Initial Comments on FERC’s Generator Interconnection NOPR

Legal Document

Dated: October 13, 2022

Posted in: , ,

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Improvements to Generator Interconnection Procedures and Agreements

Docket No. RM22-14-000



Pursuant to the Notice of Proposed Rulemaking issued by the Federal Energy Regulatory Commission (“Commission” or “FERC”) on June 16, 2022,[1] the New England States Committee on Electricity (“NESCOE”) files comments on the Commission’s proposed reforms to its pro forma Large Generator Interconnection Procedures (“LGIP”) and pro forma Large Generator Interconnection Agreement (“LGIA”) to address interconnection queue backlogs, improve certainty, and prevent undue discrimination for new technologies.  The NOPR expands on proposals presented in and inquiries made by the Commission on generator interconnection related issues in its Advance Notice of Proposed Rulemaking last year.[2] 


NESCOE is the Regional State Committee (“RSC”) for New England.  It is governed by a board of managers appointed by the Governors of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont and is funded through a regional tariff that ISO New England Inc. (“ISO-NE”) administers.[3]  NESCOE’s mission is to represent the interests of the citizens of the New England region by advancing policies that will provide electricity at the lowest possible price over the long term, consistent with maintaining reliable service and environmental quality.[4]  These comments represent the collective view of the six New England states.


NESCOE appreciates the Commission’s leadership in developing proposed changes to its pro forma LGIA and pro forma LGIP to improve generator interconnection processes.  NESCOE supports the NOPR’s overarching goal of ensuring that generator interconnection procedures and agreements are sufficient “to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, thereby ensuring that rates, terms, and conditions for Commission-jurisdictional services remain just and reasonable and not unduly discriminatory or preferential.”[5]  The generator interconnection process plays a key role in our region’s transition to a future clean energy grid by integrating new resources that help New England states achieve their decarbonization and clean energy requirements.  We look forward to continued engagement with the Commission on proposed reforms to this process.

The Commission’s acceptance of reply comments in this proceeding is particularly helpful in light of the myriad technical and policy issues that the NOPR implicates.  On many of these important issues, NESCOE will be looking to ISO-NE, transmission owners and developers, generators, and others in the region for initial reactions on some features of the proposed rule and may comment on specifics in response.

 III.         Background on New England’s regional variations to the pro forma generator interconnection procedures

NESCOE includes this brief background on New England’s generator interconnection rules to provide a broader context as the Commission considers reforms, particularly to its crediting policies.[6]  Decades ago, states’ decisions to restructure the electricity sector was driven in part by the policy objective of shifting investment risk from consumers to shareholders of merchant companies.  New England’s approach to interconnection-related network upgrade costs is aligned with this principle.

As NESCOE and others have detailed in separate proceedings, generators in New England pay the full cost of interconnection and related network upgrades.[7]  In turn, generators can inject energy onto the grid and access the ISO-NE markets at no additional charge.  Unlike the Commission’s pro forma open access transmission tariff, there is no internal point-to-point transmission service in New England.  Generators do not pay for regional transmission service in our region to transmit their power.[8]

This approach, established at ISO-NE’s inception and reflected in Schedule 11 of the ISO-NE OATT, was part of an overall construct developed “to reflect a fair and equitable balancing of [load and generator] interests.”[9] It was initially filed by NEPOOL, and after conditional acceptance by the Commission, filed by ISO-NE and accepted by the Commission.[10]  The Commission affirmed Schedule 11 with no changes as part of New England’s Order No. 2003[11] compliance process.[12]

In discussing the need for queue reforms, the NOPR does not appear to recognize the different approach that New England has taken to interconnection-related network upgrade costs.  For example, the NOPR states that “[i]nterconnection customers may be even more likely to withdraw in RTO/ISO areas where the Commission has allowed for participant funding of network upgrades, whereby the interconnection customer will not be fully reimbursed for the cost of the network upgrades.”[13]  In New England, as described above, while there is participant funding of network upgrades, the interconnection customer also receives the right to inject power into the entire regional grid at no extra cost.

In addition, generator interconnection rules have not remained static in New England.  NESCOE appreciates initiatives that ISO-NE has undertaken over the past several years to revise interconnection procedures, some of which were aimed at addressing the very same problems the Commission hopes to address with the NOPR’s proposed reforms.  For example, in 2016, ISO-NE filed proposed changes focusing on addressing a backlog of wind generation in the queue.[14]  NESCOE supported those changes, which were expected to make wind generation projects more “study ready,” similar to conventional generators.  NESCOE explained that “the new rules would facilitate the continued integration of wind resources into the ISO-NE system, enhancing competition in the energy markets and furthering state laws that foster the growth of renewable resources.”[15]  The Commission accepted the changes.[16]

Subsequently, ISO-NE proposed changes to implement a cluster approach to studying interconnection requests.[17]  NESCOE supported the proposed revisions to consider interconnection requests as part of a cluster rather than individually, and to allocate certain network upgrade costs needed to accommodate those interconnection requests on a cluster basis, when a specified set of conditions are present in the interconnection queue.[18]  The Commission accepted the revisions, finding that “[b]y allowing interconnection requests to be studied in a cluster, the Clustering Revisions should provide a means to relieve the queue backlog in northern and western Maine, which is one of the primary obstacles to interconnections in that region.”[19]

This history recounted above highlights that each region may employ different interconnection-related rules.  It also highlights the collaborative work that ISO-NE, states, and stakeholders in the region have done to improve generator interconnection processes.  As such, NESCOE fully supports the Commission’s proposal to give transmission providers the option to demonstrate that previously-approved variations continue to be consistent with or superior to the pro forma LGIP as modified by the final rule or continue to be permissible under the independent entity variation standard or regional reliability standard.[20]

 IV.         COMMENTS

A.            Reforms to Implement a First-Ready, First-Served Cluster Study Process

The Commission proposes reforms to the pro forma LGIP that would (i) require transmission providers to offer an optional informational interconnection study, designed to provide additional information to prospective interconnection customers; (ii) require transmission providers to implement a first-ready, first-served cluster study process; and (iii) impose more stringent financial commitments and readiness requirements on interconnection customers.[21]  Additionally, the Commission proposes reforms addressing the allocation of cluster study costs, the allocation of cluster network upgrade costs, and how to handle potential shared network upgrades.[22]

At a high level, NESCOE agrees with the Commission that the existence of interconnection queue backlogs is a problem that warrants potential reforms to generator interconnection processes.  The Commission notes that since the issuance of Order No. 845,[23] which included reforms aimed at addressing interconnection queue backlogs, “the interconnection queue backlog has persisted and worsened.”[24]  There are likely a multitude of reasons contributing to the problem of interconnection queue backlogs, some of which reforms to the Commission’s pro forma LGIP may be able to ameliorate, and some, on the other hand, which may be out of the Commission’s control, such as a “nationwide shortage of qualified engineers to keep pace with the increasing number of interconnection requests in the queue and associated interconnection studies.”[25]  The Commission also identifies concerns with a high number of speculative interconnection requests in queues that ultimately withdraw, thereby having clogged up the interconnection queues.[26]  The Commission concludes that “[i]n recent years, late-stage withdrawals of interconnection requests have caused significant delays in interconnection study processes.”[27]

NESCOE agrees with the Commission that there may be flaws in generator interconnection processes that require reform, and NESCOE appreciates the Commission’s efforts to improve the efficiency of generator interconnection processes.  The Commission offers a number of specific and detailed proposals in the NOPR that cover a range of issues proposing reforms to address the various articulated concerns.  NESCOE looks forward to reviewing comments from others in New England, including ISO-NE, on the practical impacts of many of the details in the proposal before weighing in on specific details.  At this time, NESCOE offers high-level feedback below.

1.              The NOPR’s Proposed Cluster Study Process Is an Improvement Over the ANOPR’s Suggested “Fast-Track” Process.

NESCOE appreciates the Commission’s shift away from a “fast-track” approach, which it had raised in the ANOPR.  There, the Commission sought comment on “whether a fast-track generator interconnection process should be developed to facilitate interconnection of generating facilities that have firmly committed to connecting to new regional transmission facilities.”[28]  The Commission also noted that it was “considering whether allowing a fast-track for ‘ready’ interconnection requests would remove barriers to entry for interconnection requests that have met certain readiness criteria.”[29]

NESCOE advocated for a more holistic approach to queue management and continues to believe that a fast-tracking approach would not fully address the problems of speculative projects.  As NESCOE explained:

Fast-tracking would move a group of projects to the front of the line, but it would not prevent speculative projects from entering the queue or root them out when more viable projects are left waiting for study. Potentially more effective reforms could include focusing on limiting or reordering speculative projects in the queue and developing rules to prevent non-viable projects from stagnating in the queue. In taking further action on the queue process, the Commission should consider prioritizing reforms that address its two concerns squarely, which may obviate need for other reforms.[[30]]

Although the issues of preventing speculative projects at the outset and preventing late withdrawals from the queue are linked, different reforms may be needed to address each one.  It is true that some late-stage withdrawals may be projects that were speculative from the outset, but there may be various reasons why previously “ready” projects may become unviable and seek to withdraw.[31]  The Commission’s proposals to move towards a first-ready, first-served cluster study process, in conjunction with its proposals requiring increased financial commitments and readiness requirements, are better suited to achieving the goals of the NOPR.

2.              NESCOE Generally Supports the Proposal for Network Upgrades to Be Shared Among Earlier-in-Time and Later-in-Time Interconnection Customers.

The Commission notes that there are currently no provisions in the pro forma LGIP requiring transmission providers to share network upgrade costs between customers studied in earlier clusters and customers studied in later clusters,[32] and preliminarily finds that the absence of any such network upgrade cost sharing provisions poses a barrier to entry to generation development.[33]  The Commission explains that earlier-in-time interconnection customers may be reluctant to move forward if there is no opportunity for cost recovery of the costs associated with network upgrades that could benefit later-in-time interconnection customers.[34]  The Commission proposes to revise its pro forma LGIP and pro forma LGIA to require sharing of network upgrade costs and describes very detailed and specific proposals.[35]

NESCOE generally supports the concept of requiring network upgrade costs to be shared between earlier-in-time and later-in-time interconnection customers.  In one New England state, for example, a conceptually similar cost-sharing mechanism is already in place at the distribution level.[36]  Indeed, NESCOE sees merit in this reform regardless of whether or not a final rule ultimately requires a cluster study process.  The first generator interconnection customer to initially fund a network upgrade likely takes on more risk compared to later-in-time generator interconnection customers.  In the event that the Commission does not require a cluster study process, NESCOE suggests that the Commission explore whether crediting could be structured to account for that dynamic.

NESCOE agrees with comments that developing actual cost-sharing arrangements can be complicated, resource-intensive, and potentially contentious.[37]  In New England, for example, some interconnection points are at or close to capacity, making the task of developing an approach that allocates costs between earlier- and later-interconnecting customers particularly challenging.  It is essential that a final rule addressing cost-sharing arrangements provides a clear and well-defined path for implementation.  One way that the Commission can minimize the contentious nature of developing cost-sharing arrangements, particularly in Regional Transmission Organizations (“RTOs”)/Independent System Operators (“ISOs”), is to allow regions some flexibility in coordinating with their states on developing proposed approaches to sharing the costs associated with earlier-in-time generator funded transmission upgrades.  NESCOE looks forward to reviewing comments from ISO-NE, interconnection customers, and others on this issue.

3.              NESCOE Generally Supports Increased Financial Commitments and Readiness Requirements.

The Commission expresses concern that interconnection queue backlogs and study delays are caused, at least in part, “by the minimal requirements for submitting interconnection requests and the tendency for non-viable projects to linger in interconnection queues.”[38]  The Commission concludes that existing pro forma LGIP requirements may be insufficient “because they do not require customers to demonstrate commercial readiness early enough in the study process to deter interconnection customers from submitting interconnection requests for, and continuing in the interconnection queue, speculative proposed generating facilities.”[39]  To address these concerns, the Commission proposes to revise the pro forma LGIP to include a “commercial readiness framework.”[40]

To effectuate this, the NOPR proposes several options for an interconnection customer to demonstrate commercial readiness, which would be required to enter a cluster study and cluster restudy:  (i) an executed term sheet (or comparable evidence) for the sale of the generating facility, or for the sale (lasting at least five years) of the facility’s energy, capacity or ancillary services; (ii) reasonable evidence that the project has been selected in a resource plan or resource solicitation process by or for a load-serving entity (“LSE”), is being developed by LSE, or is being developed for purposes of a sale to a large end-use customer; or (iii) a provisional LGIA which has been filed at the Commission (executed or unexecuted), which is not suspended and includes a commitment to construct the generating facility.[41]  The NOPR goes on to propose similar commercial readiness standards to enter the facilities study[42] and proposes to require the interconnection customer to inform the transmission provider of any material change to its commercial readiness demonstration.[43]  The Commission also finds that it may be appropriate to allow refundable deposits in lieu of a commercial readiness demonstration.[44]  The NOPR lays out its proposed levels for a “commercial readiness deposit,” which range from twice the study deposit to enter the initial study cluster, up to seven times the study deposit after receipt of the facilities study agreement.[45]

NESCOE generally supports more stringent demonstrations of commercial readiness to help weed out speculative projects.  However, NESCOE is interested in assessing the record in this proceeding, and specifically whether commenters will identify potential unintended consequences relating to this proposal.  As one potential example, the proposed criteria for a commercial readiness demonstration would appear to exclude non-contracted resources, where there may be other demonstrations that can reasonably substitute for an executed contract.  Any final rule should consider any such unintended consequences.

Likewise, NESCOE is interested in reviewing the record to assess whether the proposed requirements for commercial readiness could have the unintended consequence of narrowing the scope of resources that wish to participate in RTO/ISO markets, which in turn could diminish the benefits customers receive from competition.  If so, the Commission should consider expanding its list.  For example, commercial readiness might be demonstrated through a certified intent to participate in an RTO/ISO market coupled with an additional requirement, such as a good faith purchase of equipment.  NESCOE hopes that the Commission will remain open to allowing additional ways for projects to demonstrate commercial readiness.

B.             Reforms to Increase Speed of Interconnection Queue Processing

1.              A Final Rule Should Hold Transmission Providers, Along with Others, Accountable for Efficient Interconnection Queue Processing.

The Commission believes that compounding other factors contributing to delays in interconnection queues is the fact that the pro forma LGIP lacks a requirement for transmission providers to meet deadlines for conducting interconnection studies.[46]  NESCOE agrees that both interconnection customers and transmission providers share responsibility for the efficient processing of an interconnection queue.  NESCOE appreciates the Commission’s focus on possible improvements transmission providers can make, given their role in ensuring the timely interconnection of new resources.

NESCOE recently reiterated its strong support for transmission planning reforms in light of the New England states’ clean energy laws and mandates, which are driving substantial changes to the region’s resource mix.  As NESCOE explained, New England is moving steadily toward a clean energy future, as achieving a decarbonized system is required by laws and mandates in Connecticut, Maine, Massachusetts, Rhode Island, and Vermont.[47]  ISO-NE’s interconnection queue illustrates the rapid pace of this change.  Over a five-year time span, natural gas generation composed 48% of capacity in the 2017 queue, and by March 2022, natural gas comprised just 3% of the queue.[48]  Wind, batteries, and solar now combine for over 95% of the capacity in the queue.[49]

Timelines for completing interconnection studies are critically important—they provide predictability to the market and impact the ultimate development schedule.  At the same time, reforms to speed up interconnection queue processing are challenging to design because integral to the process are not just transmission providers but other parties, including manufacturers and the interconnecting customers themselves.  A final rule should incentivize transmission providers to complete interconnection studies in a timely manner in a way that also affords them sufficient flexibility to meet the needs of interconnecting customers.  NESCOE looks forward to reviewing suggestions made by transmission providers, transmission owners, interconnection customers, and others on the details of how to accomplish this.

2.              Elimination of the Reasonable Efforts Standard Should Be Implemented in a Way That Does Not Penalize the Transmission Provider’s Ratepayers.

The pro forma LGIP requires transmission providers to use “reasonable efforts” to process interconnection requests in a timely manner but does not include any penalties or other financial consequences if the transmission provider fails to meet the deadlines.[50]  The Commission appropriately is considering new mechanisms to hold transmission providers accountable for study delays.  There are, however, important tradeoffs to consider in any final rule implementing the proposed elimination of the reasonable efforts standard and the imposition of firm deadlines and penalties,[51] at least as is applicable to RTOs/ISOs.[52]

First and foremost, a final rule should ensure that ratepayers do not bear the cost of the penalties.  As is recognized in the NOPR, assigning penalties to RTOs/ISOs is complex, or as the NOPR puts is, “may raise several unique issues.”[53]  While well intended, the Commission’s proposal could result in numerous filings and litigation in RTOs/ISOs, draining the RTO’s/ISO’s (and others’) resources and diverting from the important business of completing studies.  This in turn could potentially increase costs to the detriment of ratepayers.  If a final rule is not carefully constructed, ratepayers could ultimately pay the penalties that an RTO/ISO would be liable for, even though consumers would not, of course, have had any nexus to the identified wrongdoing.

NESCOE appreciates the proposal that to ensure that non-profit RTOs/ISOs are able to pay any penalties incurred, they may make a FPA section 205 filing seeking to allocate such penalties to the appropriate transmission owner that is responsible for, or contributed to, the delay.[54]  This is a step in the right direction.  If the Commission does move forward with this proposal, and the penalty is charged to the transmission owner, the Commission should also ensure that the transmission owner cannot pass the penalty on to its transmission customers.

Additionally, there should be some form of exemption for situations where the cause for delay is outside the control of the RTO/ISO and the transmission owner.  The NOPR does not contemplate a situation where the delay is not the “fault” of the RTO/ISO or the transmission owner.  Likewise, the NOPR does not specify what constitutes “fault” in the event of delay in processing interconnection studies and a clear standard would be useful for RTO/ISO planning as well for avoiding costly and time-consuming disputes.  The Commission should consider developing a narrow list of presumptive “no-fault delays” to give guidance and help minimize contention going forward.  Clarity and details on these types of issues are critical if the Commission moves forward with this proposal.  This is especially important because there is not a clear connection between the threat or imposition of penalties and the timely completion of studies, especially where there are factors that may be out of the control of RTOs/ISOs.  In fact, exposure to penalties could incentivize a transmission provider to add more pre-study requirements and specificity that could result in similar overall timelines.

Finally, the Commission should consider whether such a penalty structure would unintentionally impede the interconnection of emerging technologies over time by limiting the flexibility and time for transmission providers to work with interconnecting customers on modeling and data requirements.

3.              NESCOE Supports the Concept of an Optional Resource Solicitation Study.

NESCOE appreciates the Commission’s exploration of a mechanism that would afford resource planning entities, including states, an opportunity to initiate an optional resource solicitation study.[55]  In New England, it is crucial that states have a central role given that state laws and requirements are driving changes in the resource mix and the associated impact on the interconnection queue.  NESCOE supports the concept of the proposal—optionality for states to request study of combinations of interconnection requests.  Such a tool could provide states with greater visibility into potential procurement activities.  As the NOPR explains, “[b]y giving resource planning entities the ability to initiate an optional resource solicitation study, these reforms may also enable qualifying state agencies and LSEs to obtain better information about the interconnection requirements and potential network upgrade costs of various configurations of interconnection requests associated with bids submitted into their solicitations.”[56]  A carefully constructed Optional Resource Solicitation Study process has the potential to be a valuable tool, particularly in regions like New England where state procurement processes are a significant component.

NESCOE acknowledges, as the NOPR does, the need for guardrails around such a process to ensure it does not delay the study of other interconnection requests by diverting needed resources away from the general queue.  NESCOE is directionally supportive of the proposal to prohibit transmission providers from delaying other interconnection requests not involved in the solicitation.[57]

As with other aspects of the NOPR, NESCOE looks forward to reviewing comments submitted by ISO-NE and others on details of these proposals and any suggestions on how to address the pragmatic issues of integrating optional resource solicitation studies with existing study queues.

   V.         CONCLUSION

NESCOE respectfully requests that the Commission consider its comments in developing any final rule in this proceeding or taking further action on the potential reforms discussed in the NOPR.

Respectfully Submitted,

/s/ Jason Marshall                 

Jason Marshall

General Counsel

New England States Committee on Electricity

P.O. Box 322

Osterville, MA 02655

Tel: (617) 913-0342


/s/ Phyllis G. Kimmel             

Phyllis G. Kimmel

Phyllis G. Kimmel Law Office PLLC

1717 K Street, NW, Suite 900

Washington, DC 20006

Tel: (202) 787-5704


Attorneys for the New England States Committee on Electricity

Date:  October 13, 2022

Document Source Citations

[1]     Improvements to Generator Interconnection Procedures and Agreements, Notice of Proposed Rulemaking, 179 FERC ¶ 61,194 (2022) (“NOPR”).

[2]     Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, Advance Notice of Proposed Rulemaking, 176 FERC ¶ 61,024 (2021) (“ANOPR”).  NESCOE submitted comments on the ANOPR last fall.  Initial Comments of the New England States Committee on Electricity, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“NESCOE ANOPR Initial Comments”).

[3]     ISO New England Inc., 121 FERC ¶ 61,105 (2007).  Capitalized terms not defined in these Initial Comments are intended to have the meaning given to such terms in the ISO-NE Transmission, Markets and Services Tariff (“Tariff” or “ISO-NE Tariff”) or in the NOPR.  Section II of the Tariff is the Open Access Transmission Tariff (“OATT”).

[4]     See Sept. 8, 2006 NESCOE Term Sheet (“Term Sheet”) that was filed for information as Exhibit A to the Memorandum of Understanding among ISO-NE, the New England Power Pool (“NEPOOL”), and NESCOE (the “NESCOE MOU”).  Informational Filing of the New England States Committee on Electricity, Docket No. ER07-1324-000 (filed Nov. 21, 2007).  Pursuant to the NESCOE MOU, the Term Sheet is the binding obligation of ISO-NE, NEPOOL, and NESCOE.

[5]     NOPR at P 22.

[6]     NESCOE provided this information in its ANOPR comments (see NESCOE ANOPR Initial Comments at 50-51) but repeats it here as it is relevant to this NOPR.

[7]     Comments of the New England States Committee on Electricity, Docket No. AD20-18-000 (filed May 10, 2021), at 17-19.  See also Comments and Protest of the New England Power Pool Participants Committee (“NEPOOL”), Docket No. EL18-31-000 (filed Dec. 6, 2017) (“NEPOOL Schedule 11 Comments”), at 3-11 (discussing history of origin and development of ISO-NE’s Schedule 11).

[8]     See NEPOOL Schedule 11 Comments at 4.  See also ISO-NE Tariff, Section II.12.2 (“Regional Network Service shall be taken and paid for by each Eligible Customer which has a load within the New England Control Area . . .  .”).

[9]     NEPOOL Schedule 11 Comments at 3-4

[10]   See id. at 4-7 (discussing history of Schedule 11).  The Commission accepted ISO-NE’s filing of Schedule 11 over 20 years ago.  ISO New England, Inc., et al., 91 FERC ¶ 61,311 (2000).

[11]   Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, 104 FERC ¶ 61,103 (2003), order on reh’g, Order No. 2003-A, 106 FERC ¶ 61,220, order on reh’g, Order No. 2003-B, 109 FERC ¶ 61,287 (2004), order on reh’g, Order No. 2003-C, 111 FERC ¶ 61,401 (2005), aff’d sub nom. Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).

[12]   New England Power Pool, 109 FERC ¶ 61,155 (2004).  See NEPOOL Schedule 11 Comments at 7-10.

[13]   NOPR at n.108.

[14]   ISO New England Inc. and the Participating Transmission Owners Administrative Committee, Revisions to Schedules 22, 23 and 25 of the Open Access Transmission Tariff Relating to Certain Interconnection Process Improvements, Docket No. ER16-946-000 (filed Feb. 16, 2016), at 2 (“Interconnection Process Improvements are the result of the first phase of a larger effort that the ISO, in conjunction with stakeholders, initiated in July 2015 to specifically address the interconnection challenges experienced mostly in the Maine portion of the system, where a significant queue backlog has emerged due to Interconnection Requests for more than 4,000 megawatts (as of February 1, 2016) of new generation (mostly wind).”) (emphasis in original).

[15]   Comments of the New England States Committee on Electricity, Docket No. ER16-946-000 (filed Mar. 8, 2016), at 2 (citation omitted).

[16]   ISO New England Inc. and Participating Transmission Owners Administrative Committee, Letter Order, 155 FERC ¶ 61,031 (2016) (conditionally accepting changes subject to compliance filing amending Small Generator Interconnection Agreement).

[17]   Joint Filing of Revisions to the ISO New England Inc. Transmission, Markets and Services Tariff to Incorporate a Clustering Approach in the Interconnection Procedures, Docket No. ER17-2421-000 (filed Sept. 1, 2017).

[18]   Comments of the New England States Committee on Electricity, Docket No. ER17-2421-000 (filed Sept. 22, 2017), at 4-5 (“By providing a mechanism for projects to be studied together, the Clustering Revisions increase efficiencies, inform the decisions of project developers, and offer a methodology for project developers to share upgrade costs.  Implementation of a cluster mechanism in New England also better aligns the region’s interconnection processes with those available to developers in other regions.”).

[19]   ISO New England Inc., 161 FERC ¶ 61,123, P 18 (2017).

[20]   NOPR at P 342.

[21]   Id. at P 39; see also id. at PP 40-48 (informational interconnection study), PP 53-79 (cluster study), and PP 102-148 (increased financial commitments and readiness requirements).

[22]   Id. at PP 80-83 (allocation of cluster study costs), PP 84-89 (allocation of cluster network upgrade costs), and PP 90-101 (shared network upgrades).

[23]   Reform of Generator Interconnection Processes and Agreements, Order No. 845, 163 FERC ¶ 61,043 (2018), order on reh’g, Order No. 845-A, 166 FERC ¶ 61,137, order on reh’g, Order No. 845-B, 168 FERC ¶ 61,092 (2019).

[24]   NOPR at P 18.

[25]   Id. at P 20.

[26]   Id. at PP 25-27.

[27]   Id. at P 37.

[28]   ANOPR at P 155.

[29]   Id. at P 157.

[30]   NESCOE ANOPR Initial Comments at 54-55.

[31]   Id. at 54.

[32]   NOPR at P 90.

[33]   Id. at P 97.

[34]   Id.

[35]   Id. at P 98.

[36]   In Massachusetts, the tariff governing interconnection for the three investor-owned electric distribution companies includes a “clawback” provision, allowing costs for certain upgrades to be shared among earlier- and later-in-time customers.  See Fitchburg Gas and Electric Light Company d/b/a Unitil – M.D.P.U. No. 269; Massachusetts Electric Company and Nantucket Electric Company, each d/b/a National Grid – M.D.P.U. No. 1320; and NSTAR Electric Company d/b/a Eversource Energy – M.D.P.U. No. 55 at Section 5.3.

[37]   NOPR at P 96 (citing Comments of Transmission Access Policy Study Group, Docket No. RM21-17-000 (filed Oct. 12, 2021), at 47-48).

[38]   NOPR at P 127.

[39]   Id.

[40]   Id. at P 128.

[41]   Id. at P 129.

[42]   Id. at P 130.

[43]   Id. at P 131.

[44]   Id. at P 132.

[45]   Id. at P 133.

[46]   NOPR at P 28.

[47]   Initial Comments of the New England States Committee on Electricity, Docket No. RM21-17-000 (filed Aug. 17, 2022), at 15-16.

[48]   ISO-NE, 2022 Regional Electricity Outlook, July 2022, at 15, at

[49]   Id.

[50]   NOPR at PP 161-62.

[51]   Id. at P 168.

[52]   As the RSC for New England, NESCOE’s perspective focuses on RTOs/ISOs, and NESCOE does not take a position on this issue with respect to non-RTO/ISO regions.

[53]   NOPR at P 171.

[54]   Id. at P 172.

[55]   Id. at P 223.  FERC proposes defining a resource planning entity as any entity required to develop a resource plan or conduct a resource solicitation process, including a relevant state entity, LSE or wholesale customer, depending on the state mandate.  Id. at n.315.

[56]   Id. at P 228.

[57]   Id. at P 233.