Interface Deviation exceeds the Control Band providing other actions are utilized first,
time permitting.” There is no reciprocal provision that permits NYISO or PJM to request MISO
and IESO to operate the PARs to prevent emergencies in New York or PJM. Similarly, Section

3.5.1 of the Operating Instruction identifies steps MISO may take to address emergencies within MISO or Ontario:

261 Ex. NYI-1 at 20-23.

262 Ex. NYI-1 at 20:5-11; Ex. NYI-3 at 50. 263 Ex. NYI-1 at 20:13-17.

If the emergency is within MISO or Ontario, the PARs may be adjusted up to

Max Tap utilizing emergency thermal limits as appropriate….. If emergencies are declared in both MISO and Ontario, tap positions for the PARs shall be set in the position(s) that best mitigates, or assists with the mitigation of, the overall scope of the emergencies in both areas and that achieves, to the extent practical, a fair sharing of relief requirements between the areas.”

In contrast, a more restrictive set of rules in Section 3.5.2 of the Operating Instruction
applies to operating the MI/ON PARS to address emergencies that occur in the NYISO or PJM
territories, compared to the rules that apply to operating the MI/ON PARs to address
emergencies in MISO or IESO. Section 3.5.2.1 of the Operating Instruction provides that, for an emergency outside of MISO and Ontario, the PARs may be operated to assist with the
emergency only after, among other things, the non-MISO or Ontario parties (such as NYISO or PJM) have “taken all mitigating steps except voltage reduction and shedding of firm load” to
address the problem.” Section 3.5.1 does not impose the same mitigation obligation for
emergencies within MISO or IESO. In addition, Section 3.5.2 of the Operating Instruction
provides that, for emergencies outside of MISO or Ontario, “[t]he type of assistance shall be
agreed upon and directed by MISO and the IESO.”

The Operating Instruction also provides for MISO and IESO to suspend normal operation
of the MI/ON PARs to protect MISO and/or IESO customers in the event of unexpected
operational or market outcomes in their regions, but does not provide corresponding protection
for NYISO or PJM customers in the event of unexpected operational or market outcomes in their
regions. For instance, Section 4.0 of the Operating Instruction recognizes that “normal operation
of the PARs may result in unforeseen operational or market outcomes within MISO or the
IESO.”264 That section also states that: “Depending on the nature of the event, the most
appropriate or only mitigating action may be to suspend normal operation of the PARs, i.e.

264 Ex. NYI-3 at 54-55.

change the Interface Control Mode from Regulated Mode to Bypass Mode.” “Bypass Mode” is
defined in Section 2.0 as the state in which the PARs are physically bypassed or where in-service
PARs are at or near neutral tap and MISO and IESO are not attempting to control flows to the
Interface Schedule.265 Section 4.0 of the Operating Instruction provides that if MISO and IESO
agree to suspend normal operations, “[n]ormal operations of the PARs will remain suspended
until mutual agreement [between MISO and IESO] is reached to restore them to Regulated Mode
or regulatory action occurs and a subsequent resolution plan developed and implemented.”266
While that section states that suspension of normal PAR operation “[i]n the case of anomalous
market outcomes in either jurisdiction [i.e., MISO or IESO], will only occur after consultation
with other affected markets,” MISO and IESO retain the ultimate decision making authority.
The identified provisions of the MISO/IESO Operating Instruction grant an undue
preference to MISO, IESO, and their customers.

2.Attachment SS-1

As explained by NYISO witness Yeomans,267 proposed Attachment SS-1 to the MISO

tariff268 allows MISO to temporarily suspend normal operations of the MI/ON PARs in the event of anomalous MISO market results related to the MI/ON PARs. As confirmed by MISO witness Zwergel, Attachment SS-1 does not provide for similar potential suspension of the MI/ON PARs for anomalous market results related to the PARs in NYISO or PJM markets.269

265 Id. at 51.

266 Id. at 55.

267 Ex. NYI-1 at 23:5-22.

268 Ex. MSO-Tab H (last page). 269 Tr. 202:8-13.

MISO witness Zwergel’s claim that suspensions of MI/ON PARs operation in those

circumstances would have a “very short” duration270 belies the facts. First, as explained above, MISO has sole discretion to determine when to suspend normal operations under Attachment SS1, and Attachment SS-1 places no limitations on how long a suspension of normal operations
may last. Second, as Attachment SS-1 provides, MISO must “file a report with FERC describing the circumstances and changes required to resume normal operations of the PARs.” It could take MISO weeks to identify the changes required to resume normal operations, then prepare a report describing such changes, and even longer for the Commission to then act on that report. As
summed up by NYISO witness Yeomans at the hearing, that requirement to prepare a report
prevents the event from being short-lived.271

Market anomalies are rarely resolved quickly. A good example is the NYISO’s

experience in addressing the Lake Erie loop flow issue. Although the circuitous scheduling

problem began in January 2008, it took the NYISO until July 21, 2008 to study the issue, identify the problem, develop a solution, and file the market rule change with the Commission. It took well over a year for PJM and MISO to resolve their dispute regarding the market-to-market
redispatch provisions of the JOA in Docket Nos. EL10-45, EL10-46, and EL10-60.272 The
process of identifying, analyzing, and fixing a market defect is often complex and time-
consuming. It is not clear how or why Mr. Zwergel expects that suspension of MI/ON PAR
operations to address market anomalies would have a very short duration.

270 Tr. 201:8-11.

271 Tr. 833:4-8.

272 Midwest Independent Transmission System Operator, Inc. v. PJM Interconnection, L.L.C., Order Approving

Contested Settlement, 135 FERC ¶ 61,243 (2011). This case involved three consolidated complaints (two by MISO against PJM, one by PJM against MISO), filed in March and April 2010. The parties filed a settlement agreement on January 4, 2011. On March 9, 2011, the Settlement Judge reported to the Commission that the Settlement was partially contested. The Commission issued an order approving the settlement on June 16, 2011, which made the settlement agreement effective that day.

Proposed Attachment SS-1 grants an undue preference to the MISO and its customers and should be rejected by the Commission.

3.Proposal to continue charging NYISO and PJM while MI/ON PAR

operations are suspended

The tariff revisions that MISO submitted with the Joint Application, including proposed
Attachment SS-1, require MISO to continue charging NYISO and PJM customers for the cost of
the Replacement PARs, even when their operation has been suspended to address a market
anomaly or reliability issue in the MISO or IESO markets.273 This was confirmed by MISO
witness Zwergel.274 Thus, if MISO suspends the operation of the MI/ON PARs due to an
anomaly or reliability issue occurring in the MISO’s markets, the NYISO would continue to pay
for the operation of the Replacement PARs until the MISO market anomaly or reliability issue is
resolved without receiving any of the “benefits” that MISO and ITC claim the MI/ON PARs will
provide. MISO’s proposal to require the NYISO’s customers to pay for the operation of PARs
that are not in service is unjust and unreasonable and should be rejected by the Commission.

F. NYISO and PJM and Their Customers Were Not Given the Opportunity to

Participate in Deciding Whether to Construct the PARs or Whether to Pursue Other Options In Relation to Lake Erie Loop Flow

As Sections III.B.2, III.D and IV.C of this initial brief explain, NYISO and PJM and their
customers were not given the opportunity to participate in deciding whether the Replacement
PARs were a cost-effective element in a plan to address Lake Erie loop flow, or in negotiating
how the Replacement PARs should be designed, built or operated. This fundamental unfairness

- having costs forced upon them without any input - dictates rejection of the Joint Application.

273 See Ex. NYI-7, NYI-8, NYT-30, NYI-65.

274 Tr. 201:1-5.

The lack of collaboration regarding the Replacement PARs contrasts vividly with the

cooperation undertaken in connection with the “Broader Regional Markets” (“BRM”) initiatives.
As explained by NYISO witness Pike, the new BRM rules that the ISOs and RTOs are
developing will tend to reduce Lake Erie unscheduled power flow or permit the ISOs and RTOs
to mitigate the impacts on unscheduled Lake Erie power flows at a lower overall cost.275

V. WHETHER ANY ALLOCATION OF COSTS OF THE ITC PARS TO NYISO

AND PJM AND THEIR CUSTOMERS (OR OTHERS) IS APPROPRIATE

BASED ON COST CAUSATION/INCURRENCE AND/OR BENEFICIARY PAYS
PRINCIPLES OR ON OTHER CONSIDERATIONS, AND IF SO, IS THE
PROPOSED COST ALLOCATION ROUGHLY COMMENSURATE WITH (A)
THE EXTENT TO WHICH NYISO AND PJM AND THEIR CUSTOMERS (OR
MISO, IESO OR OTHERS) CAUSED ITC TO INCUR THE COSTS OF THE
INSTALLATION AND OPERATION OF THE ITC PARS (AND, TO THE
EXTENT RELEVANT, THE REASONS FOR WHICH DETROIT EDISON/ITC
INCURRED COSTS FOR INSTALLATION OF THE ORIGINAL PAR); AND/OR

(B) THE EXTENT TO WHICH NYISO AND PJM AND THEIR CUSTOMERS

(OR MISO, IESO OR OTHERS) WILL BENEFIT FROM (OR BE HARMED BY) THE INSTALLATION AND OPERATION OF THE ITC PARS?

Any allocation of costs of the Replacement PARs to NYISO and its customers is inappropriate, for the following reasons:

• MISO has stated that asserted “benefits” should not dictate the cost allocation for
the Replacement PARs;

• Even if benefits were deemed relevant for the cost allocation, MISO and ITC have
not submitted evidence demonstrating the New York customers receive any
benefit from the operation of the Replacement PARs;

• To the extent that benefits are relevant, control by the MI/ON PARs of

counterclockwise loop flow does not benefit, and may harm NYISO and its customers;

• ITC and its customers obtain transactional and reliability benefits that have not
been accounted for in the Joint Application, and that are not available to NYISO
or PJM customers;

• The MI/ON PARs do not provide unique benefits justifying allocation of the costs
of the Replacement PARs to NYISO and PJM; and

275 Ex. NYI-46 at 15:3-18:22.

• The incurrence of the costs for the Replacement PARs was not “caused” by
NYISO or its customers.

A. MISO Has Stated that the Replacement PARs Are a Reliability Project and,

As Such, Must be Allocated Based On Cost Causation, Not Potential Benefits

MISO witness Chatterjee’s rebuttal testimony states that, because the Joint Applicants
view the Replacement PARs as a “reliability project,” their cost allocation is not based on a
“beneficiary pays” theory.276 Mr. Chatterjee’s testimony on cross-examination confirmed that
the Joint Applicants’ proposed cost allocation for the Replacement PARs is based on a DFAX
study that uses a reliability planning approach, and appropriately so in his view.277 He also states that they did not perform a study using production cost models, as that would measure benefits of the PARs, a totally different aspect of cost allocation, inconsistent with his view of the
Replacement PARs as a reliability project.278

Because MISO witness Chatterjee states that the correct way to allocate costs for the Replacement PARs is based on cost causation through a DFAX study (due to its being a reliability project), all of the testimony and exhibits of MISO and ITC in this proceeding regarding alleged “benefits” accruing to NYISO and its customers are irrelevant in this
proceeding, and should be disregarded.

B. Even if Benefits Were Deemed Relevant for the Cost Allocation, MISO and

ITC Have Not Submitted Evidence Demonstrating that New York Customers Receive Any Benefit from the Operation of the Replacement PARs

As discussed in Section V.A of this initial brief, MISO witness Chatterjee has stated that
the cost allocation for the Replacement PARs should be based on reliability considerations (as
calculated under a DFAX analysis) rather than a “beneficiary pays” approach. Accordingly,

276 See Ex. MSO-1 at 19:10-12.

277 Tr. 408:24-409:2.

278 Tr. 409:8-17.

testimony and exhibits regarding alleged benefits to NYISO and its customers should be disregarded.

However, if benefits are determined to be relevant based on MISO’s and ITC’s references
to Commission statements that allocated costs need to be commensurate with benefits,279 MISO
and ITC have not performed or submitted studies that quantify the expected benefits to NYISO
and its customers from the operation of the Replacement PARs. Accordingly, the Joint
Applicants have not met their burden, and the Joint Application should be dismissed.
MISO witness Chatterjee admitted that MISO did not perform a study of the “benefits” of the Replacement PARs to NYISO or PJM.280 ITC similarly admitted that ITC did not create any documents relating to the economic and reliability benefits of the Replacement PARs.281 Both MISO282 and ITC283 stated that they had not performed an assessment or studies to identify
specific reliability criteria that are potentially violated by Lake Erie loop flow.
Instead of submitting actual studies or even a rough attempt to quantify benefits to each of the Lake Erie control areas for cost allocation purposes, MISO and ITC rely entirely on
conclusory statements such as MISO witness Mallinger’s observation that “[r]educing
unscheduled flows will benefit the ITC System and all other systems around Lake Erie, including
the NYISO and PJM systems”284, or on statements by NYISO indicating support for the
construction of the Replacement PARs.285 Those NYISO statements were premised on untested

279 See, e.g., Joint Application Transmittal Letter at pp. 5, 7.

280 Tr. 409:8-17.

281 Ex. NYT-44.

282 Ex. PTO-4 at 2.
283 Ex. PTO-5.

284 Ex. MSO-3 at 14:21-23.

285 See, e.g., Joint Application Transmittal Letter at 5-6 (“the NYISO continues to support the implementation of the New PARs”).

MISO and ITC claims regarding the capabilities of the MI/ON PARs. For example, the draft

“Broader Regional Markets, Long-Term Solutions to Lake Erie Loop Flow White Paper”286 that accompanied the NYISO’s January 12, 2010 filing in Docket No. ER08-1281-004 states that the MI/ON PARs are “expected to be capable of controlling Lake Erie Circulation by up to
approximately 600 MW in either direction.”287 However, as explained in Section IX.A of this initial brief, MISO and ITC failed to provide with their filing or rebuttal testimony or at hearing any evidence that the operation of the MI/ON PARs will provide the claimed loop flow control. Further, Section IX.B explains that data provided by MISO in discovery shows that the MI/ON PARs in fact are failing to provide that claimed control.

In sum, to the extent that the Joint Applicants espouse the principle that cost allocation
must be shown to be commensurate with benefits, MISO and ITC have failed to make that
showing.

C.To the Extent that Benefits are Relevant, Control by the MI/ON PARs of

Counterclockwise Loop Flow Does Not Benefit, and May Harm, NYISO and

Its Customers

NYISO witness Pike’s testimony identifies the limited circumstances in which effective, coordinated operation of all of the MI/ON PARs may benefit New York.288 New York could benefit when: (a) the MI/ON PARs are operated to reduce clockwise loop flows, and

(b) components of the New York State Transmission System (“NYSTS”) that are substantially

286 Ex. ITC-26.

287 Id. at 9 (page 8 of White Paper) (emphasis added).

288 Ex. NYI-46 at 21:18-23:19 (in addition to the potential benefit from the coordinated operation of all of the

MI/ON PARs discussed in this section of the initial brief, New York may also benefit if the MI/ON PARs are

successfully operated to better conform actual power flows to scheduled power flows and the PARs operation

consistently reduces the observed magnitude and volatility of loop flows around Lake Erie.); but see NYI-66

(according to MISO’s data Lake Erie loop flow has not become more predictable since MISO and IESO began

actively operating the MI/ON PARs on April 5, 2012. Lake Erie loop flow was outside the +/-200 MW bandwidth more than 44% of the time between April 5, 2012 and July 18, 2012 and the average of the absolute value of the Lake Erie loop flow was outside the +/-200 MW bandwidth, 214 MW, for the time period.).

affected by unscheduled Lake Erie power flows are constrained.289 On the other hand, New
York may be “harmed” by the operation of the MI/ON PARs when (x) the MI/ON PARs are
operated to reduce counterclockwise loop flows, and (y) components of the NYSTS that are
substantially affected by unscheduled Lake Erie power flows are constrained, or would become
constrained in the absence of counter-clockwise Lake Erie loop flow.290
As the data MISO provided in Exhibit NYI-66 indicates, Lake Erie loop flow has
predominantly flowed in a counter-clockwise direction in 2012.291 Counterclockwise Lake Erie
loop flow tends to relieve transmission congestion in New York.292 The data MISO provided in
Exhibit NYI-66 shows that, in 2012, the MI/ON PARs have operated to block counterclockwise
Lake Erie loop flow.293 As explained above, the operation of the MI/ON PARs to block
counterclockwise Lake Erie loop flow harms New York when components of the NYSTS that
are substantially affected by unscheduled Lake Erie power flows are constrained, or would
become constrained in the absence of counterclockwise Lake Erie loop flow.294
MISO’s DFAX analysis projects that generator-to-load contributions to Lake Erie loop flows will continue to tend to be counterclockwise into the mid-term future.295 In all three of the DFAX cases, peak, shoulder peak, and light load, the projected generator-to-load contributions are counterclockwise in direction.296 Contributions are projected to be significantly

289 Ex. NYI-46 at 22:8-13.

290 Ex. NYI-46 at 22:13-16.

291 See NYI-66 (the average Lake Erie loop flow between April 5, 2012 and July 18, 2012 was 48 MW

counterclockwise); Tr. 1039:13-14 (Mr. Pike states, “In 2012, the average loop flow has been counterclockwise”).

292 Tr. 996:4-14.

293 See NYI-66 (the average Lake Erie loop flow between April 5, 2012 and July 18, 2012 would have been 85 MW counterclockwise if the MI/ON PARs had not been in service).

294 Ex. NYI-46 at 22:13-16.

295 See Ex. MSO-1B.
296 See Ex. MSO-1B.

counterclockwise in the peak and shoulder peak cases.297 The net contributions of the four

participating ISO/RTO regions (MISO, NYISO, PJM, IESO) result in an overall

counterclockwise participation on the MI/ON Interface. Therefore, it is reasonable to expect

that, on average, the MI/ON PARs will continue to be operated to reduce the magnitude of

counterclockwise Lake Erie loop flow in the mid-term future. NYISO does not expect to benefit
from the operation of the MI/ON PARs to mitigate or reduce counter-clockwise Lake Erie loop
flow.

D. ITC and Its Customers Obtain Transactional and Reliability Benefits That

Have Not Been Accounted For in the Joint Application, and That Are Not Available to NYISO or PJM Customers

ITC and its customers obtain benefits from the Replacement PARs that have not been
accounted for in the Joint Application, and that are not available to NYISO or PJM customers.
These benefits are transactional/economic and reliability-related. It would be unjust and
unreasonable, and unduly discriminatory, to allocate the costs of the Replacement PARs based
on the ability of the MI/ON PARs to reduce Lake Erie loop flow, while ignoring reliability
benefits and other benefits that only ITC and MISO are expected to receive from the MI/ON
PARs operation. For this reason, the Joint Applicants’ proposed cost allocation should be
rejected.

1.Transactional Benefits

As demonstrated in Section III.B.2 of this initial brief, the Original PAR and

Replacement PARs were built to serve the transactional and economic interests of Michigan and
Ontario utilities and their electricity customers. Exhibit NYI-56 identifies the potential for
enhanced import capability into Michigan, from both the North (over the MI/ON Interface) and

297 See Ex. MSO-1B.

into Michigan from the South. These benefits to ITC customers have not been accounted for in the proposed cost allocation, and do not accrue to NYISO or PJM customers.

2.Reliability Benefits

As demonstrated below, ITC recognized a wide array of benefits for its own and the

MISO system (in addition to the transactional and economic benefits detailed in Section III.B.2), and these benefits were neither available to NYISO or PJM customers nor accounted for in the cost allocation proposed in the Joint Application.

The reliability benefits to the ITC service territory are well-documented. For example, MISO’s analysis from 2005 states:

Based on review of studies performed by ITC, and contingency review performed
by the Midwest ISO, we conclude that the B3N circuit is beneficial to reliability
to the ITC system…. In addition to the steady state overload conditions found,
the B3N circuit contributes to import capability for the ITC system. In the
Midwest ISO expansion planning study, MTEP 05, the Midwest ISO found that
the ITC system may not have sufficient import capability by 2009 to meet typical
loss of load expectation guidelines even with the B3N circuit in service. Clearly a
decision not to restore the B3N circuit would tend to aggravate the ITC system
resource reliability situation…. Midwest ISO believes that the number of
problematic conditions possible for which restoration of the B3N circuit would
provide enhanced operator flexibility and control argue for the need to restore this
circuit to operational status.298

A 2006 e-mail from MISO witness Chatterjee to ITC witness Capra, among others, states

that:

B3N Project: A study had been performed by ITC and reviewed by Midwest ISO
last year to study the impact of not replacing the failed phase shifter. It was
concluded that the phase shifter was beneficial to reliability of the ITC system. I
manually tested one of the contingencies in the report using the latest model with
reduced load forecast model and found the overload level to be pretty close to the
one in the report.299

298 Ex. PJM-15 at 4.

299 Ex. NYI-60 at 2 (emphasis added).

In addition, the MTEP06 report in which the Replacement PARs project was approved by MISO includes a substantial list of reliability benefits to the ITC system provided by the
Replacement PARs and the restoration of the B3N circuit:

The new phase shifting transformers will increase both MVA capability and phase
angle control. Midwest ISO reviewed the impact on system performance of
system operation with and without the B3N tie between ITC and IMO in service.
The review was based both on review of the recent 2010 study reported to ECAR
by ITC, and on independent review of contingent conditions. There a substantial
number of contingencies involving multiple elements that can result in significant
system overloads without the B3N circuit, which would not occur with the B3N
circuit available. Contingencies that have the most significant impact are shown in
the table below:

• 116% for St Clair - Cypress 120 kV & St Clair - Bunce Creek 120 kV DCT

• 112% for Jewell-Spokane 345-230-120 kV & Apache-Troy 120 kV

• 102% for Jewell-Spokane 345-230-120 kV & Dean (all)

• 101% for Caniff-Northeast 120 kV & Conners Creek (all)

• 130% for Greenwood 120-345 kV & Atlanta-Tuscola 120 kV

• 104% for Pontiac 345-120 kV #303 & Pontiac-Sunbird 120 kV

• 115% for Both St.Clair-Lambton lines

Following Phase 2 analysis, there were 129 outstanding violations, 7 of which were category B violations. Proposed projects were modeled to relieve the
thermal overloads on ITC system. Subsequent analysis in MTEP06 demonstrated the project’s effectiveness in addressing the system needs. Midwest ISO
recommends the proposed projects become planned projects.300

On cross-examination, MISO witness Chatterjee discussed the MTEP06 report and

explained that the contingencies listed above, which were resolved by the B3N project, were the source of reliability issues on the ITC system:

Q Am I correct that MISO would have authorized ITC to help install the new PARs regardless of the fixing of these contingencies on MTEP 06?

300 Ex. NYI-50 at 19.

A I do not believe that is correct. MISO’s independent review showed that there
are reliability needs and that was the basis for moving forward with these PARs.

Q The reliability needs from these contingencies was the reason for moving forward with these PARs?

A Yes.

Q You would not have authorized the PARs if it wasn't fixing this reliability?

A I do not see why you'd need to replace a facility if it wasn't really identified as needed from any circumstances. This was one of the circumstances where we
identified a basic threshold of reliability needs driving the need for that PAR.301 [Emphasis added.]

Mr. Chatterjee went on to say that, if the seven needs identified in the bullets in MTEP 06 did not exist, MISO would see no need for the Replacement PARs.302
It would be unjust, unreasonable, and unduly discriminatory, to allocate the costs of the Replacement PARs in a manner that accounts for expected Lake Erie loop flow reduction, but ignores transactional and reliability benefits that only ITC, MISO and their customers will
receive from the operation of the MI/ON PARs. For this reason, the Joint Applicants’ proposed cost allocation should be rejected.

E. The MI/ON PARs Do Not Provide Unique Benefits Justifying Allocation of

the Costs of the Replacement PARs to NYISO and PJM

The MI/ON PARs do not provide unique benefits that no other PARs in the Eastern
Interconnection provide. PARs and other controllable devices are frequently used to regulate
A/C power flows. For example, the “JK PARs” at the New York/PJM border are operated to
facilitate the flow of 1000 MW of power from Rockland County, New York to Bergen County,
New Jersey. At the same time, the “ABC PARs,” located at Farragut (in Manhattan) and
Goethals (on Staten Island), are operated to bring 1000 MW of power from northern New Jersey

301 Tr. 354:4-19 (corrected).

302 Tr. 355:8-11.

into New York City. The result is a controlled “wheel” of 1000 MW of power across PJM’s

transmission system in northern New Jersey.303 Because both sets of PARs (the ABC PARs and
the JK PARs) are being operated to achieve a predetermined schedule, their operation to
effectuate the 1000 MW wheel naturally tends to reject other, unscheduled, power flows across
the transmission lines they regulate, and to reduce loop flow across those facilities.304
The Ramapo PARs at the PJM/ New York border perform a similar function. The
NYISO and PJM have contractually agreed that the Ramapo (or “5018”) transmission lines
should carry a significant portion of the net interchange (imports/exports) that are scheduled
between NYISO and PJM.305 To implement this agreement, NYISO and PJM transmission
owners jointly constructed a pair of PARs on the 5018 transmission lines. The Ramapo PARs
are ordinarily operated to ensure that a significant portion of PJM/NYISO scheduled net
interchange flows over the 5018 transmission lines. To the extent the Ramapo PARs’ operation
better conform actual flows on the 5018 transmission lines to scheduled flows on those
transmission lines (even if the Ramapo PARs do not perfectly conform actual flows to scheduled
flows), the Ramapo PARs reduce unscheduled flows over the 5018 transmission lines. Starting
in January of 2013, as part of their new Market-to-Market Coordination effort, NYISO or PJM
will be subject to a precisely calculated set of financial obligations that will apply whenever the
Ramapo PARs are off-schedule and there is congestion on a Market-to-Market flowgate. The
new Market-to-Market Coordination rules are expected to result in a better concerted effort by

303 See Ex. S-5 at 14-16; Ex. MSO-3 at 16, n. 14. Consolidated Edison Company of New York (“ConEd”) has the right to schedule 1000 MW to be wheeled across PJM’s transmission system, but can elect to schedule less than 1000 MW of power. NYISO and PJM operate the ABC and JK PARs to effectuate ConEd’s election.

304 See Ex. NYI-1 at 40:15-18.

305 See Ex. S-5 at 16-17.

NYISO and PJM to operate the Ramapo PARs to ensure that the Ramapo transmission lines carry their target schedule.

In addition to PAR-controlled transmission lines, there are several transmission lines

interconnecting Northern New Jersey (PJM) to New York City and Long Island that are operated
using even more precise control technologies. The Neptune transmission line interconnects
Long Island, New York to Sayreville, New Jersey. It is a direct current (“DC”) converter
transmission facility. The amount of power that is converted from alternating current to direct
current, then back to alternating current on the other side of the transmission line, can be
controlled with great precision.306 DC control technologies are far more precise than PAR
controls which operate based on tap movements that each represent a 30MW to 75MW change in
power flow. The Hudson Transmission Partners (“HTP”) transmission line that will enter
service in 2013 will link Ridgefield, New Jersey to Manhattan. HTP will also employ DC
converter control technology and is expected to deliver actual flow that is nearly identical to the
power flow scheduled over the direct current line. The Linden VFT scheduled line, that links
Linden, New Jersey to Staten Island, New York, uses a different, extremely precise, control
technology that is referred to as a “variable frequency transformer.” Linden VFT’s variable
frequency transformer operates to a schedule that is an order of magnitude more precise than any
PAR controlled facility is capable of achieving. Linden VFT’s variable frequency transformer
precisely conforms power flows over the line to the scheduled MWs.

As NYISO witness Zach Smith explained in Exhibit NYI-38 at 24, lines 5-9, “Other
regions are shielded from NYISO unscheduled power flows (and the NYISO is shielded from
their unscheduled power flows) by a string of PARs, Direct Current transmission lines, and a

306 See Ex. S-5 at 8.

Variable Frequency Transformer controlled transmission line, that are all located on the eastern
portion of the NYISO/PJM border, between the load centers of New York City and Northern
New Jersey.” The maps set forth below illustrate Mr. Smith’s statement that a series of
controlled transmission lines form a “shield” between Northern New Jersey and New York City.

Controllable Devices on the New York - New Jersey Border

Controllable Devices on the New York City - New Jersey Border

The maps above show that every major (230 kV or above) transmission line linking

northern New Jersey to New York City or Long Island is managed using a PAR, DC converter, or variable frequency transformer. Neither MISO, nor ITC, have been asked to contribute to the cost of any of the power control devices that are in place at the NYISO/PJM border. Most of the facilities identified on the maps have been in service, reducing loop flows, for years. Some of the PARs have been in-service for decades.

While the MI/ON PARs may reduce the magnitude of Lake Erie loop flow when all five
of the MI/ON PARs are in-service and they are effectively operated to conform flow to schedule
at the MI/ON Interface, the effective operation of other PARs, DC converters and variable
frequency transformers to conform actual power flows to scheduled power flows also reduces

loop flows. Other PARs in the Eastern Interconnection affect Lake Erie loop flow, including
PARs located within New York and in New Jersey at the NYISO/PJM border, PARs located in
Ontario at the NYISO/IESO border and PARs located in New York City.307 Use of more precise
controllable devices, including DC converters and variable frequency transformers, also help
conform actual power flows to scheduled power flows and reduces loop flow.
MISO’s DFAX analysis assumes that all of the PARs in the Eastern Interconnection
except the MI/ON PARs are in an “active” state308 while measuring the expected power flows
across the MI/ON Interface. The MISO’s DFAX analysis assumes that, when activated, the
MI/ON PARs will eliminate all loop flow across the MI/ON Interface.309
In order to estimate the loop flow control benefits that other PARs in the Eastern
Interconnection provide, NYISO witness Zach Smith re-ran MISO’s DFAX analysis with one
significant modification. Mr. Smith set all PARs in the Eastern Interconnection to not control
power flows (“inactive”) before performing the analysis, then measured the change in expected
flows across the MI/ON Interface. Changing the operating status of the PARs in the Eastern
Interconnection from “active” to “inactive” was the only change Mr. Smith made to the MISO’s
study. The DFAX analysis otherwise remained exactly the same as the MISO’s DFAX study.
The NYISO’s modified DFAX analysis shows, with the same level of certainty as the MISO
DFAX analysis provides, that significantly higher unscheduled Lake Erie power flows occur at
the MI/ON Interface when all of the PARs in the Eastern Interconnection that are NOT located at
the MI/ON Interface are deactivated.

307 See Ex. NYI-38 at 7:10-12 and n. 1.

308 See Ex. NYI-38 at 22:8-19 (A PAR is “active” when it is modeled as controlling power flows. A PAR is “inactive” when it is modeled as not controlling power flows.).

309 See Ex. MSO-Tab D at 9:17-20 (“By comparison, the contributions from each region’s generation to load transfer is shown to be zero for each region when the [MI/ON] interface PARs are controlling, since the control provided by these PARs overrides flow participation impacts on the interface combined flow.”).

RTO

MISO

WeightedChange in

WeightedParticipation on Participation on

Participationthe MI/ONthe MI/ON

on the MI/ONInterface withInterface with

Interface asAll EasternAll Eastern

Presented inInterconnectionInterconnection

MISO’sPARs ModeledPARs Modeled

DFAXas Inactive asas Inactive

AnalysisRe-Run by(increase + or

NYISOdecrease -)

190.59307.20+116.61

Percentage
Change in

Participation on
the MI/ON

Interface with
All Eastern

Interconnection
PARs Modeled

as Inactive

+61.2%

power flows increase by approximately 33.6 percent.310 As Mr. Smith explained in Exhibit NYI-

38 at 24, lines 2-20, the results set forth in the table above are not surprising. The PARs at the New York/PJM border shield other regions from potential unscheduled power flows, especially from loop flows that might otherwise occur in order to serve New York’s largest load centersNew York City and Long Island.

The results of the NYISO’s modified DFAX analysis show that the PARs that NYISO

and PJM constructed at their common border shield MISO, IESO and other Balancing Authority Areas from unscheduled power flows associated with serving New York and PJM load. The
very same sets of PARs that shield the MI/ON Interface from power flows associated with
serving New York City and Long Island load likely reduce PJM’s measured flows over the
MI/ON Interface as well.311 The loop flow reduction benefits that the PARs located in New
York and PJM provide are the same benefits MISO claims its MI/ON PARs will provide to New York and PJM customers.312 All PARs in the Eastern Interconnection tend to mitigate Lake Erie loop flows when they are being actively operated to better control power flows. The MI/ON
PARs are not unique in this regard.313 If the other PARs in the Eastern Interconnection were
removed from service, the NYISO’s modified DFAX analysis shows that Lake Erie loop flow
would be substantially higher than it is today.314

In MISO’s rebuttal testimony addressing the study Mr. Smith performed, and results

produced by NYISO witness Smith’s analysis, MISO witness Chatterjee stated “Regarding the
impacts of making other PARs inactive and measuring impact on loop flow, MISO agrees with

310 Ex. NYI-38 at 23:16-17.

311 See Ex. NYI-38 at 24:16-17.
312 See Ex. NYI-38 at 24:17-20.
313 Ex. NYI-1 at 40:16-18.
314 See Ex. NYI-38 at 25:5-10.

Mr. Smith’s determination that some other PARs influencing Lake Erie loop flow when

bypassed increase lake Erie circulation flow.”315 MISO witness Chatterjee agrees that the

MI/ON PARs are not the only PARs whose operation reduces Lake Erie loop flow, but argues that the MI/ON PARs further reduce the risk of significant Lake Erie circulation flows.316 In
other words, the MI/ON PARs provide the same benefit as other PARs in the Eastern
Interconnection provide. MISO is arguing that the degree of the potential loop flow reduction is greater for the MI/ON PARs.

MISO witness Mallinger’s rebuttal testimony similarly states that Mr. Mallinger “does

not dispute the outcome of the static analysis Mr. Smith performed.”317 However, Mr. Mallinger
argues that a correlation analysis included in the Regional Power Control Device Coordination
Study (“Coordination Study”) prepared by MISO, NYISO, PJM and IESO in 2011, using 2009
data (see Exhibit S-5) suggests that the operation of the Ramapo PARs may have increased Lake
Erie loop flow during a limited set of hours in 2009. Mr. Mallinger argues that in 19.5% of the
hours in 2009 the Ramapo PARs were not operated to conform flow to schedule.318 During

some portion of those 19.5% of hours, Mr. Mallinger suggests, the operation of the Ramapo

PARs may have increased Lake Erie loop flow by an undetermined quantity. There are several
problems with the argument that Mr. Mallinger makes on pages 15 and 16 of Exhibit MSO-3.
First, Mr. Mallinger’s argument on pages 15-16 of Exhibit MSO-3 only addresses the Ramapo PARs, and it only discusses the operation of the Ramapo PARs in 19.5% of the hours of 2009. The rebuttal testimony does not address the combined operation of all PARs in the

315 Ex. MSO-1 at 10:10-13.

316 Id. at 10:13-15.

317 Ex. MSO-3 at 16:13-14.
318 Ex. MSO-3 at 15-16.

Eastern Interconnection (excepting only the MI/ON PARs), which is what NYISO witness Smith addresses in Exhibit NYI-38 at 22-25. Mr. Mallinger’s rebuttal testimony does not identify any other PARs in the Eastern Interconnection that were arguably operated in a manner that might have increased Lake Erie loop flow.

Second, Mr. Mallinger’s argument ignores (and fails to mention) a clear, and often-
repeated statement in the Coordination Study that “A strong observed correlation between
variables does not necessarily imply that a causal relationship exists between those variables.
However, a causal relationship could exist. Further data analysis is required to determine causal
relationships.”319 The language from the Coordination Study that Mr. Mallinger quotes at the
bottom of page 15 and top of page 16 of MSO-3 is directly followed by a sentence stating “As
discussed earlier, a strong observed correlation between variables does not necessarily imply that
a causal relationship exists between those variables.”320 Mr. Mallinger’s testimony attempts to
use Exhibit S-3 to draw conclusions that are expressly contradicted by the language of the
Exhibit.

Third, the MISO data in Columns Four, Five and Six of Exhibit NYI-66 indicates that the
operation of the MI/ON PARs from April 5, 2012 through July 18, 2012 increased the magnitude
of Lake Erie loop flows in 33.7% of intervals during that time period. In 18.6% of intervals, the
operation of the MI/ON PARs increased the magnitude of loop flows either at a time when loop
flows were already outside the +/-200 MW control band, or the operation of the MI/ON PARs
actually caused Lake Erie loop flow to exceed the +/-200 MW control band. The MISO’s own
estimates of the effectiveness of the MI/ON PARs in 2012 shows that the MI/ON PARs have

319 Ex. S-5 at 5.

320 Id. at 29.

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been a more significant cause of Lake Erie loop flow in 2012 than the Coordination Study suggests the Ramapo PARs might have been in 2009.

Finally, Mr. Mallinger’s argument is, in effect, an attack on MISO’s own DFAX analysis.
MISO’s DFAX analysis assumes perfect operation of all “active” PARs, including but not
limited to the MI/ON PARs. Any attempt to compare the assumptions used in MISO’s
hypothetical DFAX to real-world results quickly identifies inconsistencies. For example,
MISO’s DFAX assumes that whenever the MI/ON PARs are being operated to conform flow to
schedule, they will remove all (100% of) unscheduled power flows at the MI/ON Interface.321
The real-world data MISO provided in Exhibit NYI-66 proves this has not occurred. From April
5, 2012 to July 18, 2012, the MI/ON PARs have been operating to conform actual power flow to
scheduled power flow at the MI/ON Interface. The average absolute value of actual Lake Erie
loop flow over the April 5, 2012 to July 18, 2012 period was 214 MW, which is significantly
more than the 0 MW loop flow assumed in MISO’s DFAX study. The NYISO identifies several
other significant problems caused by the unrealistic assumptions used to produce MISO’s DFAX
in Section VII.A of this initial brief. However, if the MISO’s DFAX analysis is deemed a
sufficiently accurate representation of expected real-world results that it can be used to allocate
the cost of the MI/ON PARs to New York, then using the DFAX study to question aspects of the
Joint Applicants’ case is equally valid.

F. It Would Not Be Appropriate to Allocate Costs of the Replacement PARs to

the NYISO or its Customers Based on Cost Causation Principles

The Joint Applicants have asserted that “cost causation” principles support allocation of a
portion of the costs of the Replacement PARs to NYISO and its customers. This assertion is

321 See Ex. MSO-Tab D at 9:17-20 (“By comparison, the contributions from each region’s generation to load transfer is shown to be zero for each region when the [MI/ON] interface PARs are controlling, since the control provided by these PARs overrides flow participation impacts on the interface combined flow.”).

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incorrect. It would not be appropriate to allocate costs of the Replacement PARs to the NYISO
or its customers based on those principles, for the reasons summarized below.
ITC’s incurrence of the costs of the Replacement PARs was “caused” by ITC’s unilateral decision to assume a contractual obligation to install the Replacement PARs in ITC’s 2007
Facilities Agreement with Hydro One322 (see Section III.B.1 of this initial brief). Sections
III.B.2 and V.D of this initial brief show that ITC’s decision to execute the 2007 Facilities
Agreement was made to address the transactional and reliability needs of ITC’s customers and
ITC’s transmission system. To the extent the Joint Applicants argue that these needs were
created by Lake Erie loop flow, they have submitted no evidence showing that problems caused
by Lake Erie loop flow required ITC to restore the B3N circuit and construct the Replacement
PARs. In particular, MISO and ITC have each admitted that they never performed an
assessment or identified specific reliability criteria that are potentially violated by Lake Erie loop
flow.323 MISO has further admitted that it did not evaluate the economic benefits of the
replacement PARs in the MTEP06 report.324

ITC decided to execute the 2007 Facilities Agreement only after it considered all other

options, and evaluated the expected benefits to the ITC system. Exhibit NYT-38 shows that ITC
considered several options after the Original PAR (and the B3N circuit that the Original PAR
was installed on) failed. Exhibit NYT-38 shows that Hydro One and ITC considered whether it
was worthwhile to restore the B3N circuit at all. Exhibit NYT-38 suggests that if ITC expected
prevailing flow to be from West to East (clockwise) it might not have decided to restore the B3N
circuit or to construct the Replacement PARs. The Exhibit explains that if prevailing flows were

322 See Ex. PTO-4 at 2-3.

323 See Ex. PTO-4 at 2-3; PTO-5. 324 Ex. PJM-16.

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expected to be East to West (counterclockwise) “then B3N is probably the least expensive way
to support needed ITC import capability.” The Exhibit also discusses options for reducing Lake
Erie circulation that did not involve the B3N circuit or the installation of the Replacement PARs,
such as strengthening ITC’s ties to its South in order to reduce the Lake Erie loop flow impact of
ITC importing power from AEP. The key point to take from Exhibit NYT-38 is that ITC
considered many options, including the option of not restoring the B3N circuit at all, then made
its decision.

The expected reliability benefits of restoring the B3N circuit and installing the

Replacement PARs were identified in MISO’s MTEP06 study. These are listed and discussed in
Section V.D of this initial brief. The reliability issues identified in MTEP06 as being resolved by
the Replacement PARs were not described as having been caused by Lake Erie loop flow,325 and
both ITC and MISO admitted they had performed no studies to demonstrate that any reliability
criteria violations or concerns were caused by Lake Erie loop flow.326 Further, MISO confirmed
that: “The contingencies identified in the 2006 MTEP Report and the detailed technical report
are the universe of documents of which MISO is aware that identify reliability criteria violations
that may arise absent the installation of the PARs.”327 In sum, the Joint Applicants have not

shown that there is any causal link between Lake Erie loop flow and the reliability issues described in the MTEP06 report.

Even accepting (for purposes of argument only) that the protection by Detroit Edison and
ITC of reliability and transactional interests was necessitated by the impacts of Lake Erie loop
flow, the Joint Applicants have failed, as discussed in Section VI.A of this initial brief, to submit

325 Ex. NYI-50 at 19.

326 Ex. PTO-4; Ex. PTO-5. 327 Ex. PTO-4 at 3.

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evidence showing the NYISO’s actual contribution to Lake Erie unscheduled power flows by

examining and providing actual data. Instead, MISO submitted a hypothetical planning analysis (the DFAX study) that posits the contributions MISO, NYISO, PJM and IESO might make to Lake Erie loop flow in 2015 under unreasonable and unrealistic assumptions. As demonstrated in Section VII of this initial brief, in numerous respects the DFAX analysis relied upon by MISO and ITC as a basis for cost allocation is fundamentally flawed.

The DFAX analysis purports to estimate the 2015 contribution to loop flow created by NYISO generation-to-load flow. The DFAX analysis relied on by MISO and ITC should be
rejected based on the cumulative effect of the following flaws, discussed in detail in Section VII of this initial brief:328

•the DFAX analysis should have included all 8,760 hours of the year (see Section

VII.A.1);

• the DFAX should have used the load duration curve for each RTO, instead of

using a single, aggregate load duration curve (see Section VII.A.2.);

• contributions to flows over the four circuits that comprise the MI/ON Interface

should not be netted against each other when determining an ISO or RTO’s contribution to the MI/ON Interface flows (see Section VII.A.3);

•the DFAX analysis does not consider the economics of dispatch (see Section

VII.A.4);

•the DFAX analysis ignore other regional contributors to Lake Erie loop flow (see

Section VII.A.5); and

• the DFAX analysis ignores the contribution of interchange transactions between

control areas, even though this contribution was recognized by MISO witness Mallinger329 (see Section VII.B).

Beyond these specific flaws, the DFAX analysis should be rejected because of the resultoriented fashion in which the analysis and associated cost proposal were developed.

328 See Ex. NYT-19 at 21:444-446.

329 Ex. MSO-Tab E at 17:11-13.

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Finally, the Joint Application fails to recognize and provide a financial credit, as it

should, because NYISO and PJM installed and paid for their own PARs and other controllable
facilities (including direct current converters and variable frequency transformers) that reduce
Lake Erie loop flow.330 Similarly, the Joint Application admittedly331 fails to give financial
“credit” to NYISO and PJM for their expenditures to develop and implement the “Broader
Regional Markets” initiatives that control or mitigate the impacts of Lake Erie loop flow.332 At
the same time, the Joint Application proposes not to charge IESO because Hydro One customers
paid the costs of the Hydro One PARs, as discussed in Section IV.C. of this initial brief.

VI. WHAT IS THE EXTENT OF THE CONTRIBUTIONS TO LOOP FLOWS OF

MISO, IESO, NYISO AND PJM AND OTHERS, AND DO THEY REPRESENT A BASIS FOR MISO/ITC TO ALLOCATE THE COSTS OF THE ITC PARS TO PJM AND NYISO?

A.MISO and ITC Have Not Presented Evidence of the NYISO’s Actual

Contribution to Lake Erie Loop Flow

Neither MISO nor ITC submitted evidence showing the NYISO’s actual contribution to
Lake Erie unscheduled power flows by examining and providing actual data. Instead, the Joint
Application relies on333 a hypothetical planning analysis (the DFAX study) that posits the
contributions MISO, NYISO, PJM and IESO might make to Lake Erie loop flow in 2015 if each
ISO/RTO only uses generation located in its control area to serve its load (an unrealistic
assumption), if the impact of transactions on loop flow is ignored, and if the principles of
economic dispatch are ignored. For the reasons explained in Section VII of this initial brief, the

330 Ex. NYI-38 at 21:20-25:10.

331 Tr. 351:22-352:1.

332 See Section IV.C of initial brief; Ex. NYI-46 at 15:3-18:22.

333 See Joint Application Transmittal Letter at 8 (“the Midwest ISO has identified the extent to which the Midwest ISO, PJM, and the NYISO contribute to the Lake Erie loop flow issue and assigned each region a percentage of ITC’s revenue requirement for the New PARs accordingly”).

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MISO’s DFAX analysis is fundamentally flawed and should not be relied on as a basis for cost allocation.

B. It is Unjust and Unreasonable, and Unduly Discriminatory, to Require

NYISO and Its Customers to Pay for a Share of Replacement PARs Costs that Are “Caused” by IESO

As discussed in detail in Section IV.C of this initial brief, it would be unjust,

unreasonable, and unduly discriminatory, to require the NYISO’s customers to be assigned cost responsibility for the Replacement PARs based on Lake Erie loop flow that MISO has
determined is caused by IESO and its customers.

VII. WHETHER THE MISO/ITC DFAX STUDY PROVIDES AN ADEQUATE BASIS
FOR THE PROPOSED COST ALLOCATION?

A. The DFAX Analysis Is Fundamentally Flawed

The DFAX analysis relied upon by MISO and ITC as a basis for cost allocation is

fundamentally flawed. The DFAX analysis purports to estimate the 2015 contribution to loop
flow created by NYISO generation-to-load flow. The DFAX analysis relied on by MISO and
ITC should be rejected based on the cumulative effect of the flaws discussed in detail below.334
Despite the NYISO’s overall recommendation that the DFAX analysis be rejected, the NYISO
addresses each significant flaw of the DFAX analysis and its individual impact below.

1.MISO’s DFAX Analysis Should Have Included All 8,760 Hours of the

Year

MISO’s DFAX analysis relied on three representative hours, each representing a multi-
hour load block, to estimate each region’s contribution to flows at the MI/ON Interface for the
entire year.335 A single hour was used to represent the “peak” 248 hours, a second to represent

334 See Ex. NYT-19 at 21:444-446.

335 Tr. 368:16-22.

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the “shoulder peak” 6,784 hours and a third to represent the “light load” 1,728 hours.336 The use of just three load blocks penalizes New York by mis-assigning a significant portion of the
NYISO’s flow participation to higher load hours, and over-counting the MWh used to determine the New York portion of the DFAX cost allocation.337 Instead of using load blocks, MISO
should have performed the DFAX analysis by calculating a weighted participation percentage for every hour of the year, as NYISO witness Zach Smith recommended in his testimony.338 On
cross-examination, Mr. Chatterjee admitted that an 8,760 hour load representation would more accurately reflect each RTO’s load over the entire year than the three load block method he
employed to produce the MISO’s DFAX analysis.339

Accurately time-normalizing the DFAX analysis is critical to calculating each region’s
weighted participation percentage. The use of only three representative load blocks cannot
accurately depict a region’s expected electricity usage over the 8,760 hours of a year.340 Each
region’s electricity usage varies significantly more than is captured in the three representative
load blocks used in the DFAX analysis.341 The slope of each ISO/RTO region’s load duration
curve, as shown in Exhibit NYI-39, depicts how significantly each region’s electricity usage
varies over the hours of a year.342 The drastic variation in electricity usage makes a

representation using only three blocks a gross over-simplification.343

336 Tr. 373:4-21.

337 Ex. NYI-38 at 14:20-15:19. 338 Ex. NYI-38 at 15:21-16:2. 339 Tr. 399:15-400:5.

340 Ex. NYI-38 at 14:12-18. 341 Ex. NYI-39.

342 Ex. NYI-39.

343 Ex. NYI-38 at 14:16-18.

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The three representative load blocks used in MISO’s DFAX analysis had to be distributed
over an entire year in order to determine each region’s weighted participation over the MI/ON
Interface for that period. Time-normalizing was MISO’s chosen method of weighting the three
hours in an attempt “to calculate the effects of contributions to loop flows through the entire
year.”344 Mr. Chatterjee determined that the peak load hour should be applied to approximately
3% of hours, the shoulder peak hour should be applied to approximately 77% of hours and the
light load hour should be applied to approximately 20% of hours.345 Mr. Chatterjee, however,
agreed that the most accurate way to time normalize the DFAX analysis would be to use all
8,760 hours of the year, rather than using just three representative hours.346 Performing the
DFAX analysis for all 8,760 hours of the year would avoid the need to determine how many
hours of the year a representative hour applies to, and more accurately considers expected
participation in each hour studied.

In his rebuttal testimony, Exhibit MSO-1, Mr. Chatterjee speculated that the 8,760 hour analysis would not result in a significantly different result than the three load block analysis
MISO used.347 However, Mr. Chatterjee did not perform any study or analysis to support his speculation.348 Contrary to Mr. Chatterjee’s unsupported speculation, NYISO witness Smith testified that performing the analysis for every hour of the year will have a significant impact on the NYISO’s participation because the MISO’s analysis significantly over-counted and overattributed megawatt-hours to the NYISO.349

344 Tr. 268:20-23.

345 See, Ex. MSO-Tab D at 10:4-21 and MSO-2. 346 Tr. 400:15-21.

347 Ex. MSO-1 at 8:5-8. 348 Tr. 405:1-7.

349 Ex. NYI-38 at 14:20-15:23.

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Instead of analyzing all 8,760 hours, MISO based its DFAX study on three typical hours
representative of 100%, 85%, and 50% of peak load levels.350 MISO assumed that load remains
steady at 85% of peak load for over nine months of the year.351 The use of 85% of peak load for
more than nine months of the year is unrealistic and unnecessarily penalizes New York. The
New York load duration curve clearly indicates that load in New York is lower than 60% of its
peak load for eight months of the year and lower than 50% of its peak load for four months of the
year.352 When the curve used for MISO’s study, “Study-NYISO Load,” is above the “NYISO
Load” hourly load duration curve in Exhibit NYI-42, the MISO’s analysis is over-counting the
MWh used to determine New York’s portion of the cost allocation.353 The area between the
curves represents the amount of MWh over-counted, since New York’s load is predominantly
less than the load assumed in the Study -NYISO Load curve utilized by MISO. In fact, MISO
over-assigned approximately 40,000,000 MWh to the NYISO in MISO’s proposed cost
allocation.354

The NYISO and Mr. Chatterjee are in agreement that using all 8,760 hours of the year
would produce the most accurate result.355 MISO should have performed its DFAX analysis in
the manner Mr. Smith recommended in his testimony to produce a more accurate assessment of
each region’s expected contribution to flows across the MI/ON Interface.356 That is, the MISO
should have conducted 8,760 DFAX runs for each region, one DFAX run for every hour of the

350 Tr. 247:1-13.

351 Ex. NYI-38 at 15:8-9.

352 Ex. NYI-38 at 15:11-13; See Ex. NYI-42. 353 Ex. NYI-38 at 15:13-16.

354 Ex. NYI-38 at 15:18-19. 355 Tr. 399:15-400:5.

356 Ex. NYI-38 at 15:21-16:2.

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year.357 Performing 8,760 DFAX runs would have resulted in a more accurate weighted

participation percentage for each region and would not have required extraordinary effort by the Joint Applicants due to the sophisticated software packages available to conduct these
analyses.358 Moreover, Mr. Chatterjee acknowledged that an 8,760-hour representation is used for MISO’s forward-looking resource adequacy analysis incorporated in its MTEP planning process,359 for similar analyses in other regions of the eastern interconnection,360and for
production cost analysis for MISO’s “top congested flowgate” study.361

2. MISO’s DFAX Should Have Used the Load Duration Curve for each

RTO, Instead of Using a Single, Aggregate Load Duration Curve

MISO’s use of an aggregate load duration curve for MISO, NYISO and PJM was

improper for the DFAX analysis. MISO should have used each region’s individual load duration
curve to perform the DFAX analysis over all 8,760 hours of the year to calculate each region’s
individual participation over the MI/ON Interface.362 According to Mr. Chatterjee’s rebuttal
testimony, “MISO is not opposed to using individual region’s load duration curves as included in
the Ventyx database.”363 Mr. Chatterjee asserts that using each region’s load duration curve will
not result in significantly different weighted participation percentages.364 Calculating the
NYISO’s participation based on the NYISO’s load duration curve, while still using MISO’s
overall method, resulted in a 0.8% reduction in NYISO’s participation.365 However, using the

357 Ex. NYI-38 at 15:21-16:2.

358 Ex. NYI-38 at 15:21-16:2. 359 Tr. 409:18-21.

360 Tr. 410:7-10.
361 Tr. 410:3-6.

362 See, Ex. NYI-38 at 9:9-17; Ex. NYI-39; Ex. NYI-40; and Ex. NYI-41. 363 Ex. MSO-1 at 7:22-23.

364 Ex. MSO-1 at 8:1-4.
365 Ex. MSO-1 at 8:1-4.

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correct load duration curve is just one step in correcting the flawed MISO DFAX analysis.

Performing the DFAX analysis for all 8,760 hours of the year (for the reasons explained above) and correcting the other flaws in the DFAX analysis that are discussed herein, in addition to
using each region’s individual load duration curve, would have resulted in more dramatic
adjustments to the weighted participation percentages and cost allocation, and would produce a more accurate result.

If the DFAX analysis used the NYISO’s forecasted 2015 load duration curve, rather than
the aggregate load duration curve, for NYISO there should be 221 hours between 100% and 85%
of peak load, 5,637 hours between 85% and 50% of peak load, and 2,902 hours at less than 50%
of peak load. MISO’s calculation of NYISO’s DFAX participation incorrectly assigned 27 hours
to the 100% (peak) load block that should have been assigned to the shoulder peak load block,
and incorrectly assigned 1,174 hours to the 85% (shoulder peak) load block that should have

been assigned to the light load block.366 These 1,174 hours should have been added to the 1,728 hours assigned to the 50% (low) load block for NYISO.367 MISO’s effort to shoe-horn the
NYISO into an aggregate load duration curve developed using the combined MISO, PJM and
NYISO load duration curves resulted in an inflated participation factor and resulting cost
allocation to the NYISO,368 while reducing MISO’s relative participation and cost allocation.
NYISO witness Smith’s direct testimony presented corrected DFAX analysis results using each region’s load duration curve.369

366 Ex. NYI-38 at 11:1-12:7.
367 Ex. NYI-38 at 11:1-12:7.
368 Ex. NYI-38 at 9:24-12:7.
369 Ex. NYI-38 at 13:2-6.

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The inflated NYISO participation factors calculated in the MISO DFAX analysis result
from NYISO’s trend towards lower participation as load decreases.370 NYISO’s participation
factors on the MI/ON Interface are greatest when the NYISO load is highest, and NYISO’s
participation factors are the lowest when the NYISO load is lowest. While the foregoing
statement might seem intuitive (NYISO’s participation is highest when its load is highest),
participation factors and load are NOT necessarily aligned in the DFAX analysis.371 PJM has a
higher participation factor as its load declines.372 According to MISO’s analysis, MISO also has
a higher participation on the MI/ON Interface as its load declines.373 However, if MISO’s
contributions over the four circuits of the MI/ON Interface are not netted to calculate an overall
interface contribution, (see Section VII.A.3 of this initial brief) its participation factors remain
relatively uniform for all three load conditions. In other words, the NYISO’s cost responsibility
declines if more of the NYISO’s hours are accurately represented as occurring in the light load
period.374 Applying the aggregate load duration curve to the NYISO over-assigns high load
hours to New York and under-assigns low load hours to New York.

MISO witness Chatterjee identified examples of instances in which the aggregate load
duration curve over-assigns MWs to the NYISO. For example, in hour 2,001 on the load
duration curve, NYISO’s load duration curve shows that load in NYISO is approximately 65%
of peak while the MISO’s study load duration curve assumes 75% of peak for the DFAX
analysis.375 In addition, the NYISO’s load duration curve shows that load in NYISO in hour

370 Ex. NYI-38 at 12:9-16.

371 Ex. NYI-38 at 12:9-16.
372 Ex. NYI-38 at 12:16-21.
373 Ex. NYI-38 at 12:16-21.
374 Ex. NYI-38 at 12:17-19.
375 Ex. NYI-42; Tr. 403:17-21.

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5,001 is approximately 55% of peak and in hour 6,900 is less than 50% of peak while the

MISO’s study load duration curve assumes 75% of peak in both hours for the DFAX analysis.376 As a result, NYISO is penalized in the overall weighted participation and receives a larger than justified cost allocation.377 Consistent with MISO witness Chatterjee’s rebuttal testimony,378 MISO should have used each individual region’s load duration curves, as included in the Ventyx database, to perform the DFAX analysis.

3. Contributions to Flows over the Four Circuits that Comprise the

MI/ON Interface Should Not be Netted Against Each Other when

Determining an ISO or RTO’s Contribution to the MI/ON Interface
Flows

MISO’s unilateral decision to permit directional contributions to the flow participation
over the four circuits that comprise the MI/ON Interface to offset each other is inappropriate and
inconsistent with other decisions that MISO made with regard to netting of contributions in the
DFAX study. MISO’s decision to allow contributions to offset in some circumstances provided
evidence that MISO’s DFAX analysis was crafted to favor the Joint Applicants’ interests.

MISO’s flow contributions on the MI/ON Interface are different from the NYISO, PJM
and IESO contributions. When power is permitted to flow freely over the four circuits of the
MI/ON Interface the four circuits actually participate in the transfer of power from MISO
generation to MISO load in addition to transferring Lake Erie loop flow.379 Unlike the NYISO,
PJM and IESO power flows in the DFAX analysis, a significant quantity of MISO’s power flows
“loop” out of, then back into MISO across the four circuits that comprise the MI/ON Interface.380

376 Ex. NYI-42; Tr. 403:25-404:16.

377 Ex. NYI-38 at 12:23-13:6.
378 Ex. MSO-1 at 7:22-23.
379 Ex. NYI-38 at 6:14-16.
380 Ex. NYI-38 at 6:17-18.

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The MISO DFAX analysis indicates that MISO power flows from Michigan to Ontario (positive distribution factors) on the L4D and L51D circuits, and flows back from Ontario to Michigan (negative distribution factors) on the J5D and B3N circuits.381

By summing the directional participation factors on all four of the circuits as MISO has
done, and netting the flows with positive distribution factors against the flows with negative
distribution factors, MISO’s use of the MI/ON Interface and true contribution to flows on the
B3N Circuit is understated. In particular, MISO is using more of the Replacement PARs’
capability than the participation factors used in the MISO’s DFAX analysis reflect.382 MISO’s
actual participation on the MI/ON Interface is inappropriately reduced by netting MISO’s
contributions across the four circuits.383 MISO’s participation factor should be 280 in the peak
case, yet the peak participation factor MISO calculated for itself is only 123.384 MISO’s
participation decreases in all three cases the DFAX analysis studied (peak, shoulder, light load)
because MISO nets its directional flow participation on the four circuits that comprise the
MI/ON Interface.385

On cross-examination by counsel for the PJM Transmission Owners, MISO witness

Chatterjee indicated that he opposed the netting of contribution factors because, “it is recognized in some cases, the aggregate impact of PJM could have a negative impact on reliability and in some cases it could have a positive impact on reliability. The clockwise or the counterclockwise would both be harmful.”386

381 Ex. NYI-38 at 6:19-21.
382 Ex. NYI-38 at 6:21-7:2.
383 Tr. 419:8-420:24.
384 Ex. NYI-74.

385 Ex. MSO-1B.

386 Tr. 367:25-368:4.

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On cross examination by NYISO counsel, Mr. Chatterjee agreed that, at any given

instant, an ISO’s or RTO’s contribution to Lake Erie loop flow can be harmful or beneficial.387
Mr. Chatterjee also agreed that on a peak load day when loop flow was significantly
counterclockwise in direction, MISO’s 151 MW peak contribution to counter-clockwise loop
flows across the B3N circuit388 could have a significant impact,389 even though MISO’s
contribution to net flow across the entire MI/ON interface (all four circuits) would be less than
MISO’s 151 MW counter-clockwise contribution on the B3N circuit.390
Mr. Chatterjee also agreed that MISO’s decision to net the directional participation of its flows on the four circuits that comprise the MI/ON Interface tended to reduce MISO’s total
DFAX participation, and thus the cost responsibility MISO is assigned in the DFAX analysis.391
Netting flow contributions across the four transmission circuits that comprise the MI/ON Interface reduces MISO’s DFAX cost allocation, but has little to no impact on NYISO or PJM. NYISO’s total participation on the MI/ON Interface is the same regardless of netting across the circuits.392 PJM’s participation decreases from 33 to 28 (by 5 MW) in the shoulder peak case when participation is netted across the four circuits.393 In other contexts, MISO witness
Chatterjee was opposed to netting.394 Netting participation across the four circuits appears to be

387 Tr. 419:14-18.

388 See Ex. NYI-74.
389 Tr. 419:19-23.
390 Tr. 419:24-420:3.
391 Tr. 420:4-19.

392 Ex. MSO-1B (NYISO’s flow participation on all four circuits is in the same direction in all three load cases).

393 Ex. MSO-1B (PJM’s flow participation on all four circuits is in the same direction in the peak case and light load
case).

394 Tr. 370:6-10.

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one way that MISO tailored the DFAX analysis it developed to produce results that are consistent with the MISO’s interests.

4. DFAX Analysis Does Not Consider the Economics of Dispatch

The MISO DFAX study is not reflective of real-world electric power system operation practices. MISO does not account for any economic impacts of generation dispatch in its hypothetical DFAX analysis.

The DFAX study was performed by increasing the output of each generator within an
RTO, pro rata, based on each generator’s maximum MW output, to serve the load within that
RTO.395 MISO’s approach dispatches all generation within an RTO pro rata, based on each
generator’s maximum output, regardless of the actual costs to dispatch that generator. In other
words, the DFAX study dispatched 80 year old oil-fired generators on an equivalent basis with
nuclear power plants and newly installed (latest technology) combined cycle power plants.

On cross-examination Mr. Chatterjee acknowledged that, in contrast to the DFAX

analysis, RTOs do not “serve their load by uniformly ramping up all of the generation in their
control area.”396 Instead, generation within an RTO is dispatched to achieve the least cost
solution to serve load, while meeting all applicable reliability requirements/rules. ISOs and
RTOs use security constrained economic dispatch software, to dispatch generation throughout
their entire system to achieve a least cost economic solution.397 Each ISO’s or RTO’s
generation-to-load impacts on Lake Erie loop flow are, as a result, affected by the economics of
dispatch.

395 Tr. 440:5-25.
396 Tr. 440:5-8.
397 Tr. 1077:4-6.

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MISO’s hypothetical DFAX analysis does not account for economics in determining

generator dispatch. Instead, the DFAX assigns MW output to all ISO/RTO dispatched

generators, pro rata, weighted based on each generator’s maximum output. MISO’s unrealistic dispatch assumptions produced unrealistic DFAX analysis flow participation results.398 An
analysis that accounts for economic dispatch of generation would produce dramatically different flow participation result.

The impact of generation-to-load power flows, measured across the MI/ON Interface is
dependent on the location of the generation and the load.399 RTOs dispatch their least expensive
resources first, to the greatest extent practical. For example, PJM operates less expensive
generation in western PJM (Illinois) to serve load in eastern PJM (Pennsylvania, New Jersey,
Maryland).400 Dispatching generation in this manner results in large power flows across the PJM
transmission system from west to east. PJM states that its dispatch of western PJM resources to
serve eastern PJM load also causes some clockwise loop flow from PJM, through MISO, IESO,
NYISO and back into PJM.401 However, MISO’s DFAX analysis does not take into account the
differences between PJM’s western and eastern generation fleets that affect PJM’s economic
dispatch. The peak scenario in the DFAX analysis indicates that, on an aggregate basis, PJM has
approximately 101,000 MW of installed generation in PJM West, and approximately 99,000
MW of installed generation in PJM east.402 The DFAX assumes that each incremental MW of
PJM load is served (approximately) 50.5% by PJM west generation and (approximately) 49.5%

398 See Tr. 440:5-8 and Ex. MSO-2.

399 See Ex. NYT-19 at 17:334-346. 400 Ex. PJM-1 at 37:20-23.

401 Ex. PJM-1 at 37:19-38:5 and Tr. 1077:7-15.

402 See Ex. MSO-1B (including underlying power flow models).

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by PJM east generation. The dispatch assumption used in the DFAX analysis is wholly

inconsistent with PJM’s testimony regarding the dispatch of its generation.

The failure to account for economic dispatch of generation creates a significant flaw in the DFAX analysis and MISO’s proposed cost allocation. Uniform ramping of all generation
within an RTO does not reflect the actual dispatch that will occur under any conditions.403 The failure to model realistic generator dispatch patterns also impacts MISO, NYISO, and IESO’s
contributions. When considered across all four of the RTOs around Lake Erie, the discrepancy is likely to have a significant impact on the DFAX analysis weighted participation percentages and resulting cost allocation. The DFAX analysis could have, and should have, been conducted in a manner that accounted for each region’s typical economic dispatch patterns. MISO could have input a typical dispatch pattern for each case studied.404

MISO’s DFAX analysis was tailored to the specific purpose of determining an

appropriate cost allocation for the Replacement PARs by identifying expected contributions to

Lake Erie loop flow in a modified, hypothetical 2015 planning case.405 MISO’s analysis was not performed to satisfy typical reliability analysis procedures or production cost analysis
procedures.406 MISO’s failure to account for economic dispatch in its DFAX analysis is a
significant omission. Because the dispatch used in the proposed DFAX cost allocation proposal bears no relationship to real-world generation dispatch, MISO has not met its burden of proving
that its proposed cost allocation method is just and reasonable, and not unduly preferential,
prejudicial or discriminatory.

403 Tr. 440:5-8.

404 MISO should have access to economic dispatch data through Ventyx or should be able to obtain such data from a similar source.

405 Ex. MSO-Tab D at 5:8-13 and 8:17-21.

406 See Tr. 408:21-409:2 and Tr. 407:21-408:1.

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5.The DFAX Analysis Should Have Associated Cost Allocation with

Flow Participation Solely on the B3N Circuit

Another flaw in the DFAX analysis discussed in NYISO witness Smith’s direct

testimony,407 was its failure to calculate the generation-to-load flow participation over only the
B3N circuit, on which the Replacement PARs are located.408 It was not appropriate for the Joint
Applicants to base the DFAX analysis on the ISOs and RTOs contributions to flows on all four
of the circuits that comprise the MI/ON Interface.409 The costs of the Replacement PARs on the
B3N circuit are the only costs that MISO and ITC are attempting to allocate to NYISO and
PJM.410 The Hydro One PARs were built prior to the Replacement PARs, were not built by ITC,
do not belong to ITC, are not located in the MISO (or in the United States), and are not the
subject of this cost allocation proceeding.411 The B3N circuit, on which the Replacement PARs
are installed, should, therefore, have been the circuit used to determine the flow contribution of
each ISO/RTO in the DFAX analysis.

Mr. Smith performed a corrected DFAX analysis in which he set only the Replacement
PARs on the B3N circuit to “inactive,” while setting all of the Hydro One PARs to “active.”412
The configuration NYISO witness Smith used allows all of the Hydro One PARs to control flow
equal to schedule.413 Under the NYISO’s corrected DFAX calculation method the L4D, L51D,
and J5D circuits did not participate in the generation-to-load transfers that are used to determine

407 Ex. NYI-38 at 6:2-8:1.

408 Ex. NYI-38 at 6:2-9.

409 Ex. NYI-38 at 6:11-7:6.
410 Tr. 430:25-431:3.
411 Ex. NYI-38 at 6:6-7.

412 Mr. Smith’s corrected analysis did not correct all of the flaws identified in this initial brief, it only corrected the
MISO’s use of participation on the entire MI/ON Interface to determine cost responsibility for the Replacement
PARs.

413 Ex. NYI-38 at 7:10-12.

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initial brief because each ISO’s or RTO’s generation-to-load transfers only participate on the B3N circuit in one direction.416

In sum, consistent with NYISO witness Smith’s testimony,417 the MISO’s DFAX

analysis is flawed. To determine an appropriate cost allocation for transmission facilities that are
located on the B3N circuit, the DFAX should have only considered participation over the B3N
circuit.

6. Cumulative Impact on DFAX Analysis of Only Considering Flows

Over the B3N Circuit and Using Each RTO’s Load Duration Curve

The magnitude of the DFAX flaws becomes more evident when multiple flaws are

corrected simultaneously. The NYISO performed a modified DFAX analysis that corrected both MISO’s failure to account for only the flows over the B3N circuit and MISO’s failure to use
each RTO’s load duration curve to determine that region’s weighted participation. The
cumulative results further reduce NYISO’s weighted participation percentage below the results
provided in Section VII.A.5 of this initial brief, which only addressed limiting the analysis to the flows over the B3N circuit, and did not incorporate the NYISO’s proposed correction to apply
each RTO’s load duration curve.

NYISO66.0419%

The NYISO’s weighted participation percentage would be smaller still if the DFAX

analysis was performed in a manner that accounted for economic dispatch, each region’s load

duration curve for 8,760 DFAX simulations (one for each hour in the year) and only participation
over the B3N circuit as discussed in Sections VII.A.1, VII.A.2, VII.A.4 and VII.A.5 of this
initial brief.

7. Other Regional Contributors to Lake Erie Loop Flow

Other flaws in the DFAX analysis include ignoring the cumulative contribution of

regions other than MISO, NYISO, PJM and IESO to unscheduled Lake Erie power flows. The
multitude of small “contributors” illustrates that if regions are permitted to assess charges to each
other on the basis of asserted “benefits” in the absence of regional agreements, this “chain
reaction” and ensuing litigation will have no logical stopping place.418
The MISO’s DFAX analysis is flawed for all of the reasons discussed in this section of the initial brief. The DFAX analysis flaws compound one another to result in a substantially inflated NYISO weighted participation percentage. The NYISO’s weighted participation

418 Ex. NYI-38 at 16-19 (referencing Ex. NYI-43).

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percentage would be a fraction of the percentage claimed by the Joint Applicants if the DFAX analysis had corrected these flaws.

B. The DFAX Analysis and Associated Cost Allocation Proposal Were

Developed in a Result-Oriented Fashion that Should Be Rejected

The DFAX analysis should also be rejected as a basis for cost allocation because it was
developed in a result-oriented fashion. To produce the DFAX analysis it included in the Joint
Application MISO developed a variety of different DFAX scenarios, and ultimately chose an
approach that avoided assigning any portion of the cost of the Replacement PARs to entities
scheduling transactions over those facilities, and that minimized the overall allocation to the
MISO.

Responses to discovery requests show and cross-examination of MISO witness Chatterjee
confirms that, while developing the method they would use to perform the DFAX study, MISO
and ITC considered allocating a portion of the cost of the Replacement PARs to entities
scheduling transactions on the MI/ON Interface. This approach was abandoned when ITC
realized that “the largest portion of the cost would effectively be collected from ITC
Transmission customers.”419 During cross-examination, Mr. Chatterjee stated that scheduled
transactions have contributed, and continue to contribute, to the loop flow on the MI/ON
Interface,420 and that entities scheduling imports and exports over the MI/ON Interface would
benefit from avoiding curtailment of those transactions.421 However, the DFAX study does not
account for Lake Erie loop flow that is caused by transactions,422 and parties scheduling

419 Ex. NYT-22 at 4.

420 Tr. 317:23-318:1.
421 Tr. 317:15-22.

422 Ex. MSO Tab D at 4:22-5:2; Ex. MSO Tab E at 17:11-13; Tr. 514:3-5.

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transactions over the MI/ON Interface are not assigned any cost responsibility under the
proposed allocation that MISO and ITC included in the Joint Application.
Despite a MISO data response prepared by Mr. Chatterjee to the contrary,423 during cross-examination Mr. Chatterjee admitted that he developed and MISO considered many different DFAX scenarios before proposing the method that MISO and ITC used in the Joint Application.424

Exhibit PTO-12 shows MISO analyzed at least eight different DFAX scenarios prior to
selecting the DFAX analysis that was presented as the basis for MISO/ITC’s proposed cost
allocation.425 There are many factors that MISO considered while it was developing the DFAX,
including: (i) whether to include IESO’s participation over the MI/ON Interface, (ii) whether to
consider impact on the MI/ON Interface from each region’s generation or from each region’s
load, (iii) whether to weight each PAR differently based on size, and (iv) whether to consider the
direction of participation.426

Exhibit PTO-12 demonstrates that there were a number of analytic approaches MISO and ITC considered in developing the DFAX analysis. In the end, it appears that MISO and ITC
chose the approach that provided the result they desired (less allocation to MISO and ITC). The DFAX analysis MISO submitted in this proceeding presents an unreliable basis for determining an appropriate cost allocation.

423 Ex. PJM-23.

424 Tr. 379:5-380:5.
425 Ex. PTO-12.
426 Ex. PTO-12.

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MISCELLANEOUS ISSUES

VIII. WHETHER THE FILING CREATES A SERVICE OBLIGATION OF MISO AND
ITC TO NYISO OR PJM OR THEIR CUSTOMERS AND, IF SO, WHAT IS THE
NATURE OF THE OBLIGATION?

The Joint Applicants argue that the NYISO’s customers should be required to pay

approximately 29 percent of the cost of ITC’s Replacement PARs. However, the tariff revisions that the Joint Applicants propose do not identify, explain or describe the product or service that the NYISO, or its customers, will receive in return for paying approximately 29 percent of the cost ITC incurs to construct and maintain the Replacement PARs (including a rate of return on ITC’s investment). At the hearing, ITC witness Grover admitted that MISO’s proposed
Schedule 36 and Attachment SS contain no description of the service that the NYISO’s
customers will receive in return for their payments.427

The Joint Applicants proposed tariff revisions specify a payment obligation that applies
to NYISO and PJM customers, but no corresponding service obligation that applies to MISO or
ITC. In fact, the Joint Applicants proposed tariff revisions do not specify any service standard(s)
that the Joint Applicants must meet in order to be paid.428 To the contrary, the MISO informed
the NYISO that the Joint Applicants’ proposed Tariff revisions require the MISO to bill the
NYISO for the Replacement PARs at times when the Replacement PARs or other MI/ON PARs
are out-of-service.429 When the Replacement PARs tripped and were out of service from May 29
to June 5, 2012, MISO stated that the bill it sent to NYISO for June 2012 would not be
discounted due to the outage.430

427 Tr. 126: 24-127:4.

428 Ex. NYI-1 at 13:23-25.

429 Ex. NYI-1 at15:5-17; NYI-7; NYI-8. 430 Ex. NYI-65 at 3.

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In response to a NYISO discovery request MISO stated that it is not subject to any tariff obligation to provide reliable service to the NYISO.431 MISO responded “no” to a NYISO data request asking whether MISO and ITC would be subject to an obligation to provide reliable
service to NYISO customers and PJM customers that are not (other than paying for a portion of the cost of the Replacement PARs) MISO customers.432 In response to a similar NYISO data request to ITC, ITC responded that it does not believe it would have any service obligation to the NYISO or to any New York Transmission Owner.433

The Joint Applicants’ proposal to charge NYISO customers for a service that is not

described, in any manner, in the MISO’s tariff, and that is not subject to any service standards, of
any sort, is unjust and unreasonable. The fact that MISO has defined service obligations to its
own customers, but not to the NYISO and PJM customers who would have to pay for the
Replacement PARs, is unduly discriminatory, unduly preferential, and unduly prejudicial. The
Commission should reject the Joint Applicants proposed tariff revisions and instruct the Joint
Applicants to refund all payments NYISO and PJM have made under MISO’s proposed Rate
Schedule 36, with interest.

431 Ex. NYI-5.

432 Ex. NYI-6.
433 Ex. NYI-9.

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IX.WHETHER AND TO WHAT EXTENT WILL THE PARS CONTROL LAKE

ERIE LOOP FLOW, INCLUDING WHETHER, IF ANY OF THE ITC PARS (OR
THE HYDRO ONE PARS) ARE UNAVAILABLE, BYPASSED, OR NOT BEING
OPERATED IN A MANNER THAT IS CONSISTENT WITH THE
PRESIDENTIAL PERMIT ISSUED TO ITC BY THE DEPARTMENT OF
ENERGY, NYISO OR PJM OR THEIR CUSTOMERS NONETHELESS SHOULD
BE REQUIRED TO PAY THE CHARGES AT ISSUE IN THIS PROCEEDING?

A. MISO’s and ITC’s Claim that the MI/ON PARs Will Remove 600 MW of

Loop Flow (Almost) All the Time is Vastly Overstated

The Joint Application and the MISO and ITC supporting testimonies, repeatedly state
that the MI/ON PARs “are expected to fully mitigate Lake Erie loop flows approximately 74%
of the time, and reduce them by approximately 600 MW the remainder of the time.”434 MISO
witness Thomas Mallinger explained the Joint Applicants’ claim in his Direct Testimony:

The Michigan-Ontario PARs, including the New PARs, are expected to fully

mitigate Lake Erie loop flows approximately 74% of the time, while any

remaining loop flow overage will be addressed through existing market solutions.
To explain, the Michigan-Ontario PARs have the ability to control up to 600 MW
of Lake Erie loop flows. [footnote omitted] This means the Michigan-Ontario
PARs will be able to hold actual flows equal to scheduled flows across the
interface as long as the potential loop flow (defined as the loop flows that would
exist if the Michigan-Ontario PARs were not regulating) does not exceed 600
MW. Once the potential flow reaches 600 MW, the Michigan-Ontario PARs will
have reached their maximum loop flow control capability. As potential loop
flows exceed 600 MW, there will be a one-for-one increase of loop flows across
the interface (for every 1 MW increase of potential loop flow there will be a 1
MW increase of actual loop flow across the interface).435

[D]uring the period of time when the Michigan-Ontario PARs are not able to

maintain actual flows equal to scheduled flows, the Michigan-Ontario PARs will still provide a 600 MW offset of potential circulation flows that will reduce the likelihood of TLR or the market-to-market process being needed to manage
congestion caused by loop flows.436

434 Joint Application Transmittal Letter at 6; Ex. MSO-Tab D at 31:18-20 (“the operation of the MI-ON PARs will
fully mitigate the problem 74% of the time and mitigate it by 600MW the remainder of the year”); Ex. MSO-Tab H
at 8:18-20 (“The Midwest ISO anticipates that the Michigan-Ontario PARs are expected to fully mitigate Lake Erie
loop flows approximately 74% of the time, and reduce them by approximately 600MW the remainder of the time.”).

435 Ex. MSO-Tab E at 19:5-17.

436 Ex. MSO-Tab E at 20:10-14.

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ITC rebuttal witness Dr. Ira Shavel offered the following explanations of the MI/ON PARs loop flow control capability:

With PARs in operation on the four lines connection Michigan and Ontario, up to
600 MW of loop flow can be controlled. Thus, when loop flow is between +600
MW (clockwise into Ontario) and -600 MW (counterclockwise into Michigan) it
can be eliminated. When it is outside of the 600 MW band it can be reduced by
600 MW. For example, if loop flow is 800 MW, the PARs will reduce it to 200

MW.437

NYISO cross-examination of Dr. Shavel:

Q So you believe it's a realistic assumption to expect that the operation of
the PARs will reduce Lake Erie loop flow to zero or remove the full 600
megawatts of Lake Erie loop flow just about every hour of every day of every
year?

A To a small number, if not to zero, yes.438

…

Q Should the Commission expect Lake Erie loop flows in excess of 600 megawatts to be reduced by 600 megawatts by the operation of the MichiganOntario PARs?

A Yes.

Q At all times? A Yes.439

On cross-examination, the NYISO asked MISO witness Mallinger what the term “fully mitigate” means.

Q On page 19, lines 5 to 6 of your direct testimony, Exhibit MSO tab E, you
state that “The Michigan-Ontario PARs, including the new PARs, are expected to
fully mitigate Lake Erie loop flows approximately 74% of the time.” What do

437 Ex. ITC-1 at 18:26-19:2.

438 Tr. 697:10-15 (corrected). 439 Tr. 698:14-19.

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you mean when you say “fully mitigate”? I'm not asking about the 74 percent. My question is, what does “fully mitigate” mean?

A“Fully mitigate” means the capability of the PARs to completely manage

the loop flows.

Q The capability to or the actual management? A The actual management of the PARs.
Q The actual management of the loop flow? A Of the loop flows.

Q So if but for the Michigan-Ontario PARs there would have been 600

megawatts of loop flow in a particular direction, clockwise or counterclockwise, it
doesn’t really matter, does the Midwest ISO expect that it and IESO will operate
the Michigan-Ontario PARs to bring Lake Erie loop flows to near zero
megawatts?

A Yes.440

The Joint Applicants have not submitted any evidence supporting their claim that the

MI/ON PARs will control 600 MW of Lake Erie loop flow nearly 100 percent of the time.441

The NYISO’s Vice President of Operations, Wesley Yeomans explained why the operating

effectiveness claimed by MISO and ITC was vastly overstated in his direct testimony.442 Section IX.B of this initial brief explains that actual MI/ON PAR operating data that MISO provided supports NYISO witness Yeomans’ testimony and shows that the MI/ON PARs have not
effectively conformed actual power flows to scheduled power flows.443 In fact, the data shows that the operation of the MI/ON PARs frequently increased Lake Erie loop flow.

440 Tr. 492:24-493:19.

441 Ex. MSO Tab E at 19:8-12. 442 Ex. NYI-1.

443 See Ex. NYI-66.

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1.MISO’s and ITC’s Claimed Operating Effectiveness Ignores the Fact

that the MI/ON PARs are Operated to Achieve a +/-200MW Control
Band

As explained by NYISO witness Yeomans,444 the MISO-IESO “Operating Instruction”
sets forth how MISO and IESO will operate the MI/ON PARs. The Operating Instruction
provides a operational target that actual power flows over the MI/ON Interface are to be
maintained within a +/-200 MW “Control Band” of the power flows that have been scheduled
over the MI/ON Interface to the maximum extent practical.445 For example, if the scheduled
flow is 400 MW from MISO to IESO, the MI/ON Interface flow will be within the Control Band
as long as the flow is from MISO to IESO, and it is less than 600 MW, and greater than 200
MW. It should not be particularly difficult for MISO and IESO to maintain the MI/ON Interface
flows within the 400MW operating range provided by the +/-200MW Control Band the vast
majority of the time.446 Lake Erie loop flows were within the Control Band in 49.41% of hours
over the year ending March 31, 2012447; before MISO and IESO even began operating the
MI/ON PARs to better conform actual power flows to scheduled power flows.448
At times when MI/ON Interface power flows are within the Control Band and are
expected to remain within the Control Band, the Operating Instruction does not require MISO
and IESO to take additional PAR actions to further reduce Lake Erie loop flow.449 MISO
witness Mallinger explained that “fully mitigate” means “completely manage” Lake Erie loop

444 Ex. NYI-1 at 11-12.

445 Ex. NYI-3 at 52 (Section 3.0, first bullet).

446 Yet MISO and IESO have had limited success keeping Lake Erie loop flow within the Control Band. See Sections IX.C and VII.B of this initial brief.

447 Ex. NYI-1 at 12:16-13:3 (referring to data in Ex NYI-4).

448 MISO and IESO did not start operating the MI/ON PARs to better conform actual power flows to scheduled power flows until April 5, 2012.

449 Ex. NYI-3 at 52 (Section 3.0) and 53 (Sections 3.4.1, 3.4.2).

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flow to “near zero megawatts.”450 However, operating to achieve the Control Band does not

require MISO and IESO to “fully mitigate” Lake Erie loop flow. Because the MI/ON PARs are
not operated to achieve near-perfect conformance between actual and scheduled power flows, it
is unlikely that the MI/ON PARs will “fully mitigate” Lake Erie loop flow with any frequency.

The MISO operating data in Exhibit NYI-66 shows that, over the April 5, 2012 to July
18, 2012 period, actual power flows measured at the MI/ON Interface were within +/-10 MW of
scheduled power flows (i.e., “fully mitigated”) in only 3.3% of the 30,121 five minute intervals
that MISO recorded. Actual MI/ON PAR operating data confirms that Joint Applicants’ claim
that the MI/ON PARs will “fully mitigate” Lake Erie loop flow in 74% of hours is vastly
overstated.

The studies and examples that ITC witness Ira Shavel included in his rebuttal testimony
(Ex. ITC-1) are similarly flawed because they incorporate the inaccurate expectation that the
MI/ON PARs will “fully mitigate,” to zero, Lake Erie loop flow whenever unscheduled power
flows are less than 600 MW, and will reduce Lake Erie loop flow by 600 MW at times when
unscheduled power flows exceed 600 MW. Again, MISO and IESO are operating the MI/ON
PARs to achieve the +/-200 MW Control Band, they are not operating the MI/ON PARs to “fully mitigate” Lake Erie loop flow.451

450 Tr. 492:24-493:19.

451 Exhibit NYI-66 shows that MISO and IESO have not done a particularly good job of operating the MI/ON PARs
to keep unscheduled power flows at the MI/ON Interface within the +/-200 MW Control Band. If MISO and IESO
have been operating the MI/ON PARs to “fully mitigate” Lake Erie loop flow, then their performance has been
abysmal. The actual performance of the MI/ON PARs from April 5, 2012 to July 18, 2012 is discussed in Section
IX.B of this initial brief.

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2.The Joint Applicants’ Expectations Regarding MI/ON PAR

Operating Effectiveness Do Not Account for PAR Outages

As NYISO witness Yeomans explained in his testimony452 and demonstrated with a
series of exhibits,453 the ability of the MI/ON PARs to mitigate Lake Erie unscheduled power
flows when one or more of the four circuits that comprise the MI/ON Interface are not PAR
controlled is severely limited. Mr. Yeomans’ example showed that if just one of the four circuits
at the MI/ON Interface is not PAR controlled, the PARs on the three remaining circuits would
have very limited ability to conform flow to schedule at the MI/ON Interface, and the local
system would have to operate near applicable reliability limits in order to provide this limited
degree of control.454 The Joint Applicants did not attempt to rebut this portion of Mr. Yeomans’
testimony.

ITC agrees that the Replacement PARs must be operated in conjunction with the Hydro
One PARs in order to impact Lake Erie unscheduled power flows.455 MISO agrees that the
MI/ON PARs’ ability to mitigate Lake Erie loop flow is significantly reduced when one or more
of the MI/ON PARs is out of service.456 MISO has also admitted that “there have been no
studies performed that quantify the effectiveness of the MI/ON PARs for any sub-optimal
condition.457

When the Replacement PARs entered service, and MISO and IESO began operating the
MI/ON PARs to better conform actual power flows to scheduled power flows at the MI/ON
Interface, MISO announced that it was not changing its method of calculating interface prices to

452 Ex. NYI-1 at 31-38.

453 Ex. NYI-30 through NYI-33.

454 See Ex. NYI-1 at 33:13-34:23; Ex. NYI-33. 455 Ex. NYI-37.

456 Ex. NYI-35.
457 Id.

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reflect an expectation that the MI/ON PARs would better control Lake Erie loop flow because Hydro One’s L4D PAR was out of service.458 NYISO witness Pike explained that MISO’s announcement was an admission that MISO did not expect the MI/ON PARs to be able to effectively conform actual power flows to scheduled power flows at the MI/ON Interface
without the L4D PAR in service.459

The Joint Applicants’ claim that the MI/ON PARs “are expected to fully mitigate Lake
Erie loop flows approximately 74% of the time, and reduce them by approximately 600 MW the
remainder of the time”460 assumes that all of the MI/ON PARs will be available 100% of the
time. The Joint Applicants’ claimed MI/ON PAR operating effectiveness does not account for
PAR outages.461 In Section IX.D of this initial brief, the NYISO reviews the MI/ON PARs’ long
history of outages. The NYISO also provides evidence that Hydro One has experienced repeated
problems with its L4D PAR (one of the MI/ON PARs) since December of 2011.462 At the
hearing on the merits NYISO witness Yeomans testified that the problems that have been
reported on Hydro One’s L4D PAR could cause that PAR to fail, or even explode.463 From
April 5, 2012 to July 18, 2012 (the period for which NYISO submitted MI/ON PAR operating
data in Exhibit NYI-66) at least one MI/ON PAR was out of service on 73 of the 104 days in the
period. Estimates of expected MI/ON PAR operating effectiveness must account for expected
MI/ON PAR outages.

458 Ex. NYI-21.

459 Ex. NYI-46 at 25.

460 Ex. MSO-Tab E at 19:5-17. 461 See Ex. NYI-1 at 29:3-12. 462 Ex. NYI-73.

463 Tr. 871:2-872:19.

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B.The MI/ON PARs Are Not Providing the Loop Flow Control Promised in the

Joint Application

1.Wes Yeomans’ Direct Testimony

NYISO witness Yeomans’ testimony addressed the first month of MI/ON PAR operation (the Replacement PARs entered service on April 5, 2012, the NYISO’s testimony was filed on
May 11, 2012). Mr. Yeomans’ testimony compared how frequently the +/-200MW Control
Band was achieved with four of the five MI/ON PARs in service, to how frequently power flows were within the Control Band in 2011 and early 2012, before MISO and IESO began operating the MI/ON PARs to better conform actual power flows to scheduled power flows at the MI/ON Interface. Mr. Yeomans concluded:

Based on the NYISO’s review of one months’ operating data with the L4D
PAR out of service, it appears that the performance of the [four] available
MI/ON PARs has not improved upon the performance that the NYISO
recorded for periods when the MI/ON PARs were not available.464

The Joint Applicants did not submit rebuttal testimony contesting or refuting Mr. Yeomans’ conclusion.

2.Introduction to Exhibit NYI-66

Following the submission of the NYISO’s testimony, the NYISO submitted a data

request to MISO and obtained data on the operation of the MI/ON PARs covering the period April 5, 2012 to July 18, 2012.465 The MI/ON PAR operating data that NYISO received from MISO was admitted into the evidentiary record as Exhibit NYI-66.

Exhibit NYI-66 covers 104 days of PAR operation broken down into 30,121 five-minute intervals. For each interval Exhibit NYI-66 provides the following information:

464 Ex. NYI-1 at 38:12-15.

465 April 5, 2012 was the date that the Replacement PARs entered service and MISO and IESO began operating the
MI/ON PARs to better conform actual power flows to scheduled power flows at the MI/ON Interface. July 18, 2012
was a day or two after the last day that NYISO was permitted to send discovery requests in this proceeding.

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Column One: the date/time, using a 24 hour clock—from interval beginning 00:00 to
interval beginning 23:55.466

Column Two: MISO’s average metered power flow over each five minute interval.467

• A positive number represents power flowing from IESO (Ontario) into
ITC (MISO). This is also referred to as counter-clockwise power flow.

• A negative number represents power flow from ITC (MISO) into IESO
(Ontario). This is also referred to as clockwise power flow.

Column Three: Scheduled interchange between MISO and IESO for each five minute
interval.468

• A positive number indicates that the power flow is scheduled in a counter-
clockwise direction.

• A negative number indicates that the power flow is scheduled in a
clockwise direction.

Column Four: The fourth column titled “5 Minute Average Adjusted Loop Flow” is
MISO’s measurement of the loop flow that actually occurred in each
interval in real-time.469

• A positive number in column four indicates that loop flow is occurring in
a counter-clockwise direction.

• A negative number in column four indicates that loop flow is occurring in
a clockwise direction.

Column Five: The fifth column, titled “Total PAR Offset” is the MISO’s estimate of the
impact that the MI/ON PARs had on loop flow in each interval.470

• The sign convention for column 5 is the opposite of the sign convention
used in columns 2, 3, 4 and 6.

o A positive number in column five indicates that MISO believes the
MI/ON PARs were influencing power flows to be in a more
clockwise direction.

o A negative number in column five indicates that MISO believes
the MI/ON PARs were influencing power flows to be in a more
counter-clockwise direction.471

466 Tr. 879:6-17.

467 Tr. 879:17-20.

468 Tr. 879:25-880:1.

469 Tr. 880:1-881:5; 882:15-17. 470 Tr. 881:10-15.

471 MISO provided its “Total PAR Offset” estimate to the NYISO after the period for requesting discovery had

concluded. MISO gave the NYISO a brief oral explanation of how its “Total PAR Offset” estimate was developed.
MISO explained that its estimate of the impact that the MI/ON PARs had on Lake Erie loop flow (measured over
the MI/ON Interface) in each 5 minute interval takes into account the tap positions of all of the MI/ON PARs and
metered flows over the interface. The NYISO was not given an opportunity to review the method that MISO used to

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Column Six: The sixth column titled “Actual Loop Flow” is the MISO’s estimate of
what the loop flow would have been if the MI/ON PARs did not exist.472

• The loop flow that was actually experienced, from column four, was
modified by MISO’s estimated “Total PAR Offset” in column five, to
arrive at MISO’s estimated “Actual Loop Flow” in column six.

• The average actual loop flow that MISO metered in each 5 minute interval
is in column four of Ex. NYI-66. Column six is MISO’s estimate of what
loop flow would have been if the MI/ON PARs did not exist.

Column Seven: The seventh column, called “Tap Move Performed,” indicates whether or
not one or more taps were moved (changed) on one or more of the MI/ON
PARs in the relevant interval (simple yes or no).473

• MISO has claimed that the data in this column is Protected Information.

Column Eight: The eighth column identifies the NERC IDC status that MISO and IESO
set the MI/ON PARs to.474

• The MI/ON PAR status is either “Regulated” or “Non-Regulated.”

• In a pleading MISO and IESO submitted to the United States Department
of Energy they committed to set the NERC IDC flag to Non-Regulated
whenever unscheduled power flows were outside the +/-200 MW Control
Band specified in the Operating Instruction, or were expected to be outside
the +/-200 MW Control Band specified in the Operating Instruction.475

• Setting the NERC IDC flag accurately is important, because it affects the
ability of reliability coordinators (NYISO, PJM, MISO and IESO) to use
TLR to address reliability concerns at times when the MI/ON PARs are
not successfully conforming actual power flows to scheduled power flows.
The importance of setting the IDC flag correctly is discussed in Section
IX.C of this initial brief.

• MISO has claimed that the data in this column is Protected Information.

develop its “Total PAR Offset” estimate, or to test the accuracy of the MISO’s “Total PAR Offset” estimate.

Because MISO employee Kevin Frankeny attested that the information MISO provided was “true and correct, to the
best of [his] knowledge, information and belief,” the NYISO uses the estimate MISO provided in this initial brief to
respond to the Joint Application. The NYISO uses MISO’s “Total PAR Offset” estimate as a matter of convenience
in this initial brief because the MISO has claimed that the actual tap positions of the MI/ON PARs in each five
minute interval that are reported in Exhibit NYI-66 are Protected Information. MISO has not claimed that its “Total
PAR Offset” estimate (which appears to be primarily based on the tap positions of the MI/ON PARs) is protected
information. The NYISO’s use of the “Total PAR Offset” estimate that MISO provided against the Joint Applicants
should not be interpreted as indicating that the NYISO agrees to or accepts the accuracy of the untested data that
MISO provided for any other purpose

472 Tr. 881:18-25; 882:7-9.

473 Tr. 884:7-17.

474 Tr. 884:21-885:8.

475 Ex. NYI-10 at 7 (“Taken together, the provisions of the CO2 [Operating Instruction] require that MISO and IESO take actions to regulate loop flow for as long as possible. When that ability is exhausted, and loop flow exceeds (or is expected to exceed) +/-200 MW, the IDC status flag will be set to “Non-Regulate.”); see also, Ex. NYI-64, Ex. NYI-72 at 2, Tr. 809:16-810:2.

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Columns Nine through Twelve: specify the PAR tap position in every 5-minute interval
for ITC’s B3N PARs (both PARs consolidated into a single entry), the
Hydro One PAR on the L4D transmission circuit, the Hydro One PAR on
the L51D transmission circuit and the Hydro One PAR on the J5D
transmission circuit.476

• PAR tap range on the B3N PARs 2-66 (1-33 each). Midpoint (neutral
tap) 34.477

• PAR tap range on the L4D and L51D PARs 1-66. Midpoint (neutral
tap) 34.478

• PAR tap range on the J5D PAR 1-35. Midpoint (neutral tap) 18.479

Exhibit NYI-66 tells a compelling story about the actual operating effectiveness of the
MI/ON PARs in their first 104 days of operation. The “story” can be told in two ways, by
tabulating the data MISO provided in various ways to show how the MI/ON PARs operated, or
by taking the data for a particular operating day and turning the raw data into a narrative of what
happened on that operating day. The NYISO uses both methods to review MISO’s Exhibit NYI-

66 data below.

3. Review of MISO’s Exhibit NYI-66 Data—Tabulation of Operating

Data Covering April 5, 2012 to July 18, 2012

The NYISO compiled statistics addressing the MI/ON PARs performance over the 104 days that are addressed in Exhibit NYI-66. The NYISO also compiled data on MISO’s and IESO’s accuracy in setting the NERC IDC status. The data the NYISO compiled addressing the IDC Status is discussed in Section IX.C of this initial brief.

The NYISO performed its analysis of the Exhibit NYI-66 data in several steps. First, the
NYISO used the data in Column Four of the Exhibit NYI-66 data to determine the average, net
directional value of loop flow for the period. On average, Lake Erie loop flow was 48 MW in a

476 Tr. 885:20-886:11.

477 Tr. 1135:3-5.

478 Tr. 887:19-21.
479 Tr. 887:22-23.

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counter-clockwise direction over the April 5 to July 18, 2012 period. The data in Column Six of
Exhibit NYI-66 (MISO’s estimate of what Lake Erie loop flow would have been, but for the
operation of the MI/ON PARs) indicated that, if the MI/ON PARs had not been in operation, the
average, net directional value of Lake Erie loop flow would have been 85 MW in a counter-
clockwise direction. The data in Column Six indicates that, on average the MI/ON PARs
blocked 37 MW of counter-clockwise loop flow over the April 5 to July 18, 2012 period.
Blocking counter-clockwise loop flow can be detrimental to the NYISO because counter-
clockwise loop flow tends to relieve transmission congestion in New York.480
The NYISO next used the data in Column Four of Exhibit NYI-66 to calculate the
average absolute value of Lake Erie loop flow for the April 5 to July 18, 2012 period. The
average absolute value of loop flow for the April 5 to July 18, 2012 period was 214 MW. On
average, the absolute value of Lake Erie loop flow was outside the +/-200 MW Control Band
specified in the Operating Instruction. This is the first of many statistics suggesting that the
MI/ON PARs were not effective in conforming actual power flows to scheduled power flows at
the MI/ON Interface.

Of the 30,121 five minute intervals for which data was provided, the Column Four data
indicated that loop flow was within the +/-200 MW Control Band in 16,696 intervals, or 55.4%
of the total intervals. As Mr. Yeomans explained in his Direct Testimony, for the twelve months
ending March 31, 2012 (just before the Replacement PARs entered service) MI/ON Interface
flow was within +/-200 MW of the MI/ON Interface schedule in 49.41% of hours.481 However,
for the seven month period commencing July 1, 2011 and ending January 31, 2012 (again, before
the Replacement PARs entered service) MI/ON Interface flows were estimated to be within +/-

480 See Section V.C of this initial brief.

481 Exhibit NYI-1 at 37:15-17; Exhibit NYI-4.

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200 MW of MI/ON Interface schedules in 57.5% of hours.482 In October of 2011, MI/ON

Interface flow was within +/-200 MW of the MI/ON Interface schedule in 75.7% of hours.483 The operation of the MI/ON PARs to better conform flow to schedule at the MI/ON Interface from April 5 to July 18, 2012 does not appear to have reduced Lake Erie loop flow.

The NYISO also checked Exhibit NYI-66 to see if the extremes in Lake Erie loop flow had been moderated by the operation of the MI/ON PARs. From April 5 to July 18, 2012, the highest recorded interval of counter-clockwise loop flow was 1444 MW, which is more than double the MI/ON PARs claimed control capability of 600 MW. The highest recorded interval clockwise loop flow was 864 MW.

Next, the NYISO tested the data in Exhibit NYI-66 Column Four to see how frequently
Lake Erie loop flow was “fully mitigated.”484 Based on MISO witness Mallinger’s testimony
that loop flow is “fully mitigated” when it is “completely managed,”485 so the NYISO used a +/-

10 MW bandwidth to perform its test. Of the 30,121 five minute intervals considered, actual

power flows were within +/-10 MW of scheduled power flows in only 1003 intervals, or 3.3% of
all intervals. This doesn’t even come close to the “fully mitigated in 74% of all hours” claim that
MISO witness Mallinger, and many other MISO and ITC witnesses, made in their testimonies.

After testing the validity of the Joint Applicants’ claims about how frequently the MI/ON
PARs would “fully mitigate” Lake Erie loop flow, the NYISO checked to see how often the
MI/ON PARs reduced Lake Erie loop flow by 600 MW or more. Column Four of Exhibit NYI-

66 (actual, real-time loop flow) identified 1,047 intervals (3.5 percent of all intervals) in which

482 Exhibit NYI-1 at 37:19-21; Exhibit NYI-4.

483 Exhibit NYI-1 at 38:1-2; Exhibit NYI-4. 484 See Section IX.A of this Initial Brief. 485 Tr. 492:24-493:19.

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Lake Erie loop flow was 600 MW or greater. Column five of Exhibit NYI, MISO’s estimated

“Total PAR Offset,” indicates that the MI/ON PARs blocked 600 MW or more of Lake Erie loop
flow in only 129 intervals, which was just 0.4 percent of the 30,121 intervals included in Exhibit
NYI-66. The Exhibit NYI-66 data indicates that the Joint Applicants’ claim that the MI/ON
PARs will block 600 MW of Lake Erie loop flow “at all times” is significantly overstated.
Finally, the NYISO reviewed the data from Exhibit NYI-66 to determine when the
operation of the MI/ON PARs actually increased the magnitude of Lake Erie loop flow. In order
to determine when the operation of the MI/ON PARs actually increased the magnitude of Lake
Erie loop flow, the NYISO compared the actual Lake Erie loop flow in column four of Exhibit
NYI-66, to MISO’s estimate of what Lake Erie loop flow would have been if there were no
PARs at the MI/ON Interface in Column Six. When the loop flow in Column Four of Exhibit
NYI-66 is greater than the loop flow in Column Six of Exhibit NYI-66 (without regard to the
direction of the loop flow in either column), it indicates that the operation of the MI/ON PARs
exacerbated Lake Erie loop flow.

The NYISO’s comparison indicated that the operation of the MI/ON PARs made Lake
Erie loop flow worse in 10,158 five minute intervals, or 33.7 percent of all intervals over the
April 5 to July 18, 2012 period. The operation of the MI/ON PARs exacerbated Lake Erie loop
flow in 5,613 intervals (18.6 percent of all intervals) during which the actual (Column Four)
Lake Erie loop flow was outside the +/-200 MW Control Band. In 1337 intervals (4.4 percent of
all intervals) the operation of the MI/ON PARs caused loop flow that was expected to be inside
the +/-200 MW Control Band to instead fall outside the Control Band. The data in Exhibit NYI-

66 indicates that from April 5 to July 18, 2012 the MI/ON PARs were frequently a cause of additional Lake Erie loop flow.

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4.Interpretation of Exhibit NYI-66 Data for Specific Operating Days

a.June 16, 2012 Operating Day

On June 16, 2012 the L4D PAR was out-of-service. The MI/ON PARs showed little ability to control of loop flow with only three of the four interface circuits PAR controlled.486 The L4D PAR was out of service on this day.487 The day began with counterclockwise loop flow close to the 200 MW limit of the Control Band. Loop flow bounced into and out of the Control Band from midnight until 1:00 a.m., after which time loop flow remained within the +/-
200 MW control band for almost all intervals until 8:00 a.m.488

Shortly after 8:00 a.m., counterclockwise loop flow exceeded the Control Band. Lake
Erie loop flow remained outside the Control Band for the rest of the day.489 MISO and IESO
made little effort to move the MI/ON PARs to better conform actual power flows to scheduled
power flows at the MI/ON Interface. The MI/ON PARs were only moved in fifteen 5-minute
intervals out of 191 5-minute intervals between 8:05 a.m. and 11:55 p.m. None of the PAR
moves that MISO and IESO took brought actual power flow significantly closer to scheduled
power flow.

In the morning,490 MISO and IESO placed the MI/ON PARs in “Regulated” mode at a
time when loop flow was hundreds of MWs away from achieving the +/-200 MW Control
Band.491 MISO and IESO then left the PARs in “Regulated” mode while the loop flow was well

486 Ex. NYI-66 at 551-559.

487 Ex. NYI-73 at 3 and 6 (the PS4 Hydro One PAR on the L4D line was bypassed on June 10, 2012 and returned to service on June 17, 2012).

488 Exhibit NYI-66 at 551-554.
489 Tr. 888:1-10 (corrected).

490 NYISO is not referencing the specific interval in which the switch to “Regulated” mode was made in order to avoid revealing Protected Information. The relevant interval occurred on page 554 of Exhibit NYI-66.

491 Ex. NYI-66 at 554 (compare the “IDC Status” column to the “5 Minute Avg Adj Loop Flow” column to identify
time intervals when the MI/ON PARs are set to Regulated but loop flow exceeds the +/-200 MW control band).

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outside the +/-200 MW control band for more than an hour. MISO and IESO’s setting of the Regulated Mode in the NERC IDC was not consistent with the commitments that MISO and IESO made to the DOE in Exhibit NYI-10.

b.July 18, 2012 Operating Day

On July 18, 2012, MISO and IESO actively operated the MI/ON PARs to control loop

flow.492 From 2:50 a.m. until around 10:00 a.m., MISO and IESO operated the PARs reasonably well to conform actual power flows to scheduled power flows within the +/-200 MW Control Band. The MI/ON PARs operation was not precise enough to always maintain loop flow within the Control Band, however when the loop flow started to leave the Control Band, MISO and IESO operated the MI/ON PARs appropriately to compensate.

Lake Erie loop flow changed dramatically between 10:00 and 10:15 a.m.493 The MI/ON
PARs were not able to keep up with the change and, by 10:10 the MI/ON PARs were making
loop flow worse, not better.494 Based on the “Actual Loop Flow” estimate in Column Six of
MISO’s data, it appears that loop flow would have remained within the +/-200MW bandwidth
from 10:10 a.m. until around 11:50 a.m. if the MI/ON PARs had not been in service.495 The
MI/ON PARs were causing approximately 400 MW of additional clockwise flow. According to
the data MISO provided, the operation of the MI/ON PARs was pushing loop flows that would
have been within the +/-200 MW control band substantially outside the control band in the

492 Ex. NYI-66. All of the operating data discussed in this section can be found in Ex. NYI-66. Additional citations are included as necessary.

493 Tr. 899:16-20.

494 For example, on July 18, 2012 at 10:15 a.m., actual loop flow from Column Four was 337 MW clockwise. The Total PAR Offset in Column Five indicates that the MI/ON PARs were being operated to cause 403 MW of
clockwise flow. So, if the MI/ON PARs had not been in service at all, loop flow would have been 65 MW in a counter-clockwise direction. Sixty-five MW of Lake Erie loop flow would have been well within the permitted Control Band. In this case the operation of the MI/ON PARs exacerbated Lake Erie loop flow.

495 Ex. NYI-66 (the column titled “Actual Loop Flow” is “what the flow would have been had there been no PARs.” Tr. 882:21-22).

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clockwise direction. MISO and IESO were operating the PARs in a manner that caused more
Lake Erie loop flow, and that pushed Lake Erie loop flow outside the Control Band.496
Starting at approximately 11:40 a.m. MISO and IESO began taking actions to bring loop flow back within the Control Band. Based on the MISO calculated Total PAR Offset term in Column Five of Ex. NYI-66,497 it took MISO and IESO an hour (until 12:40) to get the MI/ON PARs turned around so that the PARs were actually reducing clockwise flow, rather than
exacerbating it. Other periods of high clockwise loop flow occurred over the course of the day.
From 14:00 (2:00 p.m.) until 15:15 (3:15 p.m.) loop flow averaged more than 400 MW in the
clockwise direction.

Beginning around 17:00 (5:00 p.m.), loop flow became significantly counterclockwise,
and again, it took MISO and IESO approximately 45 minutes to get the MI/ON PARs turned
back around so that they were not further exacerbating the counterclockwise loop flow that was
occurring. Loop flow remains significantly counterclockwise, and outside the +/-200 MW
Control Band, from just before 17:00 (5:00 p.m.) until around 21:00 (9:00 p.m.).
Comparing the “IDC Status” column (Column Eight) to the actual loop flow data
reported in Column Four, it is apparent that on July 18, 2012 MISO and IESO placed the MI/ON
PARs in “Regulated” mode at a time when loop flow was not even close to achieving the +/-200
MW control band.498 MISO and IESO then left the PARs in “Regulated” mode while the loop
flow was well outside the +/-200 MW control band for more than two consecutive hours. MISO
and IESO’s actions were not consistent with the commitments that they made to the DOE in
Exhibit NYI-10.

496 Tr. 900:11-18.

497 Ex. NYI-66 (the column titled “Total PAR Offset” is the calculated contribution to loop flow from the MI/ON PARs Tr. 882:22-24).

498 See Ex. NYI-66 at 794.

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The Exhibit NYI-66 data for July 18 demonstrates that operating the MI/ON PARs is

more like driving a freight train than it is like driving a Porsche. Operation of the MI/ON PARs requires numerous decisions, each decision takes time and input and actions may be required of several parties (MISO, IESO, ITC, Hydro One). When a decision turns out to be wrong, it takes time to correct because the MI/ON PARs have to be tapped back in the opposite direction. PARs are electro-mechanical devices and constantly tapping them up and down will eventually wear the PARs out, so operators tend to be cautious about taking too many taps.

MISO and ITC claim that the MI/ON PARs will be operated to perfectly match flow to schedule and eliminate 600 MW of loop flow in every hour of every day. Exhibit NYI-66 shows what has actually happened is very different from what the MISO and ITC claim will happen. The hours where 600 MW of loop flow is eliminated are rare. Exhibit NYI-66 actually identifies more than 846 hours between April 5, 2012 and July 18, 2012 when MISO and IESO operate the PARs in a manner that makes loop flow worse, not better.499

The NYISO briefly discusses the Exhibit NYI-66 data addressing the June 19, 2012 and July 17, 2012 operating days in Section IX.B.5 of this initial brief.

5. Response to Joint Applicants’ Argument that the Operation of the

PARs from April 5, 2012 to July 18, 2012 is Not Indicative of Expected Future Efficacy

In Ex. ITC-13, ITC, MISO and IESO employees state “that the performance of the MI-
ON PARs since ITC’s B3N PARs went into service in early April, 2012 has been well within the
normal range for the start up phase of major new electric facilities.”500 The NYISO cannot agree

499 See Ex. NYI-66 (compare the “5 Minute Avg Adj Loop Flow” column to the “Actual Loop Flow” column to
identify time intervals when the “5 Minute Avg Adj Loop Flow” value is greater than the “Actual Loop Flow”
value).

500 Ex. ITC-13, Affidavit of Michael Moltane.

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with this statement. The operating data shows that MISO and IESO are not consistently trying to
operate the MI/ON PARs to control actual power flows to scheduled power flows.501
The NYISO would agree that the performance has been within the expected range for a startup facility if the operating data showed that MISO and IESO were taking taps on the MI/ON PARs and occasionally under-correcting, overcorrecting or overshooting the bounds of the +/-
200 MW Control Band. However, these are not the sorts of operating problems that the NYISO
has identified in its review.

While MISO and ITC are interested in recovering a portion of the cost of the

Replacement PARs from NYISO and PJM customers, Exhibit NYT-35 suggests that MISO and
ITC are not interested in undertaking a significant effort to ensure that the MI/ON PARs control
Lake Erie loop flow to within the 200 MW Control Band that they proposed to the United States
Department of Energy. Exhibit NYT-35 states that if operating to achieve the Control Band
proves too onerous, MISO, ITC and IESO need to have a way to escape the obligation that they
assumed.

MISO’s and ITC’s lack of interest in actually achieving the Control Band is evident from
the data in Exhibit NYI-66. On the limited occasions when it appears that MISO and IESO are
really trying to operate the PARs to remain within the Control Band, they can achieve significant
success. For example, on July 18, 2012 from 3:00 in the morning until approximately 10:00 in
the morning it appears that MISO and IESO actively operated the MI/ON PARs to conform
actual power flows to scheduled power flows at the MI/ON Interface. Column Five of Exhibit
NYI-66 indicates that the MI/ON PARs were operated to mitigate nearly 700 MW of loop

501 See, Ex. NYI-66.

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flow502 for a period of approximately four hours. Unfortunately, the control that was briefly

achieved by actively operating the MI/ON PARs on July 18 has been the exception, not the rule.
Much of the time, the MI/ON PARs are not being operated in the manner that would be necessary to better conform actual power flows to scheduled power flows at the MI/ON
Interface. The data in Column Seven “Tap Move Performed” of Exhibit NYI-66 indicates that
PAR tap moves only occurred in 1,458 five minute intervals, or 4.8% of the total intervals
included in the Exhibit.

On June 19, 2012, there was predictable counter-clockwise Lake Erie loop flow that
significantly exceeded the +/-200 MW Control Band for most of the day. The MI/ON PARs
were operated to counteract approximately 400 MW of loop flow, but no attempt was made to
operate the PARs to achieve the claimed limits of their control capability, or to further reduce
Lake Erie loop flow. Only one MI/ON PAR was moved in one five minute interval over the
entire day.503

On July 17, 2012 the L4D PAR was out of service. Counter-clockwise loop flow was

extremely high that day. Over the course of the day, there were only two PAR tap moves taken,
despite the loop flow being outside the +/-200 MW control band for the entire day. For much of
the day, the MI/ON PARs were slightly exacerbating (by up to 24 MW) the high Lake Erie loop
flow that was occurring. Although MISO claims that 300-350 MW of loop flow can be
mitigated with three of the four MI/ON circuits controlled,504 Column Five of Exhibit NYI-66

502 Exhibit NYI-66 indicates that the MI/ON PARs blocked 600 MW or more of Lake Erie loop flow in only 129 intervals, which was just 0.4 percent of the 30,121 intervals included in the Exhibit.

503 Ex. NYI-66 at 579.

504 See Ex. NYI-35 at 2 (“MISO believes that with the Hydro One L4D PAR out of service, overall capacity to

reduce loop flows will decline so MISO would expect the MI/ON PARs to fully mitigate loop flows 40-50% of the
time. However, the MI/ON PARs will still be able to mitigate Lake Erie loop flows by approximately 300-350
MW.”).

146

“Total PAR Offset” indicates that on July 17 the PARs were never operated to reduce Lake Erie
loop flow.505 On July 17 MISO and IESO either could not, or would not, take additional taps on
the MI/ON PARs to better conform actual power flows to scheduled power flows at the MI/ON
Interface.

Section 3.0 of the MISO/IESO Operating Instruction states “The PARs shall be operated such that: The Interface Deviation is maintained within the Control Band to the maximum extent practical considering operational feasibility, safety, equipment limitations and regulatory and
statutory requirements…” On June 19, 2012 and July 17, 2012 it is not clear from the MISO
data contained in Exhibit NYI-66 whether the MI/ON PARs had reached the limits of their
control capability, or if the operators chose not to actively operate the MI/ON PARs to better
control Lake Erie loop flow, in violation of the requirements of the Operating Instruction. The
MI/ON PARs should have been able to provide additional loop flow control on those days, based on MISO’s claims that the MI/ON PARs will provide 600 MW offset of potential loop flows
almost all of the time,506 and can provide 300-350 MW of control when one of the four circuits
on the MI/ON Interface is not PAR controlled.507

The NYISO cannot accept MISO’s, ITC’s and IESO’s claims that the MI/ON PARs are performing as expected. The data in Ex. NYI-66 shows otherwise.

C. MISO’s and IESO’s Failure to Timely Set the “Regulated/Non-Regulated”

Flag in the NERC Interchange Distribution Calculator Can Delay or Prevent
NYISO’s Ability to Use TLR to Resolve Reliability Issues at Times When the
MI/ON PARs Are Not Successfully Mitigating Unscheduled Power Flows

TLR is a procedure that Reliability Coordinators like the NYISO, MISO, IESO and PJM
use to address power flows that are causing reliability impacts on their transmission systems. It

505 Ex. NYI-66 at 786-794.

506 Ex. MSO-Tab E at 19:5-17. 507 Ex. NYI-35 at 2.

147

permits Reliability Coordinators to request the curtailment or removal of inter-Control Area

transactions that have a substantial impact on a particular transmission constraint that presents a reliability risk.508 TLR is implemented via the North American Electric Reliability
Corporation’s (“NERC’s”) Interchange Distribution Calculator (“IDC”). The IDC is a database that identifies inter-Control Area transactions that have a 5% or greater impact on the
transmission constraint that TLR is being requested to address.509 The IDC identifies proposed pro rata reductions to all of the transactions that have a 5% or greater impact on the transmission constraint to achieve the requested level of relief. The IDC transmits the pro rata transaction reductions to each of the Balancing Authorities that are participants in the transactions that need to be curtailed or removed to provide the requested relief.510

The MI/ON PARs are subject to a modeling treatment in the NERC IDC that is different
from all of the other PARs that surround Lake Erie. At times when MISO and IESO set the
MI/ON PARs to be “regulated” in the NERC IDC model, that model assumes that there is no
Lake Erie loop flow, whatsoever, crossing the MI/ON PARs, so no power flows will be seen as
crossing the MISO/IESO border and potentially causing a 5% or greater impact.511 In other
words, the IDC model will represent power flows as conforming to schedules, without regard to
what is actually happening in the real world.512 At times when the MI/ON PARs are set to “non-
regulated,” Lake Erie loop flow is permitted to flow across the MI/ON interface in the NERC
IDC model, and transactions at that interface are available to be removed via TLR in order to
address reliability concerns that Lake Erie loop flow is causing or aggravating in New York,

508 Ex. NYI-1 at 5:16-23.

509 Ex. NYI-1 at 6:3-17.
510 Ex. NYI-1 at 6:10-15.
511 Tr. 835:21-25.

512 Ex. NYI-1 at 8:14-20.

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PJM, MISO or IESO.513 All other PARs around Lake Erie are currently modeled in the IDC as “non-regulated” at all times, so transactions scheduled over those PARs remain available to be removed in order to provide TLR relief.

MISO and IESO are responsible for determining if Lake Erie loop flows are within the
+/-200 MW “control band,” and are expected to remain within the +/-200 MW control band, and for accurately setting the IDC mode to “regulated” or “non-regulated” on that basis.514 It is very important for MISO and IESO to timely and accurately reflect the correct scheduling mode for
the MI/ON PARs in the NERC IDC. When the IDC flag is set to “regulated,” this blocks the
ability of NYISO and PJM (and other control areas) to use TLRs to remove transactions that are adversely impacting reliability.515

The NYISO used the data in Exhibit NYI-66 to review how accurately and timely MISO
and IESO have been performing this important duty that has reliability implications. In
particular, the NYISO compared the actual loop flow in Column Four of Ex. NYI-66 to the “IDC
Status” in Column Eight of Ex. NYI-66. The NYISO expected to find that when the Lake Erie
loop flow in Column Four was less than 200 MW, the IDC Status flag would be set to
“Regulated.” When the loop flow in Column Four exceeded 200 MW (regardless of direction)
the NYISO expected to find the IDC Status flag set to “Non-Regulated.” However, that is not
what the NYISO found.

Considering only the days on which there was at least one change made to the IDC Status
in Ex. NYI-66 (in order to address certain infirmities in the data that the MISO provided516), the

513 Tr. 835:9-836:5.

514 Ex. NYI-10 at 7; Ex. NYI-64 at 2; Ex. NYI-72 at 2. 515 Ex. NYI-1 at 8:22-9:2.

516 See Tr. 893:18-894:14.

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NYISO found that 28.6 percent of the time that MISO and IESO set the flag to “Regulated,” it is set incorrectly. Column Four indicates that Lake Erie loop flow is in excess of 200 MW, yet MISO and IESO have set the IDC Status to “Regulated.”

MISO’s and IESO’s lack of diligence in setting the IDC Status of the MI/ON PARs could
have significant adverse reliability consequences for the NYISO, and for other potentially
impacted Control Areas. It is not acceptable for MISO and IESO to set the IDC status flag to
“Regulated,” then wait for other Reliability Coordinators to call and complain. This causes delay
that prevents timely resolution of reliability issues. It would be unjust and unreasonable for
NYISO and PJM to be charged for costs of the Replacement PARs when MISO’s and IESO’s
failure to timely and accurately implement their MI/ON PAR operating responsibilities can
prevent the NYISO, PJM, and other Reliability Coordinators from timely addressing reliability
issues arising in their Control Areas.

D.The MI/ON PARs Outage History, Including Recent Problems with Hydro

One’s L4D PAR

NYISO witness Yeomans reviewed the outage history of the MI/ON PARs from 2001 through May 11, 2012 in his direct testimony.517 Because ITC, Detroit Edison and IESO were not able to provide historical data on MI/ON PAR outages, Mr. Yeomans instead reviewed a number of NERC, NPCC and other similar third-party reports518 that were used to develop reliability planning cases, and that discuss outages of the MI/ON PARs during that period
because the outage facilities needed to be represented as unavailable in the planning cases.
Exhibit NYI-11 summarizes the reports Mr. Yeomans relied on, which show that the history of the MI/ON PARs indicates that they are prone to failure.

517 Ex. NYI-1 at 23-27.

518 These reports are attached to Mr. Yeomans’ testimony (Exhibit NYI-1) as Exhibits NYI-12, -13, -14, -15 (at p. 40), -16 (at pp. 34-35), -17 (at p. 21), -18 (at p. 24), -19 (at p. 25), -20 through -23, and -24 (at p. 22).

150

From 2003 to April 5, 2012, the MI/ON PARs were physically bypassed much of the

time and were not ordinarily being operated to regulate power flows.519 Given the MI/ON PARs operation mode, it is not surprising that the PARs service record was better than average during this time period.

On April 10, 2003, ITC’s Chief Executive Officer sent an e-mail discussing the thenrecent failure of the Original PAR. Mr. Welch’s e-mail said “it appears that these devices are nothing but junk.”520 ITC chose a different manufacturer for its Replacement PARs than the manufacturer that constructed the Original PAR.521 However, Hydro One’s L4D and L51D PARs were constructed by the same manufacturer as the Original PAR, and they are of the same approximate vintage as the Original PAR was.

Hydro One has been experiencing repeated problems with its L4D PAR. When the

Replacement PARs were placed into service on April 5, 2012, the L4D PAR was out-of-service due to a forced outage that began on December 17, 2011.522

Data responses provided by IESO indicate that problems with the MI/ON PARs have
continued in the 2011-2012 timeframe. On December 17, 2011, the L4D PAR went out of
service and did not return to service until June 1, 2012, due to a “gas accumulation alarm.”523
The reason for the outage was also described by IESO as a “bad oil sample.”524 In addition:

• The L4D PAR was bypassed on June 10, 2012 due to another “gas accumulation

alarm,” and returned to service on June 17 at 13:16; and

519 Tr. 873:8-19.

520 Exhibit NYI-29 (emphasis added).

521 Ex. NYI-1 at 30-31. See also Ex. NYI-27 through NYI-29. 522 Ex. NYI-1 at 27-29; Ex. NYI-20.

523 Exhibit NYI-73 at 1.

524 Exhibit NYI-20.

151

•The L4D PAR was bypassed on July 12, 2012 at 21:28 p.m. due to a “gas

accumulation alarm,” and returned to service on July 18 at 00:54 a.m.525

At the hearing, NYISO witness Yeomans explained gas accumulation/bad oil sample issues that arise with PARs:

On transformers and PARs, there are devices that can sense for gas developing

inside of the device so it can be inside a transformer or inside a PAR and these

alarms are important. These sensors are important and it sends alarm to operators who know to quickly take that device out of service.

Inside the transformer or the phase angle regulator are these very large copper

coils that are immersed in oil. If you have a break in the coil or a bad connection or the start of a break, anything where you start to get possibly arcing or flashing or the electricity jumping across that gap, this is submersed in oil. The oil gets
hot and it bubbles.

Mr. Yeomans went on to explain that gassing and bad oil samples present a very serious concern:

When the bubbles quite frankly pop at the top, the gas is released in the very top
of the transformer where there's an air gap, the sensor senses the gas and asset
owners and operators know that's a dangerous situation, dangerous in a couple
ways.

First of all, you may have a fault or disconnection or arcing inside the

transformer. You have oil overheating and boiling. You have pressure building up, so you have the danger of an explosion or just the information that it appears there's something wrong on the inside of that device.526

In light of the serious and recurring nature of this issue affecting the L4D PAR, there is a

heightened risk of outage of that Hydro One PAR. If the L4D PAR is removed from service, one
of the four circuits at the MI/ON Interface will not be PAR controlled. As the NYISO explains
in Section IX.A.2 of this initial brief, the MI/ON PARs have little ability to control loop flow
when one of the four circuits that comprise the MI/ON Interface is free-flowing. As Section VIII
of this initial brief explains, MISO and ITC propose to continue to charge the NYISO’s
customers for the undefined “service” that the MI/ON PARs are expected to provide, without

525 Exhibit NYI-73.

526 Tr. 871:25-872:10.

152

regard to the availability of the MI/ON PARs, or the actual ability of the PARs to conform actual power flows to scheduled power flows at the MI/ON Interface.

The MI/ON PARs will experience outages. When one or more of the MI/ON PARs is out-of-service, the MI/ON PARs’ ability to conform actual power flows to scheduled power flows at the MI/ON Interface will be limited. The Joint Applicants’ failure to address the
possibility of a MI/ON PAR outage in the proposed tariff revisions is one of many reasons that their proposed charge to the NYISO’s customers is unjust and unreasonable.

E. ITC and MISO Have Indicated a Lack of Commitment to Operate the

MI/ON PARs In the Manner Called For in the Operating Instruction and in Representations to the DOE

The September 9, 2011 e-mail from ITC to MISO provided as Exhibit NYT-35 indicates a lack of commitment by MISO and ITC to operating the MI/ON PARs to achieve the +/-200 MW Control Band called for in the Operating Instruction that MISO and IESO presented to the DOE in the Presidential Permit proceeding.527 In Exhibit NYT-35, Mr. Moltane of ITC states that he is “greatly concerned over the apparent volatility of the loop flow” shown in the August 2011 loop flow data. He goes on to state:

As you know ITC’s concurrence with 200Mw Deadband was based on the

assumption and MISO study that the PARs would only have to be moved a

limited amount of time. If I am reading this graph correctly, both MISO and ITC would have had to have a dedicated employee doing nothing but moving the
PARs all month….

At this point, I am not suggesting changing anything as we are at a critical point
in the negotiations with our external partners. However, we will need to figure
out some criteria for changing the deadband or methodology if we end up having to move these things as frequently as this chart indicates. We need to absolutely ensure that we have the flexibility to change the operation if this becomes onerous on MISO, ITC and IESO.528

527 See Ex. NYI-3 at 50 of 63 to 59 of 63. 528 Exh. NYI-35 (emphasis added).

153

Throughout this proceeding, MISO and ITC have repeatedly claimed that they intend to operate the MI/ON PARs to conform actual power flows to scheduled power flows at the MI/ON Interface in order to “fully mitigate” Lake Erie loop flow whenever it is less than 600MW, and to reduce Lake Erie loop flow by 600 MW at all other times.529 Exhibit NYI-35 indicates that ITC and MISO may not be strongly committed to achieving this operating goal.

As Section VIII of this initial brief explains, the Joint Applicants’ proposed tariff

revisions do not require MISO and ITC to “fully mitigate” Lake Erie loop flow whenever it is less than 600MW, and to reduce Lake Erie loop flow by 600 MW at all other times. The Joint Applicants’ proposed tariff revisions do not require MISO and ITC to maintain power flows within the +/-200 MW Control Band specified in the Operating Instruction. The Joint
Applicants’ proposed tariff revisions do not require MISO and ITC to do anything, or to achieve any operating target in order to get paid for the Replacement PARs.

Exhibit NYI-35 indicates that MISO and ITC may not be committed to actually achieving
the operating targets that they boldly propose in the Joint Application and their supporting sworn
testimony. In light of the evidence elicited in this proceeding, it would be unjust and
unreasonable to require New York customers to pay for a portion of the cost of the Replacement
PARs.

X. WHETHER, IF THE COSTS OF THE ITC PARS ARE ALLOCATED TO PJM,

THE COST RESPONSIBILITY ASSIGNED TO PJM BY MISO’S JANUARY 2012
TESTIMONY, WHICH INCREASES PJM’S ALLOCATION ABOVE THE
AMOUNT ALLOCATED BY THE JOINT APPLICATION, MAY BE IMPOSED
ON PJM?

The NYISO takes no position on this issue.

529 See, e.g., Ex. MSO Tab-E at 19:9-12.

154

XI.WHETHER, IF THE COSTS OF THE ITC PARS ARE ALLOCATED TO PJM

OR NYISO, PJM OR NYISO IS RESPONSIBLE (RESPECTIVELY) FOR

PAYING MISO IN THE CASE OF A PJM OR NYISO CUSTOMER’S FAILURE TO PAY PARS-RELATED CHARGES?

The NYISO expects to supports PJM’s position on this issue. NYISO will confirm its support for PJM’s position in its Reply Brief.

XII. CONCLUSION

For the reasons set forth herein, the NYISO requests the rejection of the Joint Application in its entirety.

Respectfully submitted,

/s/ Alex M. Schnell

Alex M. Schnell
James H. Sweeney

New York Independent System Operator, Inc.

10 Krey Boulevard

Rensselaer, NY 12144 (518) 356-6000

aschnell@nyiso.com
jsweeney@nyiso.com

/s/ Howard H. Shafferman

Howard H. Shafferman Daniel R. Simon

Jack N. Semrani
Ballard Spahr LLP

1909 K Street, NW, 12th Floor Washington, DC 20006
(202) 661-2200

hhs@ballardspahr.com

simond@ballardspahr.com
semranij@ballardspahr.com

Attorneys for New York Independent System Operator, Inc.

155

CERTIFICATE OF SERVICE

I hereby certify that I have this day served the foregoing document upon each person designated on the official service list compiled by the Commission Secretary in these
proceedings.

Dated at Washington, DC this 16th day of October, 2012.

/s/ Jack N. Semrani

Jack N. Semrani
Ballard Spahr LLP

1909 K Street NW, 12th Floor Washington, D.C. 20006
202.661.7640

DMEAST #15738748 v81

APPENDIX

NYISO’S STATEMENT OF CASE AND

PROPOSED FINDINGS OF FACT AND CONCLUSIONS OF LAW

STATEMENT OF CASE

The NYISO’s statement of the case is the first section of the initial brief, which is incorporated herein by reference.

PROPOSED FINDINGS OF FACT

1. Joint Applicants have failed to provide any evidence to support the justness and

reasonableness of applying rates of return on equity and capital structure that were

established in 2003 to new customers for new types of charges (initial brief at § I.D, Tr. 90:23-91:1).

2. Joint Applicants have failed, as admitted by Mr. Grover, to justify the rate and time

period for depreciation of the Replacement PARs (initial brief at § I.D, Tr. 93:23-95:4).

3. MISO and ITC have not identified any customer or contractual relationship with either

NYISO or its customers that present a valid basis for assessing the NYISO or its

customers charges for the costs of the Replacement PARs. (initial brief at § III.A; Ex. NYI-5; Ex. NYI-6; Tr. 92:17-25, 91:14-18)

4.MISO and ITC have disclaimed any service obligation to NYISO and PJM and their

customers. (initial brief at § III.A; NYI-6; NYI-9)

5. The costs of the Original PAR and the Replacement PARs were incurred due to contract

obligations that Detroit Edison and ITC voluntarily assumed. (initial brief at § III.B.1; Ex. NYI-46 at 3:20-4:15; Ex. NYI-48; NYI-46 at 4:7-9; NYI-48 at 9; Tr. 142:12-146:4; Ex. ITC Tab F at 5:8-6:34; Ex. NYI-48 at 3; Ex. NYI-53; Ex. NYI-54)

6. The costs of the Original PAR and the Replacement PARs were incurred to serve the

interests of Michigan and Ontario utilities and their electricity customers. (initial brief at § III.B.2; Ex. NYI-48 at 1; Ex. ITC Tab F at 4:21-5:3; Ex. NYI-46, at 10:6-10:10, 10:14-
21, 10:14-11:5; Ex. NYI-56 at 1, 2-3; Ex. NYI-58; Ex. NYT-38; Ex. NYI-60)

7. The Original PARs and the Replacement PARs enhance import capability into Michigan,

from the North over the MI/ON Interface and from the South. (initial brief at § III.B.2, Ex. NYI-56, Ex. NYT-38)

8.Neither the Original PAR nor the Replacement PARs were planned jointly with PJM and

NYISO. (initial brief at § III.D; Ex. NYI-38 at 20:7-21:14; Ex. NYI-44 at 39, 16, 15)

DMEAST #15812336 v11

9.MISO never asked or invited the NYISO to discuss the design, costs or cost allocation for

the Replacement PARs (as part of MISO’s MTEP06 process, or otherwise). (initial brief

at § III.D; Ex. NYT-10 at 1)

10.NYISO has never participated in MISO’s MTEP planning process. (initial brief at

§ III.D; Ex. NYI-45 at 1)

11.MISO did not perform a coordinated study with PJM to approve the Replacement PARs

project. (initial brief at § III.D, Ex. NYT-2 at 1)

12. There was no postage stamp rate in place for allocating costs across the combined

Midwest ISO-PJM-NYISO region in 1998, when Detroit Edison assumed a contractual
obligation to construct the Original PAR, or in 2007, when ITC assumed a contractual
obligation to construct the Replacement PARs. (initial brief at § IV.A; Ex. NYI-48, NYI-
49)

13.ITC did not ask the NYISO to contribute to the cost of the Replacement PARs until after

it had already begun constructing the Replacement PARs. (initial brief at § IV.A; Ex.

NYT-11 at 1)

14. The costs of the Replacement PARs did not qualify for region-wide cost sharing as a

baseline reliability project in MTEP06, and costs were allocated to ITC’s customers instead (initial brief at § IV.A; Tr. 305:19-23; Ex. PJM-9 at 1 (Table 1.4-3 to the MTEP06 report; Ex. NYI-51 at 19)

15. MISO treated the Replacement PARs as existing facilities for purposes of the MTEP

planning process and for purposes of cost allocation within MISO because the

Replacement PARs are like for like replacements for the Original PAR. (initial brief at § IV.A; Ex. PJM-11)

16. MISO has repeatedly determined that, within the MISO region, the cost of the

Replacement PARs should not be reallocated to customers outside the ITC transmission zone. (initial brief at § IV.A, Ex: NYT-2 at 4;

17. ITC first suggested to the Commission that NYISO and its customers should share in the

costs of the PARs in August 2009, and did not approach NYISO about it until October or
November of 2009. (initial brief at § IV.A; ITC’s Answer In Opposition to Request for
Clarification, Docket No. ER08-1281-000 at 3 (August 31, 2009); Ex. S-4 at 13, 25-26)\

18. ITC moved forward with the construction of the Original PAR and the Replacement

PARs without any assurance that the Replacement PARs were candidates for multiregional cost-sharing. (initial brief at § IV.A; Ex. S-4 at 25)

19.ITC proposed and MISO approved the construction of the Replacement PARs in the

MTEP06. (initial brief at § IV.A; Ex. NYI-50, NYI-51)

DMEAST #15812336 v12

20.ITC signed a contract with Hydro One that obligated ITC to construct the Replacement

PARs, at its own expense, in 2007. (initial brief at § IV.A; Ex. NYI-49 at 10, 12

(§§ 6.1.1 and 10.3))

21.The first of the two Replacement PARs was delivered in October 2008, and the second

was delivered in the fall of 2009. Both had been installed by December 2009.(initial

brief at § IV.A; Ex. S-3 at 6; Ex. S-4 at 25)

22.The Replacement PARs cannot be distinguished from other transmission facilities that

provide extra-regional benefits, the costs of which are recovered through license plate

rates.(initial brief at § IV.A.; Ex. NYI-1 at 39-40)

23. MISO’s DFAX analysis indicates that the IESO region’s generation-to-load flows are the

single largest contributing factor to Lake Erie loop flows, and that IESO’s generation-to-
load contribution causes more than half (55%) of all Lake Erie loop flow. (initial brief at § IV.C; Ex. MSO-Tab D at 32:4-6; Tr. 343:2-4)

24. The Joint Applicants provided no evidence to show the costs of the Hydro One PARs or

their proportionality to the share of Replacement PARs costs that the DFAX method

would assign to IESO’s customers, and a MISO witness stated he had no knowledge

regarding the amount of the revenue requirement or investment for the Hydro One PARs
or how Hydro One’s investment in the Hydro One PARs compares to ITC’s revenue
requirement for the Replacement PARs. (initial brief at § IV.C; Tr. 345:24-346:8)

25. The PARs at the PJM/New York border and other PARs in the Eastern Interconnection

mitigate Lake Erie loop flows when they are being actively operated to better conform actual power flows to scheduled power flows. (initial brief at § IV.C; Ex. NYI-38 at
21:20-25:10)

26. If the other PARs in the Eastern Interconnection were removed from service, Lake Erie

loop flow would be substantially higher than it is today. (initial brief at § IV.C; Ex. NYI-

38 at 25:4-10)

27. The Replacement PARs do not provide unique benefits that no other PARs can provide.

(initial brief at § IV.C, Ex. NYI-1 at 40:10-18; Ex. S-5 at 10-12; Ex. MSO-3 at 16, n. 14)

28. The Joint Applicants refused to give NYISO and PJM a financial credit for the costs they

incurred to design and implement the “Broader Regional Markets” initiatives that are designed to control or mitigate the effects of loop flow. (initial brief at § IV.C; Tr. 351:22-352:1; Ex. NYI-46 at 15:3-18:22)

29. The DFAX study appropriately does not limit its study of generation-to-load flows

occurring within MISO to those occurring within the ITC zone. Instead, the DFAX study
includes and calculates participation factors for all MISO generation and loads, regardless
of their location. MISO Transmission Owners and customers located outside the ITC
zone contribute to Lake Erie loop flow. (initial brief at § IV.D; Ex. MSO-1B; Tr. 561:2-
5)

DMEAST #15812336 v13

30.The ultimate decision-making authority under the Operating Instruction rests with MISO

and IESO in every case. (initial brief at § IV.E; Ex. NYI-1 at 20:13-17)

31. There is no provision in the Operating Instruction that permits NYISO or PJM to request

MISO and IESO to operate the MI/ON PARs to prevent emergencies in New York or PJM. (initial brief at § IV.E; Ex. NYI-3 at 50-59 (§ 3.4.2 of instruction))

32. A more restrictive set of rules applies to operating the MI/ON PARs to address

emergencies that occur in the NYISO or PJM territories compared to the rules that apply to operating the MI/ON PARs to address emergencies in MISO or IESO. (initial brief at § IV.E; Ex. NYI-3 at 50-59 (§ 3.5.2 of instruction))

33. The Operating Instruction provides for MISO and IESO to suspend normal operation of

the MI/ON PARs to protect MISO and/or IESO customers in the event of unexpected

operational or market outcomes in their regions, but does not provide corresponding

protection for NYISO or PJM customers in the event of unexpected operational or market
outcomes in their regions. (initial brief at § IV.E; Ex. NYI-3 at 50-59 (§ 4.0 of
instruction))

34. Proposed Attachment SS-1 to the MISO tariff allows MISO to temporarily suspend

normal operations of the MI/ON PARs in the event of anomalous MISO market results related to the MI/ON PARs, but does not provide for similar potential suspension of the MI/ON PARs for anomalous market results related to the PARs in NYISO or PJM
markets. (initial brief at § IV.E; Ex. MSO-Tab H; Tr. 202:8-13)

35. The tariff revisions that MISO submitted with the Joint Application, including proposed

Attachment SS-1, require MISO to continue charging NYISO and PJM customers for the cost of the Replacement PARs, even when their operation has been suspended to address a market anomaly or reliability issue in the MISO or IESO markets. (initial brief at
§ IV.E; Ex. NYI-7, NYI-8, NYT-30, NYI-65; Tr. 201:1-5)

36. The Broader Regional Markets rules that the ISOs and RTOs are developing will tend to

reduce Lake Erie unscheduled power flow or permit the ISOs and RTOs to mitigate the impacts on unscheduled Lake Erie power flows at a lower overall cost. (initial brief at § IV.E; NYI-46 at 15-18)

37. The Joint Applicants view the Replacement PARs as a reliability project, and therefore

their cost allocation is not based on a “beneficiary pays” theory. (initial brief at § V.A; Ex. MSO-1 at 19:10-12)

38.The proposed cost allocation is based on a DFAX study that uses a reliability planning

approach. (initial brief at § V.A; Tr. 408:24-409:2)

39.MISO did not perform a study using production cost models. (initial brief at § V.A; Tr.

409:8-17)

40.MISO did not perform a study of the “benefits” of the Replacement PARs to NYISO or

PJM. (initial brief at § V.B; Tr. 409:8-17)

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41.ITC did not create any documents relating to the economic and reliability benefits of the

Replacement PARs.(initial brief at § V.B; Ex. NYT-44)

42.Neither MISO nor ITC performed an assessment or studies to identify specific reliability

criteria that are potentially violated by Lake Erie loop flow. (initial brief at § V.B; Ex. PTO-4, PTO-5)

43. New York could benefit when: (a) the MI/ON PARs are operated to reduce clockwise

loop flows, and (b) components of the New York State Transmission System (“NYSTS”) that are substantially affected by unscheduled Lake Erie power flows are constrained. (initial brief at § V.C; Ex. NYI-46 at 21-22; Ex. NYT-19, at 7:131-13).

44. New York may be “harmed” by the operation of the MI/ON PARs when (x) the MI/ON

PARs are operated to reduce counterclockwise loop flows, and (y) components of the

NYSTS that are substantially affected by unscheduled Lake Erie power flows are

constrained, or would become constrained in the absence of counter-clockwise Lake Erie loop flow. (initial brief at § V.C; Ex. NYI-46 at 22; Ex. NYT-19, at 7:131-133)

45.Lake Erie loop flow has predominantly flowed in a counter-clockwise direction in 2012.

(initial brief at § V.C; Ex. NYI-66; Tr. 1039:13-14)

46.Counterclockwise Lake Erie loop flow tends to relieve transmission congestion in New

York. (initial brief at § V.C; Tr. 996:4-14)

47. In 2012, the MI/ON PARs have operated to block counterclockwise Lake Erie loop flow.

(initial brief at § V.C; See NYI-66 (the average Lake Erie loop flow between April 5, 2012 and July 18, 2012 would have been 85 MW counterclockwise if the MI/ON PARs had not been in service).

48. MISO’s DFAX analysis projects that generator-to-load contributions to Lake Erie loop

flows will continue to tend to be counterclockwise into the mid-term future.   In all three
of the DFAX cases, peak, shoulder peak, and light load, the projected generator-to-load
contributions are counterclockwise in direction.   Contributions are projected to be
significantly counterclockwise in the peak and shoulder peak cases.   The net
contributions of the four participating ISO/RTO regions (MISO, NYISO, PJM, IESO)
result in an overall counterclockwise participation on the MI/ON Interface. (initial brief
at § V.C; Ex. MSO-1B)

49. MISO analysis from 2005 documented the reliability benefits to the ITC service territory

from the restoration of the B3N circuit. (initial brief at § V.D.2; Ex. PJM-15 at 4)

50. MISO also concluded in 2005 that replacing the Original PAR was beneficial to the

reliability of the ITC system. (initial brief at § V.D.2; Ex. NYI-60 at 2)

51.The MTEP06 report in which the Replacement PARs project was approved by MISO

includes a substantial list of reliability benefits to the ITC system provided by the

Replacement PARs and the restoration of the B3N circuit that are not also provided to the

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NYISo or PJM transmission systems. (initial brief at § V.D.2; Ex. NYI-50 at 19; Ex. NYI-60 at 2)

52. MISO identified, in MTEP06, a basic threshold of reliability needs driving the need for

the Replacement PARs, and stated that if the seven needs identified in the MTEP06 list of reliability benefits to the ITC system did not exist, there would be no need for the
Replacement PARs. (initial brief at § V.D.2; Tr. 354:4-19; Tr. 355:8-11)

53. The Joint Applicants have not shown that loop flow caused any of the ITC system

reliability issues identified in the MTEP06 report. (initial brief at § V.D)

54. Other regions are shielded from NYISO unscheduled power flows (and the NYISO is

shielded from their unscheduled power flows) by a string of PARs, Direct Current

transmission lines, and a Variable Frequency Transformer controlled transmission line,
that are all located on the eastern portion of the NYISO/PJM border, between the load
centers of New York City and Northern New Jersey. (initial brief at § V.E; Ex. NYI-38 at
24:5-9)

55. Other PARs in the Eastern Interconnection affect Lake Erie loop flow, including the

PARs located in New York and in New Jersey at the NYISO/PJM border, PARs located in Ontario at the NYISO/IESO border and PARs located within New York City. (initial brief at § V.E; Ex. NYI-38 at 7:10-12 and n.1)

56. The very same sets of PARs that shield the MI/ON Interface from power flows associated

with serving New York City and Long Island load likely reduce PJM’s measured flows
over the MI/ON Interface as well. The loop flow reduction benefits that the PARs
located in New York and PJM provide are the same benefits MISO claims its MI/ON
PARs will provide to New York and PJM customers. The MI/ON PARs are not unique
in this regard. (initial brief at § V.E; Ex. NYI-38 at 24:16-17, 24: 17-20; NYI-1 at 40:16-
18)

57. The operation of the MI/ON PARs from April 5, 2012 through July 18, 2012 increased

the magnitude of Lake Erie loop flows in 33.7% of intervals during that time period. In

18.6% of intervals, the operation of the MI/ON PARs increased the magnitude of loop

flows either at a time when loop flows were already outside the +/-200 MW control band,
or the operation of the MI/ON PARs actually caused Lake Erie loop flow to exceed the
+/-200 MW control band. (initial brief at § V.E; Ex. NYI-66, columns four, five and six)

58. From April 5, 2012 to July 18, 2012, the MI/ON PARs have been operating to conform

actual power flow to scheduled power flow at the MI/ON Interface. The average

absolute value of actual Lake Erie loop flow over the April 5, 2012 to July 18, 2012

period was 214 MW, which is significantly more than the 0 MW loop flow assumed in
MISO’s DFAX study. (initial brief at §§ V.E, IX.B; Ex. NYI-66 (data in Column Four,
which is MISO’s measurement of the loop flow that actually occurred in each interval in
real-time)

59.ITC’s incurrence of the costs of the Replacement PARs was “caused” by ITC’s unilateral

decision to assume a contractual obligation to install the replacement PARs in ITC’s

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2007 Facilities Agreement with Hydro One. (initial brief at § V.F; Ex. PTO-4 at 2-3; Ex.
PTO-5)

60. The Joint Applicants submitted no evidence showing that problems caused by Lake Erie

loop flow required ITC to restore the B3N circuit and construct the Replacement PARs,
and MISO and ITC never performed an assessment or identified specific reliability
criteria that are potential violated by Lake Erie loop flow. (initial brief at § V.F; Ex. PTO-

4 at 2-3; Ex. PTO-5; Ex. PJM-16)

61. ITC decided to execute the 2007 Facilities Agreement only after it considered all other

options, and evaluated the expected benefits to the ITC system. Among the options

considered were: not restoring the B3N circuit at all, finding the least expensive way to support needed ITC import capability, and strengthening ITC’s ties to its South. (initial brief at § V.F; Ex. NYT-38)

62. The Joint Applicants have failed to submit evidence showing the NYISO’s actual

contribution to Lake Erie unscheduled power flows. (initial brief at § VI.A)

63. The Joint Application fails to recognize and provide a financial credit, as it should,

because NYISO and PJM have installed and paid for their own PARs and other
controllable facilities (including direct current converters and variable frequency
transformers) that reduce Lake Erie loop flow. (initial brief at § V.F; Ex. NYI-38 at
21:20-25:10)

64. The Joint Application proposes not to charge IESO because Hydro One customers paid

the costs of the Hydro One PARs. (initial brief at § IV.C)

65. The MISO’s DFAX analysis should have included all 8,760 hours of the year, rather than

relying on three representative hours. (initial brief at § VII.A.1; Tr. 368:16-22; Tr. 373:4-
21; Ex. NYI-38 at 15:21-16:2; Tr. 399:15-400:5)

66. The use of just three load blocks penalizes New York by mis-assigning a significant

portion of the NYISO’s flow participation to higher load hours, and over-counting the

MWh used to determine the New York portion of the DFAX cost allocation. (initial brief at § VII.A.1; Ex. NYI-38 at 14:20-15:19)

67. The use of only three representative load blocks cannot accurately depict a region’s

expected electricity usage over the 8,760 hours of a year. (initial brief at § VII.A.1; Ex. NYI-38 at 14:12-18)

68.Each region’s electricity usage varies significantly more than is captured in the three

representative load blocks used in the DFAX analysis. (initial brief at § VII.A.1; Ex.

NYI-39)

69.The slope of each ISO/RTO region’s load duration curve, as shown in Exhibit NYI-39,

depicts how significantly each region’s electricity usage varies over the hours of a year.

The drastic variation in electricity usage makes a representation using only three load

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blocks a gross over-simplification. (initial brief at § VII.A.1; Ex. NYI-39; Ex. NYI-38 at 14:16-18)

70. MISO witness Chatterjee did not perform any study or analysis to support his speculation

that performing a 8,760 hour analysis would not result in a significantly different result
than the three load block analysis MISO used. (initial brief at § VII.A.1; Tr. 405:1-7)

71 Performing the DFAX analysis for every hour of the year would have a significant impact

on the NYISO’s participation because the MISO’s analysis significantly over-counted
and over-attributed megawatt-hours to the NYISO. (initial brief at § VII.A.1; Ex. NYI-

38 at 14:20-15:23)

72. MISO’s assumption that load remains steady at 85% of peak load for over nine months of

the year is unrealistic and unnecessarily penalizes New York. The New York load

duration curve clearly indicates that load in New York is lower than 60% of its peak load for eight months of the year and lower than 50% of its peak load for four months of the year. (initial brief at § VII.A.1; Ex. NYI-38 at 15:8-9, 15:11-13; Ex. NYI-42)

73. An 8,760-hour representation is used for MISO’s forward-looking resource adequacy

analysis incorporated in its MTEP planning process, for similar analyses in other regions
of the eastern interconnection, and for production cost analysis for MISO’s “top
congested flowgate” study. (initial brief at § VII.A.1; Tr. 409:18-21; Tr. 410:7-10; Tr.
410:3-6)

74. MISO should have used each region’s individual load duration curve to perform the

DFAX analysis over all 8,760 hours of the year to calculate each region’s individual

participation over the MI/ON Interface. (initial brief at § VII.A.2; Ex. NYI-38, at 9:9-17; Ex. NYI-39; Ex. NYI-40; and Ex. NYI-41)

75. MISO’s effort to shoe-horn the NYISO into an aggregate load duration curve developed

using the combined MISO, PJM and NYISO load duration curves resulted in an inflated participation factor and resulting cost allocation to the NYISO, while reducing MISO’s relative participation and cost allocation. (initial brief at § VII.A.2; Ex. NYI-38 at 9:25-
13:2-6; Tr. 403-17-404:16)

76. MISO’s unilateral decision to permit directional contributions to the flow participation

over the four circuits that comprise the MI/ON Interface to offset each other is

inappropriate and inconsistent with other decisions that MISO made with regard to netting of contributions in the DFAX study. (initial brief at § VII.A.3)

77. When power is permitted to flow freely over the four circuits of the MI/ON Interface the

four circuits actually participate in the transfer of power from MISO generation to MISO
load in addition to transferring Lake Erie loop flow. Unlike the NYISO, PJM and IESO
power flows in the DFAX analysis, a significant quantity of MISO’s power flows “loop”
out of, then back into MISO across the four circuits that comprise the MI/ON Interface.
The MISO DFAX analysis indicates that MISO power flows from Michigan to Ontario
(positive distribution factors) on the L4D and L51D circuits, and flows back from Ontario

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to Michigan (negative distribution factors) on the J5D and B3N circuits. (initial brief at § VII.A.3; Ex. NYI-38 at 6:14-21)

78. By summing the directional participation factors on all four of the circuits as MISO has

done, and netting the flows with positive distribution factors against the flows with

negative distribution factors, MISO’s use of the MI/ON Interface and true contribution to flows on the B3N Circuit is understated. (initial brief at § VII.A.3; Ex. NYI-38 at 6:21-
7:2; Tr. 419-420; Ex. NYI-74; Ex. MSO-1B; Tr. 419:24-420:3)

79. MISO, inappropriately, does not account for any economic impacts of generation

dispatch in its hypothetical DFAX analysis. The DFAX study was performed by

increasing the output of each generator within an RTO, pro rata, based on each

generator’s maximum MW output, to serve the load within that RTO. MISO’s approach
dispatches all generation within an RTO pro rata, based on each generator’s maximum
output, regardless of the actual costs to dispatch that generator. However, RTOs do not
serve their load by uniformly ramping up all of the generation in their control area; they
use security constrained economic dispatch software to achieve a least cost economic
solution. (initial brief at § VII.A.4; Tr. 440:5-25; Tr. 440:5-8; Tr. 1077:4-6; Tr. 440:5-8)

80. It was not appropriate to base the DFAX analysis on the contribution to flows on all four

of the circuits that comprise the MI/ON Interface. The B3N circuit, on which the

Replacement PARs are installed, should have been the circuit used to determine the flow
contribution of each ISO/RTO in the DFAX analysis. (initial brief at § VII.A.5; Ex. NYI-

38 at 6:2-7:6)

81. Only considering flows over the B3N circuit avoids the issue of netting participation over

the four circuits that is discussed in Section VII.A.3 of this initial brief because each ISO’s or RTO’s generation-to-load transfers only participate on the B3N circuit in one direction. (initial brief at § VII.A.5; Ex. NYI-38 at 6:2-9)

82. The magnitude of the DFAX flaws becomes more evident when multiple flaws are

corrected simultaneously. (initial brief at § VII.A.6)

83. Other flaws in the DFAX analysis include ignoring the cumulative contribution of

regions other than MISO, NYISO, PJM and IESO to unscheduled Lake Erie power flows. (initial brief at § VII.A.7; Ex. NYI-38 at 16-19; Ex. NYI-43)

84.Mr. Chatterjee developed, and MISO considered, many different DFAX scenarios. (initial

brief at § VII.B; Tr. 349:5-350:5; Ex. PTO-12)

85. MISO and ITC abandoned the idea of charging transactions scheduled over the MI/ON

Interface for a portion of the cost of the Replacement PARs after ITC realized that the largest portion of the cost would effectively be collected from ITC Transmission
customers. (initial brief at § VII.B; Ex. NYT-22 at 2)

86.Scheduled transactions contribute to loop flow on the MI/ON Interface and entities

scheduling imports and exports over the MI/ON Interface would benefit from avoiding

curtailment of those transactions. (initial brief at § VII.B; Tr. 317:15-318:1)

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87.The DFAX study does not account for Lake Erie loop flow that is caused by transactions.

(initial brief at § VII.B; Ex. MSO Tab D at 4:22-5:2; Ex. MSO Tab E at 17:11-13; Tr. 514:3-5)

88. MISO’s proposed Schedule 36 and Attachment SS contain no description of the service

that the NYISO’s customers will receive in return for their payments. (initial brief at § VIII; Tr. 126:24-127:4)

89. MISO’s proposed Schedule 36 and Attachment SS do not specify a service obligation or

standard that Joint Aplicants must meet in order to be paid, and no discounts have been provided during outage periods. (initial brief at § VIII; Ex. NYI-1 at 15:5-17; NYI-7; NYI-8; Ex. NYI-65 at 2; Ex. NYI-5, NYI-6, NYI-9)

90. The Joint Applicants’ claim that the MI/ON PARs will “fully mitigate” Lake Erie loop

flow in 74% of hours and reduce Lake Erie loop flow by 600 MW at all other times is vastly overstated. (initial brief at § IX.A; Ex. NYI-1)

91. Lake Erie loop flows were within the Control Band in 49.41% of hours for the year

ending March 31, 2012; before MISO and IESO even began operating the MI/ON PARs to better conform actual power flows to scheduled power flows. (initial brief at § IX.A; Ex. NYI-1 at 12:16-13:3 (referring to data in Ex. NYI-4))

92. At times when MI/ON Interface power flows are within the Control Band and are

expected to remain within the Control Band, the Operating Instruction does not require MISO and IESO to take additional PAR actions to further reduce Lake Erie loop flow. (initial brief at § IX.A; Ex. NYI-3 at 52 (§ 3.01) and 53 (§§ 3.4.1, 3.4.2))

93. MISO views “fully mitigate” as meaning “completely manage” Lake Erie loop flow to

“near zero megawatts.” (initial brief at § IX.A; Tr. 492:24-493:19)

94.Over the April 5, 2012 to July 18, 2012 period, actual power flows measured at the

MI/ON Interface were within +/-10 MW of scheduled power flows (i.e., “fully

mitigated”) in only 3.3% of the 30,121 five minute intervals that MISO recorded.(initial

brief at § IX.A; Ex. NYI-66)

95. MISO and and IESO are operating the MI/ON PARs to achieve the +/-200 MW Control

Band; they are not operating the MI/ON PARs to “fully mitigate” Lake Erie loop flow. (initial brief at § IX.A; Ex. NYI-66)

96. If just one of the four circuits at the MI/ON Interface is not PAR controlled, the PARs on

the three remaining circuits would have very limited ability to conform flow to schedule at the MI/ON Interface, and the local system would have to operate near applicable
reliability limits in order to provide this limited degree of control. (initial brief at § IX.A; Ex. NYI-1 at 33:13-34:23; Ex. NYI-33; Ex. NYI-37; Ex. NYI-35)

97.There have been no studies performed that quantify the effectiveness of the MI/ON PARs

for any sub-optimal condition. (initial brief at § IX.A; Ex. NYI-35)

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98.When the Replacement PARs entered service and MISO and IESO began operating the

MI/ON PARs to better conform actual power flows to scheduled power flows at the
MI/ON Interface, MISO announced that it was not changing its method of calculating
interface prices to reflect an expectation that the MI/ON PARs would better control Lake
Erie loop flow because Hydro One’s L4D PAR was out of service. This was an
admission that MISO did not expect the MI/ON PARs to be able to effectively conform
actual power flows to scheduled power flows at the MI/ON Interface without the L4D
PAR in service. (initial brief at § IX.A; Ex. NYI-21; Ex. NYI-46 at 24-25)

99. The Joint Applicants’ claim that the MI/ON PARs “are expected to fully mitigate Lake

Erie loop flows approximately 74% of the time, and reduce them by approximately 600 MW the remainder of the time” assumes that all of the MI/ON PARs will be available 100% of the time. (initial brief at § IX.A; Ex. MSO-Tabe E at 19:5-17)

100. From April 5, 2012 to July 18, 2012 (the period for which NYISO submitted MI/ON

PAR operating data in Exhibit NYI-66) at least one MI/ON PAR was out of service on 73 of the 104 days in the period. (initial brief at § IX.A; Ex. NYI-66)

101. Based on the NYISO’s review of one months’ operating data with the L4D PAR out of

service, it appears that the performance of the [four] available MI/ON PARs has not

improved upon the performance that the NYISO recorded for periods when the MI/ON PARs were not available. (initial brief at § IX.B; Ex. NYI-1 at 38:12-15)

102. On average, Lake Erie loop flow was 48 MW in a counter-clockwise direction over the

April 5 to July 18, 2012 period. MISO estimates that if the MI/ON PARs had not been in operation, the average, net directional value of Lake Erie loop flow would have been 85 MW in a counter-clockwise direction. (initial brief at § IX.B; Ex. NYI-66 (data in
Column Six, which is MISO’s estimate of what Lake Erie loop flow would have been, but for the operation of the MI/ON PARs))

103. On average, MISO estimates the MI/ON PARs blocked 37 MW of counter-clockwise

loop flow over the April 5 to July 18, 2012 period. (initial brief at § IX.B; Ex. NYI-66 (data in Column Six, which is MISO’s estimate of what Lake Erie loop flow would have been, but for the operation of the MI/ON PARs))

104. Blocking counter-clockwise loop flow can be detrimental to the NYISO because counter-

clockwise loop flow tends to relieve transmission congestion in New York. (initial brief §§ IX.B, V.C)

105. Of the 30,121 five minute intervals for which data was provided, the Column Four data

indicated that loop flow was within the +/-200 MW Control Band in 16,696 intervals, or

55.4% of the total intervals. (initial brief at § IX.B; Ex. NYI-66 (data in Column 4,

which is MISO’s measurement of the loop flow that actually occurred in each interval in real-time))

106.For the seven month period commencing July 1, 2011 and ending January 31, 2012

MI/ON Interface flows were estimated to be within +/-200 MW of MI/ON Interface

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schedules in 57.5% of hours.(initial brief at § IX.B; Exhibit NYI-1 at 37:19-21; Exhibit

NYI-4)

107.In October of 2011, MI/ON Interface flow was within +/-200 MW of the MI/ON

Interface schedule in 75.7% of hours.(initial brief at § IX.B; Exhibit NYI-1 at 38:1-2;

Exhibit NYI-4)

108. The operation of the MI/ON PARs to better conform flow to schedule at the MI/ON

Interface from April 5 to July 18, 2012 does not appear to have reduced Lake Erie loop flow. (initial brief at § IX.B)

109. From April 5 to July 18, 2012, the highest recorded interval of counter-clockwise loop

flow was 1444 MW, which is more than double the MI/ON PARs claimed control

capability of 600 MW. The highest recorded interval clockwise loop flow was 864 MW. (initial brief at § IX.B; Ex. NYI-66 (data in Column 4, which is MISO’s measurement of the loop flow that actually occurred in each interval in real-time))

110. Using a +/-10 MW bandwidth as a proxy for loop flow being “completely managed,” of

the 30,121 five minute intervals considered, actual power flows were within +/-10 MW of scheduled power flows in only 1003 intervals, or 3.3% of all intervals, not even close to the “fully mitigated in 74% of all hours) claim of MISO witness Mallinger. (initial brief § IX.B; NYI-66 (Column 4 data))

111. The MI/ON PARs blocked 600 MW or more of Lake Erie loop flow in 0.4 percent of the

30,121 intervals included in Exhibit NYI-66. (initial brief § IX.B; NYI-66 (Column 5 data on “Total PAR Offset”)

112. The operation of the MI/ON PARs made Lake Erie loop flow worse in 10,158 five

minute intervals, or 33.7 percent of all intervals over the April 5 to July 18, 2012 period.
The operation of the MI/ON PARs exacerbated Lake Erie loop flow in 5,613 intervals
(18.6 percent of all intervals) during which the actual Lake Erie loop flow was outside the
+/-200 MW Control Band. (initial brief § IX.B; NYI-66 (comparison of actual Lake Erie
loop flow in Column Four to MISO’s estimate of what Lake Erie loop flow would have
been if there were no PARs at the MI/ON Interface in Column Six. When the loop flow
in Column 4 of Exhibit NYI-66 is greater than the loop flow in Column 6 of Exhibit
NYI-66 (without regard to the direction of the loop flow in either column), it indicates
that the operation of the MI/ON PARs exacerbated Lake Erie loop flow)

113. In 1337 intervals (4.4 percent of all intervals) the operation of the MI/ON PARs caused

loop flow that was expected to be inside the +/-200 MW Control Band to instead fall

outside the Control Band. (initial brief § IX.B; NYI-66 (comparison of Column Four and Column Six data))

114.Transmission Loading Relief (“TLR”) is a procedure that Reliability Coordinators like

the NYISO, MISO, IESO and PJM use to address power flows that are causing reliability

impacts on their transmission systems. It permits Reliability Coordinators to request the

curtailment or removal of inter-Control Area transactions that have a substantial impact

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on a particular transmission constraint that presents a reliability risk. (initial brief at

§ IX.C; Ex. NYI-1 at 5:16-23; Ex. NYI-1 at 6:3-17; Tr. 835:21-25)

115. TLR is implemented via the North American Electric Reliability Corporation’s

(“NERC’s”) Interchange Distribution Calculator (“IDC”). The IDC is a database that identifies inter-Control Area transactions that have a 5% or greater impact on the
transmission constraint that TLR is being requested to address. The IDC identifies
proposed pro rata reductions to all of the transactions that have a 5% or greater impact on the transmission constraint to achieve the requested level of relief. (initial brief at
§ IX.C; Ex. NYI-1 at 5:16-23; Ex. NYI-1 at 6:3-17; Tr. 835:21-25)

116. The IDC transmits the pro rata transaction reductions to each of the Balancing

Authorities that are participants in the transactions that need to be curtailed or removed to provide the requested relief. (initial brief at § IX.C; Ex. NYI-1 at 5:16-23; Ex. NYI-1 at 6:3-17; Tr. 835:21-25)

117. The MI/ON PARs are subject to a modeling treatment in the NERC IDC that is different

from all of the other PARs that surround Lake Erie. At times when MISO and IESO set the MI/ON PARs to be “regulated” in the NERC IDC model, that model assumes that there is no Lake Erie loop flow, whatsoever, crossing the MI/ON PARs, so no power flows will be seen as crossing the MISO/IESO border and potentially causing a 5% or greater impact. In other words, the IDC model will represent power flows as conforming to schedules, without regard to what is actually happening in the real world. (initial brief at § IX.C; Ex. NYI-1 at 6:3-17; Tr. 835:21-25; Ex. NYI-1 at 8:14-20)

118. At times when the MI/ON PARs are set to “non-regulated,” Lake Erie loop flow is

permitted to flow across the MI/ON interface in the NERC IDC model, and transactions at that interface are available to be removed via TLR in order to address reliability
concerns that Lake Erie loop flow is causing or aggravating in New York, PJM, MISO or IESO. (initial brief at § IX.C; Tr. 835:9-836:5)

119. MISO and IESO are responsible for determining if Lake Erie loop flows are within the

+/-200 MW “control band,” and are expected to remain within the +/-200 MW control
band, and for accurately setting the IDC mode to “regulated” or “non-regulated” on that
basis. (initial brief at § IX.C; Ex. NYI-10 at 7; Ex. NYI-64 at 2; Ex. NYI-72 at 2)

120. It is very important for MISO and IESO to timely and accurately reflect the correct

scheduling mode for the MI/ON PARs in the NERC IDC. When the IDC flag is set to “regulated,” this blocks the ability of NYISO and PJM (and other control areas) to use TLRs to remove transactions that are adversely impacting reliability. (initial brief at § IX.C; Ex. NYI-1 at 8:22-9:2)

121.Considering only the days on which there was at least one change made to the IDC Status

in Ex. NYI-66 (in order to address certain infirmities in the data that the MISO provided),

in 28.6 percent of the time that MISO and IESO set the flag to “Regulated,” it is set

incorrectly.(initial brief at § IX.C; Ex. NYI-66 (Column 4indicating that Lake Erie loop

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flow is in excess of 200 MW, yet in Column 8 MISO and IESO have set the IDC Status to “Regulated”))

122. MISO’s and IESO’s lack of diligence in setting the IDC Status of the MI/ON PARs could

have significant adverse reliability consequences for the NYISO, and for other potentially impacted Control Areas. (initial brief at § IX.C)

123. On June 16, 2012 the L4D PAR was out-of-service. The MI/ON PARs showed little

ability to control of loop flow with only three of the four interface circuits PAR

controlled. (initial brief at § IX.B; Ex. NYI-73 at 3 and 6 (the PS4 Hydro One PAR on the L4D line was bypassed on June 10, 2012 and returned to service on June 17, 2012); Ex. NYI-66 at 551-559)

124. On June 16, 2012, counterclockwise loop flow exceeded the +/- 200 MW Control Band,

and remained outside the Control Band for the rest of the day. MISO and IESO made

little effort to move the MI/ON PARs to better conform actual power flows to scheduled power flows at the MI/ON Interface. The MI/ON PARs were only moved in fifteen 5-
minute intervals out of 191 5-minute intervals between 8:05 a.m. and 11:55 p.m. None of the PAR moves that MISO and IESO took brought actual power flow significantly closer to scheduled power flow. (initial brief at § IX.B; Ex. NYI-66 at 551-559)

125. In the morning of June 16, 2012, MISO and IESO placed the MI/ON PARs in

“Regulated” mode at a time when loop flow was hundreds of MWs away from achieving the +/-200 MW Control Band. MISO and IESO then left the PARs in “Regulated” mode while the loop flow was well outside the +/-200 MW control band for more than an hour. (initial brief at § IX.B; Ex. NYI-66 at 554 (compare the “IDC Status” column to the “5 Minute Avg Adj Loop Flow” column to identify time intervals when the MI/ON PARs are set to Regulated but loop flow exceeds the +/-200 MW control band))

126. On July 18, 2012, Lake Erie loop flow changed dramatically between 10:00 and 10:15

a.m., and by 10:10 the MI/ON PARs were making loop flow worse, not better. At 10:15
a.m., actual loop flow (Column 4) was 337 MW clockwise; Total PAR Offset (Column 5)
indicates MI/ON PARs were being operated to cause 403 MW of clockwise flow. If the
MI/ON PARs had not been in service at all, loop flow would have been 65 MW in a
counter-clockwise direction. It appears that loop flow would have remained within the
+/-200MW bandwidth from 10:10 a.m. until around 11:50 a.m. if the MI/ON PARs had
not been in service. The MI/ON PARs were causing approximately 400 MW of
additional clockwise flow. According to the data MISO provided, the operation of the
MI/ON PARs was pushing loop flows that would have been within the +/-200 MW
control band substantially outside the control band in the clockwise direction. (initial

brief at § IX.B; Ex. NYI-66 at at794-801 (“Actual Loop Flow” estimate in Column 6))

127. Starting at approximately 11:40 a.m. on July 18, 2012, MISO and IESO began taking

actions to bring loop flow back within the Control Band. it took MISO and IESO an hour
(until 12:40) to get the MI/ON PARs turned around so that the PARs were actually
reducing clockwise flow, rather than exacerbating it. Other periods of high clockwise
loop flow occurred over the course of the day. From 14:00 (2:00 p.m.) until 15:15 (3:15

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p.m.) loop flow averaged more than 400 MW in the clockwise direction. (initial brief at § IX.B; Ex. NYI-66 at at794-801 (Column 5 (“Total PAR Offset”), the calculated
contribution to loop flow from the MI/ON PARs); Tr. 882:22-24)

128. Beginning around 17:00 (5:00 p.m.) on July 18, 2012, loop flow became significantly

counterclockwise, and it took MISO and IESO approximately 45 minutes to get the

MI/ON PARs turned back around so that they were not further exacerbating the

counterclockwise loop flow that was occurring. Loop flow remains significantly

counterclockwise, and outside the +/-200 MW Control Band, from just before 17:00

(5:00 p.m.) until around 21:00 (9:00 p.m.). (initial brief at § IX.B; Ex. NYI-66 at794-801 (MISO calculated Total PAR Offset term in Column 5))

129. On July 18, 2012, MISO and IESO placed the MI/ON PARs in “Regulated” mode at a

time when loop flow was not even close to achieving the +/-200 MW control band.

MISO and IESO then left the PARs in “Regulated” mode while the loop flow was well outside the +/-200 MW control band for more than two consecutive hours. (initial brief at § IX.B; Ex. NYI-66 at 794 (comparing the “IDC Status” column (Column 8) to the actual loop flow data reported in Column 4)

130. During 846 hours between April 5, 2012 and July 18, 2012 MISO and IESO operated the

PARs in a manner that makes loop flow worse, not better. (initial brief at § IX.B; Exh. NYI-66 (comparing the “5 Minute Avg Adj Loop Flow” column to the “Actual Loop Flow” column to identify time intervals when the “5 Minute Avg Adj Loop Flow” value is greater than the “Actual Loop Flow” value))

131. Much of the time, the MI/ON PARs are not being operated in the manner that would be

necessary to better conform actual power flows to scheduled power flows at the MI/ON
Interface. PAR tap moves only occurred in 1,458 five minute intervals, or 4.8% of the
total intervals from April 5, 2012 through July 18, 2012. (initial brief, § IX.B; Ex. NYI-

66 (data in Column 7 “Tap Move Performed”))

132. ITC has indicated that if operating to achieve the Control Band proves too onerous,

MISO, ITC and IESO need to have a way to escape the obligation that they assumed. (initial brief, §§ IX.B, IX.E; Ex. NYT-35)

133. On June 19, 2012 there was predictable counter-clockwise Lake Erie loop flow that

significantly exceeded the +/-200 MW Control Band for most of the day. The MI/ON
PARs were operated to counteract approximately 400 MW of loop flow, but no attempt
was made to operate the PARs to achieve the claimed limits of their control capability, or
to further reduce Lake Erie loop flow. Only one MI/ON PAR was moved in one five
minute interval over the entire day. (initial brief, § IX.B; Ex. NYI-66 at 574-581)

134. On July 17, 2012 the L4D PAR was out of service. Counter-clockwise loop flow was

extremely high that day. Over the course of the day, there were only two PAR tap moves
taken, despite the loop flow being outside the +/-200 MW control band for the entire day.
For much of the day, the MI/ON PARs were slightly exacerbating (by up to 24 MW) the
high Lake Erie loop flow that was occurring. Although MISO claims that 300-350 MW

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of loop flow can be mitigated with three of the four MI/ON circuits controlled, Column Five of Exhibit NYI-66 “Total PAR Offset” indicates that on July 17 the PARs were never operated to reduce Lake Erie loop flow. On July 17, MISO and IESO either could not, or would not, take additional taps on the MI/ON PARs to better conform actual
power flows to scheduled power flows at the MI/ON Interface. (initial brief § IX.B; Ex. NYI-35 at 2; Ex. NYI-66 at 786-794 (column 5))

135. The MI/ON PARs should have been able to provide additional loop flow control on June

19 and July 17, 2012, based on MISO’s claims that the MI/ON PARs will provide 600
MW offset of potential loop flows almost all of the time, and can provide 300-350 MW
of control when one of the four circuits on the MI/ON Interface is not PAR controlled.
(initial brief § IX.B; Ex. NYI-66 at 574-581, 786-794; Ex. MSO-Tab E at 19:5-17; Ex.
NYI-35 at 2)

136. The history of the MI/ON PARs indicates that they are prone to failure. (initial brief at

§ IX.D; Ex. NYI-1 at 23-27; Ex. NYI-11; third-party reports in Ex. NYI-12, -13, -14, -15 (at p. 40), -16 (at pp. 34-35), -17 (at p. 21), -18 (at p. 24), -19 (at p. 25), -20 through -23, and -24 (at p. 22))

137. The Chief Executive Officer of ITC reacted in an April 10, 2003 e-mail to the then-recent

failure of the Original PAR with the statement “it appears that these devices are nothing but junk.” (initial brief at § IX.D; Ex. NYI-29)

138. When the Replacement PARs were placed into service on April 5, 2012, Hydro One’s

L4D PAR was not in service. (initial brief at § IX.D; Ex. NYI-1 at 27-29)

139.ITC chose a different manufacturer for the Replacement PARs than the manufacturer of

the Original PAR. (initial brief at § IX.D; Ex. NYI-1 at 30-31; Ex. NYI-27 through NYI-

29)

140. On December 17, 2011, the L4D PAR went out of service and did not return to service

until June 1, 2012, due to a “gas accumulation alarm.” The reason for the outage was also described by IESO as a “bad oil sample.” (initial brief at § IX.D; Ex. NYI-73 at 1; Tr. 871:7-9; Ex. NYI-20)

141. The L4D PAR was bypassed on June 10, 2012 due to another “gas accumulation alarm,”

and returned to service on June 17 at 13:16. The reason for the outage was also described by IESO as a “bad oil sample.” (initial brief at § IX.D; Ex. NYI-73)

142.The L4D PAR was bypassed on July 12, 2012 at 21:28 p.m. due to a “gas accumulation

alarm,” and returned to service on July 18 at 00:54 a.m. (initial brief at § IX.D; Ex. NYI-

73)

143.The “gas accumulation alarm” incidents on the L4D PAR indicates a dangerous situation

and the possibility of an explosion. (initial brief at § IX.D; Tr. 871:12-872:10)

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PROPOSED CONCLUSIONS OF LAW

1.The Joint Application violates the Federal Power Act. (initial brief at § I.A)

2.The Joint Application does not meet the requirements of the Commission’s regulations.

(initial brief at § I.D)

3.The Joint Application contravenes Commission precedent. (initial brief, at § IV.A)

4.The Joint Application’s proposed cost allocation also contravenes the policies reflected in

Order No. 1000. (initial brief, at § IV.C.)

5. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because the Joint Application provides no studies or other quantification of “benefits”
they assert NYISO and PJM will receive from the Replacement PARs. (initial brief at
§ V.B)

6. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because the Replacement PARs (and the Original PAR) were built pursuant to preexisting contract obligations, and were built for the benefit of Detroit Edison and ITC customers. (initial brief at § III.B)

7. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because the provisions under which MISO and the Independent Electricity System

Operator of Ontario (“IESO”) will operate the Ontario and Michigan PARs, including the Replacement PARs (collectively, the “MI/ON PARs”), as well as the proposed MISO tariff provisions, permit MISO and IESO to favor their own customers and interests over NYISO’s and PJM’s customers and interests. (initial brief at §§ III.C, IV.E)

8. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because the Joint Application discriminates against NYISO and PJM customers by failing to propose allocation of charges to IESO customers, and by charging NYISO and PJM while MISO customers located outside the ITC transmission zone are not being charged. (initial brief at §§ IV.C, IV.D)

9. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because control by the MI/ON PARs of counterclockwise Lake Erie loop flow does not benefit, and may harm, NYISO and its customers. Lake Erie loop flow has been
counterclockwise on average for 2012 so far, and MISO’s DFAX cost allocation analysis suggests that Lake Erie loop flow will continue to occur in a counterclockwise direction into the mid-term future. (initial brief at § V.C)

10. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because the Joint Applicants no studies or analyses to support their repeated claim that the MI/ON PARs will control 600 MW of Lake Erie loop flow, and actual MI/ON PAR performance data for the period since the Replacement PARs were placed in service reveal that the claim is vastly overstated. (initial brief at § IX.A)

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11.The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because the outage history of the MI/ON PARs indicates a significant risk that the control of Lake Erie loop flow will be provided only intermittently. (initial brief at § IX.B)

12. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because, unlike the rest of the MISO tariff that charges rates for defined services, the

tariff provisions filed with the Joint Application propose charges to NYISO and PJM for
unspecified services (essentially, for “nothing”) and the collection of a rate for nothing is
unduly discriminatory to those entities and their customers. (initial brief at § VIII)

13. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because, besides seeking to charge NYISO and PJM for an undefined service, the MISO
tariff provisions fail to establish any sort of performance standard or any service
obligation of MISO or ITC to the customers that will receive the non-service. (initial
brief at § VIII)

14. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because data supplied by MISO indicates that MISO and IESO are failing to set the

MI/ON PARs-related “flag” in the Interchange Distribution Calculator properly,

precluding NYISO and PJM and other regions from using transmission loading relief

(“TLR”) to call for curtailment of transactions to protect reliability at times when the

MI/ON PARs are not successfully mitigating Lake Erie loop flow. (initial brief at § IX.C)

15. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because the Joint Applicants submitted no evidence of any actual contribution of NYISO to Lake Erie loop flow, and instead submitted a fundamentally flawed DFAX analysis that uses hypothetical data to estimate NYISO’s expected future contribution to Lake Erie loop flow. (initial brief at §§ VI.A, VII.A, VII.B)

16. The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because, while the rebuttal testimony of the Joint Applicants argues that the cost of the
Replacement PARs should be allocated based solely on “cost causation,” the Joint
Applicants have not submitted studies showing that Lake Erie loop flow causes reliability
issues, and that those reliability issues required ITC to construct the Replacement PARs.
The only specific reliability issues identified in the record as a reason for construction of
the replacement PARs are those reliability concerns identified in MTEP06. (initial brief
at §§ IV.A, IV.F and IV.D.2)

17.The charges in the Joint Application are unjust, unreasonable and unduly discriminatory

because MISO and ITC (and potentially IESO) have indicated a potential lack of

commitment to operate the MI/ON PARs in the manner called for in the Operating

Instruction and in representations to the DOE (initial brief at § IX.F).

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