UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

New York Independent System Operator, Inc. and)

PJM Interconnection, L.L.C.)Docket No. ER17-905-000

)

ANSWER OF

NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.
AND

PJM INTERCONNECTION, L.L.C.

Pursuant to Rule 213 of the Federal Energy Regulatory Commission’s

(“Commission”) Rules of Practice and Procedure,1 New York Independent System
Operator, Inc. (“NYISO”) and PJM Interconnection, L.L.C. (“PJM”) submit this answer
to protests and comments of three intervenors2 filed on February 21, 2017,3 relating to
NYISO and PJM’s joint filing in this docket of proposed revisions to the Joint Operating
Agreement between NYISO and PJM4 primarily addressing interchange scheduling and
Market-to-Market (“M2M”) coordination at the ABC and JK Interfaces upon the

118 C.F.R. § 385.213.

2Protests were submitted by:(a) Public Service Electric and Gas Company

(“PSE&G”); (b) the New Jersey Board of Public Utilities (“NJBPU”); and (c) the

NRG Companies (“NRG”).

3 Motion to Intervene, Comments and Protest of Public Service Electric and Gas

Company, Docket No. ER17-905-000 (Feb. 21, 2017) (“PSE&G Protest”); Protest of the New Jersey Board of Public Utilities, Docket No. ER17-905-000 (Feb. 21, 2017) (“NJBPU Protest”); Protest of the NRG Companies, Docket No. ER17-905-
000 (Feb. 21, 2017) (“NRG Protest”).

4 NYISO Open Access Transmission Tariff, Attachment CC - Joint Operating

Agreement Among and Between New York Independent System Operator Inc. and PJM Interconnection, L.L.C. (“JOA”).

termination of the unique arrangement referred to as the “1000 MW Wheel” or “Con Edison Wheel” on April 30, 2017.5

I.INTRODUCTION

In their protests, intervenors challenge several aspects of the Joint Filing, including the implementation of an Operational Base Flow (“OBF”) and interface pricing based on a single proxy bus. The NYISO and PJM submit this answer to address these challenges as well as other issues raised in the protests, to clarify the issues and assist the Commission in its decision-making process.6 As explained below, intervenors provide no basis for the Commission to take any other action but to accept without modification the JOA revisions submitted in the Joint Filing.

The NYISO and PJM also re-iterate their request that the proposed revised JOA
protocol revisions become effective on May 1, 2017, not subject to refund, and that,

Proposed Revisions to Joint Operating Agreement Addressing Interchange Scheduling and Market-to-Market Coordination on the ABC Interface and JK Interface After the 1000 MW Wheel Concludes of New York Independent System Operator, Inc. and PJM Interconnection, L.L.C., Docket No. ER17-905-000 (Jan. 31, 2017) (“Joint Filing”).

NYISO and PJM seek leave to submit this answer to assist the Commission’s
decision-making process and clarify the issues. The Commission regularly allows
answers for such purposes. See, e.g., Sw. Power Pool, Inc., 152 FERC ¶ 61,225,
at P 25 (2015) (“We will accept [the] answers because they have provided
information that assisted us in our decision-making process.”); Sw. Power Pool,
Inc., 144 FERC ¶ 61,059, at P 17 (2013) (“We accept the answers . . . because
they have provided information that assisted us in our decision-making process.”),
order on reh’g & compliance, 149 FERC ¶ 61,048, at P 20 (2014) (“We will
accept SPP’s answer filed in this proceeding because it has provided information
that assisted us in our decision-making process.”), order on reh’g & compliance,
151 FERC ¶ 61,045 (2015); S. Natural Gas Co., 121 FERC ¶ 61,118, at P 5 n.5
(2007) (accepting answer to protest because “it will not delay the proceeding, may
assist the Commission in understanding the issues raised, and will ensure a
complete record”); Morgan Stanley Capital Grp., Inc. v. N.Y. Indep. Sys.
Operator, Inc., 93 FERC ¶ 61,017, at 61,036 (2000) (accepting answer as “helpful
in the development of the record”).

should the Commission determine changes to the proposed protocols are necessary, that
those changes be effective prospectively. In the Joint Filing and reinforced in this
answer, the NYISO and PJM have justified the necessity for the proposed revised JOA
protocols, including the need for the 400 MW OBF. They also have explained the
ramifications if the revised protocols are not in place. Significant ramifications include:

(a) reduction of the quantity of power that can be directly exchanged between
Southeastern New York and Northern New Jersey areas; (b) undermining M2M

coordination between the NYISO and PJM because the use of the ABC Phase Angle
Regulators (“PARs”) and JK PARs would not be available to effectuate M2M Congestion
Management; (c) higher production costs for both the NYISO and PJM resulting from the
Regional Transmission Organizations (“RTOs”)7 being prohibited from using grid

equipment most efficiently to effectuate interchange and manage congestion; and

(d) increased risk to the reliability of the bulk power system because short-term reliability issues in Northern New Jersey would not be adequately addressed and historical interface transfer limits would not be maintained.

Not requiring refunds is appropriate because it is consistent with Commission precedent, as refunds would require the re-running of the markets and the interface pricing NYISO and PJM propose is just and reasonable. In short, there is ample justification for the Commission to allow the proposed JOA protocols to go into effect on May 1, 2017, without being made subject to refund, and to make any necessary changes to the protocols prospective.

In this answer both PJM and the NYISO are referred to as RTOs. Collectively, they are referred to as “the RTOs.”

II.ANSWER

A.The Use of the 400 MW OBF Is Just and Reasonable

In the Joint Filing, the NYISO and PJM proposed the use of an initial 400 MW OBF “to address the short-term reliability issues in Northern New Jersey . . . and to maintain historical interface transfer limits.”8 In support of its proposal, the NYISO and PJM fully explained the reliability issues that necessitated the OBF.9 Nevertheless, intervenors challenge the need and justification for the 400 MW OBF. As discussed below, these contentions lack merit.

1. The initial 400 MW OBF is well supported and justified

PSE&G contends that, based on the studies performed, NYISO and PJM have not
supported the need for the proposed 400 MW OBF, “especially in the years after 2018.”10
It challenges the NYISO and PJM studies alleging that “the initial 400 MW OBF were
based on extreme system conditions and extremely high levels of non-firm deliveries to

Joint Filing at 8.

See, e.g., Joint Filing, Attachment VII, Con Ed/PSEG Wheel Replacement Proposal A joint white paper from the New York Independent System Operator and PJM Interconnection, at 7 (Dec. 19, 2016).

NYISO and PJM initially studied several scenarios with different
distribution percentages. The scenario analysis identified reliability
issues in Northern New Jersey as well as delivery limitations when
exporting from PJM to the NYISO on the JK Interface and when
exporting from NYISO to PJM on the ABC Interface. The results
also showed a lack of operational flexibility under extreme system
conditions as phase angle limitations on the Waldwick PARs did
not allow for flows to be adjusted to meet scheduled targets when
high levels of exports into NYISO are assumed. NYISO power
flow results have also identified delivery limitations when
exporting to PJM on the ABC interface after securing for N-1-1 on
the NYISO system, and then attempting further deliveries.

PSE&G Protest at 6.

NYISO from PJM rather than actual historic flows.”11 This challenge fails. The
allegation that the NYISO and PJM studied extreme system conditions is a
misinterpretation of the RTOs’ explanation. NYISO and PJM studied peak conditions
using historic hours from 2016 summer operations, which is prudent. The goal of
studying the various scenarios was to preserve the transfer limit that could occur to
ensure that the new protocol was achievable without impacting reliability. The use of the
2500 MW net interchange value was appropriate and represented the historic transfer
limit that could occur. PSE&G’s assertion that “[i]n fact, 2500 MWs of net interchange
from PJM to NYSIO [sic] has never actually occurred” is simply wrong.12 As the chart13
in Attachment A shows, in the 2014 to 2016 time period, there were hours in which the
net interchange from PJM to NYISO not only reached 2500 MW but also exceeded it.
Thus, it was reasonable for the NYISO and PJM to study a 2500 MW interchange
scenario. Moreover, even assuming a 1500 MW net interchange from PJM to NYISO
(which is less than the 1600 MW that PSE&G alleges occurred in 2016),14 the studies still
revealed reliability issues on the PSE&G north transmission system, which justify the
need for the 400 MW OBF.15

PSE&G further contends the legitimacy of the 400 MW OBF is undermined
because “PJM already has the necessary tools at its disposal to address real-time

11Id.

12Id.

13The chart is attached to this filing as Attachment A.

14PSE&G Protest at 6.

15See Joint Filing, Attachment VII at 8-11.

reliability impacts on its system without the OBF.”16 This contention misses the mark.
For example, PSE&G identifies one of these tools as the implementation of “North
American Electric Reliability Corporation (“NERC”) TRL [sic] procedures.”17

Transmission Loading Relief (“TLR”) procedures are considered emergency procedures for PJM.18 NYISO uses TLR procedures when necessary to maintain reliability. It is not prudent to plan to operate the system using TLR as a normal operating procedure to address long-term reliability or seasonal impacts, or to rely on TLR procedures to remove economic transactions when other, more market-friendly, operating procedures are available (such as utilizing an OBF).19 TLR should be used to address conditions that are not anticipated. TLR procedures simply are not intended to be used in place of operating procedures, as PSE&G seems to suggest.

The TLR process occurs outside of the markets and is utilized to curtail
interchange transactions after scheduling and pricing have occurred. As a result, the
utilization of the TLR process can distort and suppress proper market signals. Price

PSE&G Protest at 7.

Id.

See Systems Operations Division, PJM Manual 13: Emergency Operations, PJM Interconnection, L.L.C., 99 (Feb. 23, 2017),

http://www.pjm.com/~/media/documents/manuals/m13.ashx.

See Regional Transmission Organizations, Order No. 2000, 1996-2000 FERC Stats. & Regs., Regs. Preambles ¶ 31,089, at 31,167 (1999) (“TLR and congestion management are both used to unload an overloaded transmission interface, and these two practices must work together. We consider congestion management and TLR are best used as sequential steps to unload a line, with congestion management used first to unload a line in a market-oriented manner, and TLR used to unload a line in a fair manner when either congestion management is unavailable or an emergency condition requires immediate action.”), order on reh’g, Order No. 2000-A, 1996-2000 FERC Stats. & Regs., Regs. Preambles ¶ 31,092 (2000), petitions for review dismissed sub nom. Pub. Util. Dist. No. 1 v. FERC, 272 F.3d 607 (D.C. Cir. 2001).

distortion occurs because as transactions are curtailed under the TLR procedure, net
interchange adjustments in the affected Balancing Authorities (“BAs”) are replaced by
BA-specific economic dispatch, rather than by coordinated congestion management.
Invoking TLR procedures would cause increased costs in NYISO and PJM, as transaction
schedules that were included in developing a least-cost dispatch are removed. If the TLR
process has been initiated, interregional interchange is not available to achieve a least-
cost dispatch until the TLR is concluded (so the inefficiency will continue as long as the
TLR is in place). The result is a less than optimal solution when using the TLR process as
opposed to developing and implementing coordinated congestion management solutions.
Simply put, TLR procedures should not be the planned normal operating procedures to
address anticipated reliability impacts, when more market-friendly operating procedures,
such as the 400 MW OBF or M2M PAR Coordination using the ABC, JK, and Ramapo
PARs, are available.

In addition to protecting reliability, the 400 MW OBF allows PJM and NYISO to maintain economic transfer capability that is similar to the transfer capability and limits that are in place today. Eliminating the 400 MW OBF would present reliability concerns that would force the NYISO and PJM to significantly reduce the economic transfer capability between their Control Areas.

PSE&G additionally alleges that because the NYISO and PJM “concede that the
OBF will not be needed after the Bergen-Linden project is completed there is no possible
justification for extending the OBF beyond 2018 when that project is expected to be in-
service.”20 PSE&G wrongfully assumes that the NYISO and PJM “plan upfront to

continue the 400 MW OBF for the next five years.”21 This mischaracterizes the
NYISO’s and PJM’s intent. The proposed JOA revisions make this clear as they state
that “[t]he initial 400 MW OBF, effective on May 1, 2017, is expected to be reduced to
zero MW by June 1, 2021” (which is less than five years).22 The June 1, 2021 date
merely represents an outside estimate as to how long the NYISO and PJM anticipate that
the initial 400 MW OBF might be necessary to address short-term reliability. As PSE&G
concedes, NYISO and PJM “have committed to annually review the OBF MW value to
determine if modification is appropriate.”23 In fact, because forward looking studies
indicate that the 400 MW OBF may be able to be eliminated after the Bergen-Linden
project is completed, which PJM expects to be in 2018,24 PJM’s intent would be to notify
NYISO pursuant to the two-year notification provision in the proposed JOA that the 400
MW OBF should be zero once the impact of the project is confirmed based on updated
modeling.

The NYISO and PJM conservatively requested authority to continue the initial
400 MW OBF to the latest date that they expect a transmission solution might be in place
and to gain operational experience in order to confirm that the transmission solution will
“obviate the reliability need for the OBF in the long-term.”25 Thus, PSE&G overreaches

Id.at 8.

Joint Filing, Attachment I, JOA proposed Schedule D § 7.2.1.

PSE&G Protest at 8; see also Joint Filing, Attachment I, JOA proposed Schedule D § 7.2.1 (“The NYISO and PJM shall review the OBF MW value at least annually.”).

PJM’s expectation that the Bergen-Linden project will be in place by June 1, 2018, is dependent on the project remaining on schedule. Any delays may impact the completion date.

Joint Filing at 9.
8

in assuming that the NYISO and PJM “plan” to keep the 400 MW OBF for five years, even if the OBF is no longer necessary.

PSE&G argues that the 400 MW OBF “has not been justified as a daily
requirement”26 and that PJM and NYISO should limit the use of 400 MW OBF only to
“times of system stress when very large non-firm net interchange from PJM to NYISO is
scheduled.”27 This argument should be rejected. In order to develop a reliable Day-
Ahead Operating Plan, including the appropriate unit commitments, it is critical to have
an accurate representation of real-time system conditions. From a market perspective, it
is beneficial to have a static OBF value that does not fluctuate on a daily basis. Without a
static value, the NYISO or PJM might, at times, apply an OBF value that is too low,
which could result in unnecessary and inefficient operations that require out-of-merit
dispatch and transaction curtailments in real-time. If the 400 MW OBF were

implemented only when expected system conditions require it, as PSE&G suggests, the
resulting lack of market certainty with regard to when the OBF would apply (shifting
from not using the OBF to using the OBF) would produce inefficient market outcomes in
NYISO’s and PJM’s Day-Ahead Markets (“DAMs”) as well as NYISO’s Transmission
Congestion Contracts (“TCC”) Market and PJM’s Firm Transmission Rights (“FTRs”).

To illustrate the RTOs’ concern, PJM FTRs awarded in the annual FTR Auction
are effective for the entire planning period (June 1 thru May 31). If FTRs are cleared in
this annual process using a model that incorporates a static 400 MW OBF but the actual
OBF MW value changes daily, or more frequently than annually, then the PJM FTR

holders are exposed to potential FTR Revenue Inadequacy. FTR Revenue Inadequacy results from more FTRs being awarded than what the Day-ahead model can support with collected congestion. If the awarded FTRs cannot be funded by collected day-ahead congestion revenues then the FTRs cannot be fully funded.

There are many circumstances in which using a static OBF provides valuable market certainty. If market participants do not know whether the OBF will be in effect for a market day it will result in a risk premium being included by market participants in their day-ahead offers, leading to higher total production costs. If the OBF is introduced only in real-time, on a difficult-to-predict basis, it would cause divergence between DayAhead and Real-Time Market outcomes, leading to higher uplift costs. Day-ahead and real-time schedules, system conditions, and prices should be aligned whenever possible, which requires a static OBF value.

2.The initial 400 MW OBF is not a “mini-wheel” for which

NYISO customers should pay

NJBPU contends that the 400 MW OBF is “essentially a miniature version of the
current Con Edison Wheel (a ‘mini-wheel’)” for which “[Consolidated Edison Company
of New York (“Con Edison”)] will continue to benefit . . . while the loads in PJM,
particularly New Jersey ratepayers, will pay the costs for the [Regional Transmission
Expansion Plan (“RTEP”)] projects enabling that flow.”28 The NJBPU mischaracterizes
the OBF. The 400 MW OBF and the Con Edison Wheel are not the same. Unlike the
Con Edison Wheel, which resulted from a request for firm transmission service over the
PJM system, the 400 MW OBF stems from an operational need and was developed by
NYISO and PJM. The NYISO did not request transmission service from PJM and the

400 MW OBF is not a firm transmission service on either the NYISO transmission system or the PJM transmission system.29

As previously explained, the purpose of the proposed initial 400 MW OBF is to
address short-term reliability issues in Northern New Jersey and to maintain historical
interface transfer limits in light of the termination of the Con Edison Wheel. Specifically,
the 400 MW OBF addresses the reliability need by providing operational flexibility and
by allowing the RTOs to utilize higher transfer limits on the JK Interface and ABC
Interface and to maintain reliability in Northern New Jersey. It also improves transfer
capability and alleviates thermal violations in Northern New Jersey that could arise when
distributing interchange across each interface.30 The NYISO and PJM worked together to
achieve the greatest interregional efficiency while addressing the identified short-term
reliability issues in Northern New Jersey.

The 400 megawatts that PJM receives over the JK Interface must be returned to
the NYISO over the ABC Interface because there are no other viable delivery options that
keep the megawatts in Southeastern New York and Northern New Jersey. The 5018 line
is primarily used to deliver economic interchange, and may not have enough transfer
capability to accommodate the OBF. Returning the MWs to the New York Control Area
(“NYCA”) over the uncontrolled transmission ties between Pennsylvania and Western
New York is impractical for a number of reasons. PJM and NYISO agree that returning
the MWs in Western New York would be unfair to New York because it would

(a) increase the frequency of Southeast New York (“SENY”) reserve shortages, (b) create

a capacity imbalance in NYISO’s SENY Capacity Zone, (c) exacerbate costly West-to-
East transmission congestion in the NYCA, and (d) require the RTOs to wastefully
consume taps on the ABC PARs to block the flow of power back into New York over the
A, B, and C lines. The efficient solution that the RTOs developed is designed to ensure
that NYISO’s customers will not be harmed by temporarily agreeing to deliver 400 MW
to PJM at the JK Interface. To achieve the same goal of maximizing efficiency while
promoting reliability, the NYISO and PJM agreed that power will ordinarily be returned
to the NYISO over the A, B, and C lines in a manner that is least likely to exacerbate
transmission congestion in New York City (the proposed 25%/37.5%/37.5%

allocation).31

PSE&G’s allegation that PSE&G and its customers receive no discernable
benefits from the 400 MW OBF lacks merit.32 The 400 MW OBF will reduce

transmission congestion in Northern New Jersey (i.e. the PSE&G zone), which will
benefit PSE&G and its New Jersey customers. At higher target flows on the JK AC
interchange from PJM to the NYISO, analysis showed actual and post-contingency
violations on the PSE&G North Transmission system. The 400 MW OBF reduces
transmission congestion in Northern New Jersey by lowering the JK target flow when
total AC interchange is flowing from PJM to NYISO. The increased transfer limit that is

See PSE&G Protest at 10.

Id. at 9 (“If Con Edison does not pay anything for the 400 MW ‘mini-wheel,’ this
will create a situation where PSE&G and its customers, who do not realize
discernable benefits associated with the 400 MW OBF, will bear the full
transmission investment and operating costs incurred to produce this benefit.”).

made possible by implementing the 400 MW OBF will benefit all PJM and NYISO customers, including PJM customers located in New Jersey.33

Similarly, PSE&G’s inference that Con Edison should bear a portion of the
investment costs associated with the Bergen-Linden project if a 400 MW OBF is

implemented once the 1000 MW Wheel Agreements are terminated is unfounded.34 One
of the concerns that PSE&G expresses is that Con Edison was allocated a large share of
the investment costs associated with the Bergen-Linden project prior to the termination of
the 1000 MW Wheel, and therefore if a 400 MW OBF is implemented in operations,
even for a short time period, Con Edison should pay for a portion of the project.35 The
flaw in this reasoning is that prior to the termination of the 1000 MW Wheel the Bergen-
Linden project costs were only allocated to Con Edison because they had firm
transmission service and accepted cost responsibility in accordance with the 2009

Settlement Agreement, which terminates such cost responsibility upon termination of the
1000 MW Wheel.36 Notably, the OBF is not a firm transmission service on either the
NYISO transmission system or on the PJM transmission system. Therefore, there is no
basis to allocate the Bergen-Linden project investment costs to Con Edison for the 400
MW OBF. Furthermore, PSE&G states “one of the driving elements behind the $1.2

See infra note 50.

PSE&G Protest at 9-10.

Id.

Settlement and Offer of Settlement of PJM Interconnection, L.L.C., New York
Independent System Operator, Inc., Consolidated Edison Company of New York,
Public Service Electric and Gas Company, PSEG Energy Resources & Trade
LLC, and the New Jersey Board of Public Utilities, Docket Nos. ER08-858-000,
ER08-867-000, EL02-23-000, at Art. 5 (Feb. 23, 2009) (“2009 Settlement
Agreement”).

billion Bergen-to-Linden project on the PSE&G system are short circuit issues associated with the A, B, and C lines. Yet, after April 30, 2017, Con Edison will still realize significant benefits for its customers in connection with the 400 MW OBF without being responsible for paying a dime towards that project.”37 PSEG incorrectly implies that Con Edison customers will realize significant short circuit benefits that arise solely from the utilization of the 400 MW OBF.38 First, the short circuit issues resolved by the BergenLinden project corrected deficiencies on the PSE&G system, not on the Con Edison system. Second, PJM technical studies show that there will be only minor changes in the short circuit levels on the Con Edison system with and without the 400 MW OBF. Therefore the PSE&G inference that the 400 MW OBF will confer significant short circuit benefits to Con Edison customers is invalid.

NJBPU’s further assertions that Con Edison seemingly “has managed to negotiate
an arrangement where it continues to benefit from this mini-wheel without paying the
RTEP costs that it litigated, and lost, at FERC” and that Con Edison’s agreement to
accept RTEP costs “was a key component of the 2009 Settlement Agreement,” and that
“it is unlikely that either PSE&G or [NJBPU] would have [accepted the 2009 Settlement
Agreement and] continuation of the [1000 MW] Wheel” otherwise39 likewise are

inapposite. First, the 400 MW OBF did not result from negotiations with Con Edison,
but rather was identified by the NYISO and PJM as an efficient method of addressing a
PJM reliability need that is fair to both regions. The RTOs developed the 400 MW OBF

PSE&G Protest at 9-10 (footnote omitted).

Id. at 9. Notably, the drivers for the Bergen-Linden project are unrelated to the 1000 MW Wheel.

NJBPU Protest at 5.

as an operating solution to reliability issues in Northern New Jersey identified in studies
conducted to evaluate system conditions upon termination of the Con Edison Wheel.
Second, the very 2009 Settlement Agreement to which the NJBPU refers, and to which
PSE&G and NJBPU both are a party, by its own terms, relieves Con Edison of any
further responsibility for “the RTEP costs that [Con Edison] litigated, and lost, at

FERC”40 once the 1000 MW Wheel ends.41 The proposed JOA protocols filed herein do
not reduce, or otherwise affect, Con Edison’s RTEP obligations related to the 1000 MW
Wheel.

3.NYISO and PJM properly account for the 400 MW OBF in

their planning models

PSE&G and NRG question why the NYISO’s planning models will generally
incorporate the initial 400 MW OBF.42 In general, the NYISO will include the 400 MW
OBF in planning models for transmission security studies representing the period from
May 1, 2017 to May 31, 2021 in an effort to align the models with the expected operation
of the bulk power system. These planning models are designed to represent the bulk
power system in the same manner as the NYISO DAM. Since the DAM is expected to
model the 400 MW OBF from May 1, 2017 to May 31, 2021, NYISO’s transmission
security planning models will also include the 400 MW OBF for the same period of time.

The NYISO’s long-term planning studies, such as the Reliability Needs
Assessment, evaluate a planning horizon of at least five years. Therefore, the NYISO’s
long-term planning studies will include at least one year without the 400 MW OBF. The

Id.

2009 Settlement Agreement at Art. 5.
PSE&G Protest at 4; NRG Protest at 2.

400 MW OBF will not be included in planning models for the 2021 summer peak and the time periods thereafter. The NYISO and PJM do not expect to utilize an OBF after May 31, 2021. If the NYISO and PJM agree to modify or terminate the 400 MW OBF value before May 31, 2021, the NYISO’s DAM model and planning models will incorporate the revised OBF for the period of time that OBF is expected to be utilized. As stated in the Joint Filing, NYISO will review all relevant study inputs with stakeholders and may include or exclude the OBF in accordance with NYISO procedures.

PSE&G and NRG also highlight an inconsistency between NYISO and PJM
planning assumptions with regard to the treatment of the 400 MW OBF. While NYISO
will include the 400 MW OBF in their transmission security studies representing the
period from May 1, 2017 to May 31, 2021, PJM will not be including the 400 MW OBF
in their assessments for this time period. The 400 MW OBF is an operational procedure
that will be in effect over a limited duration. It is not considered firm transmission
service. Short-term, non-firm operational considerations are generally not considered in
the PJM planning process. Furthermore, up until this year, PJM has included the full
1000 MW Wheel in its planning studies which covers a fifteen year period into the future.
All reliability issues associated with this 1000 MW service have been resolved on the
PJM system by planned upgrades. Because the PJM system has already been designed to
accommodate such a level of service, PJM planners assessed that any reliability issues
identified in planning under a 400 MW OBF will likely be less severe than those
identified under a 0 MW OBF. Because of this, PJM planning assessments going

forward will not include the 400 MW OBF.

In summary, NYISO and PJM have uniquely different planning processes and electrical system characteristics. Coupled with the short-term nature of the 400 MW OBF, PJM and NYISO chose to pursue different planning approaches to phasing out the 1000 MW Wheel.

4. Use of the 400 MW OBF facilitates the flow of energy between

NYISO and PJM and will not suppress prices in New York

Contrary to NRG’s suggestion, that NYISO intends to “incorporat[e] unpriced
power” into its markets,43 the 400 MW OBF will “facilitat[e] the efficient economic flow
of energy between the regions” after the 1000 MW Wheel terminates. 44 As explained
previously, it is both fair and efficient for PJM to return the 400 MW that PJM receives
over the JK Interface to New York at the ABC Interface. The NYISO will develop Day-
Ahead Locational Based Marginal Prices (“LBMPs”) that are consistent with how OBF
power is expected to flow and real-time LBMPs that are consistent with how power
actually flows. In addition, facilitating economic interchange is not price suppression for
the receiver of that interchange. Rather, it is the most economically rational outcome
associated with maximizing the value of the transmission system for which loads are
paying.

B. The Inclusion of the 400 MW OBF when Scheduling Interchange and

Determining Target Flows on the A, B, C, and J and K Lines Is Not a Barrier to Entry and Does Not Violate Order No. 888

NRG claims that the inclusion of the 400 MW OBF when scheduling interchange
and determining target flow at the ABC and JK Interfaces “prevent[s] other entities from

NRG Protest at 6. Id. at 5.

Id. at 5.

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, 1991-1996 FERC Stats. & Regs., Regs. Preambles ¶ 31,036 (1996), order on reh’g, Order No. 888-A, 1996-
2000 FERC Stats. & Regs., Regs. Preambles ¶ 31,048, order on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), reh’g denied, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in part & remanded in part sub nom. 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).

See Joint Filing, Attachment VII at 8-10. Without the 400 MW OBF applied to the JK and ABC targets, the studies show congestion in PSE&G North particularly when trying to meet the target flows on the JK (specifically for net AC interchange to NY). As an example, when AC interchange is 2500 MW to NY, the JK target flow (without the 400 MW OBF) is 375 MW. The studies showed that not only was it impossible to meet JK target flows (PARs were tapped out-no taps available), there was heavy congestion on the PSE&G North 230 & 138 kV transmission systems. Applying the 400 MW OBF to the JK target flow reduces the target making it achievable under all operating conditions (plenty of PAR tap move available) without any congestion on the PSE&G North 230 & 138 kV systems. In short, the 400 MW OBF supports higher AC interchange levels with the OBF. Without the 400 MW OBF interchange into NYISO is limited to approximately 900 to 1,100 MW, which yields a lower JK target with moderate congestion in PSE&G North. Furthermore, the PSE&G North transmission system has been upgraded with respect to the wheel for over thirty years and is able to effectively support the 1000 MW Wheel. Under the 1000 MW Wheel protocol, flows on the JK are always into PJM. The proposed JOA protocol (without 400 MW OBF) will result in flow into NYISO on the JK. The power flow studies showed congestion at higher AC interchange levels. Simply put, the system was not designed for this transfer so studies reveal congestion when delivering MW to New York on the JK.

NRG contends, the 400 MW OBF does just the opposite, it enables greater use of ties than might otherwise be possible.48

Furthermore, the 400 MW OBF is designed to position power flows within the
middle range of PAR control capability. Therefore, the 400 MW OBF helps to optimize
the system under most conditions by ensuring maximum PAR control capability remains
available for system use by all parties. Consequently, the use of the initial 400 MW OBF
is the best alternative to preserve the reliability of the two RTO systems and provide the
optimal level of economic interchange, until system conditions render it no longer
necessary.

C.NRG’s Suggestion that There Should be Separate Pricing for the ABC

and JK Interfaces Is Unworkable

NRG further suggests that the NYISO and PJM “provide a separate and unique
price for the bus located on the ABC and JK Interfaces.”49 This suggestion is simply
unworkable. To establish effective market signals, the actual flows need to align with
interchange schedules. The current PARs equipment “does not allow schedules to be
effectively aligned with actual [power] flows on an individual [bus] basis,” so

implementing separate pricing potentially would present financial gaming
opportunities.50 The gaming potential arises from the ability to schedule energy at a
given point and obtain a given price associated with that point when the actual energy
does not flow across the path associated with that point. Since the PARs cannot control

Joint Filing, Attachment VII at 10. NRG Protest at 9.

Joint Filing, Attachment VII at 5. See also Scott Harvey, Proxy Buses, Seams and Markets, LECG, LLC, (May 23, 2003),

https://www.hks.harvard.edu/hepg/Papers/Harvey_Proxy.Buses.Seams.Markets_5

-23-03.pdf.

flow precisely, if PJM and NYISO priced energy schedules at the points associated with
the PAR-controlled facilities, to the extent that energy actually flowed inconsistent with
those schedules (which we know it would) then participants would be able to take
advantage of those differences and schedule in a manner that inappropriately takes
advantages of those differences. The modeling of one proxy bus instead of three separate
proxy buses avoids this concern. The fact that the current ABC and JK PARs cannot
adequately effectuate individual interchange schedules at each interface to enable
separate pricing is not just an “excuse” as NRG wants the Commission to believe,51 it
was confirmed by PJM and its stakeholders in their PAR taskforce.52

D.The Proposed JOA Protocols Do Not Intrude on Transmission

Owners’ Rights

1.The Joint Filing does not restrict a Transmission Owner’s

right to retire their facilities

PSE&G again challenges the JOA protocols by contending that the proposed JOA
protocol requirement that facilities comprising the ABC and JK interface facilities “shall
be functional and operational at all times” violates the rights and responsibilities retained
by Transmission Owners (“TOs”) under the PJM Consolidated Transmission Owners
Agreement (“TOA”).53 Specifically, PSE&G argues that by requiring facilities to be
functional at all times, except when offline for maintenance or outages, the proposed JOA
protocols inhibit the TOs’ right to decide to retire their facilities.54 This interpretation

NRG Protest at 9.

Phase Angle Regulator Task Force, Final Proposal Report, PJM Interconnection,
L.L.C., 1-2 (Aug. 31, 2015), http://www.pjm.com/~/media/committees-
groups/task-forces/partf/20150818/20150818-draft-final-proposal-report.ashx.

PSE&G Protest at 10-11. Id. at 11-12.

overreaches and ignores important relevant language in section 7.2 of the JOA. Section

7.2 reads in relevant part:

In order to implement the NY-NJ PAR coordination process, including the
establishment and continuation of the initial and any future OBF as
defined in this Section and Section 35.2 of this Agreement, on the ABC
PARs and the Waldwick PARs, the facilities comprising the ABC
Interface and JK Interface shall be functional and operational at all times,
consistent with Good Utility Practice, except when they are taken out-of-
service to perform maintenance or are subject to a forced outage.55

When read in its entirety, the intent of this provision is clear. For the JOA NY-NJ
PAR coordination process to occur, the facilities comprising the ABC and JK Interfaces
must be functional and operational at all times. This means that, while the facilities are in
place, the RTOs are able to use the facilities on a full time basis to manage the real-time
NY-NJ PAR coordination,56 but if the facilities are no longer available for full-time use,
(e.g. they were retired), then such coordination no longer would be possible. Nothing in
the proposed provision prevents a TO from retiring its facilities. PSE&G further
mischaracterizes the level of discretion a TO has under the TOA to decide to retire their
facilities. PSE&G contends “TOs are only obligated to provide PJM with ‘reasonable
advance notice’ before permanently taking a transmission facility out of service.”57
However, Article 5 of the TOA limits TOs’ rights, requiring that they must “be exercised
in a manner consistent with a Party’s obligations under the Federal Power Act [(“FPA”)]
and the FERC’s rules and regulations thereunder.”58 This includes operating in

Joint Filing, Attachment I § 7.2 (emphasis added).

PJM’s use of such facilities is consistent with the TOA. See TOA § 6.3.1 and discussion infra Section II.D.2.

PSE&G Protest at 11. TOA § 5.

accordance with NERC standards, therefore a TO could not retire a facility if doing so would result in a reliability violation.59 Similarly, Section 3.2 of the TOA requires a TO to take steps necessary to ensure reliability and continuity of transmission services before withdrawing from the TOA.60 Thus, a TO’s rights to retire its facilities under the TOA are not as unrestricted, as PSE&G claims.

Moreover, PSE&G acknowledges that PJM made clear during the stakeholder process that the proposed JOA revisions “are not intended to supersede or modify any rights or responsibilities to the Transmission Owners under the Consolidated Transmission Owner’s Agreement.”61 In short, PSE&G’s rights and obligations regarding the retirement of facilities under the TOA are not affected by, much less violated by, the revisions to JOA section 7.2 proposed herein.

2. The Joint Filing’s reference to Good Utility Practice does not

violate the Transmission Owner’s rights to make operational
or repair decisions regarding the facilities, and is not confusing

PSE&G’s similar contention that the Joint Filing’s requirement that the ABC and
JK facilities be operated “consistent with Good Utility Practice” is confusing and intrudes
on the TOs’ rights is equally unavailing and should be disregarded. PSE&G alleges that
it is unclear “how the Good Utility Practice standard will be applied to NYISO and PJM
given that the facilities are owned by PSE&G and Con Edison.”62 It also claims that
RTOs might analyze Good Utility Practice differently from a TO, given their different

Id. § 4.5.
Id. § 3.2.

PSE&G Protest at 12 n.35. Id. at 12.

roles.63 Therefore, PSE&G asserts the requirement that the ABC and JK facilities be
operated in accordance with the RTOs’ assessment of Good Utility Practice is confusing
and intrudes on the TOs’ right to make decisions regarding the repair or operation of their
facilities.64 Contrary to these assertions, there is no intrusion of rights or confusion. As
discussed above, PJM made clear that nothing in the proposed JOA revisions is intended
to supersede or modify any rights or responsibilities to the TOs under the TOA.
Moreover, the TOA already obligates TOs (including PSE&G) to operate and maintain
their facilities consistent in accordance with “Good Utility Practice.”65 It also grants PJM
the authority to:

Direct the operation and coordinate the maintenance of the
Transmission Facilities of the [Transmission Owners] in

accordance with: (i) the Operating Agreement; (ii) the PJM Tariff;
(iii) Good Utility Practice; and (iv) NERC and Applicable

Regional Reliability Council operation and planning standards, principles and guidelines.66

In the context of PJM, JOA section 7.2 is consistent with and merely reiterates the TOs’ and PJM’s current obligations with regard to operating and maintaining the facilities in PJM comprising the ABC and JK Interfaces. PSE&G simply has failed to present any colorable argument that the proposed JOA protocol requirement that the facilities be operated full-time, and in accordance with Good Utility Practice, violates the TOA, intrudes on TOs’ rights, or is confusing, and so must be rejected.

Id. at 12.
Id. at 12.
TOA § 4.5.

Id. § 6.3.1 (emphasis added).

E.PJM’s Capacity Emergency Transmission Objective/Capacity

Emergency Transmission Limit Process to Determine Values Is Transparent

PSE&G raises unfounded concerns that PJM’s Capacity Emergency Transmission
Objective/Capacity Emergency Transmission Limit (“CETO/CETL”) process lacks

transparency.67 As PSE&G noted in its protest, PJM releases the parameters for
upcoming Base Residual Auctions for capacity and supporting studies for the
CETO/CETL values on its website.68 Furthermore, the CETO/CETL calculations are
developed using the “Load Deliverability” procedures outlined in PJM Manual 14B,
which is also on the PJM website.69 As set forth in the manuals, the implicit assumption
with the Load Deliverability Test is that the area under study is experiencing a capacity
emergency with higher than normal peak loads (i.e. 90/10 loads) and higher than normal
forced outage rates. The study procedures also assume other areas are experiencing
normal peak loads. With regard to 1000 MW Wheel, the load deliverability procedures
historically recognized the existence of the wheel and provided, pursuant to the
NYISO/PJM JOA for only 600 MW of the wheel to be redelivered to NYISO during the
load deliverability test. More specifically, for those load deliverability areas that are
electrically tied Con Edison, 1000 MW would be delivered to PJM at Waldwick only 600
MW would be delivered to NYISO at the Hudson and Linden interfaces (across ABC) for
a net of 400 MW of imports. However, while the JOA planning procedure described how

PSE&G Protest at 14.

Id. at 13 & n.36. PJM makes available the power flow cases used to calculate the CETL values pursuant to its CEII procedures.

Planning Division, Transmission Planning Department, PJM Manual 14B: PJM Region Transmission Planning Process, PJM Interconnection, L.L.C., 63 (Nov. 17, 2016), http://www.pjm.com/~/media/documents/manuals/m14b.ashx.

to model the wheel in the load deliverability studies, it did not address limits to how much PJM could import from NYISO. Thus, PJM has the flexibility to assume the appropriate level of imports from NYISO to avoid understating or overstating the level of imports into PJM that can be reliably counted on during emergencies.

Contrary to PSE&G, PJM considers factors such as potential generation
retirements.70 PJM specifically stated in the 2020/2021 Reliability Pricing Model

(“RPM”) Planning Parameters posted on its website that PJM would be reviewing and
revising (if necessary) CETL assumptions in light of “potential deactivation of several
large generators located in NYISO and in close proximity to the PARS.”71 The RPM
Planning Parameter calculations include the NYISO system parameters as known at the

See PSE&G Protest at 13.

2020-2021 RPM Base Residual Auction Planning Parameters, PJM
Interconnection, L.L.C., n.2, http://pjm.com/~/media/markets-ops/rpm/rpm-
auction-info/2020-2021-bra-planning-period-parameters.ashx (last visited Mar.
10, 2017).

The CETL values of the MAAC, EMAAC, PSEG and PS-North
[Locational Delivery Areas (“LDAs”)] are highly sensitive to
several critical modeling assumptions regarding the operation of
Phase Angle Regulators (PARs) located at PJM-NYISO interface
points at Waldwick, Hudson and Linden, as well as the extent to
which PJM can rely on imports from NYISO and New England to
provide assistance to an LDA that is experiencing a capacity
emergency. The PS-[Con Edison] [W]heel contract has
historically dictated the modeled operation of the aforementioned
PARs however the impending termination of this contract
introduces some degree of uncertainty as to the extent to which
PJM can rely on operating these PARs in a manner that provides
the maximum benefit to a PJM LDA experiencing a capacity
emergency. This uncertainty is compounded by the potential
deactivation of several large generators located in NYISO and in
close proximity to the PARs. PJM will be reviewing these
important assumptions as they pertain to the CETL values of the
MAAC, EMAAC, PSEG and PS-North LDAs, and may revise
these values from those shown pending that review.

time the model for the calculations is assembled. As mentioned in the planning parameter posting there is potential to revise the CETL assumptions, PJM will consider assumption changes in the NYISO area as part of any such revision.

In addition, contrary to PSE&G’s assumptions of what is described in the JOA,
the JOA does not prescribe any planning assumptions on the level of imports PJM can
take from NYISO. PSE&G further implies that PJM and NYISO do not know in advance
what options will be available during emergency situations.72 The JOA addresses
emergency assistance between the RTOs which requires available transfer capability in
order to share emergency energy without causing or aggravating reliability. PJM and
NYISO each maintain emergency operating plans which are coordinated (review is
required for each revision) to ensure there will be no conflicts during real-time
emergency operations. Emergency Operations are addressed in PJM Manual 1373 and
NYISO Manual 15.74 PSE&G’s concern that “PJM and NYISO operators may attempt
inconsistent PAR adjustments on their respective systems”75 thus impacting reliability is
misplaced. As described in the JOA, PJM, NYISO, PSE&G, and Con Edison coordinate
PAR moves in real-time operations76 and thus will not result in inconsistent PAR
adjustments that could impact reliability.

PSE&G Protest at 14. See supra note 18.

See NYISO Grid Operations, Manual 15 Emergency Operations Manual, New York Independent System Operator, (Nov. 18, 2016),

http://www.nyiso.com/public/webdocs/markets_operations/documents/Manuals_a nd_Guides/Manuals/Operations/em_op_mnl.pdf.

PSE&G Protest at 14.
See JOA, Schedule D § 7.

Finally, PJM disagrees with PSE&G that “[e]mergency procedures should be
included as part of the JOA.”77 Many of the issues that PSE&G raises are not unique to
the PJM/NYISO seam but are more universal. Therefore, to ensure CETL/CETO
emergency procedures are consistently applied throughout the PJM footprint, such
procedures are more appropriately left in the PJM manuals. These procedures, along
with the parameters for upcoming Base Residual Auctions for capacity and supporting
studies for the CETO/CETL values are available on its website. There simply is no need
to duplicate them in the JOA.

F. The Treatment of Rockland Electric Company Load Is Beyond the

Scope of PJM and NYISO’s Proposal and This Proceeding

In its protest, PSE&G “takes issue” with how the RTOs treat the load of Rockland
Electric Company (“RECo”). 78 This criticism is beyond the scope of this proceeding. In
the Joint Filing,79 NYISO and PJM noted that they were not proposing to modify the
construct for serving RECo load in this proceeding, and set forth how RECo load is
served today,80 and indicated that NYISO and PJM agree to continue discussions
regarding alternatives to serve the load.81 NYISO and PJM provided this information to
clarify that this proposal does not include changes to RECo load treatment. Moreover,

PSE&G Protest at 14. Id. at 15.

Joint Filing at 10.

Id. at 10-11. The Commission accepted the JOA treatment of RECo load in Docket No. ER12-718-001. See New York Independent System Operator, Inc., 140 FERC ¶ 61,205 (2012).

The current treatment of RECo load was added to the JOA in January 2013. See New York Independent System Operator, Inc., 140 FERC ¶ 61,205, at P 19 (2012) (accepting compliance filing to become effective January 15, 2013).

PSE&G makes no claim as to how the methodology for serving RECo load has any impact on the JOA revisions proposed in the Joint Filing and thus is irrelevant here. For these reasons, PSE&G’s comments regarding the RTOs’ arrangement for serving RECo load should be disregarded.

III.REQUESTED ACTION

A.It Is Critical that the Proposed JOA Revisions Be in Place on

May 1, 2017

The NYISO and PJM have requested an effective date for the JOA revisions of May 1, 2017 to coincide with the termination of the 1000 MW Wheel. As the NYISO and PJM explained in the Joint Filing, this effective date is critical. PJM and NYISO customers will incur significant costs and increased reliability risks if the proposed scheduling protocols are not in effect when the 1000 MW Wheel terminates.

Following termination of the 1000 MW Wheel on April 30, 2017, PJM and
NYISO will have only limited tariff authority to implement economic interchange over
the ABC and JK Interfaces, absent the scheduling protocols proposed in the Joint Filing.
As a result, unless the revised JOA protocols takes effect, the interchange between the
systems will be distributed almost entirely across the 5018 line and Western Ties.82 The
only interchange that will be allowed to flow over the ABC or JK Interfaces will be the
up to thirteen percent currently authorized under certain conditions when the 5018 line is
oversubscribed.83

Because the ABC and JK Interfaces effectuate flows between major load centers,
not utilizing these two interfaces for economic interchange, in the absence of the 1000

MW Wheel, will reduce the quantity of power that can be directly exchanged between the
relatively congested Southeastern New York and Northern New Jersey areas, and
additional power will be forced over the Western Ties. Increasing power flows over the
Western Ties tends to increase west-to-east congestion on the already congested
transmission facilities in New York State, Pennsylvania, and New Jersey. For NYISO,
this will aggravate constraints between upstate New York and Southeastern New York
load centers. This occurs as this energy flows through the Western Ties and across the
NYISO system to reach the Southeastern portion of the NYISO system. For PJM, more
of the MWs PJM imports from NYISO will flow into PJM west of the Ramapo
interconnection. This aggravates NYISO’s Southwestern system particularly in the
Gardenville area, which then is electrically tied to the Northwestern portion of
Pennsylvania on the PJM system.

Failure to implement the Joint Filing also will undermine the M2M coordination
between the NYISO and PJM. The PARs at the ABC and JK Interfaces were not
previously included in M2M PAR coordination because their primary function was to
facilitate delivery of the 1000 MW Wheel. Absent the proposed JOA scheduling

protocol, after termination of the 1000 MW Wheel, the RTOs will lack the tariff authority to utilize the PARs at the ABC and JK Interfaces to effectuate M2M PAR coordination. M2M PAR coordination only would apply under the current JOA protocols on the Ramapo PARs, with a target for the Ramapo PARs that continues to account for the delta between the ABC and JK flows.

Both NYISO and PJM would incur significantly higher total production costs
following termination of the 1000 MW Wheel if the proposed protocols are not in place.
The increased costs will result from the RTOs being prohibited from using grid

equipment most efficiently to effectuate interchange or manage congestion, and underutilization of grid equipment except in the case of major emergencies. As an example, on a peak summer day with high loads and high temperatures in both RTOs, more expensive generation is committed to run in order to meet load and reserve requirements. Economic transfers between the RTOs allow for lower prices for the RTO that is potentially short on reserves resulting in lower bus prices paid by loads. The commitment of additional expensive generation, while underutilizing the interchange transfer capability, is less than optimal for peak summer operating conditions, especially given the amount of congestion on the affected systems.

Finally, not being able to implement the proposed JOA protocols by May 1, 2017,
also will increase the risk to the reliability of the bulk power system. The proposed use
of the 400 MW OBF was developed specifically to address “short-term reliability issues
in Northern New Jersey . . . and to maintain historical interface transfer limits.”84
Without implementing the proposed 400 MW OBF there will be limitations to transfer
capability between NYISO and PJM. Total Transfer Capability will have to be reduced
to approximately 900 MW to 1,100 MW, thus reducing opportunities to use the

interfaces. The Joint Filing set forth a comprehensive set of JOA revisions to efficiently
implement economic interchange and M2M on the ABC and JK Interfaces as of May 1,
2017. The OBF is a necessary element of the proposed JOA revisions to obtain the full
benefit of using the ABC and JK Interfaces to facilitate economic interchange between
the two regions.

Joint Filing at 8.

B.The Commission Should Not Accept the Joint Filing Subject to

Refund But Instead Make Any Changes to the Protocols Prospective

NYISO and PJM re-iterate their request that the Commission accepts the
proposed JOA protocols not subject to refund and in the event the Commission directs
any changes to the proposed JOA protocols, that the changes be made prospectively.

NYISO and PJM recognize that the Commission currently lacks a quorum, and it
is uncertain whether a quorum will be reestablished in time to affirmatively act on the
Joint Filing by the requested effective date. NYISO and PJM also acknowledge that due
to the lack of a quorum, the Commission has issued an order85 pursuant to which it has
delegated to Commission staff the authority “to accept and suspend [FPA section 205]
filings and to make them effective, subject to refund and further order of the
Commission.”86

The Commission has an additional choice. It is within the Commission’s authority to allow the Joint Filing to take effect by operation of law. FPA section 205 provides that “[u]nless the Commission otherwise orders” the Joint Filing shall take effect “after sixty days’ notice to the Commission and to the public.”87 Courts have consistently found that actions based on statutory time frames take effect even when an agency lacks a quorum.88 Therefore, it is fully within the Commission’s authority to allow the Joint Filing by the requested effective date of May 1, 2017.

Agency Operations in the Absence of a Quorum, 158 FERC ¶ 61,135 (2017) (“Delegation Order”).

Id. at P 4.

16 U.S.C. § 824d(d).

See, e.g., Cal. Livestock Prod. Credit Ass’n v. Farm Credit Admin., 748 F. Supp.
416, 420-21 (E.D. Va. 1990) (finding that where a statute that provided that a
submittal to the agency would be presumed accepted after thirty days, it was

While the “Commission’s general practice [is] not to allow [FPA section 205 rate]
filings to go into effect by operation of law,”89 in light of the harm PJM and NYISO
customers could suffer if the 1000 MW Wheel terminates without a suitable replacement,
and as explained below, refunds would not be an appropriate remedy, it is reasonable for
the Commission to allow the proposed JOA protocols to take effect by operation of law.
In addition, if the Commission took this route, parties and the Commission would
maintain the ability to challenge the JOA revisions under FPA section 206.90

In the event that the Commission accepts the proposed JOA protocols by delegated order, it should exercise its discretion not to order refunds in any future order in which it rules on the merits, and instead make any changes to the proposed JOA protocols prospective only. The facts of this case and Commission precedent factors support this approach. First, the proxy bus prices account for the value and the expected quantity of power flow over each interface that is a component of that proxy bus.

immaterial that the agency had not acted on the submittal because it lacked a
quorum: “Section 7.11(a)(2) does not require approval by a quorum of the [Farm
Credit Administration (“FCA”)] Board.... In drafting the statute, Congress did

not distinguish among the many reasons that the FCA might cite for failing to act on a particular submission within the 30 day period By providing for 30 days

of inaction by the FCA Board, Congress clearly envisioned that there would be
periods where a full quorum of the FCA Board would be unable to act. The
FCAs’ purported inability to function without a quorum may not be used to deny
an institution its statutory right to exit the Farm Credit System.”); McLaughlin v.
Union Oil Co., 869 F.2d 1039, 1042 (7th Cir. 1989) (“The statutory condition for
the finality of an administrative law judges’ decision is merely that no member of
the Commission direct, within thirty days, that the decision be reviewed—a
condition satisfied here. There is nothing in the statute concerning the reasons no
member might direct review in a case. One reason might be, as here, the absence
of a quorum.”).

Second, the equitable principles that guide the Commission’s refund decisions
militate against refunds.91 The Commission “generally exercises its discretion and does
not order refunds when doing so would require re-running a market,” as it would here.92
Because “customers cannot effectively revisit their economic decisions . . . [or]

retroactively alter their conduct”93 refunds in such circumstances are generally denied.94
If the proposed JOA revisions are accepted and later modified by the Commission, it
would be impossible to calculate fair Market Participant refunds. By the time a new
Commission-directed protocol would be implemented, the market software would have
already run, establishing binding schedules and prices. Determining and settling on
alternative schedules and prices for transactions would mean the actual operation of the
power system would be inconsistent with the offers submitted, costs incurred, and
payments received by Market Participants, because market behavior was based upon the
economic circumstances at that time. It would be impossible to unwind how the markets
would have functioned and what transactions would have been scheduled under the

See, e.g., La. Pub. Serv. Comm’n v. Entergy Corp., 155 FERC ¶ 61,120, at P 26 (2016).

Ameren Servs. Co. v. Midwest Indep. Transmission Sys. Operator, Inc., 127
FERC ¶ 61,121, at P 157 (2009); see also Md. Pub. Serv. Comm’n v. PJM
Interconnection, L.L.C., 123 FERC ¶ 61,169, at P 49 (2008) (citing Mirant
Energy Trading, LLC v. PJM Interconnection, L.L.C., 122 FERC ¶ 61,007 (2008);
Bangor Hydro-Electric Co. v. ISO New England Inc., 97 FERC ¶ 61,339 (2001)
(finding that re-running markets even when an error was made would do more
harm to electric markets than is justifiable)); Cal. Indep. Sys. Operator, 120
FERC ¶ 61,271, at P 25 (2007) (identifying market reruns as “the exception, not
the rule”).

New York State Electric & Gas Corporation v. New York Independent System Operator, Inc., 92 FERC ¶ 61,073, at 61,307 (2000).

See, Midwest Indep. Transmission Sys. Operator, Inc., 155 FERC ¶ 61,127, at P 31 (2016).

alternate rules and, therefore, any refunds would be inaccurate. Commission precedent supports not ordering refunds in this case and making any necessary changes to the proposed JOA protocols on a prospective basis.

IV.CONCLUSION

For the reasons stated in the Joint Filing and in this answer, the Commission should reject the protests filed in this docket and permit the proposed JOA protocols to go into effect as of May 1, 2017, and to the extent that the Commission requires any changes to the protocols, such changes should be prospective.

Respectfully submitted,

/s/ Jacqulynn Hugee

Craig Glazer

VP - Federal Government Policy PJM Interconnection, L.L.C.

1200 G Street, N.W., Suite 600 Washington, D.C. 20005

(202) 423-4743

Raymond Stalter

Director, Regulatory Affairs
New York Independent System

Operator, Inc.

10 Krey Boulevard Rensselaer, NY 12144 (518) 356-8503

Jacqulynn Hugee

Associate General Counsel PJM Interconnection, L.L.C. 955 Jefferson Avenue