NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.
OPPOSING EXCEPTIONS

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.

February 6, 2013

TABLE OF CONTENTS

Page

I.INTRODUCTION.....................................................1

A.Any One of the Following Findings of the ID Independently Justifies Rejection of the Joint

Application......................................................1

B.List of Exceptions Opposed...........................................5

C.Rebuttal of Policy Considerations Claimed to Warrant Commission Review...........6

II.SUMMARY.........................................................7

III. ARGUMENT OPPOSING EXCEPTIONS.....................................9

A.The ID Should Be Upheld, Because It Does Not Contain “Fundamental Errors of Law and

Policy”.........................................................9

1.The Presiding Judge’s Ruling on the Section 205 Customer/Contractual Issue Had No Relation

to the Other Factual and Legal Holdings Confirming that the Joint Application is Unjust and

Unreasonable, and Unduly Discriminatory and Preferential......................9

2.The ID Correctly Applied Pre-Order 1000 Policies Regarding Involuntary Facility Charges .. 11

3.The Presiding Judge Correctly Determined that JAs’ Proposed Cost Allocation is Inconsistent

with Commission Opinion No. 494 and the Commission’s AEP Decision............15

4.The ID Correctly Found that the JAs Failed to Meet Their Burden of Proving that the Proposed

Rate Treatment Is Just and Reasonable Due to their Failure to Submit and Support Required

Information.....................................................20

5.Exceptions Relating to the Impact of the Joint Operating Agreement Between MISO and PJM

(the “JOA”).....................................................21

6.The Joint Application Fails to Satisfy the “At Least Roughly Commensurate” Standard...21

7.The ID Appropriately Disposed of the Judicial Estoppel and Collateral Attack Arguments.24

B.The ID Is Premised on Correct Findings of Fact.............................29

1.The Joint Applicants Failed to Prove NYISO’s Actual Contribution to Lake Erie Loop Flow

and the DFAX Study Is Flawed........................................29

2.The Joint Application Fails to Make the Required Proof of Benefits to NYISO and PJM...51

3.The ID Correctly Found That Ignoring PJM’s and NYISO’s PARs, Direct Current Converters,

Tariff and Market Loop Flow Mitigation Solutions, While Crediting IESO for Constructing

PARs, Is Unduly Discriminatory and Preferential............................59

4.The Replacement PARs Do Not Provide Unique Benefits that No Other PARs and

Controllable Devices Located Elsewhere in the Eastern Interconnection Can Provide.....64

5.The Original PAR and Replacement PARs Were Constructed to Address the Transactional,

Economic and Reliability Needs of Michigan and Ontario Utilities and their Electricity

Customers......................................................71

C.The Joint Application Has the Flaws Described in the ID.......................80

1.Requiring NYISO Customers to Pay for Costs that MISO’s DFAX Analysis Indicates Are

Caused by IESO Makes the Joint Application Unjust and Unreasonable.............80

2.The Proposal to Exempt all MISO Transmission Owners and Customers That Do Not Pay

ITC’s Zonal Rate from any Responsibility for the Cost of the Replacement PARs, While at the

Same Time Asking NYISO and PJM Customers to Pay for a Portion of Their Costs, Is Unjust,

Unreasonable, and Unduly Discriminatory, and Preferential.....................80

3.The MI/ON PAR Operating Instruction Is Unduly Discriminatory, Preferential and Prejudicial

.................................................................................................................................................. 85

4.The ID Correctly Found that the JAs Propose to Assume No Service Obligation to NYISO or

PJM Customers Pursuant to the Filing....................................88

IV. CONCLUSION......................................................96

TABLE OF AUTHORITIES

Page(s)

FEDERAL CASES

Alamito Company, 43 FERC ¶ 61,274 (1988)......................................27

Ameren Servs. Co. v. Midwest Indep. Transmission Sys. Operator, Inc., 121 FERC ¶ 61,205

(2007) (“Ameren”).....................................................62

Ameren Servs. Co. v. Midwest Indep. Transmission Sys. Operator, Inc., 125 FERC ¶ 61,161

(2008) (“Ameren II”)....................................................62

American Electric Power Corp. v. Midwest Independent Transmission System Operator, Inc., 122

FERC ¶ 61,083 (2008) (“AEP”)......................................8, 15, 16, 19

American Electric Power Corp. v. Midwest Independent Transmission System Operator, Inc., 125

FERC ¶ 61,341 (2008) (“AEP II”).......................................7, 15, 16

American Electric Power Service Corp., 49 FERC ¶ 61,377 (1989)........................12

Cargill Power Markets, LLC v. Public Service Company of New Mexico, 132 FERC ¶ 61,079

(2010)...........................................................91, 92

City of Cleveland v. FERC, 773 F.2d 1368 (D.C. Cir. 1985).............................91

El Paso Natural Gas Co., 132 FERC ¶ 61,155 (2010).................................24

El Paso Natural Gas Co., 67 FERC ¶ 61,324 (1994)..................................24

Illinois Commerce Commission v. FERC, 576 F.3d 470 (7th Cir. 2009) (“ICC”)..7, 8, 21, 23, 24, 51, 52

Indiana Michigan Power Co., 64 FERC ¶ 61,184 (1993) (“Indiana Michigan”)...........12, 13, 23

ISO New England Inc., 136 FERC ¶ 61,221 (2011)...................................30

Kinder Morgan Interstate Gas Transmission LLC, 133 FERC ¶ 61,157 (2010) (“Kinder

Morgan”)...........................................................39

Kentucky Utils. Co., 62 FERC ¶ 61,097 (1993).....................................26

Louisiana Pub. Serv. Comm’n v. Entergy Corp., 119 FERC ¶ 61,224 (2007)..................26

Midwest Independent Transmission System Operator, Inc., 133 FERC ¶ 61,275 (“Hearing

Order”)........................................................14, 24, 30

Midwest Independent Transmission System Operator, Inc., 117 FERC ¶ 61,241 (2006)...........16

Missouri Interstate Gas, LLC, et al., 122 FERC ¶ 61,136 (2008)..........................26

New York Independent System Operator, Inc., 139 FERC ¶ 61,139 (2012).................42, 43

iii

New York Independent System Operator, Inc. 139 FERC ¶ 61,138 (2012)....................41

Ozark Gas Transmission, L.L.C., 133 FERC ¶ 61,158 (2010) (“Ozark”).....................39

PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ¶ 61,063 (2007) (“Opinion No. 494”) 2,8, 15, 16

PJM Interconnection, L.L.C., 139 FERC ¶ 61,024 (2012).........................41, 42, 43

PJM Interconnection, L.L.C., 138 FERC ¶ 61,230 (2012) (the “PJM Remand Order”).........41, 42

San Diego Gas & Electric Co. v. Sellers of Ancillary Services, 115 FERC ¶ 61,230 (2006)........26

Southern California Edison Company, 70 FERC ¶ 61,087 (1995) (footnote omitted) (“WSCC”),

subsequent order approving loop flow plan, 73 FERC ¶ 61,219 (1995)................12, 13

State Farm Mutual Automobile Insurance Company v. Lincow, 715 F. Supp. 2d 617 (E.D. Pa.

2010)..............................................................25

Transcontinental Gas Pipe Line Corp., 112 FERC ¶ 61,170 (2005) (“Transcontinental”).......51, 52

United States v. Pelullo, 14 F.3d 881 (3d Cir. 1994)...................................5

United States v. Gibbs, 739 F.2d 838 (3d Cir. 1984)..................................25

United Illuminating Co., 119 FERC ¶ 61,182 (2007)..................................26

Yukon Pacific Company L.P., 71 FERC ¶ 61,197 (1995)...............................29

OTHER CASES

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).............................................................10

FEDERAL STATUTES

§ 205 of the Federal Power Act...........................................10, 11, 27

§ 206 of the Federal Power Act................................................94

REGULATIONS

Federal Rule of Evidence 103(a)(1)..............................................5

18 C.F.R. § 35.2(c)(1) (2012).................................................91

18 C.F.R. § 385.711 (2012)...................................................1

Order No. 888...........................................................47

Order No. 890...........................................................91

Order No. 1000...............................................6, 7, 10, 11, 12, 13

Order No. 1000-A......................................................10, 11

OTHER AUTHORITIES

Dept. of Energy’s Electricity Policy Coordination and Implementation, International Electricity

Regulation, Presidential Permits - Procedures...................................28

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; 177 P.U.R.4th 201(1997).............................................75

Order Establishing Revised Procedural Schedule, Docket No. ER11-1844-002 (April 3, 2012).....24

NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.
OPPOSING EXCEPTIONS

Pursuant to Rule 711, 18 C.F.R. § 385.711 (2012), the New York Independent System Operator, Inc. (“NYISO”) hereby submits this Brief Opposing Exceptions. Specifically, this brief is submitted in opposition to the exceptions raised in the Brief of the Joint Applicants on Exceptions (the “BOE”), filed on January 17, 2013 in response to the Initial Decision (“ID”) issued on December 18, 2012 by Presiding Administrative Law Judge Steven L. Sterner.1

I.INTRODUCTION

The Presiding Judge carefully considered the voluminous amount of factual evidence presented in this proceeding, and the legal arguments made by the parties. The ID is extremely thorough. The NYISO agrees with and supports the outcome reflected in the ID, and the vast majority of its findings.

In this Introduction, the NYISO points out that the ID makes numerous rulings that,

independently, justifies rejection of the Joint Application at issue in this proceeding. The NYISO also lists the exceptions that it opposes, and rebuts the policy considerations the Joint Applicants (“JAs”) claim warrant Commission review.

A.Any One of the Following Findings of the ID Independently Justifies Rejection of

the Joint Application

Any one of the following seven categories of findings from the ID2 is sufficient, independently, to justify rejection of the Joint Application.

1 Midwest Independent Transmission System Operator, Inc., 141 FERC ¶ 63,021 (2012).

2 This is not intended as an exhaustive list. Quoted provisions omit footnotes included in the ID.

The Joint Application Violates Commission Policy and Precedent

• “[T]he ITC PARs were planned wholly within the MISO structure and that planning did

not involve NYISO, PJM or any other regions.” ID at P 569.

•“MISO/ITC have made a unilateral filing without a showing that they engaged in a ‘good

faith effort’ to work out the problem.” ID at P 404.

•“[T]he Joint Applicants’ proposed cost allocation did not follow transmission planning,

as required by Commission policy.” ID at P 620.

• “…the costs of the ITC PARs are sunk costs…[and] the filing at issue violates the

Commission’s policies with regard to existing facilities, as evidenced in Opinion No. 494, AEP II, and the Commission’s approval of the JOA.” (ID at PP 659, 664)

• “(1) the proposed cost allocation does not ‘fairly assign[] costs among participants,

including those who cause them to be incurred and those who otherwise benefit from

them;’ (2) does not ‘provide[] adequate incentives to construct new transmission;’ and (3)
is not ‘generally supported by state authorities and participants across the region.’” ID at
P 651.

The Joint Application Violates Cost Causation Principles

• “[T]he Joint Applicants have not proved that the proposed cost allocation is consistent

with the Commission’s policy of allocating costs based on cost causation.” (ID at P 620). “[T]he Joint Applicants provided no cost causation studies….” ID at P 726.

• “…[Detroit Edison Company (“DEC”)] and Ontario Hydro agreed to construct the

Original PAR and the Hydro One PARs [i.e., the PARs on the Canadian side of the

Michigan-Ontario interface] to prevent or control power flows that were interfering with scheduled transactions between Michigan and Ontario….” ID at P 445.

• “It is clear DEC decided to construct the Original PAR to benefit itself and its customers

and strictly for local concerns and that the ITC PARs were replacements meant for the same purpose…[and] are not new transmission facilities [but] replacements for preexisting facilities.” ID at PP 448-49.

• “[T]he Joint Applicants’ pre-existing contract obligations show that it voluntarily agreed

to assume all of the costs of the Original PAR and the ITC PARs, which replaced the Original PAR.” ID at P 571.

•“…the ITC PARs were needed and originally intended to address local reliability

concerns only.” (ID at P 453)

• “…the Joint Applicants have failed to show that NYISO and PJM caused the harm that

resulted in the Joint Applicants’ need to install the ITC PARs;” (ID at P 723). “Even if
one were to accept the Joint Applicants’ argument that the ITC PARs were installed
because of Lake Erie loop flow, the Joint Applicants have failed to submit credible and
persuasive evidence of NYISO’s and PJM’s actual contribution. By the same token, the
Joint Applicants have failed to credit NYISO and PJM for the costs of the PARs and

other facilities installed by NYISO and PJM that reduce Lake Erie loop flow and for the ‘Broader Regional Markets’ initiatives.” ID at P 725.

• “…Joint Applicants have not presented credible and persuasive evidence of the actual

harmful contributions of PJM and NYISO to Lake Erie loop flow. … the Joint

Applicants have failed to establish a causal link between the alleged harmful flows and ITC’s decision to incur the costs of the ITC PARs.” ID at P 769.

• “Reallocating the costs caused by IESO to NYISO and PJM, by definition, violates the

cost causation principle adhered to by the Commission.” ID at P 778.

• “The Joint Applicants, the filing parties herein, have the burden of proving that NYISO is

a significant contributor to Lake Erie loop flow. …The Joint Applicants, however, have made no such demonstration.” ID at P 774.

The Joint Application Fails to Demonstrate Benefits to NYISO and PJM and Their Customers

• “…the Joint Applicants have failed to show that NYISO or PJM will be benefitted by the

operation of the ITC PARs. …the Joint Applicants failed to produce any credible benefits analysis to support the proposed cost allocation.” ID at PP 723, 732.

• “[T]he undersigned agrees that New York customers may be harmed when the PARs are

operated to reduce counterclockwise loop flows and when certain components of the New York transmission system are constrained or would become constrained because of the lack of counterclockwise flow.” ID at P 743.

• “…MISO/ITC have failed to convincingly demonstrate, through the use of credible

probative evidence, that the ITC PARs will have identifiable and quantifiable multiregional benefits.” ID at P 887.

• “…any benefit accrues primarily to ITC since both the Original and ITC PARs were

intended to relieve thermal overload on the ITC system.” ID at P 629.

• “[T]he Joint Applicants clearly have not met their burden of establishing the benefits that

PJM and NYISO and their customers would receive by the Joint Applicants’ operation of
the PARs. Therefore, the proposed cost allocation is not consistent with cost causation.”
ID at P 631.

• “…merely because many of the participants herein, or the Commission, may have said

that the issue is worthy of interregional attention does not mean that NYISO, PJM, or

their stakeholders directly and financially benefit from the Joint Applicants’ operation of
the PARs, nor does it serve as evidence to support the conclusion that the facilities were
the product of a interregional planning effort involving NYISO and PJM.” ID at P 647.

The DFAX Study Is Flawed

•The DFAX Study:

“…is ill-suited as a basis to allocate the costs of the ITC PARs to NYISO and PJM

and is fatally flawed.” ID at P 731.

“…is merely a hypothetical snapshot of estimated flows in 2015 and does not

accurately measure cost incurrence, benefits, or detriments [and]… cannot be relied

upon to predict how system usage will change over time, not can it be relied upon to

predict loop flows for the next 48 years.” ID at P 731.

“…deviates from the methodology the Commission approved for use under the

JOA….” ID at P 826.

“…is also flawed because it is based on power flow contributions not only across the

B3N circuit (where the ITC PARs are installed), but across the L51D and L4D

circuits and the J5D circuit. …” ID at P 829.

“…is flawed because, although IESO is the largest flow contributor, the Joint

Applicants do not allocate any of the costs to it.” ID at P 830.

“…should have included all 8,760 hours of the year.” ID at P 833.

“should have covered a broader region; should have identified which power flows

actually cause harm; should have considered benefits scheduled transactions will
receive from the ITC PARs (such as offsets of the impact of flows from other
regions); should not have been used where impacts of facilities change frequently;
should have been based on the contribution to flows only on the circuit where the
ITC PARs are located; should not have netted MISO’s power flows from Michigan to
Ontario on two circuits that loop back to Michigan on two other circuits against each
other; should have set the ITC PARs on the B3N circuit “to inactive,” and the Hydro
One PARs to [“active,”] producing a more focused assessment of generation-to-load
impacts on that circuit; should have used only the load duration curves for the regions
to which the ITC PARs costs are proposed to be allocated; should have been
conducted for each region based on that region’s load level for each hour of the year;
should have included an amount of PJM generation and an amount of MISO
generation; and should not have dispatched generation within each RTO pro rata
based on each generator’s maximum output.” ID at P 835.

• “[T]he Commission stated that the static nature of the [DFAX] method makes it unjust

and unreasonable as the sole determinant of cost allocation.” ID at P 835.

The Joint Application Fails to Provide the Supporting Data Required by the Commission’s Rules

• “[T]he failure not only to submit, but to convincingly establish, the depreciation rate,

return on equity, or capital structure that was used to calculate the revenue requirement
that the Joint Applicants seek to recover from NYISO and PJM violates Commission
policy prohibiting the use of stale data to justify a rate of return. … [T]he Joint
Applicants have failed to comply with 18 C.F.R. § 35.13(h)(10), which requires
Statement AJ, consisting of statements of depreciation and amortization expenses. …
[T]he [JAs] did not file Statement AJ … [or] Statement AV…. Having examined the
cumulative errors and missing data, the undersigned finds that the Joint Applicants have
not met their burden of proving that the proposed cost allocation is just and reasonable.”
ID at PP 667-68, 670.

The Cost Allocation in the Joint Application Is Unjust and Unreasonable, Unduly Discriminatory and Preferential

• “[T]he Joint Applicants have not met their burden of proving that 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. Specifically, the undersigned
finds that: (1) the Joint Applicants’ filing violates the FPA and Commission policy; (2)
the proposed cost allocation violates postage stamp rate and sunken cost recovery
policies; (3) the Joint Applicants have not met their burden of proving that the proposed
rate treatment is just and reasonable; and (4) the Joint Applicants have not met their
burden of proving that the proposed cost allocation is not unduly discriminatory or
preferential.” ID at P 618.

•“…the Joint Applicants’ filing is inconsistent with the existing MISO Tariff provisions

regarding the allocation of costs associated with ‘like-for-like’ replacement facilities.”

ID at P 451.

•“(1) the proposed cost allocation grants IESO and customers in MISO outside of the ITC

zone an undue preference; and (2) the Operating Instruction for the ITC PARs and the

MISO Tariff discriminate against NYISO and PJM.” ID at P 671.

•“[T]he ITC PARs do not provide unique benefits that no other PARs can provide.” ID at

P 748.

• “[T]he Joint Applicants’ proposal credits IESO’s customers for transmission facilities

Hydro One installed, but gives no credit for NYISO’s or PJM’s transmission facilities and market initiatives that also reduce Lake Erie loop flow. … [S]uch an allocation is unduly preferential, prejudicial, and discriminatory.” ID at P 780.

The Tariff Provisions Filed by JAs Fail to Include Rules Specifying the Obligation to Serve the Customers That Must Pay for the Replacement PARs

• “[T]he filing does not create a service obligation of the Joint Applicants to NYISO or

PJM or their customers. … [T]he Joint Applicants are legally incorrect that the DOE
Presidential Permit obviates the need to provide a service obligation in the Tariff. …
[T]he Joint Applicants have failed to ‘specify which services [they] actually offer[]’. … [R]equiring NYISO or PJM to pay for a portion of the ITC PARs without a
corresponding service obligation of MISO/ITC is unjust and unreasonable. … [G]iven the fact that MISO has a defined service obligation to its own customers, but not to NYISO
or PJM customers, the proposed cost allocation is unduly discriminatory, preferential, and prejudicial.” ID at PP 855, 857, 859, 861.

• “[S]hould the Commission conclude that NYISO and PJM must pay a portion of the costs

of the ITC PARs, NYISO and PJM should not be required to pay during outages of those PARs.” ID at P 888.

B.List of Exceptions Opposed

The NYISO opposes the exceptions numbered 1-4, 6-19, and 21-26.

C.Rebuttal of Policy Considerations Claimed to Warrant Commission Review

The Commission should decline to review the ID. The Presiding Judge carefully considered the
voluminous amount of factual evidence presented in this proceeding, and the legal arguments made by the
parties. The ID is extremely thorough. As indicated in Section I.A (pp. 1 to 5) of this brief, the ID makes
numerous findings. Many of the findings in the ID independently justify rejection of the Joint
Application.

In Section IV (on page 12) of their BOE, the JAs contend that Commission review of the ID is
warranted for two policy reasons. The Commission should find that neither reason justifies Commission
review.

First, the JAs argue that the foundation of Order No. 1000’s transmission cost allocation program
will be undermined if the Presiding Judge’s findings regarding the necessity of a contractual or customer
relationship are not modified.3 The JAs are incorrect, as Order No. 1000’s cost allocation principle four
is fully consistent with the outcome of, and principles upheld in, the ID. Order No. 1000’s cost allocation
principle four provides that “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.”4

In this proceeding, JAs propose to allocate a portion of the cost of ITC’s replacement PARs (the
“Replacement PARs”) to NYISO and PJM customers located outside the MISO region without a
voluntary agreement by NYISO, PJM or their customers, to pay for a portion of the costs of the
Replacement PARs. The evidence shows that NYISO and PJM took no role in the planning of those
facilities. Accordingly, the ID is consistent with Order No. 1000’s policies and the Commission should
decline to review it.

3 BOE at 12.

4 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 136 FERC ¶ 61,051, at P 657 (2011) (“Order No. 1000”), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g, Order No. 1000-B, 141 FERC ¶ 61,044 (2012).

Second, the JAs contend that the ID required an overly precise calculation of benefits and

causation to justify cost allocation, referring to the “roughly commensurate” standard of Illinois

Commerce Commission v. FERC (“ICC”).5 The JAs also raise the specters of “free riders” and a

discouragement of “undertaking projects where benefits cannot be precisely quantified and matched to
individual consumers,”6 as reasons for the Commission to review the ID. The JAs’ failure to prevail on these issues resulted from (a) their failure to satisfy the ICC “roughly commensurate” standard, (b) their utter failure to offer evidence of the burdens allegedly imposed on MISO/ITC by loop flow actually
caused by NYISO or PJM, and (c) their failure to demonstrate the benefits the Replacement PARs will
provide to NYISO or PJM. The NYISO addresses these failures in Section III.A.6 (pp. 21 to 24) and
III.B.2 (pp. 51 to 59)of this brief.

Order No. 1000’s cost allocation principle four will preclude - on a going-forward basis -

unilateral filings such as the Joint Application, mooting the associated allocation battles over burdens and benefits. Order No. 1000 will foster projects planned and agreed to among regions by consensus, based on a common perception of benefits and burdens. The Commission should decline to review the ID, as it will not create any adverse precedents.

II.SUMMARY

In response to the JAs’ BOE, the NYISO makes the following arguments:

• The Presiding Judge’s ruling on the Section 205 customer/contractual issue had no

relation to the ID’s other factual and legal holdings confirming that the Joint Application is unjust and unreasonable, and unduly discriminatory and preferential. The JAs fail to support the claim that the Presiding Judge’s ruling on the Section 205 issue somehow influenced other rulings. See Section III.A.1 of this brief.

• The ID correctly applied pre-Order No. 1000 policies regarding involuntary facility

charges. Prior to Order No. 1000, Commission policy was to consistently reject

unilateral filings by single utilities proposing to impose charges, terms and conditions on
a neighboring utility that, according to the filing utility, was responsible for loop flows.
The Presiding Judge’s finding of a lack of a “good faith effort” by the JAs to work out the
problem was solidly based on record evidence. See Section III.A.2 of this brief.

5 576 F.3d 470 (7th Cir. 2009) .

6 BOE at 12.

•The Presiding Judge correctly determined that JAs’ proposed cost allocation is

inconsistent with Commission Opinion No. 4947 and the Commission’s American

Electric Power Corp. v. Midwest Independent Transmission System Operator, Inc.8 order (“AEP”) and order on rehearing (“AEP II”). See Section III.A.3 of this brief.

• The ID correctly found that the JAs failed to meet their burden of proving that the

proposed rate treatment is just and reasonable, due to their failure to submit required information. See Section III.A.4 of this brief.

• The Joint Application fails to satisfy the “at least roughly commensurate” standard of

ICC. As its fundamental calculus, ICC calls for comparison of the costs assessed against a party to the burdens imposed or benefits drawn by that party. The JAs have misstated both the pertinent “burdens imposed” and “benefits drawn” elements in an attempt to sidestep significant evidentiary holes in their case. The ID properly assessed the
evidence relating to both elements and found that the Joint Application did not meet the tests of ICC. See Section III.A.6 of this brief.

• The Presiding Judge appropriately disposed of the JAs’ judicial estoppel and collateral

attack arguments. The JAs failed to satisfy the elements of judicial estoppel, and the

NYISO’s arguments do not constitute a collateral attack on the DOE Presidential Permit. See Section III.A.7 of this brief.

• The Joint Application failed to prove NYISO’s actual contribution to Lake Erie loop flow

and the DFAX Study is flawed. First, Lake Erie loop flow is not always harmful.

Second, the Commission should reject the argument that loop flow over the entire

Michigan-Ontario interface should be taken into account when allocating the cost of the
Replacement PARs. Third, the ID correctly found that the DFAX study is flawed in
multiple respects. Fourth, the use of the DFAX method is not “common” in Commission
proceedings, and the Commission recently found its use inappropriate. Fifth, the DFAX
study is unreliable because it was prepared in a result-oriented fashion. Sixth, it would be
unjust and unreasonable to require NYISO and PJM to file a Section 206 complaint when
the DFAX Study no longer reasonably represents contributions to loop flow. Seventh,
the ID correctly held that MISO should have used a representation of load for each of
8,760 hours in the year to perform the DFAX analysis. See Section III.B.1 of this brief.

•The Joint Application fails to make the required proof of benefits to NYISO and PJM.

The Presiding Judge did not apply “too stringent a standard of proof.” See Section III.B.2

of this brief.

• The ID correctly found that ignoring PJM’s and NYISO’s transmission facilities, tariff

solutions and market solutions that mitigate Lake Erie loop flow, while crediting the

Independent Electricity System Operator (Ontario) (“IESO”) for Canadian utility Hydro
One’s construction of three PARs at the Michigan/Ontario Interface (the “Hydro One
PARs”), is unduly discriminatory and preferential. See Section III.B.3 of this brief.

• The Replacement PARs do not provide unique benefits that no other PARs or

controllable devices located elsewhere in the Eastern Interconnection provide. See Section III.B.4 of this brief.

7 PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ¶ 61,063 (2007) (“Opinion No. 494”).

8 122 FERC ¶ 61,083 (2008); reh’g den. 125 FERC ¶ 61,341 (2008).

•The Original PAR and Replacement PARs were constructed to address the transactional,

economic and reliability needs of Michigan and Ontario utilities and their electricity customers. See Section III.B.5 of this brief.

• JA’s proposal to require NYISO customers to pay for costs that MISO’s DFAX analysis

indicates are caused by IESO makes the Joint Application unjust and unreasonable. See Section III.C.1 of this brief.

• JA’s proposal to exempt all MISO Transmission Owners and MISO customers that do

not pay ITC’s zonal rate from any responsibility for the cost of the Replacement 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 discriminatory, and unduly preferential. See Section III.C.2 of this brief.

• The Operating Instruction for the Replacement PARs and Hydro PARs (collectively, the

“MI/ON PARs”) is unduly discriminatory, preferential and prejudicial due to the
operational discretion granted to MISO and IESO, and due to the inequality of the
operating rules set forth in that agreement. See Section III.C.3 of this brief.

• The ID correctly found that the JAs propose to assume no service obligation to NYISO or

PJM customers pursuant to the filing. The failure to define service obligations in the

MISO Tariff makes the proposed charges unjust and unreasonable. The JAs are incorrect that all terms and conditions of service do not have to be included in its FERC tariff, and that the provisions of ITC’s DOE-jurisdictional agreements or Presidential Permit obviate the need to submit tariff rules governing the service MISO proposes to provide. See
Section III.C.4 of this brief.

III.ARGUMENT OPPOSING EXCEPTIONS

A.The ID Should Be Upheld, Because It Does Not Contain “Fundamental Errors of

Law and Policy”

1. The Presiding Judge’s Ruling on the Section 205 Customer/Contractual

Issue Had No Relation to the Other Factual and Legal Holdings Confirming that the Joint Application is Unjust and Unreasonable, and Unduly
Discriminatory and Preferential

The JAs take exception to the ID’s holding that Section 205 of the FPA “only permits the

assessment of costs to entities with which [the filing] utility has a customer or contractual relationship.”9
The JAs argue this holding presents a basis for overturning all of the Presiding Judge’s rulings on all
issues presented in this proceeding, alleging that the holding “negatively influenced the Decision’s rulings
on several other issues (See, e.g. ID at P 511, P 558 and P 561), and indeed, unavoidably jaundiced the

9 BOE at 13, citing ID at P 367.

Presiding Judge’s view of the entire record.”10 The Commission should reject this allegation, as the JAs have provided no explanation or support for the concept that this holding somehow “infected” the myriad of other separate legal and factual findings the Presiding Judge made, many of which confirmed that the Joint Application is unjust and unreasonable, and unduly discriminatory and preferential.

In Order No. 1000, the Commission stated that “[n]either section 205 nor section 206 of the FPA state or imply that an agreement is a precondition for any transmission charges.”11 In Order No. 1000-A, the Commission rejected on rehearing arguments that “the costs of new transmission facilities can only be allocated within a preexisting contractual relationship,”12 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.”13 The NYISO brought to the attention of the Presiding Judge the
Commission’s position on this issue in Order Nos. 1000 and 1000-A.

The NYISO disagrees with the Commission’s determination in Order Nos. 1000 and 1000-A
regarding its authority to accept rate filings under Section 205 of the Federal Power Act (“FPA”)14 that
require entities to pay for facilities when those entities do not have a contractual or customer relationship
with the filing utility. The NYISO raised this issue in its request for rehearing of the Commission’s order
setting this proceeding for hearing.15 The Commission has not acted on the NYISO’s rehearing request.
Also, the NYISO, along with several other parties, filed petitions for review with the U.S. Court of
Appeals for the District of Columbia Circuit of the Commission’s determination on this issue in Order
Nos. 1000 and 1000-A,16 due to the breadth of the Commission’s asserted statutory authority and the

10 BOE at 13-14.

11 Order No. 1000 at P 533.

12 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) (“Order No. 1000-A”).

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

14 16 U.S.C. § 824d (2006).

15 See 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 (January 21,
2011).

16 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).

divergence of this determination from Commission precedent without a reasoned explanation.17 Many other parties to this proceeding disagree with the Commission’s determination in Order Nos. 1000 and 1000-A, including the NYTOs, the PJM TOs, and Trial Staff. In sum, the customer/contract issue is currently unresolved, as it is pending in judicial review. The ID’s ruling on the customer/contract issue was made with full awareness of the current posture of that issue.18

The BOE cites no evidence or logic, and fails to offer even an explanation, to support the claim

by the JAs that the Presiding Judge’s disagreement with the Commission’s position regarding the scope of its authority under Section 205 of the FPA, as announced in Order Nos. 1000 and 1000-A, “negatively influenced” rulings or “unavoidably jaundiced the Presiding Judge’s view of the entire record.” For
example, the JAs fail to explain how the legal determination by the Presiding Judge relates to or
prejudiced any of the factual determinations listed in Section I.A of this Brief Opposing Exceptions (pp. 1 to 5), all of which are supported by substantial record evidence.

The Commission should reject the JAs’ suggestion that other findings are unreliable or must be ignored because the Presiding Judge reached a legal conclusion with which the JAs disagree.

2.The ID Correctly Applied Pre-Order 1000 Policies Regarding Involuntary

Facility Charges

On page 14 of their BOE, the JAs assert that the ID erroneously found that “prior to Order No.

1000, the Commission’s policy with respect to interregional cost allocation was ‘the same as that found in

17 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).

18 The ID explained at P 330 (footnotes omitted):

In response to the assertion that the proposed cost allocation is barred because there is no customer or contractual relationship, as required by section 205 of the FPA, MISO/ITC assert that the
Commission does not require such a relationship. MISO/ITC quote from Order No. 1000, in
which the Commission stated that “[n]either section 205 nor section 206 . . . state or imply that an agreement is a precondition for any transmission charges.” Furthermore, the Commission stated it has jurisdiction to ensure those who benefit also pay “regardless of their contractual relationship with the owner of those transmission facilities.” The JAs argue that, based on the Commission’s binding ruling, the argument that the lack of a customer or contractual relationship prevents the
section 205 filing from being approved must be rejected.

See also id. at P 336 (recognizing that the “NYISO asserts that it is challenging [the Order No. 1000] holding on
appeal as contrary to Commission precedent”) (footnotes omitted); id. at P 377 (acknowledging that “NYISO is
currently seeking appellate judicial review of portions of Order No. 1000-A” involving charging rates to third
parties).

cost allocation principle four of Order No. 1000’ (Id. at P 411).” Specifically, the JAs assert that, “prior to Order No. 1000, the Commission never had a policy that prohibited involuntary interregional cost allocation in appropriate cases. That policy prohibition was established for the first time in Order No. 1000 and it is inextricably linked to the new transmission planning reforms adopted in that order.”19 In addition, the JAs challenge the finding in P 412 of the ID that:

The JAs have violated this policy in that the proposed cost allocation for the interregional transmission facility (the [Replacement] PARs) is not limited to the transmission
planning region in which the PARs are located and the JAs have not engaged in any
consensual negotiation to resolve the alleged loop flow problem.

The JAs’ challenge is based on an assertion that ITC attempted “in good faith prior to the filing [of the Joint Application] to negotiate a consensual cost sharing arrangement with NYISO and PJM, but that attempt was summarily rebuffed.”20 The Commission should reject both challenges.

The JAs gloss over the actual content of paragraph 411 of the ID. In that paragraph, as well as in
paragraphs 391-400, the Presiding Judge reviewed the cases cited in the parties’ briefs, and appropriately
found - citing American Electric Power Service Corp.21 and Indiana Michigan Power Co.22 - that the
Commission’s pre-Order No. 1000 policy was, like Order 1000 cost allocation principle four, premised
on consensual arrangements between neighboring utilities.23 This is readily verified: In the 1995 order
involving the Western Systems Coordinating Council (“WSCC”), the Commission accepted for filing a
loop flow solution that was developed by the signatories to the WSCC Agreement to address a

longstanding problem.24 The plan called for the use of controllable devices owned by five of the 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

19 BOE at 14.

20 Id. at 15 (footnote omitted).

21 49 FERC ¶ 61,377 (1989).

22 64 FERC ¶ 61,184, at p. 62,553 (1993) (“Indiana Michigan”).

23 In addition, as discussed in Section III.A.3 (pp. 15 to 20) of this Brief Opposing Exceptions, the pre-Order 1000 cost allocation policy incorporated the “cost allocation must follow transmission planning” concept reflected in Order No. 1000 (at PP 501, 670). The BOE implicitly recognizes this common thread by that recognizing (at p. 14) the “link[age]” in Order No. 1000 between cost allocation and transmission planning.

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

Commission contrasted attempts to impose charges on neighbors through Section 205 filings stating:
“The Commission has consistently rejected unilateral filings by single utilities proposing to impose
charges, terms and conditions on a neighboring utility that, according to the filing utility, is responsible
for loop flows.”25 The JAs have not cited a single case from the pre-Order No. 1000 period where the
Commission approved non-consensual charges imposed by one utility on another to address loop flow
issues.

Having reviewed the applicable precedent and correctly discerned that the pre-Order 1000 policy was premised on consensual arrangements, in P 412 of the ID, the Presiding Judge considered the facts and found that the JAs failed to engage in good faith consensual negotiations before they submitted their cost allocation proposal to the Commission.26 Specifically, the Presiding Judge found that, contrary to the pre-Order No. 1000 Commission policy, “MISO/ITC have made a unilateral filing without a showing that they engaged in a ‘good faith effort’ to work out the problem.”27

The Presiding Judge finding of the lack of a “good faith effort” on the part of the JAs was solidly
based on record evidence: ITC admitted in discovery 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.28 ITC first suggested that NYISO and its customers should share in the costs of the PARs in
August of 2009.29 ITC did not approach NYISO until October or November of 2009.30 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.”31 ITC’s request that NYISO contribute was made

25 WSCC at p. 61,250.

26 Indiana Michigan, 64 FERC ¶ 61,184 at p. 62,554 (1993) (requiring “a good faith attempt at working out the problem”).

27 ID at P 404, citing Indiana Michigan at P. 62,554.

28 Ex. NYT-11 at 1. Nor do the JAs assert - as they cannot - that any agreement to share costs was attempted with NYISO or PJM prior to the construction of the Original PAR, of which the PARs at issue in this proceeding were simply replacements.

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

30 See Ex. S-4 at 13, 25-26. Footnote 2 of the BOE also cites to Ex. S-4, and admits that this recitation of the timing of the demand for payment is correct.

31 Ex. S-4 at 25.

after the completion of MISO’s planning process, after the construction of the ITC PARs was essentially
complete, and over two years after ITC assumed a contractual obligation to construct the ITC PARs.32
ITC moved forward with the construction of the Replacement PARs without any assurance that the
Replacement PARs were candidates for multi-regional cost-sharing. Planning and building new
transmission facilities without the involvement or consent of the neighboring regions, then demanding
payment from those regions after the facilities were constructed and the costs sunk, does not constitute a
“good faith effort” to consensually resolve an interregional cost sharing issue. The Presiding Judge’s
ruling is fully justified.

The JAs’ allegation that the Commission’s decision setting this proceeding for hearing33 “shows” that they attempted in good faith to negotiate a cost-sharing arrangement34 is easily dismissed. The cited portion of the Commission order “shows” nothing of the sort. It is part of the “Background” section of the order, in which the Commission recounted statements made by various parties, but made no rulings. The order set all factual matters for hearing, stating:

The Filing Parties’ proposed tariff sheets raise issues of material fact that cannot be

resolved based on the record before us, and that are more appropriately addressed in the
hearing and settlement judge procedures ordered below. Our preliminary analysis
indicates that the Filing Parties’ proposed tariff sheets have not been shown to be just and
reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or
otherwise unlawful.35

For these reasons, the findings in paragraphs 411 and 412 of the ID are correct and appropriate, and should be upheld.

32 ID at P 657.

33 133 FERC ¶ 61,275 at P 8 (“Hearing Order”).

34 BOE at 15.

35 Hearing Order at PP 43-44.

3.The Presiding Judge Correctly Determined that JAs’ Proposed Cost

Allocation is Inconsistent with Commission Opinion No. 494 and the Commission’s AEP Decision

On pages 15 to 18 of their BOE the JAs attempt to distinguish this proceeding from Commission Opinion No. 494 and AEP/AEP II in order to show that their cost allocation proposal is “not inconsistent with applicable pre-Order No. 1000 precedents.”36

In paragraphs 634-664 of the ID the Presiding Judge reviewed the Commission’s “postage stamp rate and sunken cost recovery policies”37 and found that the JAs’ proposal “violates the Commission’s policies with regard to existing facilities, as evidenced in Opinion No. 494, AEP II, and the Commission’s approval of the JOA.”38 The ID uses a step-by-step process to apply the policies that the Commission announced in Opinion No. 494 (expanding upon Order No. 890) and AEP/AEP II to the facts presented in this proceeding.39 The Presiding Judge ultimately determined that allocating the cost of the Replacement PARs to NYISO and PJM customers would be inconsistent with the pre-Order No. 1000 cost allocation policies that are set forth in the identified Commission orders.40

On page 15 of their BOE the JAs quibble with one statement, in one paragraph, of the in-depth analysis the Presiding Judge provided in his ID and argue that paragraphs 42 and 44 of Opinion No. 494 do not impose an absolute prohibition against re-allocating the cost of pre-existing transmission facilities that were not constructed pursuant to a Joint Planning process. Even if the JAs’ contention is correct, their proposal is inconsistent with Commission policy, as the Presiding Judge correctly explained in the ID, and as the Commission explained in AEP II:

[W]hile AEP’s existing 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 new
facilities that were planned pursuant to each RTO’s regional planning process. [footnote
omitted] The existing facilities within each RTO were created principally to serve the
customers of the transmission owners on whose system they are located and were not the
product of centralized regional planning. Furthermore, AEP undertook financial

36 BOE at 15.

37 ID at p. 265, heading 2.

38 ID at P 664.

39 See, e.g., ID PP 651, 654, 657-659.

40 ID at P 664.

responsibility for the existing projects they planned before it was known whether any cost sharing policy would be adopted.41

JAs next argue that the FPA Section 206 standards of proof do not apply to FPA Section 205

filings. This distinction is of no import. The guidance that the Commission provided on cost allocation
issues in Opinion No. 494, AEP and AEP II, is just as relevant to determining whether JAs’ cost
allocation proposal is just and reasonable in this proceeding, as it was to determining whether or not the
existing PJM and MISO tariff rules addressing cost allocation for transmission facilities were just and
reasonable in the proceedings that Opinion No. 494 and AEP/AEP II addressed.
On page 16 of their BOE JAs argue that the Replacement PARs are not “existing facilities”
because they are “relatively small, discrete facilities located at a single substation,”42 because the Joint
Application was submitted before the Department of Energy granted ITC’s Presidential Permit, and
because the Joint Application was submitted before the Replacement PARs entered service.
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 Midwest Independent Transmission System Operator, Inc., 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.43 The Commission
rejected challenges to this determination from developers of the excluded projects, noting that they had
“moved forward with those projects without any assurance that such projects would be candidates for
regional cost-sharing.”44 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

41 AEP II at P 42.

42 JAs do not explain why they believe the “relatively small” size of the Replacement PARs is relevant to determining whether or not they are “existing facilities” for cost allocation purposes.

43 117 FERC ¶ 61,241 at P 96 (2006).

44 Id.

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.45

There was no postage stamp rate in place for allocating costs across the combined Midwest ISOPJM-NYISO region in 1998,46 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.47 ITC 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.48

The Replacement PARs were approved for construction in the MISO region’s transmission

planning process in the 2006 MISO Transmission Expansion Plan (“MTEP06”). The costs of the

Replacement PARs did not qualify for region-wide cost sharing as a baseline reliability project.49 Instead,
the costs were allocated to ITC’s customers under a license plate rate: MISO’s Attachment O rate for the
ITC zone.50 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.51 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.52

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 2009,53 and did not approach NYISO about it until

45 Id. at PP 86, 96.

46 Ex. NYI-48. See also ID at P 657.

47 Ex. NYI-49. See also ID at P 657.

48 Ex. NYT-11 at 1. See also ID at P 646.

49 Tr. 305:19-23; Ex. PJM-9 at 1 (Table 1.4-3 to the MTEP06 report). See also ID at P 656.

50 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)). See also ID at P 656.

51 See Ex. PJM-11 (data response to NYISO/ITC 1-14). See also ID at P 451.

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

53 See ITC’s Answer In Opposition to Request for Clarification, Docket No. ER08-1281-000 at 3 (August 31, 2009). See also ID at P 657.

October or November of 2009.54 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,55 or in 2007, when ITC assumed a contractual obligation to construct the
Replacement PARs.56 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.”57 As PP 443, 449, 651, 654-655 and 664 of the ID determined, the Replacement PARs are “existing facilities” for cost allocation purposes. It would be inconsistent with Commission policy and precedent to permit the JAs to re-allocate a portion of the cost of the PARs to NYISO or PJM customers.

In addition, as explained in Section III.C.2 (pp. 80 to 85) of this Brief Opposing Exceptions, it

would be unduly discriminatory, unduly preferential, unduly prejudicial, unjust and unreasonable to allow a license plate cost allocation method to be used to 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.

On page 17 of their BOE the JAs argue that operating the MI/ON PARs to address the impact

Lake Erie loop flow has on MISO and IESO’s ability to schedule interchange at the Michigan/Ontario

interface will also affect Lake Erie loop flow at other locations around Lake Erie. As the NYISO explains
in Section III.B.3 (pp. 59 to 64) of this Brief Opposing Exceptions, the same can be said for any
transmission facility that operates to better conform actual power flows to scheduled power flows,
including the ABC, JK and Ramapo PARs located at the NYISO/PJM border. In Section III.B.5 (pp. 71
to 80) of this Brief Opposing Exceptions, the NYISO explains that paragraphs 631, 886 and 887 of the ID

54 See Ex. S-4 at 13, 25-26. See also ID at P 657.

55 Ex. NYI-48. See also ID at P 657.

56 Ex. NYI-49. See also ID at P 657.

57 Ex. S-4 at 25.

correctly find that the Replacement PARs were planned and constructed to address local issues affecting ITC’s transmission system.

At the bottom of page 17 of their BOE JAs make a wholly inaccurate argument that the

transmission facilities addressed in AEP “had apparently never been the subject of any interregional

review whatsoever.” In P 98 of AEP the Commission 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 JAs’ argument that the MEN Study (that was conducted in 1999),58 or the loop flow studies that MISO and PJM conducted in 2007 and 2008, somehow show that the Original PAR and Replacement PARs were the product of regional planning.59

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 explained “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.”60 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.”61 The
Commission should reach the same conclusion in this proceeding.

58 Ex. NYI-44.

59 As NYISO witness Zachary Smith explained in Ex. NYI-38 (at 20:2-21:14), the MEN Study was not a multiregional 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.

60 AEP at P 98.

61 Id.

4.The ID Correctly Found that the JAs Failed to Meet Their Burden of

Proving that the Proposed Rate Treatment Is Just and Reasonable Due to their Failure to Submit and Support Required Information

In P 670 of the ID, the Presiding Judge found that the JAs had failed to meet their burden of

proving that the proposed rate treatment is just and reasonable. This failure stemmed from a number of
fatal shortcomings, including the JAs’ failure to “submit testimony or other evidence to support the
depreciation rate, return on equity, or capital structure that were utilized to calculate the revenue
requirement that the JAs seek to recover from the NYISO and PJM.”62 The Presiding Judge found that
this failure “violates Commission policy prohibiting the use of stale data to justify a rate of return.”63
Further, JAs’ failure to file Statement AJ alone means that they “are not in a position to meet their burden
of proof for cost recovery;”64 the judge also found that “the [JAs] have failed to file a statement and
explanation of the percentage rate of return requested by a utility, in violation of 18 C.F.R. §

35.13(h)(22)…[which] requires the [JAs] to file Statement AV.”65

In the BOE, the JAs offer a variety of explanations for the existence of this fatal gap, including that: (i) the “rate filing…specifically explained why the submission of cost of service data was not
required;” (ii) the hearing order repeated the explanation offered in the Joint Application; (iii) the
Commission did not issue a deficiency letter or otherwise request additional cost-of-service information; and (iv) the timing of the New York and PJM parties’ challenge to the failure to provide such
information. Beyond this, the JAs argue that the submission of cost of service data was not required.66
The Commission should reject the rationales and arguments of the JAs and uphold the findings of the ID, for the reasons set forth in the pertinent portion of the Brief Opposing Exceptions of the New
York Transmission Owners, which the NYISO supports.

62 ID at P 666.

63 ID at P 667 (footnote omitted).

64 ID at P 667 (footnotes omitted).

65 ID at P 668 (footnote omitted).

66 BOE at 19.

5.Exceptions Relating to the Impact of the Joint Operating Agreement

Between MISO and PJM (the “JOA”)

At pages 20-21 of the BOE, the JAs assert that the JOA does not bar the allocation of

Replacement PARs costs to PJM. The NYISO is not responding to this assertion.

6.The Joint Application Fails to Satisfy the “At Least Roughly

Commensurate” Standard

On pages 3 and 21 of their BOE the JAs contend that under the 7th Circuit’s order in ICC, “the

proper standard for evaluating the cost allocation proposal in this case is whether the costs proposed to be
allocated to NYISO and PJM are ‘at least roughly commensurate’ with their respective contributions to
Lake Erie loop flow and with the benefits they will receive from the physical control of loop flow that
[the Replacement] PARs will provide.” On page 22 of their BOE, JAs argue that P 396 of the ID does not
“clearly recognize” the applicability of the “at least roughly commensurate” cost allocation standard from
ICC, and argue it is not clear what standard of evaluation the Presiding Judge applied in paragraph 396 of
the ID.67

The formulation of the ICC standard of proof that the JAs propose in their BOE is incorrect and incomplete. JA’s formulation is designed to avoid recognizing substantial flaws in the JA’s case that the Presiding Judge identified in the ID. As its fundamental calculus, ICC calls “‘for comparing the costs
assessed against a party to the burdens imposed or benefits drawn by that party.’”68 JAs have misstated both the pertinent “burdens imposed” and “benefits drawn” elements in an attempt to sidestep significant evidentiary holes in their case. The ID properly assessed the evidence relating to both elements and found the Joint Application did not meet the tests of ICC.

First JAs improperly substitute the “respective contributions [of NYISO and PJM] to Lake Erie
loop flow”69 as a proxy for the “burdens” that NYISO and PJM “imposed” on the ITC’s transmission
system. This is a highly inappropriate proxy. As the ID explained, under ICC the JAs needed to show

67 The NYISO addresses JAs’ other arguments related to the Presiding Judge’s incorporation of the ICC standard into the ID in Section III.B.2 (pp. 51 to 59) of this Brief Opposing Exceptions.

68 ICC at 476 (citing Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004)).

69 JAs propose to determine NYISO’s and PJM’s “respective contributions to Lake Erie loop flow” using a DFAX analysis that addresses a future (2015) planning year.

that the need for the Replacement PARs was driven, at least in part, by the burden imposed on MISO/ITC
by actual loop flow contributions of NYISO and PJM.70 As shown in testimony and at hearing, and as
explained in the ID, the JAs failed to show that loop flow caused by NYISO or PJM contributed to the
need that the Replacement PARs were installed to address. The ID correctly determined that the
“reliability benefits of installing the [Replacement] PARs were listed in the MTEP06 study, but none of
the issues addressed at that time were described as having been caused by Lake Erie loop flow,”71 and
that “Joint Applicants have failed to show a causal link between Lake Erie loop flow and the reliability
issues described in the MTEP06 report.”72 Further, the Presiding Judge found that “[e]ven if one were to
accept the [JAs’] argument that the [Replacement] PARs were installed because of Lake Erie loop flow,”
the JAs “failed to submit provide credible and persuasive evidence of NYISO’s and PJM’s actual
contribution”73 to Lake Erie loop flow.

As summarized appropriately in the ID:

PJM argues that because it did not “cause” the need for the installation of the ITC PARs,
it should not be allocated any costs. NYTOs argue that MISO/ITC have failed to support
their claim that the proposed cost allocation is roughly commensurate with causation

because they have not performed any study of cost causation, benefits, beneficiaries, reliability, or economics. The undersigned agrees.74

Instead of presenting evidence that the Replacement PARs were constructed to address Lake Erie
loop flow caused by PJM and NYISO, the JA’s instead rely on their DFAX analysis, which purports to
project the loop flow that NYISO and PJM will cause in a hypothetical, future, 2015 planning year. The
JA’s DFAX analysis does not prove that (a) the need for the Replacement PARs was “cause” by Lake
Erie loop flow, or (b) that loop flow caused by NYISO or PJM was the reason ITC constructed its
Replacement PARs.

Second, the JAs’ assumption that any reduction in Lake Erie loop flow is a “benefit drawn” is
inaccurate. In Section III.B.2 (pp. 51 to 59) of this brief, the NYISO explains that the Presiding Judge

70 ID at P 725.

71 ID at P 724 (citing Ex. NYI-50 at 19).

72 Id.

73 ID at P 725.

74 ID at P 728 (emphasis added, footnote omitted).

correctly found that the JAs had failed to prove that NYISO and PJM would draw benefits from the installation of the Replacement PARs.75

JA’s assumption that the only relevant benefit is the reduction of Lake Erie loop flow makes their
proposed cost/benefit comparison incomplete as well. The ICC standard reasonably encompasses
consideration of the full array of benefits that the MI/ON PARs provide to the JAs. Many of these
benefits do not accrue to NYISO or PJM. In Section III.B.5 (pp. 71 to 80) of this brief, the NYISO
demonstrates that the Original PAR and Replacement PARs provide operational, transactional, regulatory
and reliability benefits to Detroit Edison, ITC, MISO and their respective customers that are not available
to NYISO or PJM.

Paragraph 396 of the ID correctly determined the applicability of the 7th Circuit’s ICC decision.
Paragraphs 388-404 of the ID discuss the Commission’s rejection of unilateral filings by utilities that
propose to impose loop flow related costs on neighboring utilities. In P 393 of the ID the Presiding Judge
restates with approval an argument PJM made: that the Commission only addresses loop flow issues as a
last resort, after efforts to resolve loop flow issues on a mutually acceptable basis have failed. In P 393
the Presiding Judge explained that only as a last resort, to address situations that could not be resolved
consensually, will the Commission consider unilateral cost allocation if the proponent can demonstrate
that the loop flow places a burden on its system. In P 394 of the ID, the Presiding Judge lists a series of
cases that the JAs relied on to support their proposed cost allocation, including ICC. In the paragraphs
that follow, the Presiding Judge evaluates whether or not each of the cases listed in P 394 should be read
to excuse the JAs from the obligation to resolve loop flow and other operational issues on a consensual
basis prior to submitting a Section 205 filing. In P 395, the Presiding Judge concludes that the
Commission’s Indiana Michigan76 decision rejected a filing that unilaterally proposed to impose charges
for loop flows on neighboring utilities. In P 396 the Presiding Judge evaluated ICC and correctly
determined that ICC did not involve an attempt by one utility to unilaterally impose charges for loop

75 ID at P 740.

76 64 FERC ¶ 61,184 (1993).

flows on one or more neighboring utilities. Instead, the case involved a cost allocation dispute within the boundaries of PJM, between and among PJM’s members.

In P 396 of the ID the Presiding Judge also quoted sections of the ICC decision that are different from, but not inconsistent with, the “roughly commensurate with costs and benefits” standard that the JAs appear to support. If the JAs are suggesting that the Commission should apply the “roughly
commensurate” standard set forth in ICC, but ignore all of the other guidance that the 7th Circuit provided in ICC, then the Commission must reject the JAs’ position.

The Presiding Judge appropriately applied the “roughly commensurate” standard in P 396 of the ID. The Commission should reject the JA’s exception.

7.The ID Appropriately Disposed of the Judicial Estoppel and Collateral

Attack Arguments

a.The JAs Fail to Satisfy the Elements of Judicial Estoppel

The JAs argue that the NYISO should have been judicially estopped from arguing that the

Operating Instruction for the Replacement PARs was unduly discriminatory “because NYISO’s position
on the plan in this case is inconsistent and irreconcilable with the position it took on the plan before DOE
in the ITC Presidential Permit proceeding.”77 The Commission should reject this argument, for several
reasons.

First, any rights the JAs may have had to raise judicial estoppel concerns have been waived

because the JAs did not seek rehearing of the Hearing Order, which did not limit the scope or nature of
the issues or arguments that could be addressed at the hearing.78 More broadly, the JAs waived any right
they may have had to raise judicial estoppel arguments by failing to make motions necessary to preserve
those arguments. The NYISO filed its initial testimony on May 11, 2012. The April 3, 2012, Order
Establishing Revised Procedural Schedule required motions to strike testimony to be submitted by July

77 BOE at 22.

78 See, e.g., El Paso Natural Gas Co., 132 FERC ¶ 61,155, P 86 (2010) (concluding that a party waived its rights by failing to seek rehearing); El Paso Natural Gas Co., 67 FERC ¶ 61,324 (1994) (same).

23, 2012. JAs did not submit a motion to strike any portion of Mr. Yeomans’ testimony. Mr. Yeomans’
May 11, 2012 testimony addressed the discriminatory provisions of the Operating Instruction.
By raising judicial estoppel and collateral attack arguments for the first time in their Post-Hearing Initial Brief, the JAs essentially asked the Presiding Judge to ignore record evidence. It is well-settled that a party is precluded from raising an evidentiary objection in a post-trial submission when the party failed to object to the evidence at trial when it was first introduced.79 A party must raise an objection as soon as the party knows or reasonably should know of the grounds for objection, unless postponement is desirable for a “special reason” and “not unfair to the opposition.”80 This rule applies equally to
objections on estoppel grounds. In United States v. Pelullo, 14 F.3d 881 (3d Cir. 1994), the court held
that a party had properly preserved on appeal its collateral estoppel argument by having objected to the
admission of underlying evidence at trial.

The JAs stipulated to the admission of Exhibit NYI-66, which contains actual data on Lake Erie loop flow measured at the Michigan/Ontario Interface (the “MI/ON Interface”) and data addressing the
actual operation of the MI/ON PARs. The Joint Stipulation that resulted in the unopposed admission of Exhibit NYI-66 provided that Exhibit NYI-66 “may be used for all purposes in this proceeding.”81 The JAs could not, after the conclusion of the hearing, ask the Presiding Judge to limit the use of this evidence by precluding the NYISO from making arguments based on admitted evidence, including Mr. Yeomans’ testimony and exhibits, and Exhibit NYI-66.

79 See Federal Rule of Evidence 103(a)(1), which provides that a party may claim error in a ruling to admit evidence
only if the error “affects a substantial right of the party and . . . a party, on the record . . . timely objects or moves to
strike.” (emphasis added). In State Farm Mutual Automobile Insurance Company v. Lincow, 715 F. Supp. 2d 617,
635 n.16 (E.D. Pa. 2010), the court determined that the defendant could not raise evidentiary arguments in its post-
trial motions that it failed to raise at trial. In that case, the defendant waived its argument that the plaintiffs did not
lay a proper foundation for the introduction of an exhibit because the defendant failed to object on this basis at trial.

80 United States v. Gibbs, 739 F.2d 838 (3d Cir. 1984).

81 August 10, 2012 Joint Stipulation at 2 (“MISO, ITC and IESO agree that the data responses that NYISO is
requesting permission to offer into the evidentiary record in this proceeding are authentic copies of the original
responses and they do not object to the new exhibits that are identified above being entered into the evidentiary
record in this proceeding. NYISO and the other signatories hereto hereby agree that they do not object to the
statements of MISO, ITC and IESO attached hereto as Exhibit ITC-13 being entered into the evidentiary record in this proceeding. The Exhibits described above may be used for all purposes in this proceeding, except that no crossexamination of witnesses of MISO, ITC and IESO will be conducted by any party or participant using Exhibit Nos. NYI-64 through NYI-73, or Exhibit No. ITC-13…”).

JAs’ extremely tardy request, if granted, would raise significant due process concerns. For

example, assuming arguendo that a motion to strike portions of Mr. Yeomans’ testimony had been timely submitted and granted by the Presiding Judge, the NYISO would have adjusted its trial strategy based on the ruling and might have emphasized different issues and arguments at the hearing on the merits, and
sought admission of a different set of exhibits that would have been consistent with its modified strategy. The same can be said for the admission of Exhibit NYI-66. JAs’ estoppel arguments were not timely
raised, would have significantly impacted the NYISO’s trial strategy if they had been timely raised and granted, and must now be rejected as untimely.

Beyond this, as the Commission has explained, “[t]he doctrine of judicial estoppel applies only
where, as a result of prior testimony, parties have relied upon that testimony and changed positions by
reason of that testimony.”82 The Brief on Exceptions, however, fails to allege (let alone demonstrate) that
the JAs (1) relied on the NYISO’s prior testimony in the DOE Presidential Permit proceeding and (2)
changed their position in this proceeding as a result of the NYISO’s earlier testimony. The JAs, therefore,
have “failed to make the required allegations under the doctrine of judicial estoppel,”83 and their claim
must therefore be rejected.

Furthermore, “[t]he doctrine of judicial estoppel has been rejected in many jurisdictions and has never been applied by the Commission.”84 The Commission refused to apply judicial estoppel in the Missouri Interstate Gas85 order relied on by the JAs. The instant proceeding is not the appropriate
opportunity for the Commission’s first foray into applying the judicial estoppel doctrine.

82 San Diego Gas & Electric Co. v. Sellers of Ancillary Services, 115 FERC ¶ 61,230, at P 33 & n.59 (2006)

(citation omitted); see also Louisiana Pub. Serv. Comm’n v. Entergy Corp., 119 FERC ¶ 61,224, P 45 & n.32 (2007)
(quoting San Diego Gas & Electric); United Illuminating Co., 119 FERC ¶ 61,182, P 80 & n.52 (2007) (same).

83 Louisiana Pub. Serv. Comm’n v. Entergy Corp., 119 FERC ¶ 61,224 at P 45 (“In this case, AEEC does not allege that it relied upon prior testimony by the Louisiana Commission and changed positions by reason of that testimony. Thus, AEEC has failed to make the required allegations under the doctrine of judicial estoppel.”).

84 Kentucky Utils. Co., 62 FERC ¶ 61,097, p. 61,705 (1993); see also Louisiana Pub. Serv. Comm’n v. Entergy
Corp., 119 FERC ¶ 61,224, P 45 & n.32 (2007) (quoting Kentucky Utils. Co.). Furthermore, research has not
identified a single Commission order applying the doctrine of judicial estoppel. See also ID at PP 891-892.

85 Missouri Interstate Gas, LLC, et al., 122 FERC ¶ 61,136 at PP 36-44 (2008)..

b.The ID Does Not Constitute a Collateral Attack on the DOE

Presidential Permit

The BOE also argues that “[t]he ID’s finding that the PARs operating plan discriminates against NYISO and PJM should be vacated as an improper collateral attack on DOE’s Presidential Permit.”86 The Commission should deny this exception.

The JAs argue that, in the Presidential Permit proceeding the NYISO filed comments with DOE
supporting ITC’s proposed operation of the PARs, and DOE ultimately took these comments into account
to issue the Presidential Permit. The JAs argue that DOE’s approval of the Presidential Permit ultimately
prohibited the Presiding Judge - and by extension, the Commission - from considering whether the PARs
operating plan is discriminatory in the context of the JAs’ rate filing at the Commission.87 The Brief on
Exceptions, however, fails to acknowledge that the purpose of the DOE proceeding, and the

determinations reached therein, involved legal and factual issues that are separate and distinct from those that the Commission must consider in this proceeding under Section 205 of the FPA.
As summarized by the Commission, the basis for the collateral attack doctrine is:

the fact that it is contrary to sound administrative practice and a waste of resources to relitigate issues in succeeding cases once those issues have been fully determined. Absent a showing of significant change in circumstances, the relitigation of an issue is simply not justified.88

The DOE proceeding did not litigate or determine any issues related to cost allocation for the
Replacement PARs, much less whether the provisions of the Operating Instruction would be consistent
with a proposal under the Federal Power Act to allocate costs of the Replacement PARs to NYISO or
PJM. The DOE proceeding focused on the reliability impact the Replacement PARs would have on the
U.S. power grid.

DOE’s criteria for decision-making on Presidential Permit applications are specific and limited. As explained by DOE:

86 BOE at 25; see also id. at 26 (arguing that “the ID’s finding that the PARs operating plan is discriminatory ‘amount[s] to a collateral attack’ on DOE’s approval” of the PARs operating plan).

87 BOE at 25-26.

88Alamito Company, 43 FERC ¶ 61,274 at p. 61,753 (1988) (“Alamito”) (emphasis added).

Executive Order 12038 states that, before a Presidential permit may be issued, the action must be found to be consistent with the public interest. The two criteria used by DOE to determine if a proposed project is consistent with the public interest are:

1. Environmental Impact - The National Environmental Policy Act of 1969 (NEPA)
requires that Federal agencies give due consideration to the environmental
consequences of their actions….

2. Impact on Electric Reliability - DOE considers the effect that the proposed project

would have on the operating reliability of the U.S. electric power supply system; i.e., the ability of the existing generation and transmission system to remain within
acceptable voltage, loading and stability limits during normal and emergency
conditions. The standards DOE applies include the standards of the North American Electric Reliability Council (NERC) and the standards of the member regional
councils that are formulated by the utilities themselves.89

Page five of DOE’s February 24, 2012 Order in OE Docket No. PP-230-4 (Exhibit ITC-14)

states:

DOE has also assessed the impact the proposed international transmission facilities

would have on the reliability of the U.S. electric power supply system. Based on the

information filed in this docket as discussed above, DOE has determined that the

installation and operation of the proposed international transmission facilities by ITC, as conditioned herein, would not adversely impact the reliability of the U.S. electric power supply system.90

The NYISO agrees with DOE’s reliability determination, and nothing in the ID conflicts with it. The NYISO does not expect that the terms and conditions set forth in the Operating Instruction (when properly followed) will “adversely impact the reliability of the U.S. electric power supply system.”
NYISO witness Wesley Yeomans explained on cross-examination that, consistent with the stated scope of DOE’s review, the NYISO only raised issues that could “adversely impact the reliability of the U.S.
electric power supply system” at DOE.91 At DOE the NYISO was “really focused on the reliability
concerns and what we could comment to modify the CO2 [MI/ON PAR Operating Instruction] and make sure the TLR process still works for New York so we can maintain reliability...”92

89 See Dept. of Energy’s Electricity Policy Coordination and Implementation, International Electricity Regulation,
Presidential Permits - Procedures available at http://energy.gov/oe/services/electricity-policy-coordination-and-
implementation/international-electricity-regulatio-9 ; see also ID at P 895.

90 ID at P 896 (citing Ex. ITC-14 at 4-5).

91 Tr. 833:9-834:15.

92 Tr. 833:24-834:3.

The JAs’ citation (at p. 26 of the BOE) of Yukon Pacific Company L.P.,93 is inapposite, as the

parties found in Yukon Pacific to have engaged in a collateral attack had made the same arguments at both DOE and the Commission, and DOE had already ruled on those arguments. That is not the case with
respect to the Replacement PARs. The limited scope of DOE’s Presidential Permit jurisdiction means
that arguments related to cost allocation would not have been appropriate to raise at DOE. The other
orders listed in the BOE at 26 are cited without any explanation of why or how they could be applicable
in the current circumstances.

NYISO understandably made no arguments at DOE regarding cost allocation or the Operating

Instruction’s relation thereto, because these arguments would have been pertinent only to matters outside
the scope of DOE’s Presidential Permit jurisdiction. Thus, under the Commission’s Alamito test, no
collateral attack is present here, because there was no “relitigation” at the Commission of something
litigated at DOE, and the issues presented in the Joint Application under the Federal Power Act were in
no way determined, much less “fully determined” by DOE. The Presiding Judge thus found correctly
“that the Presidential Permit concerned the granting of permission to build a facility and that the Permit
has nothing to do with the Commission’s jurisdiction to regulate the charges associated with that facility,”
and that “[t]he DOE order cited by the JAs did not determine any issues related to cost allocation or the
justness and reasonableness of rates for the [Replacement] PARs, but focused on the effect on reliability
of the PARs.”94

For these reasons, the ID does not constitute a collateral attack on the DOE Presidential Permit.

B.The ID Is Premised on Correct Findings of Fact

1.The Joint Applicants Failed to Prove NYISO’s Actual Contribution to Lake

Erie Loop Flow and the DFAX Study Is Flawed

The JAs argue that the ID’s findings rejecting the DFAX Study “are inconsistent with the record
and with precedent and commonly accepted facts in numerous respects.”95 Beyond the DFAX Study

93 71 FERC ¶ 61,197 at p. 61,698 (1995).

94 ID at P 898.

95 BOE at 27.

(which the ID found to be flawed in numerous respects), the JAs offer the generalization that “it is a well known fact that both NYISO and PJM … contribute significantly to Lake Erie loop flow.”96 The JAs also claim that “NYISO has not denied that it contributes to loop flow.”97

There are many things that the NYISO has “not denied.” JAs bear the burden of proof in this

proceeding. “Where, as here, a filing is made under section 205 of the FPA, the burden of proof is on the
filing party to show that its proposal is just and reasonable; the onus is not on protesters … to show that
the proposal is unjust and unreasonable.”98 The JAs must demonstrate (among other things), based on
evidence in the record, that the NYISO is a significant actual contributor to Lake Erie loop flow, and that
the NYISO’s contribution to Lake Erie loop flow caused ITC to construct its Replacement PARs, before
the Presiding Judge can find the proposal to be just and reasonable and not unduly discriminatory or

preferential.99 The JAs have failed to make this required showing, which is why they instead allege that the NYISO “not denied” that it contributes to Lake Erie loop flow.

The Joint Application does not contain any evidence of the NYISO’s actual contribution to Lake
Erie loop flow.100 Instead, the Joint Application relies on101 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 principles of economic dispatch
are ignored.

96 Id.

97 Id.

98 ISO New England Inc., 136 FERC ¶ 61,221, P 20 (2011).

99 Id.; see also Hearing Order at P 44 (“Our preliminary analysis indicates that the Filing Parties’ proposed tariff sheets have not been shown to be just and reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful.”).

100 ID at 725 (“…the JAs have failed to submit credible and persuasive evidence of NYISO’s and PJM’s actual contribution.”).

101 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”).

The MISO’s DFAX study is flawed in every material respect,102 and was developed in a resultoriented fashion that merits rejection for that reason alone.103 As detailed in Section III.B.1.c.i (pp. 37 to 38) of this Brief Opposing Exceptions, the Presiding Judge agreed with the flaws identified by NYISO
and the other parties.

Having failed to submit specific evidence of NYISO’s actual contribution to loop flow, the JAs now seek to rely on two studies that MISO and PJM performed several years ago: the 2007 MISO/PJM loop flow study (Ex. ITC-4) and the 2008 Phase II study (Ex. ITC-24). However, these studies do not, in fact, prove that NYISO “contribute[s] substantially to Lake Erie loop flow.”

JAs propose to allocate the cost of the Replacement PARs based on the loop flow impact of

operating each ISO/RTO’s generation to serve that ISO/RTO’s load.104 The 2007 study (Ex. ITC-4)

makes it clear that no study was performed to estimate the loop flow impact of NYISO generation serving
NYISO load.105 Hence, the 2007 study provides no evidence of the NYISO’s contribution to Lake Erie
loop flow.

The 2008 study cautioned that its analysis uses data for NYISO (an “external system”) that may
be inaccurate: “Modeling information for the analysis below is sourced from PJM’s EMS state estimator,
which limits the accuracy of the results for external systems.”106 In the 2008 study, PJM and MISO also
warn that “One limiting factor in quantifying all flowgate impacts in the Phase II Study was lack of
consistent data. The Phase II Study shows that much of the source of flow on the flowgates cannot be

102 ID at PP 731 and 826-833; see also Section III.B.1.c.1 (pp. 37 to 38) of this Brief Opposing Exceptions. 103 See Tr. 317:15-318:1; see also Section III.B.1.c.iv (pp. 43 to 44) of this Brief Opposing Exceptions. 104 Ex. MSO Tab E at 5:2-4.

105 See Ex. ITC-4 at 5 of 43 (“No such study has been performed with NYISO.”) and 36 of 43 (“…there have been no attempts to quantify the NYISO market flows….”). JAs refer in the BOE to page 40 of 43, but that page states: “NYISO Generation-to-Load Flow: Not currently calculated.”

106 Ex. ITC-24 at 14 of 34. In a similar vein of caution, “PJM and Midwest ISO have chosen not to pursue gathering
interconnection-wide tag data for the Phase II study. Because PJM only has access to historical tags that intersect
the PJM control area, we cannot accurately reproduce parallel path flows unless the tag is a ‘wheeling’ schedule
whose contract path crosses PJM’s border.” Id. Likewise, at page 4 of 34, the study states “…only PJM and
Midwest ISO have a Joint Operating Agreement that requires reporting generation-to-load impacts for constraints.”

determined with readily available data without using simulator tools.”107 It is apparent from PJM’s and
MISO’s explanation that the 2008 study was only intended to grossly approximate the loop flow impact
of external systems, including NYISO and Ontario. The study also explains that it was not possible for
MISO and PJM to accurately apportion responsibility for loop flow (a) among the tagged External
Transactions that were not scheduled to or through MISO or PJM; or (b) between those tagged External
Transactions and the generator-to-load impacts of 31 different “external systems” that included Ontario,
NYISO and TVA; or (c) between and among the generator-to-load impacts of the 31 external systems.108
For these reasons, the Commission should uphold the ID’s findings that “the JAs have failed to submit credible and persuasive evidence of NYISO’s and PJM’s actual contribution” and “provided no cost causation studies.”109

a.Lake Erie Loop Flow is Not Always Harmful

On pages 27-29 of their BOE, JA argue that “because of its volatility and unpredictability, Lake Erie loop flow causes problems all of the time, not just when it causes actual [transmission] congestion.” JAs argue that it was not appropriate for the ID to focus on loop flows that cause transmission congestion, which the ID referred to as “harmful” loop flows. The JAs’ contention is not consistent with the
evidentiary record in this proceeding.

NYISO witness Robert Pike explained on page 22, lines 6-16, of his testimony (Exhibit NYI-46):

Possible benefits to New York would depend on how the MI/ON PARs are

operated (i.e., what their mission is) and how effectively they are able to achieve
their intended function. If all of the MI/ON PARs are operated to, and are able
to, successfully conform actual power flows to scheduled power flows at the
MI/ON Interface, New York may “benefit” if/when (a) the MI/ON PARs are
operated to reduce clockwise loop flows, and (b) components of the New York
State Transmission System that are substantially affected by unscheduled Lake
Erie power flows are constrained. New York may be “harmed” if/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

107 Ex. ITC-24 at page 33 of 34. The 2008 study also states: “To increase the accuracy of the model…control areas would require a combined model updated by all partners in the interconnection. … As of the [time of the Phase II study], historical models, tags and distribution factors are not available for the chosen dates.”
108 Ex. ITC-24 at 8 of 34 (“The remaining 31 zones represent control areas in the Midwest ISO, NYISO and the other NYPP zones, TVA and the other SERC zones, SPP, etc.”).

109 ID at PP 725, 726.

substantially affected by unscheduled Lake Erie power flows are constrained. [Emphasis added.]

The word “constrained” in the above statement refers to times when transmission congestion is present.110 JAs have not questioned the accuracy of Mr. Pike’s statements, and the Presiding Judge endorsed them in paragraph 743 of the ID.

On page 28 of the BOE, JAs argue that the reason Lake Erie loop flow solutions are in place all
the time is because Lake Erie loop flow causes harm all the time. That statement is not accurate.
NYISO’s and PJM’s implementation of the redispatch component of Market-to-Market Coordination
(“M2M”) does not apply at times when the Non-Monitoring RTO’s unscheduled flows are not causing a
detrimental congestion impact on the Monitoring RTO’s transmission system. This rule applies even
when the Non-Monitoring RTO’s flows are in excess of that RTO’s M2M Entitlement.111
On page 29 of their BOE, JAs argue that Financial Transmission Rights (“FTRs”) Transmission Congestion Contracts (“TCCs”) and “tying up of transmission capacity that could otherwise be used for scheduled transactions” are not related to transmission congestion. JA’s contention falls far from the mark. TCCs and FTRs are hedges against transmission congestion. They settle based on the actual
transmission congestion experienced, or not experienced. When Lake Erie loop flow “t[ies] up of
transmission capacity that could otherwise be used for scheduled transactions” that means Lake Erie loop
flow is causing transmission congestion.

NYISO witness Pike also testified:

New York may 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. In order
to achieve benefits related to more consistent power flows, the NYISO would need to be
able to reserve less transmission system capacity to protect against the uncertainty of
encountering large (magnitude) or more volatile loop flows without creating additional
reliability risks….112

110 See Tr. 996:4-14.

111 See § 7.1.2(a)(i) of Schedule D to Attachment CC to the NYISO’s OATT, which provides that M2M redispatch coordination is not invoked when M2M Flowgates on the Monitoring RTO’s transmission system aren’t subject to transmission congestion, without regard to whether or not the Non-Monitoring RTO’s M2M Market Flow exceeds that RTO’s M2M Entitlement on the relevant M2M Flowgate.

112 Ex. NYI-46 at 22:18-23:2.

If New York reserves less transmission system capacity to protect against the uncertainty
of encountering large (magnitude) or more volatile loop flows, the impacts of
unexpectedly large or volatile power flows on New York will be more significant when
they occur.113

The evidence adduced in this proceeding shows that the operation of the MI/ON PARs has not
reduced the volatility of Lake Erie loop flow. Comparing the data in Column Four of Exhibit NYI-66114
to the data in Column Six of Ex. NYI-66115 shows that the operation of the MI/ON PARs during their first
104 days of operation increased the absolute magnitude of Lake Erie loop flow in 33.7% of hours.116 The
MI/ON PARs did not reduce the volatility of Lake Erie loop flow; to the contrary Exhibit NYI-66 shows
the operation of the PARs increased the magnitude of Lake Erie loop flow in approximately 1/3 of hours,
while reducing Lake Erie loop flow in other hours. Lake Erie loop flow became less predictable when the
MI/ON PARs entered service.

The JA have not shown that Lake Erie loop flow is always harmful. The JA’s exceptions should be rejected.

b. The Commission Should Reject the Argument that Loop Flow Over

the Entire Michigan-Ontario Interface Should be Taken Into
Account When Allocating the Cost of the Replacement PARs

The JAs take exception to the finding in P 829 of the ID that the DFAX study was structurally flawed “because it is based on power flow contributions not only on the B3N circuit (where the
[Replacement] PARs are located), but also across the L51D and L4D circuits and the J5D circuit.” The JAs contend that “it would have been clearly inappropriate to focus solely upon the B3N circuit when assessing contributions to loop flows across the interface”117 because all four referenced circuits are operated together to control loop flow across the interface.118

113 Ex. NYI-46 at 23:16-19.

114 Column Four of Ex. NYI-66 contains the actual, measured, real-time loop flow that occurred in each interval. See Tr. 880:1-881:5; 882:15-17.

115 Contrary to the column heading, Column Six of Ex. NYI-66 sets forth MISO’s estimate of what the actual, measured, real-time loop flow would have been if the MI/ON PARs did not exist. See Tr. 881:18-25; 882:7-9. 116 Tr. 877:9-12.

117 BOE at 30.
118 Id. at 29.

As Staff witness Zugris119 and NYISO witness Zach Smith120 explained in their testimonies, 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.121 The Hydro One PARs located on the L4D, L51D, and J5D circuits 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.122 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.

The record shows why the JAs propose to include flows over the circuits that are controlled by

the Hydro One PARs in their cost allocation proposal; because doing so significantly reduces MISO’s

cost allocation. NYISO witness 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.”123 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 each ISO’s/RTO’s flow
contribution. Only the B3N circuit participated in the generation-to-load transfers, and the resulting
DFAX analysis focused on the four ISOs/RTOs flows over the B3N circuit—the circuit on which ITC’s
Replacement PARs are installed.124 The results of NYISO witness Smith’s correction of solely this error in the DFAX analysis are set forth below:

119 Ex. S-6 at 34:9-18.

120 Ex. NYI-38 at 7:4-6.
121 Tr. 430:25-431:3.
122 Ex. NYI-38 at 6:6-7.

123 Mr. Smith’s corrected analysis did not correct all of the DFAX Study flaws identified in his testimony, it only corrected the MISO’s use of participation on the entire MI/ON Interface to determine cost responsibility for the Replacement PARs.

124 Ex. NYI-38 at 7:12-15; 7:16-18.

RTO

Midwest
ISO

WeightedWeighted

Participation%

154.1127.66%

Weighted
Weighted %
Participation

190.5920.93%

Weighted
%

Difference

6.73%

IESO271.7448.78%504.4855.41%-6.62%

Analyzing flows over only the B3N circuit results in an almost 7% increase to MISO’s allocation. If the
costs IESO causes are reassigned pro rata to the other areas for cost allocation purposes as the JA
propose, MISO’s cost responsibility increases by 14% compared to the DFAX study and cost allocation
the JAs propose.

Only considering flows over the B3N circuit and Replacement PARs also avoids the bias that

would result from MISO’s netting of its participation over the four circuits that comprise the MI/ON

Interface in the DFAX analysis. The problems inherent in MISO’s proposal to net its flows are explained
by NYISO witness Smith125 and discussed in Section III.B.1.c.ii (pp. 39 to 41) of this Brief Opposing
Exceptions.

The ID correctly found that 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.

c.The ID Correctly Found that the DFAX Study Is Flawed In Multiple

Respects

The BOE objects to the ID’s finding (in P 731) that “the DFAX study was flawed because it is
‘merely a hypothetical snapshot of estimated flows in 2015’ and cannot be ‘relied upon to predict how

125 Ex. NYI-38 at 6:2-9 (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); Ex. NYI-38 at 6:14-16 (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); Ex. NYI-38 at 6:17-18.

system usage will change over time nor can it be relied upon to predict loop flows for the next 48

years.’”126 The JAs argue, instead, that reliance on the DFAX study is “reasonable and appropriate”127

because “[u]sing DFAX analyses based on reasonable forecasted data … is common in Commission

proceedings.”128 Citing orders relating to the allocation of Replacement PARs charges within NYISO and
PJM, the JA argue that the DFAX “is an approach which has specifically been endorsed by the
Commission as an appropriate method for determining contributions to loop flow.”129 The Commission
should reject these arguments, and uphold the ID’s detailed findings that the DFAX study JAs proposed
in this proceeding contains multiple, fatal, flaws and does not present an appropriate basis for cost
allocation.130

i.The ID appropriately found a myriad of flaws in the DFAX

study

The flaws in the DFAX study were well-documented in the evidence and briefing, and were

considered carefully in the ID. As summarized by the Presiding Judge: “NYISO witness Mr. Smith,

NYTOs witness Mr. Clarke, PJM witness Mr. Bresler, and Staff witness Ms. Zugris all found significant
flaws in the model and in the way the Study was conducted.”131 It is significant that the BOE addresses
only three issues out of the entire 12-paragraph litany of holdings explaining the flaws found in the
DFAX study.132 Ignored in the BOE, for example, are the holding in paragraph 827 that the JAs did not
use the DFAX methodology specified in the PJM/MISO JOA and the holdings of paragraph 835 that the
DFAX study:

•“should have covered a broader region;”133

•“should have identified which power flows actually cause harm;”134

126 BOE at 30.
127 Id.

128 Id.
129 Id.

130 ID at PP 826-837.

131 Ex. NYI-38 at 5-19; Ex. NYT-19 at 5-21; Ex. PJM-1 at 29-35; Ex. S-6 at 30-36. 132 ID at PP 826-837.

133 See Tr. 750:11-751:21.

134 Ex. PJM-1 at 26:1-35:19, Ex. PJM-2, Ex. PJM-4, Ex. PJM-13, Ex. PJM-14, and Ex. PJM-15.

•“should have considered benefits scheduled transactions will receive from the

[Replacement] PARs (such as offsets of the impact of flows from other regions);”135

•“should not have been used where impacts of facilities change frequently;”136

•“should not have netted MISO’s power flows from Michigan to Ontario on two circuits

that loop back to Michigan on two other circuits against each other;”137

•“should have used only the load duration curves for the regions to which the

[Replacement] PARs costs are proposed to be allocated;”138

•“should have included an amount of PJM generation and an amount of MISO

generation;”139 and

•“should not have dispatched generation within each RTO pro rata based on each

generator’s maximum output.”140

Setting aside the numerous flaws in the DFAX analysis that the JAs did not specifically address
in their BOE, the ID contains three findings of DFAX study flaws to which the JAs specifically excepted:

(i) that the DFAX study is based on power flow not only on the B3N circuit (where the Replacement

PARs are located), but also across the L51D and L4D circuits and the J5D on which the Hydro One PARs
are located;141 (ii) the use of three load blocks rather than all 8,760 hours in the year;142 and (iii) JAs’
failure to allocate any costs to IESO, even though it is the “largest flow contributor.”143 The NYISO
responds to each of these exceptions in Sections III.B.1.b (pp. 34 to 36), III.B.1.d (pp. 48 to 50), III.B.3
(pp. 59-64) and III.C.1 (p. 80), respectively, of this Brief Opposing Exceptions. The NYISO addresses
the JAs’ “generic” exception to the Presiding Judge’s rejection of the DFAX analysis in this section of its
Brief Opposing Exceptions.

135 Ex. NYT-19 at 4-21.

136 Ex. NYT-19 at 8:14-9:11. 137 Ex. NYI-38 at 6-7.

138 See Ex. NYI-38 at 9-12, Ex. NYI-39, Ex. NYI-40, and Ex. NYI-41. 139 Ex. NYI-38 at 19.

140 See Tr. 440:5-25.

141 ID at P 829, addressed in BOE at 29-30.

142 ID at P 833, addressed in BOE at 31-32.

143 ID at P 830, addressed indirectly in BOE at 47-49.

ii.The DFAX Study does not use “reasonable forecasted data”

The JAs’ argument that the DFAX Study is based on “reasonable forecasted data” is “common” in Commission proceedings144 must be rejected for several reasons. First, the JAs’ DFAX study does not use “forecasted data” but rather a static snapshot that, as discussed further below, has been found
unacceptable by the Commission.145 As NYTO witness Clarke explained, “even assuming that the
proposed cost allocation was sound for the year projected, nevertheless, the flawed methodology would not be able to accurately reflect system conditions for the remaining years, since the approach uses a forecasted snapshot of system conditions that are constantly changing.”146

The JAs’ reliance147 on Ozark Gas Transmission, L.L.C.,148 and Kinder Morgan Interstate Gas
Transmission LLC 149 to support their claim that it is proper to use a static one-year snapshot to develop
rates for the Replacement PARs is wholly inappropriate. Neither of these cases involved rate filings.
Both were orders relating to the Commission’s institution of an investigation under Section 5 of the
Natural Gas Act (parallel to an investigation under Section 206 of the Federal Power Act). As a first step
in understanding the existing pipeline rates and whether they remained just and reasonable, the
Commission required the submission of actual cost and revenue information for the latest 12-month
period available.150 The imposition of this data submission requirement - which would be followed by
litigation regarding what forecasting approach would be appropriate to set rates in the future - in no way
implies that a 12-month slice of data for a near-term year is sufficient to set just and reasonable rates for
facilities over a long future period.

144 BOE at 30.

145 The BOE characterizes the DFAX study as being based on “forecasted data” because its uses “forecasted data for
the year 2015.” The expected useful life of the Replacement PARs likely extends 45 years beyond 2015. The
DFAX study is based on only a single year of data. It is not a forecast that reasonably represents expected
conditions over the Replacement PARs useful life. The JAs refer to the “Midwest ISO RECB 1” order (Midwest
Independent Transmission System Operator, Inc., 114 FERC ¶61,106 (2006)) as support for a single-year approach,
but provide no explanation, or even a paragraph cite, explaining how that proceeding relates in any way to the
instant proceeding.

146 ID at 168 (Ex. NYT-19 at 8-9). 147 BOE at 31.

148 133 FERC ¶ 61,158 at P 3 and P 10 (2010) (“Ozark”).

149 133 FERC ¶ 61,157 at P 3 and P 10 (2010) (“Kinder Morgan”). 150 Ozark at P 10; Kinder Morgan at P 10.

Second, the DFAX study does not use “reasonable…data” because it proposes to selectively net
some power flows, but not others, when calculating each ISO’s/RTO’s contribution to Lake Erie loop
flows. The record in this proceeding shows that, in performing the DFAX analysis, MISO picked-and-
chose when to permit netting of flow contributions, and when not to permit netting of flow
contributions.151 One example is MISO’s decision to net flow participation over the four circuits that
comprise MI/ON Interface when determining contribution to Lake Erie loop flow152 (which reduces
MISO’s cost allocation) but MISO’s opposition to PJM’s proposal that “beneficial” loop flows be netted
against “harmful” loop flows (which would reduce PJM’s cost allocation and increase MISO’s cost
allocation).153

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.154 Unlike the NYISO, PJM and IESO power flows in the DFAX
analysis, a significant quantity of MISO’s power flows “loop” out of MISO (into Canada), then back into
MISO across the four circuits that comprise the MI/ON Interface.155 The 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 into Michigan (negative distribution factors) on the J5D and B3N
circuits.156

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 flow contributions in the DFAX study. By

151 Tr. 370:6-10; Tr. 419:8-420:24; and Ex. MSO-1B.

152 Ex. MSO-2 (MISO calculated one RTO’s contributions over the four individual circuits as a net value,

accounting for the direction of contribution over each circuit, however, MISO did not consider the overall direction of each RTO’s contribution to Lake Erie loop flow).

153 ID at PP 813-815.

154 Ex. NYI-38 at 6:14-16.
155 Ex. NYI-38 at 6:17-18.
156 Ex. NYI-38 at 6:19-21.

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. MISO’s decision to allow contributions to offset in some circumstances, but not others, provided evidence that MISO’s DFAX analysis was crafted to favor the JA’s interests.

MISO’s selective use of netting illustrates the flawed, biased nature of the DFAX analysis and supports its rejection.

iii. The use of the DFAX methodology is not “common” in

Commission proceedings, and the Commission recently found its use inappropriate

The JAs are incorrect in arguing that the use of DFAX analyses is “common” in Commission proceedings. The Joint Applicants cite to one example of the use of a DFAX methodology for cost allocation - the PJM/MISO JOA. The DFAX cost allocation method in the JOA was the product of negotiation between PJM and MISO. The NYISO has not identified, and the JAs have failed to cite, a single Commission order that directed a utility to use the DFAX method, or that determined the DFAX method was superior to other cost allocation methods.

As is explained correctly in paragraph 831 of the ID (and ignored in the BOE):

The [JAs’] reliance on PJM Interconnection, L.L.C. for the proposition that the

Commission has approved the DFAX methodology for determining contributions is

misplaced.157 The undersigned is in agreement with Staff’s reading of the case, which is
that the Commission merely stated that there are several methods for determining
contributions, one of which would be a DFAX methodology.158 Moreover, the
undersigned agrees that in New York Independent System Operator, Inc. the Commission
made the same general suggestion of possible methods.159 In neither case, as Staff
correctly points out, did the Commission approve MISO/ITC’s DFAX methodology; in
fact, the Commission stated that the static nature of the method makes it unjust and
unreasonable as the sole determinant of cost allocation.160 As discussed above, while the

157 Footnote omitted.

158 PJM Interconnection, L.L.C., 139 FERC ¶ 61,024, at P 17 (2012). 159 139 FERC ¶ 61,138, at P 16 (2012).

160 PJM Interconnection, L.L.C., 138 FERC ¶ 61,230, at P 37 (2012) (“The DFAX model is unable to identify the
causes of multiple constraints, fails to account for the fact that a high voltage upgrade will resolve multiple
constraints in multiple areas in addition to the constraint that is the focus of a DFAX analysis, and fails to account
for changes in usage and flow direction over time, particularly given the 40 year or longer life span for transmission
facilities.”).

Commission has approved the DFAX methodology in the JOA, the [JAs] failed to follow that process here.161

In the PJM order referenced by the Presiding Judge (the “PJM Remand Order”),162 the

Commission rejected a snapshot, static DFAX model, of the type offered in this proceeding, as

inappropriate for allocating costs of higher-voltage transmission facilities with a long useful life.163 The
Commission based this finding on the fact that a static DFAX model “fails to account for changes in
usage and flow direction over time, particularly given the 40 year or longer life span for transmission
facilities.”164 With respect to the failure to account for changes in usage and flow direction, the
Commission explained: “Changes occur over time to generator, load, and flow patterns, as well as other
structural changes, such as new transmission facilities and changes to, or retirement of, old transmission
facilities.”165 In this proceeding, ITC witness Grover stated the Replacement PARs will have a long-term useful life, in the neighborhood of 40 to 48 years.166 NYTO witness Clarke explained that the DFAX
analysis submitted in this proceeding inappropriately fails to take into account future usage and flow
changes over the Replacement PARs’ long useful life, and the Presiding Judge agreed.167 The JAs’ briefs recognizes that “Lake Erie loop flow can and does change direction frequently.”168 The application of the principles enunciated in the PJM Remand Order to the instant proceeding, confirms that the DFAX Study is an inappropriate basis for JAs’ proposed cost allocation.

The JAs’ reliance169 on the orders issued by the Commission170 in connection with the declaratory order requests filed by NYISO and PJM with respect to the pass-through to their customers of MISO

161 ID at P 831.

162 PJM Interconnection, L.L.C., 138 FERC ¶ 61,230 (2012).

163 The Commission found that “the difficulties of using flow-based analyses apply, to some extent, to lower voltage
facilities as well.” PJM Remand Order at P 41. The Replacement PARs are more like higher-voltage facilities,
given the broad impacts that Joint Applicants argue they will have on the four ISO/RTO Lake Erie region.
164 Id. at P 37.

165 Id. at P 38.
166 Tr. 94:5-9.

167 Exhibit NYT-19 at 8:160-10:191. See also ID at P 731. 168 BOE at 44-45.

169 BOE at 30.

170 New York Independent System Operator, Inc., 139 FERC ¶ 61,139 (2012); PJM Interconnection, L.L.C., 139 FERC ¶ 61,024 at P 17 (2012)).

charges under Schedule 36 is, as found by the Presiding Judge,171 similarly unavailing. The PJM order
indicates that DFAX is one among “a number of potential methods” for cost allocation and that cost
allocation proponents must demonstrate any selected method meets Section 205 standards.172 The
NYISO order goes on to dispel the notion that DFAX is the appropriate allocator of costs from a
Commission perspective by making explicit that “other options [besides DFAX and the other example
provided in that paragraph of the order] may be equally or more appropriate.”173 The fact that the JAs
used a DFAX method to develop their unjust and unreasonable,174 unduly preferential, unduly prejudicial
and unduly discriminatory175 cost allocation does not fix the numerous flaws that the Presiding Judge
identified in the proposed cost allocation. The JAs have not met their Section 205 burden. The Joint
Application should, accordingly, be rejected.

iv.The DFAX study is unreliable because it was prepared in a

result-oriented fashion

Evidence was submitted that the DFAX analysis is unreliable 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.

Exhibit NYT-22 shows, 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 External Transactions (imports and exports) at 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.”176

171 ID at P 831.

172 139 FERC ¶ 61,024 at P 17.

173 139 FERC ¶ 61,139 at P 16 (emphasis added). 174 See, e.g., ID at PP 618, 835.

175 See, e.g., ID at PP 671, 780, 861. 176 Ex. NYT-22 at 4.

During cross-examination, Mr. Chatterjee stated that scheduled External Transactions have

contributed, and continue to contribute, to the loop flow on the MI/ON Interface,177 and that entities

scheduling imports and exports over the MI/ON Interface would benefit from avoiding curtailment of

those transactions.178 The operation of the MI/ON PARs and the modeling of the MI/ON PARs in the

NERC IDC is expected to reduce the frequency with which TLRs disrupt External Transactions scheduled over the MI/ON Interface.179 However, the DFAX study does not account for Lake Erie loop flow that is caused by transactions,180 and parties scheduling transactions over the MI/ON Interface are not assigned any cost responsibility under the JA’s proposed cost allocation.

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.181 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.182
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.183
In the end, it appears that MISO and ITC chose the approach that produced the result they desired (less cost allocation to MISO and ITC). For this reason, the DFAX analysis MISO submitted in this
proceeding presents an unreliable basis for determining a just and reasonable cost allocation.

177 Tr. 317:23-318:1.

178 Tr. 317:15-22.

179 Ex. NYI-46 at 8:16-22.

180 Ex. MSO Tab D at 4:22-5:2; Ex. MSO Tab E at 17:11-13; Tr. 514:3-5. 181 Tr. 379:5-380:5.

182 Ex. PTO-12.
183 Ex. PTO-12.

v.It would be unjust and unreasonable to require NYISO and

PJM to file an FPA Section 206 complaint when the MISO
DFAX study no longer reasonably represents contributions
to loop flow

In their BOE JAs argue that if “circumstances regarding loop flow change substantially in the
future, and if NYISO or PJM believe that the MISO DFAX study is no longer reasonably representative of their respective contributions to loop flow, they will be free to seek changes in cost allocation … by filing a complaint with the Commission pursuant to Section 206 of the FPA.”184 In the BOE JAs
repeatedly state that the magnitude and direction of Lake Erie loop flow varies significantly from hour-to-
hour, from day-to-day and from year-to-year.185 In light of these expected changes, if the Commission were to overrule the Presiding Judge and require NYISO and PJM customers to pay for some portion of the cost of the MI/ON PARs, then MISO tariff must contain all the rules necessary to ensure that rates remain just and reasonable when predictable changes in circumstances occur, like a change in Lake Erie loop flow, or the outage of one or more of the PARs at the MI/ON Interface.

The NYISO’s customers are currently paying for a portion of the cost of the Replacement PARs
(subject to refund) under a FERC-accepted rate based on a single “hypothetical snapshot of estimated
flows in 2015.”186 The NYISO’s customers are receiving and paying for (subject to refund) a FERC-
jurisdictional service from the MISO.187 This is true even though MISO does not propose to identify the
NYISO or PJM customers that are paying for the Replacement PARs as MISO customers in its tariff.188
The evidence adduced in this proceeding shows that MISO intends to treat the NYISO and PJM

customers that are contributing to the cost of the Replacement PARs differently from MISO’s existing

customers. The Presiding Judge correctly concluded that since “MISO has a defined service obligation to

184 BOE at 31.

185 BOE at 44 (“[t]he record in this case is replete with evidence that Lake Erie loop flow can and does change
direction frequently”); See e.g. Ex. ITC-4 at 16 and 20; Ex. ITC-3 at 6-7; Ex. 5-6 at 19-20; Ex. NYI-66; and Tr.
1039:9-14.

186 ID at P 731.

187 The Joint Application Transmittal Letter (at 7) refers to the filing’s context as the allocation of the “costs of

jurisdictional transmission facilities.” If the New York customers that are paying for the Replacement PARs are not receiving a FERC-jurisdictional service from MISO, then the Commission lacks authority to accept the tariff
revisions proposed in the Joint Application.

188 See Ex. NYI-5. None of the MISO Tariff changes filed with the Joint Application identify the NYISO or PJM customers that are paying for a portion of the cost of the Replacement PARs as MISO customers.

its own customers, but not to NYISO or PJM customers, the proposed cost allocation is unduly discriminatory, preferential, and prejudicial.”189

The MISO Tariff identifies many different types of customers (such as Tariff Customers,190

Market Participants,191 Transmission Customers,192 Coordination Customers,193 Reliability Coordination
Customers194 and Congestion Management Customers195) that receive different services from MISO. The
services these customers receive are also described in the MISO Tariff.196 The MISO Tariff has over
3,500 pages of Commission-accepted tariff rules in place that describe the services that MISO provides to
its existing customers.197 MISO’s tariff sets forth the circumstances under which MISO may permissibly
bill its existing customers for providing a service,198 and the circumstances under which the MISO is
precluded from doing so.199 The tariff revisions proposed in this proceeding are not comparable to the
tariff provisions that govern MISO’s provision of service to its existing customers.200
The Joint Application fails to propose tariff rules to protect the NYISO and PJM customers from the unjust and unreasonable charges that will occur when the Lake Erie loop flow circumstances change (i.e. a change in magnitude and/or direction), or when other predictable changes in circumstances occur

189 ID at P 861.

190 See Module A to the MISO Tariff § 1.652. The MISO Tariff is available on the web at
https://www.midwestiso.org/_layouts/MISO/ECM/Download.aspx?ID=19218.
191 See Module A to the MISO Tariff § 1.384.

192 See Module A to the MISO Tariff § 1.666.
193 See Module A to the MISO Tariff § 1.98.
194 See Module A to the MISO Tariff § 1.559.
195 See Module A to the MISO Tariff § 1.83.

196 See, e.g., Module A to the MISO Tariff § 1.676 (Transmission Service is defined as “Point-To-Point

Transmission Service provided under Module B of this Tariff on a firm and non firm basis, including HVDC

Service, and the Network Integration Transmission Service under Module B of this Tariff.”); Preamble to Part II of Module F to the MISO Tariff (“The Transmission Provider shall provide, subject to the terms and conditions of this Part II of Module F, specific congestion management services, including redispatch of generation within the Energy and Operating Reserve Markets, for interconnected transmission providers.”).

197 See https://www.midwestiso.org/_layouts/MISO/ECM/Download.aspx?ID=19218 (MISO tariff);

https://www.midwestiso.org/Library/Agreements/Pages/Agreements.aspx (agreements designated under the MISO
tariff).

198 See, e.g., Section 2.2 of Schedule 23 of the MISO tariff, which addresses monthly billing by Transmission Provider for cost recovery of Schedule 10 and 17 charges applicable to services provided to customers under “Carved-Out GFAs.”

199 For example, Section 2.2 of MISO tariff Schedule 23 states that if the Carved-Out GFA Customer receives a bill directly from the MISO, MISO shall not bill the Transmission Owner for these costs, and cost recovery will not occur under Schedule 23.

200 ID at P 861; see also Ex. NYI-6.

(e.g., when one or more of the MI/ON PARs fail and the MI/ON PARs are not able to conform actual
power flows to scheduled power flows at the MI/ON Interface).201 Instead of developing the necessary
tariff rules, the JAs suggest that the NYISO or PJM, which are not directly subject to the charges and are
not MISO customers,202 should instead file a complaint under Section 206 of the FPA on behalf of their
respective customers, and demonstrate that the circumstances have changed and the cost allocation
proposed in the Joint Application is no longer just and reasonable.203 JAs suggest that only after NYISO
or PJM step in and demonstrate that the rates MISO is charging are unjust and unreasonable, should the
Commission modify the cost allocation.204 The JAs’ position on this issue would require the NYISO or
PJM to file a complaint under Section 206 of the FPA in order to prevent MISO from charging an unjust
and unreasonable rate to its customers for a Commission-jurisdictional service.205
JAs’ proposed tariff revisions addressing service to NYISO and PJM customers are not, in any way, comparable to the rules that MISO has in place addressing service to MISO’s existing customers.206 For example, the MISO Tariff provides a credit to MISO customers whose energy schedules associated with confirmed Point-To-Point Transmission Service are curtailed due to a TLR event.207 JAs’
suggestion that a FPA Section 206 complaint should be required to protect NYISO and PJM customers
from unjust and unreasonable charges that are assessed by the MISO turns on its head the concept that
ISOs and RTOs have a duty to administer their tariffs in a non-discriminatory manner for all customers.208

201 ID at P 734 (the Presiding Judge found that the Replacement PARs cannot mitigate loop flow without the Hydro One PARs also being in service); see also Ex. NYI-1 at 39:1-16; Ex. NYI-37.

202 NYISO is being compelled to act as an involuntary collection agent for MISO and ITC and to pass-through

monies it collects from its customers to MISO for disbursement to ITC. Schedule 36 of the MISO tariff provides that MISO bills the NYISO “on behalf of its customers.” See Ex. ITC Tab A at § II.

203 BOE at 31.

204 Id.

205 Id.

206 See ID at P 861.

207 See MISO Tariff Schedule 7 at § 10.

208 Order No. 888 states: “The primary purpose of an ISO is to ensure fair and non-discriminatory access to

transmission services and ancillary services for all users of the system.” See Promoting Wholesale Competition

Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by
Public Utilities and Transmitting Utilities, Order No. 888, FERC Statutes and Regulations, Regulations Preambles
January 1991-June 1996 ¶ 31,036, at p. 31,730 (1996), order on reh'g, Order No. 888-A, FERC Statutes and
Regulations, Regulations Preambles July 1996-December 2000 ¶ 31,048, order on reh'g, Order No. 888-B, 81
FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom.

Consistent with the findings in the Initial Decision, the Commission must require MISO to include rules in its Tariff that ensure the rates MISO charges its customers for Commission-jurisdictional service remain just and reasonable.

d. The ID Correctly Held that MISO Should Have Used a

Representation of Load for Each of 8,760 Hours in the Year to Perform the DFAX Analysis

The BOE states that the ID “seemingly accepted NYISO’s argument that the DFAX Study should have used all 8,760 hours in the test year, rather than using three representative load blocks.”209 The BOE does not dispute that it would be more accurate to use all 8,760 hours in the test year to depict each
ISO/RTO region’s electricity usage (load), as demonstrated in the testimony of NYISO witness Smith,210 and as admitted to by MISO witness Chatterjee.211 Instead, JAs assert that “correcting this so-called flaw [would] not have a significant impact on the [cost allocation] results,”212 and objects that the ID ignored JAs’ argument that the impact of the correction would be minimal.

The cost allocation impact of correcting the biases and errors that MISO incorporated into their
DFAX analysis is multiplicative, not additive. NYISO witness Zach Smith explained that using the
appropriate, region-specific load duration curve for each ISO/RTO in conjunction with performing the
DFAX study for each hour of the year, would significantly impact the calculation of the proposed cost
allocation.213 JAs admitted they did not perform any analysis to refute Mr. Smith’s testimony.214
JAs have admitted it is appropriate to correct MISO’s use of a blended load duration curve that averaged the load duration curves for the NYISO, MISO, PJM and IESO regions, which had the effect of increasing the cost allocation to NYISO and decreasing the cost allocation to MISO.215 JAs’ BOE
incorrectly contends that fixing the load duration curve error will achieve the same result as performing

Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

209 BOE at 31 (citing ID at P 833). 210 See Ex. NYI-38 at 15:21-16:2. 211 Tr. 399:15-400:5.

212 Id. at 32 (citing Ex. MSO-1 at 8). 213 Ex. NYI-38 at 12:23-13:6.
214 Tr. 405:1-7.

215 Ex. MSO-1 at 7:21-8:4.

the DFAX analysis for all 8,760 hours of the year.216 JAs’ contention is not correct. On cross-

examination, MISO witness Chatterjee agreed that (1) the use of a region-specific load duration curve for
each ISO/RTO and (2) whether it is appropriate to perform the DFAX analysis using just 3 representative
hours, or if it is instead appropriate to perform the analysis for all 8,760 hours of the year were two
distinct issues.217

Using each region’s correct load duration curve to perform the analysis only fixes half of the

problem.218 As MISO witness Chatterjee grudgingly admitted, performing the DFAX analysis for all

8,760 hours of the year will produce a “more accurate” (i.e., a different) cost allocation result than relying
on just 3 representative hours, as MISO’s DFAX did.219 The determination that the Presiding Judge made
in paragraph 833 of the ID is consistent with the evidence that was presented for his consideration, and
should be upheld.

The BOE attempts to mischaracterize NYISO witness Smith’s testimony by stating that Mr.

Smith’s “recommended solution to [the failure to use data for all 8,760 hours of the year] was that

NYISO’s own ‘load duration curve’ should have been used in the study”220 citing to page 15 of Exhibit
NYI-38, Mr. Smith’s testimony. The BOE also incorrectly suggests that the chart on page 13 of Mr.
Smith’s testimony (the figures in which the JAs characterize as “very close” to the DFAX Study results)
was prepared to show the impact of running the DFAX analysis on all 8,760 hours of the year. However,
Mr. Smith’s testimony does not state or suggest that the DFAX Study’s failure to use all 8,760 hours
could be solved by simply using NYISO’s own load duration curve in conjunction with the “three load
block” method MISO used to perform the DFAX. The chart on page 13 of Mr. Smith’s testimony does
not represent a re-running of the DFAX analysis using all 8,760 hours of the year for each ISO/RTO.
Instead, as is clear from the preceding discussion,221 the chart on page 13 simply corrects the three load

216 BOE at 32.

217 Tr. 399:17-400:5.

218 Ex. NYI-38 at 13:8-16:2.
219 Tr. 399:17-20; 400:6-10.
220 BOE at 32.

221 Ex. NYI-38 at 8:4 -13:4

blocks to reflect the NYISO’s (and the other regions’) individual load duration curves. It does not also

make the recommended correction to use all 8,760 hours of the year to perform the DFAX analysis. That the 8,760-hour corrected DFAX study was not performed by Mr. Smith or included in Mr. Smith’s
testimony is clear from the subsequent discussion in Mr. Smith’s testimony:

The MISO should have conducted the DFAX analysis for each region based on that

region’s load level for each hour of the year. That is, MISO should have conducted 8,760 DFAX runs for each region. This analysis could be completed in a reasonable amount of time by adjusting load levels to correspond to each hour for all regions.222

The NYISO and MISO witness Chatterjee agree that using all 8,760 hours of the year would

produce the most accurate cost allocation result.223 MISO should have performed its DFAX analysis in
the manner NYISO witness Smith recommended to produce a more accurate assessment of each region’s
expected contribution to flows across the MI/ON Interface.224 That is, the MISO should have conducted
8,760 DFAX runs for each region, one DFAX run for every hour of the year.225 Performing 8,760 DFAX
runs would have produced a more accurate weighted participation percentage for each region and would
not have required extraordinary effort by the JAs due to the sophisticated software packages available to
conduct these analyses.226 Mr. Chatterjee acknowledged that an 8,760-hour representation is used in

MISO’s forward-looking resource adequacy analysis incorporated in its MTEP planning process,227 for similar analyses in other regions of the eastern interconnection,228and for production cost analysis for MISO’s “top congested flowgate” study.229

For the foregoing reasons, the Commission should uphold the determination that the Presiding Judge made in paragraph 833 of the ID.

222 Ex. NYI-38 at 15:21-16:2 (emphasis added). 223 Tr. 399:15-400:5.

224 Ex. NYI-38 at 15:21-16:2.
225 Ex. NYI-38 at 15:21-16:2.
226 Ex. NYI-38 at 15:21-16:2.
227 Tr. 409:18-21.

228 Tr. 410:7-10.
229 Tr. 410:3-6.

2.The Joint Application Fails to Make the Required Proof of Benefits to

NYISO and PJM

On pages 32-37 of their BOE the JAs argue that the Presiding Judge (i) applied the wrong

standard of proof to determine whether the NYISO and PJM would derive sufficient benefits from ITC’s
Replacement PARs to justify the proposed cost allocation, and (ii) incorrectly determined that the JAs
failed to show that sufficient benefits will accrue to NYISO and PJM customers to justify the proposed
cost allocation.

JAs first argue that the Presiding Judge applied too stringent a standard of proof when

determining the benefits that the Replacement PARs are expected to provide to NYISO and PJM because he required the benefits to possess some minimum attributes in order to be recognized.230 In particular, JAs complain that in paragraph 736 of the ID, the Presiding Judge stated that “JAs have failed to submit evidence that shows specific objective and reproducible benefits.”

The requirement in ICC that benefits be “at least roughly commensurate” with the charges

imposed does not address or explain what types of benefits satisfy the standard of proof. The ICC

decision provided some limited guidance regarding the types of benefits that will satisfy the standard of proof. On page 476 of ICC, the 7th Circuit quoted with approval the Commission’s Transcontinental Gas Pipe Line Corp. (“Transcontinental”) order,231 in which the Commission found that a claim of
generalized gas pipeline system benefits was not enough to justify requiring existing shippers to subsidize an increase in electric pipeline operational costs caused by a new pipeline expansion project. The
Commission rejected the cost allocation proposed in Transcontinental because it found that the claimed benefits were unquantified, unsupported and/or speculative.232

In this proceeding it was the Presiding Judge’s responsibility as the trier of fact, to weigh the

evidence and determine if the benefits that JAs claim will accrue to NYISO and PJM are so generalized,

230 BOE at 32-33.

231 ICC, 576 F.2d at 476, citing 112 FERC ¶ 61,170, at pp. 61,924-61,925 (2005).
232 Id.

speculative, non-quantifiable, or poorly supported that they cannot be relied on to justify the proposed

cost allocation. The Presiding Judge made the necessary determinations in his ID.

The Judge explicitly addressed the 7th Circuit’s “roughly commensurate” standard in PP 396, 400, 624-628 of the ID. In P 626 of the ID the Presiding Judge found:

Some benefit to PJM and NYISO and their customers may arise from the operation of the [Replacement] PARs just because of the fact that MISO, NYISO, and PJM are part of an interconnected network. However, the question is: have the [JAs] demonstrated enough of a benefit to justify the costs that they want shifted to PJM and NYISO? The question must be answered in the negative.233

In paragraph 628 of the ID, the Judge explained that the MISO witness who prepared the MISO’s DFAX
cost allocation method admitted that he did not “make any measurement of benefits” or “prepare a cost
allocation that is roughly commensurate with the benefits that the various parties receive.” In paragraph
887 of the ID, the Presiding Judge determined that the Replacement PARs were planned to address
thermal overloads on ITC’s local transmission system, not to benefit neighboring regions, and found that
“MISO/ITC have failed to demonstrate, through use of credible probative evidence, that the
[Replacement] PARs will have identifiable and quantifiable multi-regional benefits.” The Presiding
Judge’s decision that benefits must be identifiable, quantifiable, and multi-regional in order to justify the
allocation of the cost of the Replacement PARs to NYISO and PJM is consistent with the guidance that
the 7th Circuit provided in ICC and the Commission’s Transcontinental decision that is quoted in ICC.
On pages 33 and 34 of their BOE, JAs next argue that various statements that NYISO made
supporting the prompt completion of ITC’s Replacement PARs and the coordinated operation of the
MI/ON PARs, before the Replacement PARs actually entered service, prove that the operation of the
MI/ON PARs will control Lake Erie loop flow and will provide benefits to New York. JAs make these
strained arguments because: (x) they have not performed, and did not submit, any studies that quantify the

233 The language the Presiding Judge used in P 626 of the ID closely parallels the following language in the 7th Circuit’s ICC decision:

No doubt there will be some benefit to the midwestern utilities just because the network is a

network, and there have been outages in the Midwest. But enough of a benefit to justify the costs that FERC wants shifted to those utilities? Nothing in the Commission’s opinions enables an answer to that question.

ICC, 576 F.3d at 477 (emphasis in original).

expected benefits to NYISO and its customers from the operation of the Replacement PARs; and (y) the data that the NYISO submitted in Exhibit NYI-66 proves that the MI/ON PARs have not controlled Lake Erie loop flow in the manner JAs claimed the MI/ON PARs would.

NYISO witness Robert Pike explained on page 22, lines 6-16, of his testimony (Exhibit NYI-46):

Possible benefits to New York would depend on how the MI/ON PARs are

(y) components of the New York State Transmission System that are

substantially affected by unscheduled Lake Erie power flows are constrained.

JAs have not questioned the accuracy of Mr. Pike’s statements, and the Presiding Judge endorsed
them in paragraph 743 of the ID. MISO witness Chatterjee admitted that MISO did not perform a study
of the “benefits” of the Replacement PARs to NYISO or PJM.234 ITC similarly admitted that ITC did not
create any documents relating to the economic or reliability benefits of the Replacement PARs.235 Both
MISO236 and ITC237 stated that they did not perform assessments or studies to identify specific reliability
criteria that are potentially violated by Lake Erie loop flow. In PP 625-628, 732-749 and 886-887 of the
ID, the Presiding Judge determined that JAs failed to produce credible evidence showing that the

operation of the MI/ON PARs will benefit NYISO or PJM customers.

The NYISO statements indicating support for the construction and operation of the Replacement
PARs that JAs cite on pages 33 and 34 of their BOE do not “prove” that the New York Control Area
(“NYCA”) will benefit from the operation of the Replacement PARs. The statements that JAs rely on
were all made before the MI/ON PARs entered service and were premised on untested MISO and ITC
claims regarding the loop flow control capabilities of the MI/ON PARs. For example, the draft “Broader

234 Tr. 409:8-17; ID at P 628.

235 Ex. NYT-44.

236 Ex. PTO-4 at 2.
237 Ex. PTO-5.

Regional Markets, Long-Term Solutions to Lake Erie Loop Flow White Paper”238 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.”239 Because all of these documents were produced before the Replacement PARs entered
service, it was not possible for NYISO to know how effective the collective operation MI/ON PARs
would be, or what impact the operation of those facilities would have on the NYCA.
Instead of submitting actual studies, or even a rough attempt to quantify the expected benefits to each of the Lake Erie control areas for cost allocation purposes, JAs offered the testimony from MISO witness Mallinger,240 and later, ITC witness Shavel,241 that identified areas in which generalized benefits, such as reductions in transmission congestion and system losses, might occur if the MI/ON PARs operate perfectly, to the limits of their purported control capability, at all times, without fail.242 The testimony of NYISO witness Wesley Yeomans,243 and the actual MI/ON PAR operating data and Lake Erie loop flow data contained in Ex. NYI-66, defeat the JAs vastly overstated expectations regarding the MI/ON PARs operating effectiveness. NYISO witness Pike’s testimony presented a more realistic explanation of the potential benefits and harms that MISO and IESO’s operation of the MI/ON PARs could have on the NYCA.244 The Mallinger and Shavel testimonies did not address, or attempt to discount their claimed benefits to reflect any of the trade-offs that occur between and among the ISOs and RTOs that surround Lake Erie. For example, a reduction in counterclockwise Lake Erie loop flow that might benefits MISO might, at the same time, harm the NYISO (assuming both transmission systems are experiencing
congestion on transmission facilities that are impacted by Lake Erie loop flow at the time).

238 Ex. ITC-26.

239 Id. at 9 (page 8 of White Paper) (emphasis added). 240 Ex. MSO-Tab E and MSO-3.

241 See, e.g., Ex. ITC-1 at 22:15-18. ITC witness Shavel’s estimate of the benefits the MI/ON PARs might have

provided had they been operational in 2010 and 2011, is unsupportable because Dr. Shavel assumed the MI/ON

PARs would perfectly conform actual power flows to scheduled power flows in every hour of every day; an

assumption that is not supported by the actual MI/ON PAR operating data and Lake Erie loop flow data in Ex. NYI-

66.

242 See BOE at 34-35.

243 Ex. NYI-1 at 9-13, 23-39.

244 Ex. NYI-46 at 21:18 - 23:19.

The Joint Application and 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.”245 However, the JAs did not submit any evidence supporting their bald claims that the MI/ON PARs will control 600 MW of Lake Erie loop flow nearly 100 percent of the time.246

The MI/ON PARs’ actual performance has not come close to meeting the JAs’ claim that the
MI/ON PARs would “fully mitigate” Lake Erie loop flow whenever it is less than 600 MW, and will
reduce Lake Erie loop flow by 600 MW at all other times.247 Actual MI/ON PAR operating data that
MISO provided in discovery, was admitted into the evidentiary record as Exhibit NYI-66. Exhibit NYI-

66 shows that the MI/ON PARs did not effectively conform actual power flows to scheduled power flows during their first 104 days of operation (from April 5 to July 18, 2012), and that the PARs were frequently a cause of additional Lake Erie loop flow during that time period.

Exhibit NYI-66 shows the average absolute value of Lake Erie loop flow for the entire 104-day
period was 214 MW, which is significantly more than zero MW of Lake Erie loop flow, and is also
outside than the +/-200 MW control band that MISO and IESO are expected to operate the MI/ON PARs
to achieve.248 The Exhibit NYI-66 data MISO provided indicates that the operation of the MI/ON PARs
increased the magnitude of Lake Erie loop flow in 10,158 five minute intervals, or in 33.7 percent of all
intervals over the April 5 to July 18, 2012 period.249 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 that MISO and IESO are expected to operate the MI/ON

245 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.”). 246 Compare Ex. MSO Tab E at 18:8-18 with MSO Tab E at 19:8-12.

247 Ex. MSO-Tab E at 19:1-20:21; Ex. ITC-1 at 15:19-24; Tr. 492:24-493:19.

248 Column Four of Ex. NYI-66 sets forth the actual Lake Erie loop flow that occurred in each interval. 214 MW is the average absolute value of Column Four of Exhibit NYI-66.

249 See page 38 of this Brief Opposing Exceptions; Tr. 877:9-12.

PARs to achieve.250 In 1337 intervals (4.4 percent of all intervals) the operation of the MI/ON PARs

caused Lake Erie loop flow that was expected to be inside the +/-200 MW Control Band to instead exceed the Control Band.251 Exhibit NYI-66 shows that the effective loop flow control that the JAs promised in the Joint Application and in their testimony did not, in fact, materialize.

The BOE next attempted to identify the potential range of benefits that the MI/ON PARs could
provide if and when the MI/ON PARs are effectively operated to better conform actual power flows to
scheduled power flows. On pages 35 and 36 of the BOE, JAs assert that a study performed for the
NYISO estimated that between October 2008 and November 2009 “loop flow had caused a total of
approximately $430 million in pricing inefficiencies in the four control areas around Lake Erie...” As
NYISO witness Robert Pike repeatedly explained to counsel for ITC at the hearing, JAs misinterpret the
study. Mr. Pike explained that the “$430 million is not a cost incurred”252 by the ISOs and RTOs around
Lake Erie. Rather, the $427 million is an estimate of the total gross value of the over-priced and under-
priced loop flow for the specific period from October 2008 through November 2009, without regard to
whether the loop flow was increasing or decreasing congestion costs or whether that loop flow was
circulating around Lake Erie, or not.253

The impact that Lake Erie loop flow has on congestion costs depends on the system topology of
each ISO or RTO, the direction of loop flow, and the locations where transmission congestion is being
experienced. One direction of loop flow, which the study identifies as “forward” loop flow,254 aggravates
constraints and increases transmission costs of a particular ISO or RTO. Loop flow in the other direction,
referred to as “reverse” loop flow in the study, relieves constraints and reduces congestion costs.255 The
total cost of congestion cited by the JAs represents the loop flow impacts on transmission constrained

250 In 18.6% of the data intervals in Ex. NYI-66, Column Six contains a value outside the +/-200 MW Control Band
and Column Four contains a value whose magnitude is larger than the magnitude of the Column Six value.
251 In 4.4% of the data intervals in Ex. NYI-66, Column Six estimates that the loop flow would have been within the
+/-200 MW Control Band, however, Column Four indicates that the actual measured loop flow was outside the
Control Band.

252 Tr. 1013:21-22.

253 Ex. ITC-23 at Attachment B slide 9; see also Tr. 1003:15-19 and Tr. 1013:14-22.

254 See Ex. NYI-46 at 22:13-16 and Tr. 1080:4-8 (the direction of “forward” loop flow is different for New York than it is for PJM).

255 Tr. 1010:8-11.

facilities in both directions for all four RTOs around Lake Erie, which is “not the equivalent of [$]427

[million] in loop flow costs because the forward and reverse loop flow[] [impacts] are offsetting in terms of congestion costs.”256

The JAs still do not appear to understand that the “price inefficiencies” referred to in the Patton
study include “inefficiencies” that reduce transmission congestion and associated congestion costs.257 Dr.
Patton’s study suggests that there may be times when NYISO, PJM, MISO and IESO can better
coordinate interregional transaction scheduling and dispatch to increase economic efficiency by taking
advantage of beneficial loop flows. Operating the MI/ON PARs on a strict flow-to-schedule basis could
actually prevent these potential benefits of interregional coordination from being realized.
The purpose of the study was not to estimate the impact of unscheduled power flows on
congestion costs, it was to determine the potential benefits that improved scheduling, and coordinated
congestion management could provide to the ISOs and RTOs around Lake Erie.258 The estimated cost of
congestion calculated in the study was an intermediate step in the process of determining potential
production cost savings that could be achieved by implementing an identified set of market
improvements. The study addresses “production cost savings because it is the most accurate measure of
the improvement in economic efficiency.”259 Production cost savings accrue through the joint and
coordinated actions of the ISOs and RTOs around Lake Erie to make the most efficient use of the regions’
collective transmission systems.

The estimated impact of Lake Erie loop flow on the cost of congestion can be positive or negative
and will change with every change in direction of loop flow.260 The direction of Lake Erie loop flow
changes frequently.261 The congestion costs and loop flows identified in the study are based on the
system conditions that existed during the late 2008 through late 2009 study period. During the study

256 Tr. 1013:13-18.

257 Tr. 1013:13-21.

258 Tr. 1010:22-25 (the study did not draw any conclusions directly from the estimated cost of congestion). 259 Ex. ITC-23 at Attachment B slide 2.

260 Tr. 1013:13-22.

261 See BOE at 44 -45.

period average Lake Erie loop flow was significantly clockwise.262 The study indicates that NYISO was subject to slightly higher forward loop flow costs than reverse loop flow cost reductions. For other ISOs and RTOs, the forward loop flow costs and reverse loop flow cost reductions identified in the 2008-2009 study almost exactly offset.

Because the direction and magnitude of loop flow can vary significantly from hour-to-hour, from day-to-day and from year-to-year, a one-year snapshot like the Patton study does not present a valid basis for reaching any conclusions about the expected long-term impact of loop flow on congestion costs.
Reviewing a snapshot of the impact of Lake Erie loop flow on the cost of congestion in 2012 would
produce significantly different results from the 2008-2009 study. In 2012 Lake Erie loop flow has
occurred in a predominantly counterclockwise direction.263 When Lake Erie loop flow is predominantly counterclockwise in direction, Lake Erie loop flow will tend to relieve transmission congestion in New
York and reduce congestion costs.264

The data in Column Four of Exhibit NYI-66 shows that, on average, Lake Erie loop flow was 48
MW in a counter-clockwise direction over the April 5, 2012 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 instead have been 85 MW in a counter-clockwise
direction. Exhibit NYI-66 indicates that, on average, the MI/ON PARs blocked 37 MW of counter-
clockwise loop flow. As explained above, counterclockwise Lake Erie loop flow tends to relieve
transmission congestion in New York. Over the April 5, 2012 to July 18, 2012 period the operation of the
MI/ON PARs may have increased the cost of transmission congestion in New York. MISO’s DFAX
analysis suggests (to the extent that analysis is found to have any credibility) that the ISOs and RTOs net

262 Ex. ITC-23.

263 Tr. 1039:13-14; see also Ex. NYI-66.

264 Tr. 1014:13-16; Ex. NYI-46 at 22:13-16. Congestion costs and LBMPs in New York were also generally lower in 2012 than they were in 2009 because natural gas prices were generally lower in 2012 than they were in 2009. See Tr. 1079:17-20.

generation-to-load contribution to Lake Erie loop flow will continue to be significantly counterclockwise in direction in 2015.265

For the foregoing reasons, JAs have failed to show that their proposal to allocate 29.1% of the

cost of the Replacement PARs to the NYISO’s customers is roughly commensurate with the benefits that
NYISO customers are expected to receive from the operation of those facilities. The ID correctly and
appropriately rejected the JAs’ claims that they satisfied ICC’s “roughly commensurate” standard.266

3. The ID Correctly Found That Ignoring PJM’s and NYISO’s PARs, Direct

Current Converters, Tariff and Market Loop Flow Mitigation Solutions, While Crediting IESO for Constructing PARs, Is Unduly Discriminatory and Preferential

On page 37 of their BOE, JAs allege, “[t]he ID appears to have found that the scheduling

restrictions put in place by NYISO in the exigent circumstances case, and the various market based

congestion management programs that have been developed by NYISO and PJM are sufficient to control
loop flows,” citing the ID at paragraph 779.267 The JAs’ exception misstates the finding of paragraph 779
and ignored the finding that the Presiding Judge made in paragraph 780 of the ID. In paragraph 779, the
Presiding Judge found that PJM and NYISO have effective “market based” loop flow mitigation solutions
in place. The Presiding Judge did not find (or suggest) that the NYISO and PJM market solutions that are
in place are, by themselves, “sufficient to control loop flows,” which is what the JAs claim the ID

found.268 Rather, the ID found that PJM and NYISO market solutions have “positive mitigating

effects”269 and help reduce and manage Lake Erie loop flow. In paragraph 748 of the ID the Presiding Judge made a similar determination that PARs, direct current converters, and other controllable
transmission facilities that NYISO and PJM have installed at the border between New York City and Northern New Jersey reduce Lake Erie loop flow and provide loop flow control benefits that are similar to the benefits that the MI/ON PARs may provide.

265 See Ex. MSO-1B.

266 See ID at PP 625-628, 732-749, 886-887. 267 BOE at 37.

268 BOE at 37.
269 ID at P 773.

Paragraph 780, which is premised on the finding in paragraphs 748 and 779, finds as follows:

Therefore, the undersigned finds that the [JAs’] proposal credits IESO’s
customers for transmission facilities Hydro One installed, but gives no
credit for NYISO’s or PJM’s transmission facilities and market
initiatives that also reduce Lake Erie loop flow. The undersigned
concludes that such an allocation is unduly preferential, prejudicial, and
discriminatory.270

The finding of paragraph 780 is fully supported with record evidence. For example:

•The JAs’ DFAX analysis indicates that IESO causes 55% of all Lake Erie loop flow.271

•The JAs made no attempt to weight the charges Hydro One incurred to construct its

PARs against the substantial portion of Lake Erie loop flow that the JAs allege IESO
causes, or against the costs that ITC incurred to construct the Replacement PARs.272

• The JAs’ refused to give the NYISO and PJM any credit for the PARs and direct current

transmission facilities at their common border that reduce Lake Erie loop flow. The

record demonstrated that these facilities provide substantial contributions to the control of loop flow.273

• As discussed in Section III.B.4 (pp. 64 to 70) of this brief, the Replacement PARs do not

provide unique benefits that no other PARs can provide.274

• The JAs refused to provide credit to NYISO and PJM for the market solutions they have

developed, including the Broader Regional Markets initiatives.275

Because the JAs grossly misunderstood or misconstrued the finding in P 779 of the ID, the
remainder of Section V.B.3 of the JAs’ BOE (pp. 37-39) is directed at a false target, and requires no
response.

270 ID at P 780.

271 See, e.g., ID at P 593 & n.1913 (citing NYISO Initial Br. at 70 (citing Ex. NYT-1 at 17:11-13 and Ex. MSO-
1B)).

272 See, e.g., ID at P 777 (“The argument by the JAs that IESO already paid its ‘fair share’ by installing three of the five PARs on the Michigan-Ontario interface fails without further analysis because the JAs have not even submitted evidence demonstrating the amount of those costs and their value today after depreciation.”); id. at P 675 (“When questioned about how he could say that IESO paid its fair share when he did not know what it had paid, [MISO witness Chatterjee] answered non-responsively.”).

273 As demonstrated in the study performed by NYISO witness Smith, the PARs at the 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. Ex. NYI-38 at 21:20-25:10. If the other PARs in the Eastern
Interconnection were removed from service, Lake Erie loop flow would be substantially higher than it is today. Id.
at 25:4-10.

274 See, e.g., Ex. NYI-1 at 40:10-18. 275 Ex. NYI-46 at 13:1-15:1.

The JAs also took exception to the findings in PP 776-778 of the ID that the JAs’ cost allocation proposal was unjust and unreasonable, and discriminatory to NYISO and PJM because it failed to allocate a portion of the costs for the Replacement PARs to IESO, despite the fact MISO’s DFAX analysis
indicates that IESO causes 55% of all Lake Erie loop flow.276 The Commission should reject the JAs’
exceptions. Re-assigning responsibility for costs that MISO’s analysis indicates are caused by IESO to
the NYISO and PJM is unjust, unreasonable, and unduly discriminatory, because it violates the
Commission’s cost causation principles.

The Presiding Judge’s findings in PP 776-778 were well supported in the record. JAs 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.277 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.”278 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.”279
MISO witness Chatterjee also asserts that “just and reasonable rates require that customers pay only those
costs that are attributable to them,”280 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.”281

The JAs’ proposed cost allocation method patently violates the principles that the JAs espouse.
MISO’s DFAX analysis indicates that the IESO region’s generation-to-load flows are the single largest

276 BOE at 47; Ex. MSO-1B.

277 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.

278 Joint Application Transmittal Letter at 5. 279 Ex. MSO-Tab D at 29:9-16.

280 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).

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

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.282 MISO witness Chatterjee recognized at hearing that IESO is “part of the cost causation….”283 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 require 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.

In Ameren Servs. Co. v. Midwest Indep. Transmission Sys. Operator, Inc. (“Ameren”),284 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.”285 The Commission affirmed on rehearing that failing to assess such costs to virtual bidders
meant the rate MISO assessed other customers was unduly discriminatory.286 JAs admit that IESO
contributes to the cost causation that allegedly created the need for the Replacement PARs. Rather than
allocate to IESO the costs it caused, JAs propose to allocate those costs to the NYISO and PJM. JA’s
proposal is the very type of discrimination the Commission prohibited in Ameren II.
The rationales offered by the JAs 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),

282 Ex. NYT-1, at 17:11-13; see Ex. MSO-1B, IESO_Gen, Total Participation.

283 Tr. 343:2-4.

284 121 FERC ¶ 61,205 (2007). 285 Id. at P 81.

286 Ameren Servs. Co. v. Midwest Indep. Transmission Sys. Operator, Inc., 125 FERC ¶ 61,161 at PP 39-44 (2008) (“Ameren II”).

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.
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.287
The agreements assigned cost responsibility for the L51D and L4D PARs to Ontario Hydro/Hydro
One.288 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 without seeking 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.289

With respect to the “crediting” argument, even assuming for purposes of argument that it has

merit, the JAs 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

287 See Ex. NYI-48 at 2 § 3.2 and NYI-49 at 12 § 10.3.

288 Id.

289 Tr. 343:5-7.

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.290

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 JAs 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, or for developing tariff and market solutions that achieve the
same purpose.

Accordingly, the Commission should uphold the findings in paragraphs 776 through 778, as well as those of paragraphs 748, 773, 779 and 780.

4. The Replacement PARs Do Not Provide Unique Benefits that No Other

PARs or Controllable Devices Located Elsewhere in the Eastern Interconnection Provide

In Section V.B.4 (pp. 39-40) of the BOE, the JAs attack as erroneous and “illogical and

inconsistent with the record” the ID’s findings that the Replacement PARs are not unique.291 The JAs
claim uniqueness based on the Replacement PARs’ “location, design of the power grid in that area, and
the function they will perform.”292 The JAs’ contentions are not consistent with the evidentiary record.
The Commission should uphold the ID’s findings relating to the lack of uniqueness of the Replacement
PARs.

JAs’ BOE ignores the substantial evidence in the record that the Replacement PARs do not

provide unique loop flow control benefits that no other PARs in the Eastern Interconnection provide. The Presiding Judge relied on record evidence in reaching his conclusions. In paragraph 748 of the ID, the Presiding Judge found that:

290 Tr. 345:24-346:8.

291 BOE at 39-40.
292 Id.

the [Replacement] PARs do not provide unique benefits that no other PARs can provide.
[fn. 2396293] Not only have the [JAs] not shown that the Michigan-Ontario PARs
provide unique benefits that justify the proposed cost allocation to NYISO and PJM, but
the undersigned finds that there is a direct current converter transmission facility
interconnecting PJM to NYISO that has even greater precision than PARs. [fn. 2397]

PARs and other controllable devices are frequently used to regulate 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 into New York City. The result is a controlled “wheel” of 1000 MW of power across PJM’s transmission system in northern New Jersey.294 Because 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.295

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 will carry a significant
portion of the net interchange (imports/exports) that are scheduled between NYISO and PJM.296 To
implement this agreement, NYISO and PJM transmission owners jointly constructed a pair of PARs on
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.297

293 Footnote 2396 cites to the testimony of NYISO witness Yeomans (at Ex. NYI-1 at 39:19-40:18), which refers (at fn. 11) in turn to the testimony of NYISO witness Smith in Exhibit NYI-38 (at 21:22-25:10) regarding the non-
uniqueness of the Replacement PARs.

294 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.
295 See Ex. NYI-1 at 40:15-18.

296 See Ex. S-5 at 16-17.

297 As part of their new Market-to-Market Coordination effort, NYISO and PJM are subject to a precisely calculated
set of financial obligations that apply when the Ramapo PARs are off-schedule and there is congestion on a
coordinated flowgate. The new rules provide financial incentives for NYISO and PJM to operate the Ramapo PARs

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.298 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 Linden VFT scheduled line, that links Linden, New Jersey to Staten Island, New York, uses a different control technology that 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 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 map set forth below
illustrates Mr. Smith’s statement that a series of controlled transmission lines form a “shield” between
Northern New Jersey and New York City.

to ensure that the Ramapo transmission lines carry their target schedule. See Commission Docket No. ER12-718 and Schedule D to Attachment CC to the NYISO OATT.

298 See Ex. S-5 at 8.

Controllable Devices on the New York - New Jersey Border

The map above shows 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, has 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 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 Lake Erie loop flow.299
MISO’s DFAX analysis assumes that all of the PARs in the Eastern Interconnection except the MI/ON PARs are in an “active” state300 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.301

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.

The results produced by the NYISO’s modified DFAX analysis are set forth in the table below.
The table provides (1) the weighted participation on the MI/ON Interface for each region from the
MISO’s original DFAX analysis (Exhibit MSO-1-a), which set all PARs EXCEPT the five MI/ON PARs
to be “active,” (2) the weighted participation on the MI/ON Interface for each region based on the
NYISO’s modified DFAX analysis with ALL PARs in the Eastern Interconnection set to be “inactive,”

299 See Ex. NYI-38 at 7:10-12 and n. 1.

300 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.).

301 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.”).

and (3) the impact (including both the change in participation factor and the % change) that deactivating the other PARs in the Eastern Interconnection has on expected loop flow at the MI/ON Interface.

WeightedChange inPercentage

WeightedParticipation onParticipation onChange in

Participationthe MI/ONthe MI/ONParticipation on

on the MI/ONInterface with AllInterface with Allthe MI/ON

RTOInterface asEasternEasternInterface with All

Presented inInterconnectionInterconnectionEastern

MISO’s DFAXPARs Modeled asPARs Modeled asInterconnection

AnalysisInactive as Re-Inactive (increasePARs Modeled as

Run by NYISO+ or decrease -)Inactive

MISO190.59307.20+116.61+61.2%

PJM96.82182.89+86.07+88.9%

NYISO118.64235.75+117.11+98.7%

IESO504.48490.43-14.05-2.8%

Total

The NYISO’s modified DFAX analysis shows significantly higher expected unscheduled Lake
Erie power flow contribution at the MI/ON Interface when all of the other PARs in the Eastern
Interconnection are deactivated. MISO’s loop flow participation at the MI/ON Interface increased by
more than sixty percent, and PJM and NYISO’s participation nearly doubled. Overall, unscheduled
power flows increase by approximately 33.6 percent.302 As NYISO witness 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 centers-New 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

302 Ex. NYI-38 at 23:16-17.

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.303 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.304 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.305 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.306

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 Mr. Smith’s determination
that some other PARs influencing Lake Erie loop flow when bypassed increase lake Erie circulation
flow.”307 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.308 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.

For the foregoing reasons, and based on the substantial evidence considered by the Presiding Judge, the Commission should uphold the ID’s findings relating to the (non)uniqueness of the
Replacement PARs.

303 See Ex. NYI-38 at 24:16-17.
304 See Ex. NYI-38 at 24:17-20.
305 Ex. NYI-1 at 40:16-18.
306 See Ex. NYI-38 at 25:5-10.
307 Ex. MSO-1 at 10:10-13.
308 Id. at 10:13-15.

5.The Original PAR and Replacement PARs Were Constructed to Address the

Transactional, Economic and Reliability Needs of Michigan and Ontario Utilities and their Electricity Customers

The BOE, at 41-42, seeks to divert attention from the clear evidence, and related findings of the
ID, that the Original PAR and Replacement PARs were constructed to address the transactional,
economic and reliability needs of Michigan and Ontario utilities and their electricity customers.
Specifically, the BOE states that the ID’s finding in paragraph 448 that “DEC decided to construct the
Original PAR to benefit itself and its customers and strictly for local concerns” is “false.”309 The BOE
premises this statement on an assertion that paragraph 661 of the ID regarding the 2001 Presidential
Permit for the Original PAR is “confusing.”310 The BOE then attempts to turn a claim made by Detroit
Edison in its application for a Presidential Permit for the Original PAR into an implication that the
Department of Energy ruled that the Original PAR was installed to meet interregional, rather than local
Michigan and Ontario, purposes. This is clearly incorrect, and a wide array of record evidence
demonstrates that the motivating force behind the installation of the Original PAR and the Replacement
PARs was the transactional, economic and reliability needs of the Ontario and Michigan utilities and their
customers.

The 2001 Presidential Permit (Ex. MSO-4) for the Original PAR, at page 2, recited the contents
of Detroit Edison’s application in the following language in the “Background” section of that document:

In its application, Detroit [Edison] claimed that the combined effect of these two

proposals would be to provide enhanced control over the inadvertent power flow between Michigan and Ontario and, by extension, around Lake Erie.

Nowhere in the “Discussion,” “Finding and Decision,” or “Order” sections of the Presidential

Permit is there a finding that the Original PAR is being installed to meet an interregional need. Nor does
what “Detroit claimed,” as recited in the “Background” section, actually state that the “enhanced control”
is being sought for anything other than Detroit Edison’s own purposes. Accordingly, the Commission

309 BOE at 41.

310 Id. Paragraph 661 states “The words ‘by extension, around Lake Erie’ are found in DEC’s filing, and are not from the DOE permit.”

should reject JA’s argument and instead rely, as the ID did, on the record evidence demonstrating that
local needs caused the installation of the Original PAR and the Replacement PARs.
Detroit Edison and ITC elected to construct, and pay for, the Original PAR and Replacement
PARs in order to better serve the transactional and economic needs of the utilities and their customers.
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.”311
ITC witness Capra’s testimony 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.”312 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.313

311 Ex. NYI-48 at 9. See also ID at P 445. 312 Ex. ITC Tab F at 4:21-5:3.

313 Ex. ITC Tab F at 6:12-6:16. See also ID at P 446.

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.314

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 fourtenths of one percent of the NYISO’s total real-time scheduled interchange sourced from, or sank in MISO.315 These are the only transactions that could possibly have been scheduled across the MI/ON Interface.316 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.317

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 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.”318 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

314 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.

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

316 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).
317 Ex. NYI-46 at 10:14-11:5.

318 Ex. NYI-56 at 1.

Michigan from the South. The circumstances under which New York might benefit from the operation of the Replacement PARs are more limited.319

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.

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 OH-MI 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.320

319 See Ex. NYI-46 at 21:18-23:19.

320 Ex. NYI-56 at 2-3.

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….321

…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…. 322

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 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.”323 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.324 The addition of 1000 MW of import

321 Ex. NYI-56 at 2.

322 Ex. NYI-56 at 3.
323 Ex. NYI-56 at 3.

324 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).

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-12781.325 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,

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 2002.326 [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

325 Ex. NYI-58. See also ID at P 450.

326 Ex. NYI-58 at 9.

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.”327

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 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”).328 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.329 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.

ITC installed the Replacement PARs to meet local reliability needs, as well. 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

327 Ex. NYT-38 at 2.

328 Ex. NYT-38 at 2.
329 Id.

B3N circuit would provide enhanced operator flexibility and control argue for the need to restore this circuit to operational status.330

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.331

In addition, the MTEP06 report in which the Replacement PARs project was approved by MISO includes a substantial list of reliability problems on the ITC system that would be met 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.332

330 Ex. PJM-15 at 4.

331 Ex. NYI-60 at 2 (emphasis added). 332 Ex. NYI-50 at 19.

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?

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.333 [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.334

The JAs offered no evidence establishing that the reliability issues reflected in these

contingencies were “caused” by Lake Erie loop flow, much less by NYISO-caused loop flow. 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.335 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.336 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.”337 In sum, nothing in the MTEP06 report attributes any of the need for the Replacement PARs to NYISO power flows.

333 Tr. 354:4-19 (corrected).

334 Tr. 355:8-11.

335 Ex. NYI-50 at 19. See also ID at P 724. 336 See Ex. PTO-4 at 2-3; PTO-5.
337 Ex. PTO-4 at 3.

For these reasons, the Commission should reject the JAs’ attempt to distract from their failure to establish that Lake Erie loop flow, whatever the source, was the “cause” of the investment in the
Replacement PARs. Instead, the evidence shows that MISO’s Board of Directors approved the
construction of the Replacement PARs to address the seven local contingencies on the ITC system that are identified in the MTEP06.

C.The Joint Application Has the Flaws Described in the ID

1.Requiring NYISO Customers to Pay for Costs that MISO’s DFAX Analysis

Indicates Are Caused by IESO Makes the Joint Application Unjust and Unreasonable

Contrary to the assertions on pages 47-49 of the BOE, the failure to propose allocation of a

portion of the Replacement PARs costs to IESO makes the Joint Application unjust and unreasonable. Section III.B.3 (pp. 59 to 64) of this Brief Opposing Exceptions responds to these assertions.

2. The Proposal to Exempt all MISO Transmission Owners and Customers

That Do Not Pay ITC’s Zonal Rate from any Responsibility for the Cost of the Replacement PARs, While at the Same Time Asking NYISO and PJM Customers to Pay for a Portion of Their Costs, Is Unjust, Unreasonable, and Unduly Discriminatory, and Preferential

At pages 50-51 of the BOE, the JAs except to the ID’s ruling in paragraph 678 that it would be
unjust, unreasonable, and unduly discriminatory and preferential to allocate a portion of the costs of the
Replacement PARs to NYISO and PJM because the Replacement PARs are not eligible for cost sharing
within MISO. The JAs offer three reasons for their exception. First, they argue that the manner in which
MISO’s share will be allocated within MISO is irrelevant, and the fact that the MISO Tariff requires
allocation of MISO’s share exclusively to the ITC zone within MISO should not control how total costs
of the Replacement PARs should be divided at the RTO level. Second, the JAs contend that “no one has
argued…that if PJM was correct regarding the effect of the JOA as between MISO and PJM, MISO
would thereby also be barred from allocating costs to NYISO.”338 Third, the JAs argue that “if it is true,
as the [ID] has found, that the absence of cost sharing within MISO creates undue discrimination and
preference, the [ID’s] solution - i.e., to expand the discrimination by exempting NYISO and PJM from

338 BOE at 50-51.

paying their fair shares of the PARs costs.”339 The Commission should uphold the ID’s ruling, as it is well supported by substantial facts and reasoning.

First, the Commission should reject the JAs’ argument that the manner in which the MISO Tariff
allocates the costs of the Replacement PARs within the MISO region is irrelevant to the proposal to
charge NYISO and PJM, as this argument is inconsistent with the principles espoused by the JAs in this
proceeding. Specifically, JAs 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.340 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.”341 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.”342 MISO witness Chatterjee also asserts that “just and reasonable rates require
that customers pay only those costs that are attributable to them,”343 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.”344
Contrary to the JAs’ 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

339 Id. at 51.

340 See Ex. MSO-Tab D at 29:13-20. MISO has indicated that NYISO and its customers are not MISO market participants. See Ex. NYI-5 and NYI-6.

341 Joint Application Transmittal Letter at 5. 342 Ex. MSO-Tab D at 29:9-16.

343 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).

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

flows.345 The JAs’ 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,346 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 service territory.347 The Joint Application Transmittal Letter
confirmed that the JAs do not propose to allocate the cost of the Replacement PARs to MISO customers
located outside the ITC pricing zone.348

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.349 MISO witness Mallinger admitted that the “rest of MISO benefit[s] from the replacement PARs.”350

There is no cost-causation basis for exempting non-ITC MISO customers from cost responsibility
for the Replacement PARs. The JAs argue that costs caused by the activities of one entity should not be
paid by another. However, the JAs fail to apply the cost allocation principles they espouse. Accordingly,
the finding in paragraph 678 of the ID - that the JAs’ 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

345 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.

346 Tr. 305:9-306:5.

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

348 Joint Application Transmittal Letter at 16.

349 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.

350 Tr. 561:3-5.

charging customers in the NYISO and PJM for a portion of the cost of the Replacement PARs, is unjust, unreasonable, unduly preferential, unduly discriminatory - is well-reasoned and supported and should be upheld by the Commission.

Second, the JAs are incorrect in stating that “no one has argued…that if PJM was correct

regarding the effect of the JOA as between MISO and PJM, MISO would thereby also be barred from allocating costs to NYISO.”351 The NYISO made exactly this argument and the Initial Decision
appropriately found the evidentiary and legal points raised by the NYISO to be meritorious.352
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 were made that the JOA barred charges to PJM, 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.353

• 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.354

•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

351 BOE at 50-51.

352 ID at PP 541-542.

353 Ex. NYI-49 at 10 (§ 6.1.1); and at 12 (§ 10.3). 354 BOE at 47-49.

MISO Transmission Owners, other than ITC, and their customers, will benefit from the Replacement PARs.355

• 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 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, in and of itself dictates rejection of the Joint Application.

Third, the JAs’ argument that “exempting NYISO and PJM from paying their fair shares of the
PARs costs” would be “expanding the discrimination”356 is verbal “smoke and mirrors” and ludicrous on
its face. The finding of the ID is that it is unduly discriminatory to seek to charge NYISO and PJM given
the exemption of non-ITC MISO customers, not that it is discriminatory to fail to charge non-ITC MISO
customers. There is thus no discrimination to “expand” upon. Nor is the ID “exempting NYISO and

355 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.

356 BOE at 51.

PJM” from a cost allocation that is otherwise proper. The ID found that the proposed cost allocation is unjust and unreasonable.

In 2007 ITC negotiated and entered into a facilities agreement with Hydro One under which ITC assumed the obligation to install the Replacement PARs at ITC expense.357 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. Accordingly, the risk that ITC would be unable to recover a portion of the cost of the Replacement PARs from customers outside its own MISO zone is a problem
that is properly assigned to ITC.

3.The MI/ON PAR Operating Instruction Is Unduly Discriminatory,

Preferential and Prejudicial

The JAs take exception to the ID’s finding that the Replacement PARs Operating Instruction
unduly discriminates against NYISO and PJM because, the JAs allege, the ID did not address the facts
and argument the JAs presented on this issue.358 The Commission should deny this exception and affirm
the ID’s finding.

The MISO-IESO Operating Instruction359 provides MISO and IESO broad discretion to suspend
normal operation of the MI/ON PARs to address reliability concerns, possible future reliability concerns,
or anomalous market results that occur in the MISO or IESO control areas. The same treatment is not
available for reliability concerns or market anomalies that occur in the NYISO or PJM control areas.360 It
would be unduly discriminatory, preferential and prejudicial to allocate the cost of the Replacement PARs
equally between and among NYISO, MISO, PJM and IESO based on each area’s alleged contribution to
Lake Erie loop flow, when the benefits that the MI/ON PARs are expected to provide are not limited to
controlling Lake Erie loop flow, and have not been shown to be equivalently apportioned.

357 Ex. NYI-49.

358 BOE at 51 (citing ID at P 681 & PP 682-692). 359 Ex. NYI-3 at 50-59.

360 Id.

The Operating Instruction is unduly discriminatory. Neither the NYISO nor PJM have the right to determine how MISO and IESO operate the MI/ON PARs.361 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.”362 The Operating Instruction also grants MISO and IESO discretion 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.363

In contrast, the Operating Instruction does not provide any ability to adjust the MI/ON PARs to
prevent an emergency in New York or PJM, nor does it permit the normal operation of the MI/ON PARs
to be suspended to address market anomalies that occur in NYISO’s or PJM’s markets. Section 3.5.2.1 of
the Operating Instruction provides that, for an emergency outside of MISO and Ontario, the MI/ON 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.364 Section 3.5.1 of the Operating Instruction does not impose the same
mitigation obligation before the MI/ON PARs may be operated to address MISO or IESO emergencies.
In addition, Section 3.5.2 of the Operating Instruction provides that, for emergencies that occur outside of
MISO or Ontario, “[t]he type of assistance shall be agreed upon and directed by MISO and the IESO.”365

The BOE tries to justify the lower levels of protection the Operating Instruction provides to the
NYISO and PJM on the basis that “these provisions merely reflect the fact that because of the
geographical proximity of the PARs to the MISO and IESO control areas, the PARs are likely to be more
useful in addressing emergencies and unforeseen market developments there than in more remote

361 ID at P 682 (finding that “the JAs’ proposed multi-regional operation of the PARs would ultimately be under the JAs’ and IESO’s sole control and discretion”); see also Ex. NYI-1 at 20:5-11; Ex. NYI-3 at 50.
362 ID at P 684; Ex. NYI-3 at 53.

363 ID at P 686; Ex. NYI-3 at 54.
364 ID at P 685; Ex. NYI-3 at 54.
365 ID at P 685; Ex. NYI-3 at 54.

locations.”366 Based on that admission, the JAs should have proposed a far lower cost allocation to the
NYISO and PJM because the JA have admitted that the benefits that the operation of the MI/ON PARs
are expected to provide are not equally available to all regions. Indeed, the proper cost allocation to
NYISO and PJM is zero, for the many reasons supported by the record and determined in the ID.

On page 52 of the BOE, the JAs argue that the ID’s finding “that NYISO and PJM will have no
say in PARs operating decisions and that MISO and IESO have ‘the intent to operate the [Replacement]
PARs to benefit the MISO and IESO systems only’” (ID at P 683) is incorrect.367 Evidence addressing
MISO’s and IESO’s actual operation of the MI/ON PARs belies this claim. MISO and IESO have not
been operating the PARs in accordance with the requirements of the PAR operating rules they submitted
to DOE. ITC’s Presidential Permit (Ex. ITC-14) requires JAs to operate the PARs to maintain the

Interface Deviation within a +/-200 MW Control Band “to the maximum extent practical.” However, the
PAR operating data in Exhibit NYI-66 shows that from April 5, 2012 to July 18, 2012 power flows at the
MI/ON Interface were within the +/-200 MW Control Band only 55.4% of the time. The PAR control
JAs achieved over the 104-day period from April 5, 2012 to July 18, 2012 does not compare favorably to
the Lake Erie loop flow that occurred before the MI/ON PARs were being operated to better conform
actual power flows to scheduled power flows. For the seven-month period commencing July 1, 2011 and
ending January 31, 2012 (before the Replacement PARs entered service, and before MISO and IESO
began operating the MI/ON PARs to better conform flow to schedule) MI/ON Interface flows were
estimated to be within +/-200 MW of MI/ON Interface schedules in 57.5% of hours.368 Actual operating
evidence shows the operation of the MI/ON PARs to better conform flow to schedule at the MI/ON
Interface “to the maximum extent practical” from April 5 to July 18, 2012 was not very effective.
On pages 52 and 53 of their BOE, the JAs attempt to defend the unduly discriminatory provisions of the Operating Instruction by asserting that the JAs received input from or had discussions with NYISO

366 BOE at 52 (citing Exhibit MSO-3 at 21, lines 10-26).

367 BOE at 52.

368 Ex. NYI-1 at 37:19-21; Ex. NYI-4.

in connection with the Presidential Permit proceeding for the Replacement PARs.369 As explained in P 895 of the ID, the factors reviewed by DOE in considering a Presidential Permit are limited to whether the facility will have adverse environmental or reliability impacts. DOE makes no determination as to whether an operating agreement for a DOE-jurisdictional facility is consistent with the applicant’s
proposal to assign a portion of the costs of those facilities to third parties. These are matters reserved to the Commission’s jurisdiction and authority. The positions that the NYISO took and the comments that the NYISO provided in the DOE Presidential Permit proceeding were appropriately and necessarily
limited to addressing matters within the DOE’s jurisdiction.

The ID correctly found “that the Operating Instruction provides the JAs with enormous discretion to suspend normal operation of the Michigan-Ontario PARs, but that the same treatment is not available
to NYISO or PJM,” and that “this results in undue discrimination against NYISO and PJM in favor of
MISO and IESO.”370 Undue discrimination also results from: (i) the Operating Instruction’s inclusion of terms permitting MISO/IESO to adjust PARs operations in order to prevent an emergency in MISO or
Ontario, given the absence in the Operating Instruction of a “reciprocal provision permitting NYISO or
PJM to do the same to prevent an emergency in their own regions,”371 and (ii) the inclusion in the
Operating Instruction of extra requirements imposed on NYISO and PJM in order for MISO/IESO to
operate the MI/ON PARs to assist with emergencies in NYISO and PJM, versus the requirements for
assisting with emergencies in MISO or Ontario.372

4. The ID Correctly Found that the JAs Propose to Assume No Service

Obligation to NYISO or PJM Customers Pursuant to the Filing

a. JAs’ Failure to Define Service Obligations to the NYISO and PJM

Customers in the MISO Tariff Makes the Proposed Charges Unjust and Unreasonable

The JAs propose to charge NYISO customers for the Replacement PARs based on a theory that
the operation of the MI/ON PARs will significantly reduce Lake Erie loop flow and provide benefits to

369 BOE at 52-53.

370 ID at P 687.
371 ID at P 684.

372 ID at PP 684-685.

the NYISO’s customers.373 However, the JAs do not propose to assume any obligation, whatsoever, to
actually reduce Lake Erie loop flow in their proposed tariff revisions.374 The Presiding Judge correctly
found that “the [JAs] assume no service obligation to NYISO or PJM or to their customers pursuant to the
filing”375 and concluded “that requiring NYISO or PJM to pay for a portion of the [Replacement] PARs
without a corresponding service obligation of MISO/ITC is unjust and unreasonable.”376 The JAs take
exception to these findings.377 In addition, the JAs note378 that the ID found it improper that NYISO and
PJM would be required to continue their payments even when the Replacement PARs are out of

service.379

The JAs’ proposed tariff revisions do not identify the service that JAs will provide in return for the millions of dollars NYISO’s customers are required to pay each year, and do not contain any
performance or service standards that JAs must satisfy.380 MISO’s proposed tariff revisions are not just and reasonable, and are unduly discriminatory and prejudicial,381 because they do not tie NYISO
customers’ obligation to pay to a reciprocal obligation in the MISO Tariff that (1) MISO and IESO actually operate the MI/ON PARs to reduce Lake Erie loop flow in the manner described in the Joint Application, and (2) the operation of the MI/ON PARs significantly reduces Lake Erie loop flow.
On page 13 of his testimony, NYISO witness Wesley Yeomans explained:

Despite the fact that the testimony of MISO witnesses Mallinger (at 19), Chatterjee (at
26, 31) and Zwergel (at 8) repeatedly state “[t]he MI/ON PARs “will fully mitigate Lake
Erie loop flow approximately 74% of the time and will mitigate it by approximately 600
MW the remainder” (Chatterjee at 26), in response to discovery requests, MISO and ITC
have indicated that they are not proposing to actually be held to meeting this operating
standard, or to meeting any operating standard, in order to collect the charges proposed in
this proceeding. MISO and ITC state that their proposed tariff revisions will require

customers in New York and PJM to pay for the Replacement PARs even when the

373 See, e.g., Ex. MSO Tab E at 19:8-12.

374 See BOE at 53; Ex. NYI-5; Ex. NYI-6; Ex. NYI-9. 375 ID at P 853.

376 ID at P 861.

377 BOE at 53-54.
378 BOE at 53.
379 See ID at P 860.
380 See ID at P 855.
381 ID at P 861.

Replacement PARs are not in service, or when one or more of the Hydro One PARs are

not available.382[Underlining added.]

Mr. Yeomans went on to recommend that if the Commission allows the collection of the charges
JAs propose, the JAs should be required to meet the performance expectations they create in their direct
testimony in order to collect the charges.383 Throughout their pleadings in this case the JAs claim the
MI/ON PARs will “fully mitigate” Lake Erie loop flow when it is less than 600 MW and reduce Lake
Erie loop flow by 600 MW at times when Lake Erie loop flow exceeds 600 MW.384 If the Commission
allows the collection of the charges JAs propose, the JAs must be required to satisfy the self-created

performance standard that they describe in their pleadings, i.e., to “fully mitigate” Lake Erie loop flow

when it is less than 600 MW and to reduce Lake Erie loop flow by 600 MW at times when Lake Erie loop flow exceeds 600 MW, in order to charge NYISO customers.

b.JAs are Incorrect that All Terms and Conditions of Service Do Not

Have to Be Included in its FERC Tariff

In their BOE, JAs argue that it is not necessary to include a service obligation in MISO’s tariffs
because ITC’s Presidential Permit specifies certain operating requirements for the MI/ON PARs.385
However, the JAs have asked the Commission to grant their requested cost allocation and to require the
NYISO to collect,386 and the NYISO’s customers to pay for, a portion of the cost of ITC’s Replacement
PARs.387 By requesting the Commission’s authorization to impose the charges, and Commission review
of the proposed cost allocation,388 the JAs admit they are providing Commission-jurisdictional service.389

382 Ex. NYI-1 at 13:19-28.

383 Ex. NYI-1 at 16:2-11.

384 Ex. MSO-Tab E at 19:1-20:21; Ex. ITC-1 at 15:19-24; Tr. 492:24-493:19. 385 BOE at 53.

386 NYISO is being compelled to act as an involuntary collection agent for MISO and ITC and to pass-through

monies it collects from its customers to MISO for disbursement to ITC. MISO’s proposed Schedule 36 provides

that MISO bills the NYISO “on behalf of its customers.” See Midwest Independent Transmission System Operator, Inc. and International Transmission Company d/b/a ITCTransmission, (“Joint Application”) Tab A at § II, Docket No. ER11-1844-001 (filed October 20, 2010).

387 See Joint Application’s transmittal letter (“Joint Application Transmittal Letter”) at 15-17. 388 Id.at 1.

389 Id. at 7 (noting that “costs of jurisdictional transmission facilities must be allocated in a manner that satisfies the cost causation principle”). If the New York customers that are paying for the Replacement PARs are not receiving a FERC-jurisdictional service from MISO, then the Commission lacks authority to accept the tariff revisions proposed in the Joint Application.

Commission-jurisdictional service must be adequately described in the MISO’s tariffs, including the
relevant terms and conditions of the service that is being provided. JAs’ filing failed to satisfy this
requirement.

Section 35.2(c)(1) of the Commission’s regulations specifies that a “tariff” must include in

writing a description of the “service” being provided.390 The proposed revisions to MISO’s tariffs do not identify the FERC jurisdictional service that MISO is “offering.”391 Compliance with the requirement to identify in MISO’s tariffs the electric service that MISO is offering is not optional. The Presiding Judge concluded that the JAs are proposing to assume no service obligation to NYISO or PJM or their
customers.392 The Presiding Judge correctly determined that ITC’s Presidential Permit does not create a service obligation of the JAs to NYISO or PJM or their customers and, even if it did, the service
obligation would also need to be clearly specified in the MISO tariff.393

In Cargill Power Markets, LLC v. Public Service Company of New Mexico, the Commission

found that Public Service Company of New Mexico’s Open Access Transmission Tariff (“OATT”) “does
not specify which services it actually offers” even though “the Commission does require the OATT to
state accurately which services are offered.”394 “The Commission’s regulations require that ‘[e]very
public utility shall file with the Commission . . . full and complete rate schedules . . . clearly and
specifically setting forth all rates and charges . . . [and the] practices, rules and regulations affecting such
rates and charges.’”395 The Presiding Judge agreed with the NYISO that the JAs failed to “specify which

390 18 C.F.R. § 35.2(c)(1) (2012) (“The term tariff as used herein shall mean a statement of (1) electric service … offered on a generally applicable basis, (2) rates and charges for or in connection with that service, and (3) all
classifications, practices, rules, or regulations which in any manner affect or relate to the aforementioned service, rates, and charges. This statement shall be in writing. Any oral agreement or understanding forming a part of such statement shall be reduced to writing and made a part thereof.” [emphasis added]).

391 In the hearing, ITC witness Grover admitted that he could see no description in the proposed tariff provisions of the service that NYISO would be receiving in return for the payments. Tr. 127:2-4.

392 ID at 853.

393 See ID at P 857.

394 132 FERC ¶ 61,079 at P 22 (2010).

395 Id. at P 23 n. 18 citing 18 C.F.R. § 35.1(a) (2010); City of Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985); Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261, at P 989 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

services [they] actually offer” as required by the Commission’s holding in Cargill Power Markets,

LLC.396 The ID also correctly held that “MISO and ITC do not think they have any service obligation” and that “the filing does not create a service obligation of the JAs to NYISO or PJM or their
customers.”397

The tariff revisions JAs propose in this proceeding do not identify, describe or explain the

jurisdictional service that MISO is providing.398 The proposed tariff revisions do not include any service standards, rules, or criteria that MISO must satisfy or meet in order to demonstrate that it is providing adequate service.399 For these reasons, the JAs proposed tariff revisions do not satisfy the requirements of the Commission’s regulations, are not just and reasonable, and were correctly rejected by the Presiding Judge.400 Contrary to JAs’ claims that the service standards could be addressed in service agreements with NYISO and PJM,401 a bilateral service agreement between NYISO and the JAs is not necessary
because all of the terms and conditions of service must be specified in MISO’s tariffs.

c. Response to JAs’ Argument that the Provisions of ITC’s DOE-

Jurisdictional Agreements and Presidential Permit Obviate the Need
To Submit Tariff Rules Governing the Service MISO Proposes to
Provide

On pages 53 and 54 of the BOE, the JAs argue that it is not important that MISO will have no

tariff obligation to serve the NYISO and PJM customers it is charging for ITC’s Replacement PARs, and
it is not important that the terms and conditions under which MISO is providing service to NYISO
customers are not specified in MISO’s tariffs, because ITC’s Presidential Permit addresses how ITC must
operate the MI/ON PARs. JAs allege that they are required to maintain the Interface Deviation (i.e., the
difference between actual and scheduled flow) within +/-200 MW to the maximum extent practical.402

396 ID at P 859, citing Cargill Power Mkts., LLC v. Public Serv. Co., 132 FERC ¶ 61,079 at P 22 (2010). 397 ID at P 855.

398 Tr. 124:21-23 (on cross-examination MISO witness Grover admitted that the service being provided is not

described in the tariff or otherwise specified but stated “I guess if I had to name the service, I would say it’s control of Lake Erie loop flows, flow equal to schedule”).

399 Tr. 126:24-127:4 (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).
400 ID at P 861.

401 BOE at 54.

402 BOE at 53-54.

The ID correctly held that the JAs’ arguments regarding MISO’s service obligation are fatally flawed. The Presiding Judge found that the “JAs are legally incorrect that the DOE Presidential Permit obviates the need to provide a service obligation in the Tariff.”403 The “DOE delegated authority over rates, terms, and conditions of service to the Commission for facilities that provide open access
transmissions service.”404 Since the Replacement PARs involve open access transmission service, the Commission has the authority to determine whether a proposal is just and reasonable and to require a service obligation to be incorporated into a tariff.405 In addition to the Presiding Judge’s specific findings and conclusions, there are several problems with the JAs’ contentions.

First, there has been evidence presented in this proceeding showing that, while MISO and ITC are interested in receiving payment from NYISO customers for a portion of the cost of the Replacement
PARs, MISO and ITC may not be committed to actually achieving the operating targets that they boldly proposed in the Joint Application and supporting sworn testimony. In Exhibit NYT-35, Mr. Moltane of ITC first states that he is “greatly concerned over the apparent volatility of the loop flow” shown in the August 2011 loop flow data. Mr. Moltane then goes on to state:

As you know ITC’s concurrence with 200 Mw 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.406

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 600 MW, and to reduce Lake Erie

403 ID at P 857.

404 ID at P 857.
405 ID at P 857.

406 Ex. NYT-35 (emphasis added).

loop flow by 600 MW at all other times.407 However, Exhibit NYT-35 indicates that ITC and MISO may
not be strongly committed to achieving this operating goal.408 If the JAs are not required to specify how
the MI/ON PARs will be operated in MISO’s FERC tariff, the Commission’s ability to protect customers
that are paying for a portion of the cost of the PARs will be limited to exercise of the Commission’s FPA
Section 206 authority (which does not permit refunds for periods prior to the filing of a complaint).409

Second, DOE’s decision granting ITC’s Presidential Permit (Ex. ITC-14) was issued on February
24, 2012, before the Replacement PARs entered service on April 5, 2012, so the JAs are subject to the
DOE requirement to operate the PARs to maintain the Interface Deviation within the+/-200 MW Control
Band “to the maximum extent practical.” However, the data in Exhibit NYI-66 shows that from April 5,
2012 to July 18, 2012 power flows at the MI/ON Interface were within the +/-200 MW Control Band only

55.4% of the time. The PAR control JAs achieved over the 104-day period from April 5, 2012 to July 18,
2012 does not compare favorably to periods in 2011 before the MI/ON PARs were being operated to
better conform actual power flows to scheduled power flows at the MI/ON Interface.410
Perhaps more important, the DOE Presidential Permit does not impose any consequence on
MISO or ITC when the MI/ON PARs are not effectively operated to maintain the Interface Deviation
within the +/-200 MW Control Band “to the maximum extent practical.”411 JAs do not propose any
consequence, such as excusing the NYISO customers that are paying for the Replacement PARs from
their payment obligation, for inefficient or ineffective operation of the MI/ON PARs in their filing. The
DOE standard excuses poor performance when one or more of the MI/ON PARs are out-of-service
because it is not possible to operate the MI/ON PARs to reduce a significant quantity of Lake Erie loop
flow under those conditions.

407 See, e.g., Ex. MSO Tab-E at 19:5-12. 408 See ID at P 888.

409 16 U.S.C. § 824e(b) (2006) (“In the case of a proceeding instituted on complaint, the refund effective date shall not be earlier than the date of the filing of such complaint.”)

410 Ex. NYI-1 at 37:19-21; Ex. NYI-4; Ex. NYI-66. 411 See Ex. ITC-14 at 3 and Article 3.

As the NYISO's testimony412 and Exhibit NYI-66413 show, when one or more of the four circuits
that comprise the MI/ON Interface are not PAR controlled, the ability of the remaining MI/ON PARs to
better conform actual power flows to scheduled power flows is minimal.414 MI/ON PAR outages
dramatically reduce MISO’s and IESO’s ability to operate the MI/ON PARs to conform actual power
flows to scheduled power flows at the MI/ON Interface. Under the JAs’ proposal, when one or more of
the four circuits at the MI/ON Interface is not PAR-controlled, NYISO customers will be paying JAs for
the costs of the Replacement PARs, but will not be getting a reduction in Lake Erie loop flow in return for
their payment.

Third, as NYISO witness Yeomans explained, the MI/ON PAR Operating Instruction that MISO
and IESO executed does not require MISO and IESO to operate the MI/ON PARs to conform actual
power flows to scheduled power flows at times when the MI/ON PARs are set to “Non-Regulated
Mode.”415

Because there are no proposed tariff rules specifying the JAs’ service obligation, and in light of the demonstrated grounds for uncertainty regarding the manner in which the MI/ON PARs will actually be operated, the Presiding Judge was more than justified in his finding that “should the Commission
conclude that NYISO and PJM must pay a portion of the costs of the ITC PARs, NYISO and PJM should not be required to pay during outages of those PARs.”416

412 Ex. NYI-1 at 33:13-34:23; Ex. NYI-33.

413 Ex. NYI-66 at 551-559.

414 See ID P 734.

415 Ex. NYI-1 at 16:18-19:23; Tr. 813:12-814:22; Tr. 815:23-818:10. 416 ID at P 888.

IV.CONCLUSION

For the reasons described herein, the Commission should uphold the ID in its entirety.
Respectfully submitted,

/s/ Alex M. Schnell

Alex M. Schnell
James H. Sweeney