Docket Nos. ER17-905-000 and ER17-905-0011

161 FERC ¶ 61,033

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Neil Chatterjee, Chairman;

Cheryl A. LaFleur, and Robert F. Powelson.

New York Independent System Operator, Inc.

PJM Interconnection L.L.C.

Docket Nos.

ER17-905-000

ER17-905-001

ORDER ACCEPTING TARIFF REVISIONS AND DENYING REQUEST FOR REHEARING AND CLARIFICATION

(Issued October 6, 2017)

On January 31, 2017, pursuant to section 205 of the Federal Power Act (FPA),[1] the New York Independent System Operator, Inc. (NYISO) and PJM Interconnection, L.L.C. (PJM) (together, the RTOs) submitted proposed revisions to the Joint Operating Agreement (JOA) between NYISO and PJM that is set forth in Attachment CC to NYISO’s Open Access Transmission Tariff (OATT). In addition, NYISO submitted proposed revisions to its Market Administration and Control Area Services Tariff (Services Tariff).
The proposed revisions address interchange scheduling and the implementation of Market-to-Market (M2M) coordination at the ABC Interface and JK Interface on the border of Southeastern New York and Northern New Jersey, and are intended to govern the operation of the facilities at these interfaces upon termination of the firm transmission service agreements (TSAs) that implemented a wheeling arrangement that included specific operating protocols for these facilities. The RTOs seek an effective date for the proposed tariff revisions of May 1, 2017.
On March 31, 2017, pursuant to the authority delegated by the Commission’s February 3, 2017 Order Delegating Further Authority to Staff in Absence of Quorum,[2] the proposed OATT and Services Tariff revisions were accepted for filing, suspended for

a nominal period, to become effective May 1, 2017, as requested, subject to refund and further Commission order.[3]

In this further order, we accept the proposed revisions to the NYISO OATT and Services Agreement, effective May 1, 2017, as requested.
Public Service Electric and Gas Company (PSEG) and the New Jersey Board of Public Utilities (New Jersey Board) filed a request for rehearing, and Linden VFT, LLC (Linden) filed a request for clarification, or in the alternative, rehearing of the March 31, 2017 Order.
As discussed below, we deny the requests for rehearing and clarification.

I. Background

At the time of the RTOs’ filing, the JOA for M2M coordination of the ABC and JK Interfaces included specific operating protocols that were established pursuant to a settlement agreement (Settlement Agreement) that included the TSAs that continued a wheeling arrangement that enabled Consolidated Edison Company of New York (ConEd) to transfer 1,000 MW of power over the JK Interface in northern New Jersey for delivery back to ConEd over the ABC Interface to New York City.[4] On April 28, 2016, ConEd informed PJM that it was not exercising the rollover provisions of the TSAs pursuant to sections 2.2 and 2.3 of the PJM Open Access Transmission Tariff (PJM Tariff) and, therefore, the TSAs would terminate on April 30, 2017, by their terms. With the termination of the TSAs, the wheeling arrangement has ended and the protocols governing the operation of the ABC and JK Interfaces became obsolete.

II. RTOs’ Filing

The wheeling arrangement allows the RTOs to implement interchange between the two RTOs by reviewing offers and scheduling transactions over the PJM-NY AC Proxy Bus. As a result of ending the wheeling arrangement, the RTOs propose to combine the ABC and JK Interfaces with the 5018 line and the Western ties into an aggregate PJM-NY AC Proxy Bus. According to the RTOs, combining the interfaces and redefining the

proxy bus would allow for the RTOs to leverage existing interchange scheduling constructs in both regions and can be implemented in a timeframe that accommodates the required May 1, 2017 effective date. The RTOs also state that doing so would support use of the existing Phase Angle Regulators (PARs)[5] located on the ABC and JK Interfaces. For purposes of pricing calculations at the PJM-NY AC Proxy Bus, the RTOs propose to reflect the impacts of imports and exports on the NYISO and PJM transmission systems, weighted by specific power flow distribution percentages applied to the interchange in the market models.

The RTOs note that the proposed interchange percentages were the result of studies conducted by both RTOs involving several scenario analyses. Notably, the studies identified reliability issues in Northern New Jersey as well as delivery limitations when exporting from PJM to NYISO on the JK Interface and when exporting from NYISO to PJM on the ABC Interface. As a result, the RTOs conducted further studies to identify operating procedures that would preserve historical Total Transfer Capability. The studies focused on summer peak cases, natural system flows with zero interchange scheduled between PJM and NYISO, and flows with all interface PARs held at neutral tap.
The RTOs concluded that a natural system flow occurs from NYISO to PJM over the JK Interface and from PJM to NYISO over the ABC Interface. Given this, the RTOs propose to include a natural system flow offset, referred to as an Operational Base Flow (OBF), of 400 MW into PJM over the JK Interface and 400 MW into New York on the ABC Interface when scheduling interchange and when determining target flows. According to the RTOs, the 400 MW OBF is needed to resolve the short-term reliability issues in Northern New Jersey and to maintain historical interface transfer limits. Without an OBF, the RTOs argue that the Total Transfer Capability between the two areas would have to be reduced. The RTOs determined that the proposed OBF also supports operational flexibility and allows the RTOs to utilize higher transfer limits on the JK Interface and ABC Interface to maintain reliability in Northern New Jersey.
The OBF would be applied over the JK Interface from NYISO to PJM and over the ABC Interface from PJM to NYISO in conjunction with the interchange distribution percentages. The RTOs propose to develop an M2M PAR target value for the ABC PARs and JK PARs by combining the applicable static percentage of scheduled interchange, the applicable OBF value, and the applicable percentage of Rockland Electric Company (Rockland) load. The RTOs state that the instant filing does not propose to modify Rockland load.

The RTOs’ proposal allows the RTOs to mutually agree to review the OBF MW value at least annually to determine if modification of the OBF MW value, or the distribution of the OBF MWs across the PARs, is appropriate. The RTOs commit to post any modifications to the OBF MW value, including a need for a future OBF, or the OBF distribution across the PARs on their respective websites and stakeholder processes. Further, the RTOs expect to reduce the initial OBF value to zero within five years, once the Bergen-Linden Corridor Project, currently under development in Northern New Jersey, is completed. The RTOs state the NYISO planning models representing the bulk power system from May 1, 2017 through May 31, 2021 will incorporate the initial 400 MW OBF, and PJM planning models will assume no OBF for future cases.
In addition, the RTOs propose to include provisions in the JOA that will permit either RTO to establish a temporary OBF in order to address a short-term reliability issue. The proposed JOA revisions state that, once an RTO requests a temporary OBF, the OBF value must be set at a level that both RTOs agree they can reliably support. The RTO that establishes the OBF must: (1) explain the reliability need to the other RTO; (2) describe how the OBF addresses the identified reliability need; and (3) identify the expected long-term solution to address the reliability need. NYISO and PJM reviewed the proposed initial 400 MW OBF using these three criteria.
The RTOs state that the OBF is not a firm transmission service on either the NYISO transmission system or the PJM transmission system and that NYISO and its Market Participants will not be subjected to PJM Regional Transmission Expansion Plan (RTEP) cost allocations as a result of implementation of an OBF. Specifically, the RTOs explain that the proposed JOA revisions provide that the OBF will not result in charges from one RTO to the other RTO, or from one RTO to the other RTO’s Market Participants, except for the settlements described in the Real-Time Energy Market Coordination and Settlements provisions set forth in Sections 7 and 8 of Schedule D to the JOA. The RTOs note that, absent the proposed revisions, they would have no tariff authority to implement economic interchange over the ABC Interface and JK Interface or to utilize M2M PAR coordination at these interfaces. Without the wheeling arrangement, the ABC and JK Interfaces would need to be utilized for economic interchange to avoid reducing the exchange of power between the congested Southeastern New York and Northern New Jersey areas. In addition, the RTOs state that these interfaces would need to be used to avoid additional power being forced over the Western ties and increasing congestion on already congested transmission facilities.

III. Notice of Filing and Responsive Pleadings

Notice of the RTOs’ January 31, 2017 filing was published in the Federal Register, 82 Fed. Reg. 9374 (2017) with interventions and protests due on or before February 21, 2017.
Notices of intervention were filed by the New York Public Service Commission (New York Commission), Delaware Public Service Commission, and New Jersey Board. Timely motions to intervene were filed by ConEd, NRG Power Marketing LLC and GenOn Energy Management, LLC (NRG Companies), American Municipal Power, Inc., PSEG, New Jersey Division of Rate Counsel, the New York Transmission Owners, and Entergy Nuclear Power Marketing, LLC. Rockland, Dayton Power and Light Company (Dayton), FirstEnergy Service Company (FirstEnergy), American Electric Power Service Corporation (AEP), Linden, Exelon Corporation (Exelon), Dominion Resources Services, Inc. (Dominion), PPL Electric Utilities Corporation (PPL), Duke Energy Corporation (Duke), and Hudson Transmission Partners, LLC (Hudson) and Neptune Regional Transmission System, LLC (Neptune), and the City of New York filed out-of-time motions to intervene.
Protests were filed by the New Jersey Board, NRG Companies, and PSEG and comments were filed by ConEd, Linden, and Rockland.
The New York Commission, ConEd, the Indicated New York Transmission Owners,[6] and the RTOs filed answers to the protests. PSEG filed an answer to the RTOs’ answer. The RTOs filed an answer to Linden’s comments, and, in turn, Linden filed an answer to the RTOs’ answer. New Jersey Board filed late comments.

IV. Procedural Matters

Pursuant to Rule 214 of the Commission’s Rules of Practice and Procedure,[7] the notices of intervention and timely, unopposed motions to intervene serve to make the entities that filed them parties to this proceeding.
Pursuant to Rule 214(d) of the Commission’s Rules of Practice and Procedure,[8] we will grant the late-filed motions to intervene of Rockland, Dayton, FirstEnergy, AEP Linden, Exelon, Dominion, PPL, Duke Hudson and Neptune, and the City of New York,

given the interest in the proceeding, the early stage of the proceeding, and the absence of undue prejudice or delay.

Rule 213(a)(2) of the Commission’s Rules of Practice and Procedure [9] prohibits an answer to an answer or protest unless otherwise ordered by the decisional authority. We will accept the answers filed in this proceeding because they have provided information that assisted us in our decision-making process.

V. Discussion

We find that the proposed JOA revisions represent a just and reasonable solution to address the expiration of the wheeling arrangement, and therefore we accept the RTOs’ proposal, effective May 1, 2017. The proposal will manage congestion and enable efficient economic interchange between the Northern New Jersey and Southeastern New York areas through the implementation of interface pricing based on an aggregate PJM-NY AC Proxy Bus and M2M coordination at the ABC and JK Interfaces. In addition, the proposal will also address short-term reliability issues in Northern New Jersey. Without the proposed revisions, historical congestion issues would be exacerbated and reliability concerns would force the RTOs to significantly reduce the economic transfer capability between the RTOs. We expect the RTOs to abide by their commitment to review the OBF MW value at least annually to determine if modification is appropriate. Below, we address the various issues raised by commenters.

A. Reliability Need for the OBF

1. Protest

PSEG states that the studies undertaken by the RTOs do not support the reliability need for the OBF. PSEG explains that the studies were based on extreme system conditions including high levels of non-firm deliveries to NYISO from PJM rather than historic flows. PSEG notes that the scenarios used in the RTOs’ studies assumed 2,500 MW of net interchange from PJM to NYISO during emergency conditions. PSEG argues that this level of net interchange has never occurred. Further, PSEG argues that, since the OBF will not be needed after completion of the Bergen-Linden Corridor Project in 2018, there is no need to extend the OBF beyond that date.
PSEG argues that PJM currently has the tools necessary to address real-time reliability impacts on its system without the OBF. PSEG points to PJM’s ability to curtail non-firm exports through the use of its transmission loading relief procedures. Further, PSEG notes that PJM is able to support approximately 1,100 MW of exports even assuming extreme conditions and no OBF.

2. Answers

In response to PSEG’s argument that its studies have not supported the OBF, the RTOs state that they prudently analyzed various scenarios that preserve the transfer limit that could occur to ensure that the proposed operating procedures, including the OBF, were achievable without impacting reliability. The RTOs clarify that the 2,500 MW net interchange value represented the historic transfer limit that could occur and provide data that demonstrates that this level of net interchange has actually occurred in the past. The RTOs therefore support their net interchange assumptions in their studies as reasonable, and note at a lower 1,500 MW net interchange, studies demonstrated reliability issues on the PSEG system which still justified a 400 MW OBF.[10]
The RTOs state that, while PJM is able to address real-time reliability impacts on its system through transmission loading relief procedures, these procedures should only be relied upon in emergency situations and not for system planning purposes. Further, the RTOs note that the transmission loading relief procedures can increase costs in NYISO and PJM, as well as distort and suppress proper market signals.
The RTOs also respond to PSEG’s argument that the proposed OBF should not continue to be used once the Bergen-Linden Corridor Project is completed in 2018. The RTOs explain that the proposed JOA revisions note the expectation that the OBF will be reduced to 0 MW by June 1, 2021. The RTOs note that the proposed JOA revisions also require the RTOs to annually review the OBF MW value to determine if modification is appropriate. Further, the proposed revisions require that any modification of the OBF value will be implemented no sooner than two years after mutual agreement on such modification. As a result of these proposed revisions, the RTOs state that PJM intends to notify NYISO that the 400 MW OBF should be zero once the impact of the project is confirmed based on updated modeling.

3. Commission Determination

We find the proposed OBF mechanism to be just and reasonable. If the RTOs fail to take action to address the termination of the wheeling arrangement, as of the termination date, the RTOs will have no procedures in place to manage the flow of power between the relatively congested Southeastern New York and Northern New Jersey areas. Accordingly, the RTOs propose in this filing revisions to the JOA to combine the ABC

Interface and JK Interface with the 5018 line and Western ties into an aggregate PJM-NY AC Proxy Bus. The RTOs also propose to utilize the PARs at the ABC Interface and JK Interface for M2M PAR coordination, in the same manner that they currently use the Ramapo PARs for M2M PAR coordination. These actions will allow NYISO and PJM to effectuate aggregate interchange schedules across the PJM-NY AC Proxy Bus, as well as manage regional congestion.

However, when the RTOs conducted scenario analyses involving the flow of power between the regions, they identified reliability issues in Northern New Jersey and delivery limitations when importing and exporting power on the JK and ABC Interfaces. Given these constraints, the RTOs worked with stakeholders to identify the initial 400 MW OBF as a crucial aspect of their proposal to resolve short-term reliability issues and to maintain historical interface transfer limits. Additionally, the proposed OBF will enable efficient economic interchange between the relatively congested Northern New Jersey and Southeastern New York areas. Because the OBF is necessary to support the RTOs’ goal of effectuating aggregate interchange schedules across the PJM-NY AC Proxy Bus, and managing regional congestion, we find that the OBF is just and reasonable.
We do not agree with PSEG’s assertion that the RTOs inappropriately based the proposed OBF on extreme system conditions and extremely high levels of non-firm deliveries to NYISO from PJM. Rather, we find that the RTOs appropriately considered historical flows during 2016 summer peak conditions. Further, the RTOs sufficiently supported their decision to use a net interchange value of 2,500 MW as a historic transfer limit that could occur. We find that the RTOs have properly demonstrated the need for the proposed OBF through the use of actual historical flows and a reasonable net interchange value.[11]
We are also not persuaded by PSEG’s arguments that the filing is unjust and unreasonable since PJM could use the North American Electric Reliability Corporation (NERC) transmission loading relief procedures to address real-time reliability impacts on its system without the OBF. These procedures represent a less economically efficient outcome compared to the RTOs’ proposal to implement economic interchange over the ABC Interface and JK Interface and also utilize M2M PAR coordination at these interfaces. We find no basis for rejecting the RTOs’ proposal to rely on planned flows and market pricing instead of transmission loading relief procedures.
With regard to PSEG’s argument that there is no need to extend the OBF beyond the completion date of the Bergen-Linden Corridor Project in 2018, we find that the proposed JOA revisions sufficiently address this concern. Specifically, proposed

section 7.2.1 of the JOA would require the RTOs to review the OBF MW value at least annually to determine if modification is appropriate. While the RTOs have preliminarily concluded through forward-looking studies that the proposed OBF may be able to be eliminated after the Bergen-Linden Corridor Project is completed, the RTOs have appropriately committed to first confirm the impact of the project based on updated modeling. PJM would then notify NYISO that the proposed 400 MW OBF should be reduced to zero.

B. OBF as a Daily Requirement

1. Protests

PSEG contends that the 400 MW OBF has not been justified as a daily requirement because the studies show that the OBF is only needed during limited times of system stress when a high amount of non-firm net interchange from PJM to NYISO is scheduled. PSEG argues that the OBF should only be used in those limited circumstances.
NRG also argues that incorporating unpriced power into the NYISO day-ahead market suppresses energy prices in New York. Further, NRG argues that one of its generating units’ ability to operate at full output will be impacted by the OBF assumptions.[12]

2. Answers

The RTOs disagree that the proposed OBF has not been justified as a daily requirement and that it should only be utilized during times of system stress when a high amount of non-firm net interchange from PJM to NYISO is scheduled. The RTOs explain that an OBF must be set at a static value in order to have an accurate representation of real-time system conditions and effectively develop a reliable Day-Ahead Operating Plan. In addition, the RTOs argue that, without a static value, 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. The RTOs contend that an OBF implemented only when expected system conditions require it would result in a lack of market certainty with regard to when the OBF would apply, which would produce inefficient market outcomes.
The RTOs explain the 400 MW OBF will not create price suppression because Locational Marginal Prices (LMPs) will be created in the day-ahead energy market

consistent with how power is expected to flow, and in the real-time energy market consistent with how power actually flows.[13] The RTOs explain it is fair and reasonable to return the 400 MW PJM receives over the JK Interface to New York at the ABC Interface, and facilitating economic interchange is not price suppression for the receiver of the interchange.[14]

3. Commission Determination

We find that the RTOs have justified the proposed OBF as a daily requirement. If the OBF is not set as a daily requirement, market participants would find it difficult to precisely predict when the OBF will take effect. We also find that a static OBF would help align day-ahead and real-time schedules, system conditions, and prices and therefore, limit uplift costs.
We are not persuaded by NRG’s argument that the proposed OBF will result in the economically inefficient outcome of including unpriced power in NYISO’s day-ahead market. Rather, we find that the proposed OBF will facilitate interregional economic interchange while appropriately pricing power in both the NYISO day-ahead market and real-time market, to reflect the value of transmission to all market participants. We agree with the RTOs that the LMPs will reflect real-time power flows, and are not persuaded that the 400 MW OBF constitutes unpriced power flowing into NYISO. Rather, we find it is flow that is exchanged between the RTOs that is managed and priced through interchange schedules.

C. Cost Allocation

1. Comments and Protest

ConEd states that it is appropriate that New York market participants will not incur RTEP charges, or any other charges beyond those already stated in Sections 7 and 8 in the JOA, considering the temporary nature and purpose of the initial 400 MW OBF.[15] ConEd states New York market participants should not incur RTEP charges as a result of RTOs utilizing an OBF to address short-term reliability issues in Northern New Jersey. ConEd states it will oppose the RTOs’ proposal if the Commission rejects the proposed OBF.[16]
PSEG argues that the RTOs’ proposal is not just and reasonable because there is no requirement that ConEd compensate PJM for the benefit of sinking its deliveries in NYISO’s Zone J, which it states provides substantial benefits.[17] PSEG states the Commission has previously authorized compensation for loop flows when those loop flows provide benefits to entities in adjoining systems.[18] PSEG argues one of the driving elements behind the Bergen-Linden Corridor Project on the PSEG system are short circuit issues associated with the ABC Interface facilities, which impose costs on PJM customers as a result of ConEd’s use of this part of the PJM system.[19]
New Jersey Board states that the 400 MW OBF is a smaller version of the previous 1,000 MW ConEd wheeling agreement, in which ConEd and New York customers will receive benefits without cost responsibility.[20] New Jersey Board argues that past litigation has demonstrated the benefits that ConEd receives from this wheeling agreement, and now ConEd will continue to benefit from PJM RTEP projects while loads in PJM will pay for those projects that support the wheel. New Jersey Board argues the RTOs’ proposal undermines the beneficiary pays model by allowing ConEd to avoid cost responsibility that New Jersey ratepayers in particular will be responsible for.[21]

2. Answer

In their answer, the RTOs state that protesting parties have mischaracterized the OBF as a mini-wheel agreement. The RTOs explain the OBF did not result from a request for firm transmission service like the original Wheeling Agreement, but rather stems from an operational need, which was not requested by NYISO from PJM.[22] The

RTOs explain the OBF is not firm transmission service on either the NYISO or PJM system. The RTOs explain that the OBF was developed to address short-term reliability issues in Northern New Jersey, and was the alternative that would achieve the greatest interregional efficiency.[23]

The RTOs explain the 400 MW PJM receives over the JK Interface need to be returned to NYISO over the ABC Interface because there are no other viable options to keep the megawatts in Southeastern New York and Northern New Jersey. The RTOs explain the 5018 line does not have enough transfer capability to support an additional 400 MW flow, and utilizing the transmission ties between Pennsylvania and Western New York for this flow would create several significant reliability problems as well as increase costs as a result of increased congestion.[24] The RTOs state utilizing the ABC Interface for the 400 MW flow, the OBF, will least likely impact transmission congestion in New York City, maximizing economic efficiency and supporting reliability.[25]
The RTOs explain that contrary to its arguments, PSEG will benefit from the reduced transmission congestion in Northern New Jersey that will result from the 400 MW OBF and the increased transfer limit the OBF supports. The RTOs explain higher target flows on the JK and AC interchange create post-contingency violations on the PSEG system, and the OBF reduces transmission congestion in Northern New Jersey by lowering JK target flow when total AC interchange is flowing.[26] The RTOs explain that ConEd was initially allocated costs for the Bergen-Linden Corridor Project because ConEd received firm transmission service and accepted cost responsibility under its Service Agreement. The RTOs explain the OBF is not firm transmission service on either NYISO or PJM’s system and therefore provides no basis for costs to be allocated to ConEd. Furthermore, the RTOs explain that ConEd will not receive significant short circuit benefits solely from the 400 MW OBF, as PJM technical studies demonstrate only minor changes to short circuit levels will occur on the ConEd system with the proposed OBF.[27] Finally, the RTOs argue that the termination of ConEd’s Settlement Agreement relieves it of any RTEP cost allocation responsibility, and the proposed JOA revisions do not affect ConEd’s RTEP obligations related to the Wheeling Agreement.[28]
In its answer, ConEd states it would be unjust and unreasonable to require ConEd to incur transmission, delivery or RTEP costs related to a temporary operating protocol. Primarily, ConEd explains imposing RTEP costs on ConEd without its consent would violate the Order No. 1000 requirement that planning regions cannot allocate costs of regional or interregional transmission projects to entities outside of their region, without their consent.[29] ConEd explains that the RTOs approved the OBF on the condition that entities in New York would not incur RTEP charges or other transmission and delivery charges. ConEd explains that RTEP charges imply a commitment to the PJM system, and that it is unjust and unreasonable to apply these requirements to an operational protocol.[30] ConEd argues that PSEG references financial benefits from outdated studies that do not apply to the 400 MW OBF, and that ConEd recently evaluated the financial impact of terminating its current transmission service.[31] ConEd also argues that the OBF is not loop flow under which the Commission should impose charges, but an intentional power flow designed by the RTOs, and that the precedent PSEG cites involves parties voluntarily resolving loop flow cost issues.[32]
ConEd answers that the protests misrepresent the 400 MW OBF as a continuation of ConEd’s expiring PJM transmission service and incorrectly imply that ConEd needs the OBF for reliability. ConEd clarifies that the 400 MW OBF will not entitle ConEd to firm transmission service, rollover rights, or service for any set period of time. ConEd argues that it did not request the OBF and notes that the OBF was developed due to short-term reliability needs identified by PJM in Northern New Jersey.
The New York State Commission emphasizes that the identification of reliability issues in Northern New Jersey is what led the RTOs to negotiate and reach an agreement to create the proposed OBF. Further, the New York State Commission notes that the ending of the wheeling arrangement will not result in any reliability issues for ConEd. The New York State Commission states that ConEd’s termination notice for the wheeling arrangement did not contain a need or concern to negotiate a flow between the RTOs.
PSEG states that to the extent ConEd receives similar loop flow deliveries through the OBF, PJM has previously suggested that RTEP costs would apply.[33] PSEG also argues that PJM cannot claim short circuit reliability violations on the PSEG system are not related to the interconnections with New York on the BC Interfaces, as PJM has recommended HVDC converters on the BC Interface to block “migration of short circuit duty impacts from the Con Edison system to the PJM system.”[34]
Indicated New York Transmission Owners state that neither NYISO nor its participants have provided consent needed for costs to be allocated to NYISO under Order No. 1000, and therefore under Cost Allocation Principle 4 of Order No. 1000 costs cannot be allocated to NYISO and its participants.[35] Indicated New York Transmission Owners state the OBF is an operational protocol that avoids a new transmission project under which there is no basis to allocate costs to NYISO customers, similar to how there would be no basis to allocate costs of an avoided transmission project in general.[36]

3. Commission Determination

We find that the JOA need not assign cost responsibility to ConEd for PJM RTEP projects, including the Bergen-Linden Corridor Project. Prior to the termination of the TSAs, cost responsibility for PJM RTEP projects, such as the Bergen-Linden Corridor Project,[37] which addresses short-circuit reliability issues on the PSEG transmission

system,[38] was allocated to ConEd because it had firm transmission service pursuant to the TSAs, resulting from a settlement that required ConEd to bear cost responsibility for RTEP costs in PJM during the term of ConEd’s service. The settlement providing for the wheeling arrangement specifically states that RTEP cost assignments are eliminated with the termination of the TSAs.[39] ConEd terminated the TSAs under its terms, and under the proposed operating protocol, ConEd would not receive firm transmission service on either the NYISO transmission system or on the PJM transmission system.

We do not find, as several protesters allege, that the proposed OBF represents firm transmission service or continues a portion of the wheeling arrangement. The operating procedures that were put in place for the wheeling arrangement stemmed from the firm transmission service that was at the heart of the 2008 TSAs. We find that the proposed OBF is an operational protocol that was developed by the RTOs due to reliability needs identified in Northern New Jersey.[40] The proposed OBF will not entitle ConEd to firm transmission service or rollover rights for any set period of time and therefore, NYISO and PJM cannot treat these flows as firm transmission for the purposes of planning and capacity market obligations.

D. Interface Pricing

1. Protest

NRG argues that the economically correct approach to pricing at the ABC and JK Interfaces would be to establish separate prices on each controllable tie that accurately represents the value of power flowing between Northern New Jersey and New York City, rather than averaging all prices across all ties between PJM and NYISO into a single proxy bus. Specifically, NRG argues the weighting the RTOs apply to the proxy bus prices is an improvement because it takes into account the prices at the controllable ties, but it is not an accurate way to price these ties. NRG states the PARs at the ABC and JK Interfaces permit flows on the facilities to be controllable, therefore the flows can be measured and priced.[41] NRG states a unique price can be provided for the bus on the ABC and JK Interfaces, and this would provide a more accurate price signal.
NRG states the Commission should not accept the RTOs’ consensus that the older PARs at these interfaces cannot reliably control flows, and should at a minimum direct the RTOs to create a separate pricing regime by a specified date.[42] NRG argues a more accurate price signal would support upgrading the PARs, and the current proposed pricing regime arbitrarily assumes a 400 MW flow that preserves historic flows.[43] PSEG also argues the adjustments to distribution percentages on the PARs on the ABC Interface facilities are not transparent and seem to be changed according to ConEd’s historic preference to deliveries on the B and C PARs.[44]

2. Answer

The RTOs explain it is not possible to provide “separate and unique” prices for the bus on the ABC and JK Interfaces because the current PARs equipment does not allow the interchange schedules to align with flows on an individual bus basis.[45] The RTOs explain implementing separate pricing would allow potential gaming opportunities to occur because a resource would be able to schedule energy at a certain point that may not actually flow across that point, while still receiving a price associated with that certain point.[46] The RTOs explain modeling one proxy bus instead of three avoids inconsistent actual energy flows to what was scheduled, and this was confirmed by PJM stakeholders in their PAR taskforce.[47]

3. Commission Determination

We find the RTOs’ proposal to establish a single price for the PJM-NY AC proxy bus to be just and reasonable. We agree that the inability to precisely control flows with

the current PARs technology provides a gaming opportunity where actual energy flows would be inconsistent with scheduled energy flows, as the PARs technology cannot control flow precisely on each individual interface bus at the facilities. The Commission previously has found that utilizing a single hub for multiple interfaces can support feasible schedules that establish accurate LMPs and manage congestion.[48] The RTOs have proposed a reasonable aggregate proxy bus for the interfaces that avoids pricing energy flows inconsistently with interchange schedules, as it is not possible with the current technology to accurately provide unique prices for the ABC and JK PARs as the protesters request. Given these concerns, we also will not direct the RTOs to create a separate pricing regime by a date certain, as NRG requests. However, as the RTOs study their systems we expect they will evaluate potential transmission upgrades that may permit separate pricing.

E. Transmission Owner Rights

1. Protest

PSEG states requirements in the JOA that the ABC Interface and the JK Interface facilities should be “functional and operational at all times except when taken out of service to perform maintenance or are subject to a forced outage” are inconsistent with the court’s determination in Atlantic City Electric v. FERC [49] that transmission owners retain control over their facilities as well as the PJM Consolidated Transmission Owners Agreement (CTOA) between PJM and the PJM Transmission Owners to implement that decision.[50] PSEG states the JOA also does not specify how the good utility practice standard will be applied to NYISO and PJM, and it is not clear how each RTO analyzes good utility practice to their own customers. Alternatively, if the provision is not rejected, PSEG argues a cost recovery mechanism needs to be incorporated if either RTO were to choose to replace a facility when a transmission owner chose not to do so.[51]

2. Answer

The RTOs state that the JOA provisions require facilities at the JK and ABC Interfaces to remain operational only to support the NY-NJ PAR coordination process, and only apply when the RTOs are able to use the facilities for NY-NJ PAR coordination.[52] The RTOs explain that if the JK and ABC facilities are not available for the RTOs’ use, the NY-NJ PAR coordination would not be possible. The RTOs explain that nothing in the provisions prohibit a transmission owner from retiring its facilities, and the provisions comport with TOs’ rights to retire facilities under the CTOA. The RTOs state the proposed JOA provisions do not violate the rights and obligations of PSEG under the TOA, and reiterate requirements under the TOA that transmission owners operate and maintain their facilities in accordance with good utility practice.[53]
In its answer, ConEd states it supports provisions requiring PSEG to ensure the JK and ABC Interfaces remain operational, but that it also supports a cost recovery mechanism if the RTOs request certain upgrades for the facilities that are against PSEG’s judgment.[54] ConEd explains that NYISO and PJM have confirmed that existing interregional transmission facilities benefit all market participants in each of their regions, and no single transmission owner should be responsible for costs of facilities for which the RTOs determine how they are used. ConEd states that the Commission should, pursuant to a section 206 proceeding, require the RTOs to revise the JOA to include cost recovery and decision-making provisions for these and other interregional facilities.[55]

3. Commission Determination

We find that the proposed operating protocols do not infringe on the rights retained by PJM transmission owners consistent with Atlantic City and do not remove any rights of the transmission owners under their TOAs. Atlantic City recognizes that the

transmission owners retain control over their own facilities except to the extent to which they transfer those rights to PJM.[56] Here, PSEG retains full rights to retire any of its facilities, subject to any limitations already set forth in the CTOA. As the RTOs explained, nothing in the proposed JOA revisions is intended to supersede or modify any rights or responsibilities to the PJM transmission owners under the CTOA. Further, as the RTOs explain, the CTOA already obligates the PJM transmission owners to operate and maintain their facilities consistent with good utility practice. Further, the CTOA grants PJM the authority to direct the operation and coordinate the maintenance of the transmission facilities of the PJM transmission owners in accordance with NERC and Applicable Regional Reliability Council operation and maintenance standards, principles and guidelines. Accordingly, we find that PSEG’s obligation to maintain its facilities in accordance with good utility practice is unchanged by PJM’s proposal. Because PJM’s proposal does not place any additional obligations on PSEG for maintaining or replacing facilities, we see no reason to address cost allocation issues relating to replacement of facilities. Furthermore, we agree with the RTOs that the JOA provisions as proposed only reiterate existing requirements for transmission owners to maintain their facilities in accordance with good utility practice and only apply to when the transmission facilities are available for the NY-NJ PAR coordination process.

F. Other Issues

1. Rockland Load

a. Protest

PSEG states PJM should adjust current procedures for serving Rockland load. PSEG argues PJM is failing to provide sufficient transfer capability to deliver Rockland’s Network Resources to its Network Load, as obligated by planning provisions in PJM’s tariff. PSEG also argues that PJM mischaracterizes the service provided to LSEs by Rockland as Network Integration Transmission Service when it should be characterized as Point-to-Point Transmission Service because the service originates in PJM, flows through NYISO and back into Rockland’s load zone from NYISO.[57] PSEG states that the effect of failing to categorize the service results in the incorrect rate being charged to load serving entities and in the incorrect allocation of revenues to PJM transmission owners associated with providing such service.

b. Answer

Rockland filed an answer stating the RTOs’ proposal makes no changes to the service to Rockland’s load, and that PSEG recognizes this in its protest.[58] Rockland states PSEG argues the current Rockland service does not comply with PJM’s Tarff as it should be characterized as Point to Point Service and not Network Integration Service. Rockland states that PSEG’s arguments regarding Rockland’s service are outside of the scope of the proceeding and should be rejected.[59]
In their answer, the RTOs restate they do not propose to modify the service to Rockland’s load in this proceeding. The RTOs also reiterate that they agree to continue discussion on alternative ways to serve Rockland load, and explained how Rockland’s load is served.[60] The RTOs state they include this information to clarify their proposal does not involve changes to how Rockland’s load is served, and PSEG’s comments are outside of the scope of this proceeding.

c. Commission Determination

PSEG’s concerns regarding service provided to Rockland load are beyond the scope of this proceeding. The instant filing primarily involves interchange scheduling and M2M coordination at the ABC and JK Interfaces once the wheeling arrangement concludes. In pursuit of these efforts, the RTOs have sufficiently supported their proposal to incorporate the current Rockland load construct in the calculation of M2M PAR target flow values for each of the ABC PARs and Waldwick PARs. We are not persuaded by PSEG’s argument that the RTOs should be directed to modify service to Rockland.

2. PJM’s Capacity Emergency Transmission Objective/Capacity Emergency Transmission Limit Process

a. Protest

PSEG states planning assumptions regarding import flows from recent studies supporting Capacity Emergency Transmission Objectives/Capacity Emergency Transmission Limits values in the Base Residual Auction have historically assumed

much lower imports than the planning assumption of 1,300 MW to 1,600 MW of imports used in the JOA protocols.[61] PSEG also argues the RTOs do not explain how the Capacity Emergency Transmission Objectives/Capacity Emergency Transmission Limits (CETO/CETL) calculations accounted for certain deliverability violations when NYISO exports power to PJM on the ABC Interfaces, and may have not coordinated models to determine generation adequacy.[62] PSEG argues the JOA protocols do not specify how the seam will be managed under emergency conditions, and unexplained assumptions regarding expected exports from NYISO when the system is under stress underscores this need.[63]

b. Answers

The RTOs state that the allegation that PJM’s CETO/CETL determinations lack transparency is unfounded, as PJM posts parameters and studies for the CETO/CETL values used in its Base Residual Auctions on its website, and calculations for CETO/CETL values that use load deliverability procedures are outlined in PJM’s manuals.[64] The RTOs explain that PJM’s manuals outline that load deliverability studies assume peak summer conditions, and that PJM considers potential generation retirements in its CETL assumptions. The RTOs also explain the JOA provides flexibility to determine an appropriate level of imports in load deliverability studies from NYISO to PJM, and that the JOA addresses emergency assistance between the RTOs which allows PJM and NYISO to coordinate PAR adjustments.[65]
In an answer, PSEG argues the RTOs’ Answer does not justify its import assumptions of 1,600 MW when calculating CETO/CETL values and this lack of transparency needs to be addressed. PSEG reiterates that the RTOs’ explanation of CETO/CETL determinations does not justify transparent processes. PSEG argues the RTOs did not consider that the JOA permits the use of the JK and ABC PARs for Market to Market purposes under certain circumstances, and the level of congestion that would occur without a 400 MW OBF identified by the RTOs studies would be diminished.[66]

c. Commission Determination

We find that the explanation provided in the RTOs' Answer demonstrates that PJM is transparent with the information related to CETL/CETO values and calculations, as this information is posted on its website, and the processes used to calculate these values are outlined in its manuals. Thus, we decline to require additional provisions regarding the sharing of these values.

3. Order No. 888 Compliance

a. Protest

NRG argues that the RTOs’ proposal is not just and reasonable because it fails to follow the requirements under Order No. 888.[67] NRG states that the RTOs’ proposal to include an OBF of 400 MW over the Controllable Ties when scheduling interchange and when determining target flows represents a barrier to open access by preventing other entities from using those ties.

b. Answer

In its answer, the RTOs argue that the proposed OBF would not create a barrier to entry that violates Order No. 888. The RTOs explain that the OBF would instead increase the scheduling capability over the ties, and therefore allow more opportunities for market participants to schedule interchange that uses the ABC and JK facilities. Absent the OBF, the RTOs argue that the scheduling limit would have to be reduced. The RTOs state that since the OBF was designed without using the full flow control capabilities of the PARs, the maximum PAR control capability would remain available for system use by all parties. The RTOs argue that use of the OBF represents the best alternative to preserve system reliability while providing the optimal level of economic interchange.

c. Commission Determination

We are not persuaded by NRG’s argument that the proposed OBF violates Order No. 888. We agree with the RTOs that the proposed OBF would ensure that maximum PAR control and transfer capability would remain available to market participants. We also agree with the RTOs that the proposed OBF would increase the available scheduling capability over the ties, and therefore allow for more opportunities for market participants to schedule interchange that uses the ABC and JK facilities. As a result, scheduling capability over the ties will not be degraded and market participants will not face a barrier to entry.

4. Incorporating the OBF in the RTOs’ Planning Models

a. Protest

NRG and PSEG argue that there are unexplained inconsistences between the planning criteria utilized by PJM and those utilized by NYISO. NRG states that, while PJM intends to assume no OBF in its planning models, NYISO will continue to assume the full 400 MW OBF for at least the next five years. NRG argues that the RTOs have not explained this discrepancy. Further, NRG requests that the Commission require NYISO to clarify how the 400 MW OBF will be included in its planning for the next five years. NRG states that it is not clear how NYISO will conduct its planning models, including its 10-year reliability analysis to incorporate the 400 MW OBF for only five years.

b. Answer

In regard to differences in their respective planning processes, the RTOs explain NYISO’s planning models will include the OBF for transmission security studies through 2021 as planning studies are designed to represent the power system according to the NYISO day-ahead energy market.[68] The RTOs explain NYISO will also include an OBF in its five year Reliability Needs Assessment, which will include a year without the OBF since the OBF will not be included in the planning models after 2021. The RTOs explain that while NYISO includes the OBF in its studies, PJM does not include the OBF in its planning studies because the system has been planned for 1,000 MW of service and reliability issues identified under a 400 MW OBF would be less severe than those identified without an OBF.[69]

c. Commission Determination

We find that the RTOs have sufficiently supported their differing modeling treatments of the proposed OBF. We find NYISO’s proposal to model the proposed OBF in the day-ahead market and in its transmission security models until the date the OBF is expected to be reduced to zero is consistent with NYISO’s existing modeling practices. We also agree with PJM’s decision to not include the proposed OBF in their planning models because “short-term, non-firm operational procedures are generally not considered in the PJM planning process.”[70] As the RTOs note, PJM will not include the proposed 400 MW OBF in its planning assessments because its system has already been designed to accommodate such flows.[71]
Any effort to require consistent transmission planning is beyond the scope of this FPA section 205 proceeding.[72] We also note NYISO’s commitment that, if NYISO and PJM agree to modify or reduce the proposed OBF before the date it is expected to no longer be needed, NYISO will adjust its day-ahead market model and planning models to incorporate the revised OBF until it is no longer utilized.

5. Requests for Hearing

a. Comments

Linden requests that the Commission set the matter for evidentiary hearings and consider the relationship of this proceeding with the cost allocation issues raised in Docket No. ER17-950-000 regarding the Bergen-Linden Corridor Project.[73] Specifically, Linden argues that the Bergen-Linden Corridor Project was previously proposed to support the wheeling arrangement. Linden states that since it has been assigned a significant cost responsibility for the Bergen-Linden Corridor Project, the Commission should now examine whether the Bergen-Linden Corridor Project is needed with the

establishment of the OBF.[74] PSEG argues that, given the concerns raised in its protest, the filing raises issues of material fact which should be set for hearing and settlement procedures. Specifically, PSEG argues that the 400 MW OBF is not needed for reliability purposes, and that the studies relied upon by the RTOs failed to address normal system operating conditions or consider the impact of uplift payments if the 400 MW OBF is in the dispatch model. New Jersey Board contends that the issues raised by the filing raise the same contentious issues raised in establishing the wheeling arrangement which were set for hearing and settlement procedures.

b. Answer

In response to Linden’s request, the RTOs argue that the instant proceeding and the Docket No. ER17-950-000 proceeding present discrete issues that should be addressed separately.[75] The RTOs state that Linden’s arguments regarding the cost allocation of the Bergen-Linden Corridor Project are outside the scope of this proceeding and irrelevant to the justness and reasonableness of the JOA protocol procedures filed in the instant proceeding.

c. Commission Determination

We deny the requests to set the instant proceeding for hearing and settlement procedures. The issues in this proceeding relate to whether the JOA revisions proposed by the RTOs represent a just and reasonable solution to operating their systems upon the cancellation of the wheeling arrangement. Whether the Bergen-Linden Corridor Project continues to be necessary is outside the scope of this filing.
With respect to PSEG’s arguments, as previously noted, the RTOs have identified reliability issues in Northern New Jersey and delivery limitations when importing and exporting power on the JK and ABC Interfaces, and the proposed OBF will enable efficient economic interchange between the relatively congested Northern New Jersey and Southeastern New York areas. Further, the OBF is necessary to support the RTOs’ goal of effectuating aggregate interchanges schedules across the PJM-NY AC Proxy Bus, and managing regional congestion.[76] Moreover, as noted, the OBF does not establish firm transmission service.

G. Requests for Rehearing and Clarification

1. PSEG and New Jersey Board, and Linden Requests

PSEG and the New Jersey Board contend that the Commission failed to respond to the arguments raised in the protests,[77] and departed from established precedent requiring reasoned decision-making and a satisfactory explanation of its decision.[78] PSEG and the New Jersey Board further contend that the March 31, 2017 Order does not contain a refund mechanism that adequately protects consumers in New Jersey from application of the initial 400 MW OBF.
Linden states that the March 31, 2017 Order did not address any of the arguments raised in protest of the RTO’s filing. Linden seeks clarification that the March 31, 2017 Order is not a final order of which Linden needs to seek rehearing in order to preserve its rights to seek review, and that the Commission will issue a substantive order addressing its arguments. In the alternative, Linden seeks rehearing and contends that without a further order addressing the arguments raised in the protests, the March 31, 2017 Order is arbitrary and capricious and not the result of reasoned decision-making.

2. Commission Determination

The requests for rehearing and clarification are denied because the arguments raised in the protests are addressed in this further order, as discussed above.
The PSEG and New Jersey Board request for rehearing of the refund mechanism is moot because the proposed Tariff revisions are accepted as originally proposed, as discussed above, effective May 1, 2017. Therefore, no refunds are at issue.

The Commission orders:

(A)The RTOs’ filing is hereby accepted, effective May 1, 2017, as requested, as discussed in the body of this order.

(B)The requests for rehearing and clarification of the March 31, 2017 Order are denied, as discussed in the body of this order.

By the Commission.

( S E A L )

Kimberly D. Bose,

Secretary.

[2] Agency Operations in the Absence of a Quorum, 158 FERC ¶ 61,135 (2017).

[3] See New York Independent System Operator, Inc., 158 FERC ¶ 62,270 (2017) (March 31, 2017 Order).

[4] See PJM Interconnection, L.L.C., 132 FERC ¶ 61,221 (2010) (approving the Settlement Agreement continuing the wheeling arrangement, and the related service agreements and operating protocols).

[5] A PAR is an electrical device that is used to help control power flows.

[6] The Indicated New York Transmission Owners include: Central Hudson Gas & Electric Corporation, ConEd, Niagara Mohawk Power Corporation, New York State Electric & Gas Corporation, Orange and Rockland Utilities, Inc., Power Supply Long Island, and Rochester Gas and Electric Corporation.

[35] Indicated New York Transmission Owners Answer at 4.

[36] Indicated New York Transmission Owners Answer at 4.

[37] We note that under its Order No. 1000 regional cost allocation methodology, PJM previously assigned cost responsibility for PJM RTEP projects, including the Bergen-Linden Corridor Project, to ConEd, based on ConEd’s use of the facility during the term of the TSAs and what PJM identified as corresponding benefits to ConEd. See Consolidated Edison Company of New York, Inc. v. PJM Interconnection, L.L.C., 151 FERC ¶ 61,227 (2015), reh’g denied, 155 FERC ¶ 61,088 (2016).

[38] The RTOs also state that the short circuit issues resolved by the Bergen-Linden Corridor Project correct deficiencies on the PSEG system, not on the ConEd system.

[39] PJM Interconnection, L.L.C., 132 FERC ¶ 61,221 (2010) (approving the Settlement Agreement continuing the wheeling arrangement, and the related Service Agreements and Operating Protocols). See section (b)(xi) of Schedule 12 of the PJM Tariff.

[48] Discrepancies between scheduled and actual flows can occur when contract paths for scheduling power do not match physical flows, which can contribute to loop flows, inefficient interface scheduling, and gaming opportunities. CAISO resolved problems with persistent discrepancies between modeled and actual flows by combining multiple interface buses into a single proxy bus. See California Independent System Operator, Corp., 124 FERC ¶ 61,271, at PP 34-40 (2008); order on reh’g and clarification, 128 FERC ¶ 61,103 (2009).

[49] Atlantic City Electric Company, et al. FERC, 295 F.3d 1 (D.C. Cir. 2002) (Atlantic City).

[67] NRG Protest at 4 (citing 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 Stats. & Regs. ¶ 31,036 (1996), order on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 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. 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)).

[73] In Docket No. ER17-950-000, PJM submitted proposed revisions to the PJM Tariff to revise cost responsibility assignments for certain projects included in the PJM RTEP as a result of the conclusion of the wheeling arrangement.

[77] PSEG and New Jersey Board included PSEG’s protest and responsive pleading with their rehearing request.

[78] PSEG and New Jersey Board Rehearing Request at 9 (citations omitted).