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UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Building for the Future Through Electric
Regional Transmission Planning and Cost Allocation and Generator Interconnection
Docket No. RM21-17-000
INITIAL COMMENTS OF THE
NEW ENGLAND STATES COMMITTEE ON ELECTRICITY
August 17, 2022
Pursuant to the Notice of Proposed Rulemaking issued by the Federal Energy Regulatory Commission (“Commission” or “FERC”) on April 21, 2022, and the Commission’s Notice on Requests for Extension of Time issued in this docket on May 25, 2022, the New England States Committee on Electricity (“NESCOE”) files comments on the Commission’s proposed reforms to address deficiencies in the Commission’s electric regional transmission planning, cost allocation, and generator interconnection processes.
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. 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.
The Commission’s commitment to meaningful transmission planning reform is clear from the depth and breadth of the proposals contained in the NOPR. NESCOE appreciates the Commission’s leadership in seeking to ensure that Commission-jurisdictional transmission rates remain just and reasonable and not unduly discriminatory or preferential, and in recognizing that existing Order No. 1000-compliant regional transmission planning “processes may not be planning transmission on a sufficiently long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand.”
NESCOE has long expressed that in order for regional transmission planning processes to produce transmission rates that are just and reasonable, such planning processes cannot ignore the existence of state public policy requirements. The NOPR sets the stage for needed change. It provides momentum for fundamental shifts in regional transmission planning.
In New England, the historic shift in clean energy resource development is not just the future—it is here now. As described below, New England is in many ways already charting a path toward enhanced visibility into transmission needs driven by the changing resource mix and public policy requirements. NESCOE looks forward to continuing close work with the Commission and its staff to effectuate what appears to be a shared vision between the Commission and the New England states on planning proactively for the future grid and ensuring that states can occupy a meaningful role in planning and cost allocation processes. The New England states greatly value their partnership with the Commission.
While NESCOE strongly supports many aspects of the NOPR, there is a noticeable gap in the rules proposed. The Commission leaves for another time proposed reforms to implement enhanced cost oversight in connection with transmission rates. The ANOPR drew a straight line from proposed long-term regional transmission planning reforms and the need to protect consumers from excessive costs. It stated that “[t]he potential for a significant investment in the transmission system in the coming years underscores the importance of ensuring that ratepayers are not saddled with costs for transmission facilities that are unneeded or imprudent.” The Commission also expressed “that ensuring just and reasonable rates, while maintaining grid reliability, remain the priorities for regional transmission planning, and cost allocation processes, and generator interconnection processes, and any comments proposing revisions to existing regulations should address their impact on reliability and costs to customers.” The Commission solicited comment on “whether the current approach to oversight of transmission investment adequately protects customers, particularly given the potentially significant and very costly investments proposed to meet the transmission needs driven by a changing resource mix, and, if customers are not adequately protected from excessive costs, which potential reforms may be required and are legally permissible to ensure just and reasonable rates.”
NESCOE strongly supported the concept of independent transmission monitors as a means of ensuring transmission costs are transparent and closely scrutinized. NESCOE also advocated that the Commission “prioritize reforms that promote cost discipline and cost containment generally, not just tethered to potential transmission monitors. Key among these reforms should be enhancing competition in the development and construction of transmission solutions.” The NOPR omits any proposal on independent transmission monitors and, in NESCOE’s view, takes a major step backwards in proposing to reinstate some form of the federal right of first refusal (“ROFR”) based on the current record.
The Commission’s plan to hold a technical conference this fall focusing on cost management issues related to transmission planning should be a helpful forum for continuing discussion in this area. However, NESCOE emphasizes the challenge in commenting on proposed long-term regional transmission planning rules without knowing whether and how the Commission intends to reform transmission cost oversight and management. This leaves open crucial questions regarding the details of and timing of potential reforms addressing transmission cost management. The farther out the planning horizon is, the less certain transmission providers, states, and stakeholders can be that any identified transmission need will still exist at the future date, or that it will not have changed. Additional tools to help manage and provide greater visibility into cost implications are critical. As an independent market monitor to four regional transmission operators (“RTOs”)/independent system operators (“ISOs”) commented in this proceeding, the NOPR’s contemplated reforms “will have substantial economic implications for different classes of customers” and enhanced oversight of transmission system planning and costs “would enhance the transparency of the planning processes and help ensure that the most economic investments are identified.” To the extent the Commission adopts a final rule implementing long-term regional transmission planning reforms, it should accompany those reforms with proposed rules providing for enhanced cost oversight and cost containment. To this end, NESCOE respectfully asks the Commission to expedite the development of a companion proposed rule providing for consumer cost protections.
Additionally, as the Commission develops a final rule in this proceeding, it should be careful to ensure that it does not inadvertently impede ongoing progress in regions where states and RTOs/ISOs are already collaborating on executing new planning frameworks that align directionally with the NOPR. In New England, for example, ISO-NE recently implemented Tariff provisions that establish a process by which the New England states can request longer-term transmission modeling. ISO-NE is in the process of completing the first analysis under this new process, the 2050 Transmission Study, which ISO-NE initiated in response to the New England states’ previously articulated concerns on the need for longer-term visibility into system needs accounting for state laws and mandates. At the states’ request, ISO-NE is expected to commence soon a stakeholder process addressing the potential for project solicitations following study results and addressing an associated cost allocation mechanism. NESCOE respectfully cautions the Commission against implementing reforms that are so prescriptive that they could disrupt momentum in New England on these issues or redirect resources needed to bring them to completion on their current time track.
NESCOE appreciates that other regions may not be in a similar circumstance and that the Commission may wish to establish minimum standards on many of these issues. But first and foremost, the Commission should “do no harm,” as Commissioner Christie recently noted in relation to a proposed rule on interconnection, in prescribing regulatory reforms and should be careful not to impede progress in regions like ISO-NE that have already acted directionally consistent with the NOPR.
As discussed throughout the comments below, NESCOE believes that some of the proposals in the NOPR, while well-intentioned, are overly detailed and prescriptive. These proposals could, at best, divert resources from New England’s progress on these very issues, or worse, throw a wrench into those efforts altogether because they may not match fully to the minute details of the NOPR’s proposals. NESCOE’s comments are intended to help ensure that new planning rules align with these activities, provide greater flexibility in some areas, and do not serve at cross-purposes to regions that generally share the Commission’s priorities for long-term regional transmission planning reforms. NESCOE offers these comments in the spirit of continued close collaboration with the Commission.
NESCOE’s comments center around three primary themes: (1) the need for regional flexibility, (2) the importance of a central role for states, and (3) consumer protection. NESCOE summarizes its perspective on key issues at the highest level in this executive summary, with more detail and explanation included in the comments below.
NESCOE generally supports reforms that would require transmission providers to conduct regional transmission planning on a longer-term basis, with the goal of evaluating transmission needs driven by changes in the resource mix and demand. New England has already made significant progress in this area—progress that is directionally consistent with much of the NOPR. ISO-NE recently implemented Tariff changes establishing a longer-term transmission planning process that gives the New England states the ability to request longer-term scenario modeling. Later this year, ISO-NE will initiate a stakeholder process to address the potential for project solicitations following the results of a longer-term study requested by the states and an associated cost allocation mechanism.
Against this backdrop, NESCOE believes that some of the proposed requirements set forth in the NOPR are too prescriptive and could undermine the work underway in New England. NESCOE recommends that the Commission focus on establishing broad principles in its reforms while allowing regions flexibility in determining the details of how best to comply with the reforms. Areas where NESCOE believes flexibility is warranted include:
- Adaptation of and/or modification of existing Order No. 1000 processes to comply with a final rule in this proceeding;
- The appropriate planning horizon for modeling Long-Term Scenarios;
- The frequency with which Long-Term Scenarios are developed and completed;
- Development of the factors to be incorporated into Long-Term Scenarios;
- The specific number of Long-Term Scenarios that should be used;
- The study of high-impact, low-probability events in Long-Term Scenarios;
- Which data inputs to use for Long-Term Scenarios;
- Establishment of geographic zones for use in Long-Term Scenarios;
- Consideration of the impact of generator interconnection-transmission needs in Long-Term Regional Transmission Planning;
- The ability of transmission providers, following consultation with states, to propose on compliance a list of benefits to be considered in evaluation of regional transmission facilities in Long-Term Regional Transmission Planning as well as in cost allocation processes;
- The time horizon over which such benefits will be measured; and
- Implementing right-sizing reforms to account for public-policy driven transmission needs.
NESCOE appreciates the Commission’s recognition of the importance of state involvement in long-term regional transmission planning processes. When it comes to transmission that is being considered to meet state energy and environmental policies, states are more than just a stakeholder. States must have a central role in long-term regional transmission planning related to such state public policy requirements. NESCOE supports the aspects of the NOPR that recognize such a role for states. For example, NESCOE supports the proposals that transmission providers should consult with and seek support from states in the development of selection criteria.
However, in certain respects, the NOPR stops short of fully recognizing the central role that states should play in long-term regional transmission planning. To provide a cohesive structure that would ensure states have a central role throughout all of the proposed reforms, NESCOE respectfully requests that the Commission require transmission providers either to (1) elevate and codify the states’ role in the tariff for all aspects of Long-Term Regional Transmission Planning, or (2) explain how and why, following consultation with the relevant state entities, the transmission provider developed a different approach. Bringing state officials into the conversation both early on and on a continuing basis is the best way to ensure that long-term regional transmission planning will take into account changing resource mixes—both current and future—needed to meet evolving state public policy requirements.
NESCOE commends the Commission for recognizing that states must play a key role in the development of regional transmission cost allocation methods. NESCOE supports the proposal to require transmission providers to attempt to obtain agreement from states regarding whether the region should have an ex ante long-term regional transmission cost allocation method, a state agreement process, or a combination thereof. However, there are certain aspects of the NOPR’s proposed cost allocation rules where the role of states needs to be further clarified and elevated, including:
- The definition of “agreement” should be decided by the relevant state entities;
- The definition of relevant state entities should be expanded to accommodate the composition of RSCs, such as NESCOE; and
- State entities should be provided sufficient time to agree on a cost allocation method, and subsequently, on the actual cost allocation in the event an ex post state agreement approach is used.
Additionally, a few of the proposals regarding the cost allocation reforms are unclear. In particular, and as explained in detail below, NESCOE seeks clarification that if a transmission provider files a State Agreement Process, no ex ante cost allocation method is required. NESCOE also seeks clarification regarding the implications of the Commission’s statements referring to an “alternate” cost allocation method and unanimous agreement of states under such alternate cost allocation method.
NESCOE fully supports the aspects of the NOPR that require transparency. The NOPR proposes to require transmission providers to revise their OATTs, for example, to establish open and transparent processes to offer stakeholders and states with a meaningful opportunity to propose potential factors for incorporation into development of Long-Term Scenarios. These proposals for transparency run throughout the NOPR and NESCOE commends the Commission for its commitment to transparency.
NESCOE strongly supports the Commission’s proposal that the Construction Work in Progress (“CWIP”) incentive should not be available for Long-Term Regional Transmission Facilities. This approach appropriately balances consumer and investor interests.
The Commission should not move forward with proposed actions on reinstating the ROFR in certain circumstances. Meaningful competition is critical to encouraging new market entrants, a bigger pool of ideas, and cost containment practices that incumbent transmission providers have no incentive to offer outside a competitive process. To the extent the Commission continues to be inclined to pursue a rollback of ROFR reforms, it should do so in a separate proceeding where a more focused record can be developed to facilitate the Commission’s decision.
Finally, as discussed above in Section II, the NOPR neglects to address in any meaningful way issues related to cost containment. The upcoming technical conference on these issues may be helpful but it is difficult to see a path forward to long-term regional transmission development as the Commission envisions in the NOPR without any consideration of consumer costs.
Over the past several years, NESCOE has been working closely with ISO-NE to develop a planning process that takes a longer-term view so that the transmission system will be more capable of supporting the changing resource mix. As NESCOE emphasized nearly two years ago, “[a]s a region, we cannot effectively plan for integrating clean energy resources and decarbonization of the electricity system required by certain states’ laws without having a clear understanding of the investments needed in regional transmission infrastructure.”
ISO-NE responded constructively to the Vision Statement’s framework for longer-term regional planning. It undertook two key initiatives in response to the Vision Statement’s identification of the need for a new transmission planning framework: (1) launching the 2050 Transmission Study, designed to provide an analysis through inputs and assumptions developed by the states to enable visibility into potential future transmission system needs that account for the clean energy transition over a longer-term planning horizon; and (2) developing Tariff changes for longer-term transmission planning—a supplementary transmission planning mechanism under which ISO-NE will perform state-requested, scenario-based transmission analyses over potentially longer time horizons.
With respect to the 2050 Transmission Study, in November 2021, ISO-NE presented preliminary assumptions and its proposed methodology, and in April 2022, ISO-NE presented preliminary results of the study. The 2050 Transmission Study examines transmission needs to serve load while satisfying North American Electric Reliability Corporation (“NERC”), Northeast Power Coordinating Council, Inc. (“NPCC”), and ISO-NE reliability criteria in 2035, 2040, and 2050. It will provide transmission upgrade “roadmaps” to satisfy those needs considering both constructability and cost. As ISO-NE explained, “one the goals of the 2050 Transmission Study is to address observed transmission system overloads in a coordinated, long-term-oriented way.” ISO-NE and NESCOE are in discussions on approaches to solution development and cost assumptions/estimates, and these efforts are expected to carry through the remainder of 2022 and possibly into 2023.
Regarding the second initiative, following a stakeholder process last year, ISO-NE filed Tariff changes with the Commission “to incorporate a supplementary transmission planning process for the performance of state-requested, scenario-based transmission analysis to identify high-level transmission infrastructure that could meet state-identified energy policies, mandates, or legal requirements on a regular basis.” These changes provide a mechanism for the New England states, through NESCOE, to request that ISO-NE perform transmission analyses to meet state energy policies, mandates, or legal requirements (“Longer-Term Transmission Study”); such analyses could extend beyond a ten-year planning horizon (but are not required to do so). NESCOE strongly supported the changes, which FERC accepted by letter order, effective February 25, 2022.
The Tariff revisions ensure that the 2050 Transmission Study is not just a one-off analysis for New England. This work is ongoing. As ISO-NE indicated in its filing, the second phase of its effort, scheduled to begin later this year, “will address the rules to enable a state or states to elect potential options for addressing the transmission analysis’ identified issues and cost allocation for the associated transmission infrastructure.”
2. NESCOE Generally Supports the Proposal to Require Transmission Providers to Participate in Long-Term Regional Transmission Planning, so Long as a Final Rule Retains Sufficient Flexibility and Does Not Impede Existing Progress.
The cornerstone of the NOPR is its proposed requirement that transmission providers “conduct long-term regional transmission planning on a sufficiently forward-looking basis to meet transmission needs driven by changes in the resource mix and demand.” The Commission proposes to require transmission providers to participate in a regional transmission planning process that includes Long-Term Regional Transmission Planning, which the Commission defines as:
regional transmission planning on a sufficiently long-term, forward-looking basis to identify transmission needs driven by changes in the resource mix and demand, evaluate transmission facilities to meet such needs, and identify and evaluate transmission facilities for potential selection in the regional transmission plan for purposes of cost allocation as the more efficient or cost-effective transmission facilities to meet such needs.[]
In its ANOPR Comments, NESCOE generally supported the direction in which the Commission seemed to be headed and expressed appreciation for the Commission’s leadership in recognizing a need for longer-term and comprehensive regional transmission analysis to account for this changing resource mix. New England is moving steadily toward a clean energy future. Achieving a decarbonized system is required by laws and mandates in Connecticut, Maine, Massachusetts, Rhode Island, and Vermont. As ISO-NE stated in a report last month, “[t]he New England states are moving to reduce carbon emissions from the electric, heating, and transportation sectors, setting aggressive targets to increase renewable energy resources and reduce greenhouse gas emissions to nearly zero by 2050.” In just the past five years, ISO-NE’s generator interconnection queue demonstrates the fast pace of this change. Natural gas generation composed 48% of capacity in the 2017 queue, and by March 2022, was down to just 3%. Wind and solar now combine for over 70% of the capacity in the queue.
Particularly in light of the ongoing collaborative work in New England on transmission planning, it is paramount to give regions like ISO-NE flexibility in implementing reforms. The Commission should take great care to ensure that it does not inadvertently undermine ongoing progress where states and RTOs/ISOs are already collaborating on executing new planning frameworks. This would include allowing transmission providers the flexibility to demonstrate in their compliance filings that their existing tariff provisions are already in compliance with any forthcoming final rule. Such flexibility would be consistent with the Commission’s approach in prior rulemakings, including Order No. 1000. 
3. States Must Occupy a Central Role in Transmission Planning and Cost Allocation Related to State Requirements.
It is critical that a final rule ensure that states are centrally involved in all aspects of Long-Term Regional Transmission Planning related to the execution or integration of state energy and environmental requirements. This is imperative if the proposed reforms are to effectively address the Commission’s articulated concern that Order No. 1000 regional transmission planning and cost allocation processes “may not be planning transmission on a sufficiently long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand.”
To be successful, the reforms must provide regions flexibility to involve and rely upon state input (including utilizing RSCs where applicable) regarding the various phases of transmission planning and cost allocation where state laws and policies are implicated: (1) identification of laws, regulations, and/or policies that drive potential transmission needs; (2) evaluation of transmission projects to meet those needs; (3) selection of transmission projects; and (4) cost allocation. In New England, the Commission carved out a role for states with respect to identification of Public Policy Requirements driving transmission needs, but orders on compliance excluded states in New England from having any special role in evaluating or selecting projects to meet those needs. The New England states can only offer input on projects as a “stakeholder,” even if a state’s own legal requirements are identified as being drivers of the projects and despite the Federal Power Act (“FPA”) clearly reserving authority to states over electric power supply within their borders.
This absence of a defined state role throughout the public policy planning process was a flaw in Order No. 1000 that, in New England, has impeded use of Tariff provisions for public policy-driven projects. Where transmission upgrades support the execution of state laws, New England state officials need confidence that they will occupy a central role in the decision-making process. Indeed, “state involvement in regional transmission planning processes is becoming more important as states take a more active role in shaping the resource mix and demand, which, in turn, means that those state actions are increasingly affecting the long-term transmission needs for which we are proposing to require public utility transmission providers to plan in this NOPR.”
NESCOE respects that regions may wish to develop different processes in their tariffs for public-policy driven projects. Accordingly, a final rule in this proceeding should include a requirement that transmission providers either (1) elevate and codify the states’ role in the tariff for all four phases of Long-Term Regional Transmission Planning processes (identification, evaluation, selection, and cost allocation); or (2) explain how and why, following consultation with the relevant state entities, the transmission provider developed a different approach. Bringing state officials into the conversation both early on and on a continuing basis is the best way to ensure that regional transmission planning will take into account a changing resource mix—both current and future—needed to meet evolving state public policy requirements.
4. Regions Should Be Given Sufficient Flexibility to Adapt Their Order No. 1000 Public Planning Processes to the Requirements of a Final Rule.
The Commission states that while it does not propose to change the existing Order No. 1000 requirement to consider transmission needs driven by public policy requirements in the regional transmission planning process, it does propose to clarify that compliance with this existing Order No. 1000 requirement will be achieved through the Long-Term Regional Transmission Planning that it proposes in the NOPR. Or stated differently, transmission providers will “be deemed to comply with” the existing Order No. 1000 public policy transmission planning requirements through the NOPR’s proposed requirement that they conduct Long-Term Regional Transmission Planning, as defined and discussed in the NOPR.
NESCOE strongly supports a final rule that would afford regions the flexibility to take a fresh look at their Order No. 1000 public policy planning processes and, if appropriate, discontinue those procedures that have not proven useful. In such a case, transmission providers should be permitted to propose replacement provisions that, if developed to provide both flexibility and a central state role, could provide meaningful tools for greater visibility into transmission systems needs and mechanisms for potential infrastructure development.
NESCOE could support the proposed requirement that transmission providers must demonstrate that an Order No. 1000 process for public policy projects is “consistent with or superior to” any final rule in this docket, so long as the Commission takes a broad view of what is “consistent with or superior to” and provides sufficient flexibility as set forth in these comments.
5. A More Holistic, Combined Approach to Regional Transmission Planning Could Be Appropriate if Reliability Remains Paramount and Regions Retain Flexibility.
NESCOE supports the Commission’s proposal not to mandate changes to the Order No. 1000 planning process with respect to reliability and economic projects. Although NESCOE does not advocate for reliability and economic processes to be subject to the reforms in the NOPR, NESCOE believes there could be value to exploring holistic approaches to planning. The Commission states that “public utility transmission providers could propose a regional transmission planning process that plans for reliability needs, economic needs, transmission needs driven by Public Policy Requirements, and transmission needs driven by changes in the resource mix and demand simultaneously through a combined approach.” NESCOE sees value in such an approach. Consumers may not realize full benefits from a traditional siloed approach to regional transmission planning with reliability, economic, and public policy projects considered separately.
That said, NESCOE emphasizes that there are situations where reliability planning needs to continue to be paramount. Accordingly, any reforms that would permit the integration of reliability, economic, and public policy transmission planning must be implemented in a way that does not inadvertently disrupt system planning to ensure system reliability.
Additionally, the Commission should afford transmission providers adequate flexibility to design approaches that make sense for their specific regions. For example, last year NESCOE presented to ISO-NE’s Planning Advisory Committee (“PAC”), an approach that seeks to integrate reliability system planning and public policy transmission planning called Overlay Network Expansion (“ONE”) Transmission. The ONE Transmission concept seeks to leverage ISO-NE’s only existing routine transmission planning process—system reliability planning—to provide visibility into potential cost-effective investments to support public policy-driven resources. Providing sufficient flexibility to regions to explore combined approaches to regional transmission planning would enable discussions to continue regarding the ONE Transmission concept and potential other ways to achieve consumer cost savings through increased efficiencies and scale, and by eliminating silos in current planning that fail to co-optimize infrastructure projects.
Another area of possible reform is related to the proposed requirement, discussed below in Section VIII.B, to require transmission providers to consider how reliability or economic projects might be “right-sized” to account for public-policy driven transmission needs. NESCOE has requested that ISO-NE explore changes in this area as part of its 2023 Work Plan, and ISO-NE is currently considering including that as a project for next year. NESCOE appreciates the openness the NOPR evinces to these types of creative regional approaches.
Flexibility is necessary to ensure that Long-Term Scenarios are developed in a manner that works best for each region. Although generally supportive of the NOPR’s longer-term planning reforms, NESCOE is concerned that the proposed rule is overly prescriptive in some areas as explained below in Section IV.B.3.
1. NESCOE Supports Requiring Transmission Providers to Describe in Their OATTs the Processes They Will Use to Develop Long-Term Scenarios.
NESCOE fully supports the proposal that transmission providers amend their OATTs to explicitly describe the open and transparent processes that they will use to develop Long-Term Scenarios that meet these requirements.
The NOPR proposes that regional planning processes for near-term reliability and economic needs need not be modified to incorporate Long-Term Scenarios. NESCOE agrees with the proposal not to prescribe the use of Long-Term Scenarios in reliability and economic planning.
The Commission also asks whether transmission providers should be required to incorporate some form of scenario analysis into existing reliability and economic planning processes to identify efficient or cost-effective transmission facilities. NESCOE does not believe this proposal should be adopted. Under the reforms proposed in the NOPR, Long-Term Scenarios would be developed under a specific framework for decision-making and, consequently, states may be comfortable exploring scenarios to provide information as part of a process that gives them a central role in evaluation, selection, and cost allocation. By contrast, states may be reticent to participate if those types of scenarios were automatically input into reliability or economic processes where states have no decision-making role. Instead, regions should be afforded the flexibility to align reliability and economic scenario planning with longer-term public policy planning.
The Commission proposes to require transmission providers to develop Long-Term Scenarios using no less than a 20-year transmission planning horizon, and inquires whether a 20-year planning horizon is the appropriate length. NESCOE does not support a one-size-fits-all planning horizon requirement.
NESCOE commends the Commission for recognizing the importance of regional transmission planning to take longer views. That said, NESCOE believes that there is not one specific transmission planning horizon that is the “right” timeframe; rather, this is an area where the Commission should refrain from being overly prescriptive. There may be a need at any given time for short-term, medium-term, and/or long-term analyses. As noted above, ISO-NE’s longer-term transmission planning Tariff changes were approved earlier this year. These Tariff changes provide a mechanism for the New England states, through NESCOE, to request transmission analyses based on state-provided scenarios. There is no prescribed timeframe under this Tariff provision. Studies conducted under this process can examine the full range of potential needs, along with cost information, from, for example, a five-year horizon up through a multi-decade period, as did the first study under this mechanism, the 2050 Transmission Study.
A final rule that lacks this flexibility could serve at cross-purposes to regional efforts like those recently implemented in New England. If the Commission were to require, for example, a 20-year minimum horizon, this would not capture the 2035 study results, one among several scenarios that the New England states requested in the 2050 Transmission Study. Moreover, such a rigid requirement could divert resources already focused on meeting requests under ISO-NE’s longer-term transmission planning process to study a time horizon that the states, stakeholders, and ISO-NE may not find useful.
There is a critical need for states, in partnership with transmission providers, to have the ability to adapt modeling to emerging needs and changing laws as they arise. Given that transmission providers like ISO-NE have finite resources, devoting resources to a 20-year analysis, when what really may be needed by the region is a 12-year outlook, would be counterproductive. For these reasons, NESCOE urges flexibility in this proposed reform.
NESCOE understands why, in a generic rule, the Commission may prefer to set a minimum standard for the time horizon applicable to Long-Term Scenarios. However, for the reasons provided above, NESCOE respectfully asks that the Commission ensure that any such requirement allows transmission providers to demonstrate that existing tariff provisions—such as those in New England—are “consistent with or superior to” a final rule mandating a minimum time horizon.
ii. The Commission Should Provide Flexibility in Determining the Frequency with Which Long-Term Scenarios are Developed.
The Commission proposes that transmission providers must develop Long-Term Scenarios at least every three years, and asks if a frequency of no less than three years appropriately balance the benefits and burdens of such updates. As with the length of the planning horizon, NESCOE believes that there is no single right interval that would make sense to impose on transmission providers across the country. While a final rule should require that transmission providers establish a clear definition of the time frame for updating scenarios or developing new ones, the Commission should afford each region the flexibility to determine that frequency.
iii. The Proposal That Transmission Providers Must Complete Long-Term Scenarios Within Three Years and Before the Next Three-Year Assessment Occurs Is Too Rigid.
NESCOE has concerns with the Commission’s proposal that transmission providers must complete development of Long-Term Scenarios within three years, before the next three-year assessment commences. This proposal is inflexible and could potentially interfere with existing procedures in New England.
ISO-NE’s recently-approved longer-term transmission planning Tariff provisions require that a scenario planning process be concluded before a new one can begin. A request for a Longer-Term Transmission Study may be submitted to ISO-NE no earlier than six months from the conclusion of the prior study. If the Commission were to mandate an across-the-board requirement that Long-Term Scenarios must be conducted every three years, and that a new Long-Term Scenario could not be initiated until after that three-year period, such a requirement could conflict with the forward-looking process already established in New England.
i. The Commission Should Provide Regions Flexibility in the Development of Factors to be Incorporated into Long-Term Scenarios.
The Commission’s inquiries into whether and how the proposed categories of factors outlined in the NOPR adequately capture factors expected to drive changes to resource mix and demand is another area where NESCOE cautions the Commission against being overly prescriptive. NESCOE agrees that there are laws that affect the future resource mix and demand, for example, by addressing decarbonization and electrification, and expects that such factors would be taken into account in Long-Term Regional Transmission Planning
NESCOE appreciates the flexibility the Commission is evincing in proposing that if transmission providers would like to incorporate additional categories of factors into the development of Long-Term Scenarios, they may do so upon a demonstration that such an approach is consistent with or superior to a final rule in this proceeding. However, NESCOE is concerned that the baseline proposal requiring minimum factors to is too prescriptive, at least for the New England region where there is already a Tariff process in place that allows states, in consultation with ISO-NE and stakeholders, to identify factors to be reflected in the long-term scenarios that states request. A final rule should allow for flexibility in deciding which of these factors should be incorporated into Long-Term Scenario Analyses. In building in such flexibility, the Commission would avoid the potential to be asked to sit as an arbiter over whether or not certain state laws drive transmission needs, or whether certain policy goals should be discounted or weighed more heavily. This would be consistent with the approach the Commission took in Order No. 1000 where it did “not…require the identification of any particular transmission need driven by any particular Public Policy Requirements.”
Ensuring adequate state input and decision-making into Long-Term Regional Transmission Planning will, in turn, ensure that the factors considered in Long-Term Scenario analyses are nimble enough to adapt to evolving state priorities, amended legal requirements, and changing state policy preferences.
ii. Transmission Providers Should Be Required to Publish the Factors They Propose to Use in Long-Term Scenarios.
NESCOE supports the proposal to require transmission providers to identify and publish on OASIS or a public website a list of factors they will incorporate in their development of Long-Term Scenarios. However, as noted above, it is also critical that the early involvement of states and stakeholders inform the development of these factors for use in their Long-Term Scenario analyses.
iii. NESCOE Fully Supports Open and Transparent Processes for Proposing Factors, But States Must Play a Central Role.
NESCOE supports, with a caveat, the proposal that transmission providers must revise their OATTs to establish open and transparent processes that offer stakeholders and states with a meaningful opportunity to propose potential factors for incorporation into development of Long-Term Scenarios. NESCOE objects to the proposed treatment of states as just any other stakeholder. When it comes to developing factors that relate to a legal requirement, mandate, or policy of a state government that forms the basis of a factor to be studied in Long-Term Scenario Analysis, as discussed more broadly above, states must occupy a central role in determining those factors. If the Commission were to adopt a final rule that relegates states to “stakeholder” status, the reforms would likely run into the problem that underlies the Order No. 1000 public policy process in New England. There, under the current ISO-NE Tariff, the states’ defined role in the transmission planning process implemented pursuant to Order No. 1000 begins and ends when policy needs are identified. The states do not have a decision-making role over other aspects of the process, including project selection, even though state laws or policies could be the driver for that project. The Commission can and must avoid this outcome in promulgating a final rule here to ensure that states have a meaningful voice in connection with projects intended to advance state laws and mandates.
The Commission proposes that transmission providers must develop at least four distinct Long-Term Scenarios as part of Long-Term Regional Transmission Planning, and asks whether four Long-Term Scenarios will provide sufficient information.
NESCOE is strongly in favor of a final rule that would provide flexibility to transmission providers to propose procedures that set a baseline for the minimum number of scenarios that they will develop. NESCOE’s position is informed by the longer-term transmission planning process that ISO-NE recently implemented. That process does not set a minimum or maximum number of scenarios. As explained above, in the 2050 Transmission Study, at NESCOE’s request, ISO-NE is conducting analyses for the years 2035, 2040 and 2050, focusing on transmission needs in order to serve load while satisfying NERC, NPCC, and ISO-NE reliability criteria under one future scenario. These analyses will produce a transmission upgrade “roadmap” to satisfy the transmission needs under a “likely scenario.”
As the Commission recognizes, “modeling multiple scenarios requires additional time and effort, and may add to the costs of Long-Term Regional Transmission Planning.” NESCOE is concerned that if the Commission were to impose a one-size-fits-all requirement on the number of Long-Term Scenarios that transmission providers must model, ISO-NE could end up having to conduct a Long-Term Scenario that it and/or the New England states believe unnecessary and not useful. Not only would this end up costing New England consumers more money, but it could divert resources from other Long-Term Scenarios that the states and ISO-NE do find important.
While NESCOE does not see a benefit to New England of a final rule that would require a specific number of scenarios, given the state-led scenario process we have in place in ISO-NE’s Tariff, we recognize that the Commission may wish to promulgate generic regulations that set a baseline across all regions. Accordingly, like our comments on the Commission’s proposed time horizon applicable to Long-Term Scenarios, NESCOE respectfully asks that the Commission ensure that any requirement regarding the minimum number of scenarios allows transmission providers to demonstrate that existing tariff provisions are “consistent with or superior to” a final rule mandating a minimum time horizon.
A final rule in this proceeding also should preserve the ability of transmission providers to reserve scenarios for states’ decision on how they are developed, including states providing the inputs and assumptions. NESCOE emphasizes that it is not requesting a final rule that limits the ability of transmission providers and stakeholders to request certain scenarios. Instead, a final rule should allow flexibility for transmission providers, in consultation with states, to study other scenarios, but not if it reduces or eliminates the ability of states to define scenarios in ways that are useful to them.
The Commission proposes that the four Long-Term Scenarios must be (1) plausible, and (2) diverse. NESCOE is generally supportive of this broad, common-sense proposal. This support is conditioned, however, on the understanding that transmission providers can rely on the judgment of state officials regarding modeling of scenarios to help achieve state public policy requirements. NESCOE is likewise generally supportive of the proposal that if a transmission provider produces a base case scenario, it should be consistent with the most likely scenario to occur, provided that such judgment is based on consultation with the states.
iii. While NESCOE Supports the Study of High-Impact, Low-Frequency Events, the Commission Should Allow Regions Flexibility to Determine What Is Most Appropriate for Their Circumstances.
The Commission proposes that at least one of the four distinct Long-Term Scenarios must account for uncertain operational outcomes that determine the benefits of or need for transmission facilities during high-impact, low-frequency events (e.g., extreme weather events or potential cyberattacks).
NESCOE agrees that visibility into impacts on the transmission system from high-impact, low-frequency events is needed. These types of issues are not new, and regions are already grappling with them. ISO-NE explains that “[e]nergy-security risks in New England are well documented, highlighting the importance of conducting comprehensive energy-security assessments covering a wide range of operating conditions, including low-probability, high-impact reliability risks (tail risks) related to extreme weather.” ISO-NE has recently been working with the Electric Power Research Institute (“EPRI”) to conduct a probabilistic energy-security study for the New England region under extreme weather events and to develop a framework for ISO-NE to assess operational energy-security risks associated with extreme weather events. NESCOE also commends the Commission’s initiative taken with two recent notices of proposed rulemakings addressing reliability risks associated with extreme weather events.
Nonetheless, the proposed rule raises questions about whether codifying such a requirement to conduct a specific type of Long-Term Scenario analysis blurs the line between public policy planning and reliability planning, contrary to the NOPR’s contention that none of the proposals sought to alter the reliability planning process. Any such tension, however, can be avoided by making the study of these types of events discretionary rather than mandatory under Long-Term Regional Transmission Planning.
NESCOE supports the proposal that transmission providers must disclose (subject to any applicable confidentiality protections) information and data inputs they use to create each Long-Term Scenario. This transparency requirement is needed to ensure that states and stakeholders have access to full information they need to understand and if warranted, give input to the transmission provider on the Long-Term Scenario modeling. The ISO-NE longer-term transmission Tariff provisions are consistent with this proposal as they require ISO-NE to post on its website not only any request from NESCOE for a Longer-Term Transmission Study, but also the proposed scope of work that may be performed, along with any associated parameters and assumptions.
v. A Final Rule Addressing Stakeholder Input into the Development of Long-Term Scenarios Should Not Undercut Existing Regional Work on Public Policy-Driven Planning.
The Commission proposes that transmission providers must give stakeholders an opportunity to provide timely and meaningful input into the identification of which Long-Term Scenarios will be developed. Similarly, the Commission proposes that transmission providers must revise their OATTs “to outline an open and transparent process that provides stakeholders, including states, with a meaningful opportunity to propose which future outcomes are probable and can be captured through assumptions made in the development of Long-Term Scenarios.”
NESCOE supports these proposals with two caveats. First, as emphasized above, states are not just any other stakeholder. Second, as the Commission works to fashion a final rule, it should be careful not to undermine existing processes like the longer-term transmission planning process in ISO-NE’s Tariff, which already provides a mechanism for state input. NESCOE expects this is not the intent of the Commission, but cautions against adopting a final rule that is so inflexible that it would require modifications to processes that already work for regions like New England.
NESCOE supports the proposal that transmission providers must explain on compliance how their process will identify a plausible and diverse set of Long-Term Scenarios. This proposal is consistent with the Order No. 1000 principle of transparency and will further the ultimate goal of transmission studies that meet the region’s needs.
NESCOE appreciates the Commission’s clarification that by proposing to require transmission providers to use “best available data inputs” when developing Long-Term Scenarios, it is “not imply[ing] that there is a single ‘best’ value for each data input…but rather that best practices are used to develop that data input.” Nonetheless, NESCOE is concerned that the Commission’s proposals and inquiries here lean towards being unnecessarily prescriptive. The Commission inquires whether it should facilitate the development of data inputs that meet this proposed requirement by identifying or standardizing the best available data inputs that meet this proposed requirement. The Commission should not attempt to standardize “best available data inputs.” This effort will be better accomplished if done on a region-by-region basis by transmission providers with input from states and stakeholders.
ii. NESCOE Agrees That the Process by Which Transmission Providers Determine Which Data Inputs to Use in Long-Term Scenarios Should Be Subject to Existing Order Nos. 890 and 1000 Planning Principles.
NESCOE supports the proposal that the existing Order Nos. 890 and 1000 transmission planning principles would apply to the process through which transmission providers determine which data inputs to use in their Long-Term Scenarios. The example the NOPR provides—that transmission providers must give stakeholders the opportunity to provide timely and meaningful input concerning which data inputs to use in Long-Term Scenarios—is apt.
i. NESCOE Supports Giving Transmission Providers the Option to Consider Whether to Establish Geographic Zones.
NESCOE appreciates the NOPR’s thoughtful approach to the issue of identification of geographic zones. The NOPR proposes to require transmission providers, as part of their regional transmission planning processes, to consider whether to identify, with stakeholder input, specific geographic zones within the transmission planning region that have the potential for development of large amounts of new generation. The salient point is that the Commission only proposes that transmission providers consider whether to identify geographic zones.
NESCOE supports this overall approach, which does not mandate the use of geographic zones. Whether to implement geographic zones in Long-Term Scenarios should be an option for transmission providers to decide with the region, with states in a central role and with input from stakeholders. Indeed, ISO-NE’s longer-term transmission planning process specifically references geographic zones as a possible area of study. Allowing this optionality appropriately recognizes that resource types and locations that satisfy the requirements of diverse laws and policy imperatives, including prioritizing economic development, may well change over time.
The NOPR is very specific about how geographic zones should be studied, to the extent regions elect to identify them. It proposes a series of proposed requirements for each of the three steps: identification, assessment, and incorporation of geographic zones into Long-Term Scenarios. For example, for step one, the Commission proposes to require that any method that transmission providers choose to use to identify geographic zones within the transmission planning region “use best available data, including atmospheric, meteorological, geophysical, and other surveys, to identify geographic zones with potential for development of large amounts of new generation.” NESCOE appreciates the detail that the Commission provides in this area but, again, cautions against an overly prescriptive approach. A final rule could include such details as guidance but not mandate their application.
iii. States Should Have a Central Role in Decisions Regarding the Potential Creation of Geographic Zones.
The Commission inquires how transmission providers in multi-state regions may reconcile or account for differing energy policy interests or preferences in implementing this proposed requirement, while respecting and not overriding those state preferences. This question underscores the importance of states playing a central role in the development of Long-Term Scenarios and at all stages of the process, with the tariff setting forth how states in multi-state regions will engage in that process. As noted above, NESCOE already has the ability under the recently-adopted longer-term transmission planning process to identify geographic zones for study by ISO-NE.
1. The Commission Should Allow Regions Flexibility on How Best to Consider the Impact of Generator Interconnection-Transmission Needs in Long-Term Regional Transmission Planning.
The Commission should not adopt the proposal that Long-Term Regional Transmission Planning must consider regional transmission facilities that address interconnection-related needs identified multiple times in the generator interconnection process but that have never been constructed due to the withdrawal of the underlying interconnection request(s).
As a threshold matter, it is not clear that withdrawals from the interconnection queue establish that transmission upgrades are needed or would be more efficient. The proposed rule draws a nexus that may not necessarily be true. NESCOE previously cautioned against developing one-size-fits-all prescriptive rules that would base findings of transmission needs on the level of generation projects in the interconnection queue. As NESCOE explained, in New England, there is insufficient data to support relying on the existence of generation projects in the interconnection queue to accurately identify or solve for reliability needs. The NOPR’s detailed proposal regarding reliance on data about withdrawals of generators from the interconnection queue does not ameliorate this issue. Any nexus between the generator interconnection queue and regional transmission planning are best addressed as part of a region-specific longer-term scenario planning process and identification of appropriate inputs and assumptions.
NESCOE opposes the NOPR’s proposed approach, which would impose very specific, detailed obligations on transmission providers to incorporate into Long-Term Scenario factors related to interconnection queue withdrawals. To be clear, NESCOE does not oppose the modeling of generator interconnection-related transmission needs in Long-Term Scenario development. But it should be up to each region to determine whether and, more importantly, how to address generator interconnection related transmission needs in Long-Term Scenarios.
If the Commission does, nonetheless, proceed with a final rule directing that transmission providers consider generator interconnection related transmission needs in Long-Term Regional Transmission Planning, it should keep the rule broad enough so that transmission providers may determine the way that is best suited for their regions. Transmission providers should not be forced to use data on past interconnection withdrawals as the basis for Long-Term Scenario analyses. As recently observed by Commissioner Riley Allen of the Vermont Public Utility Commission at a Joint Federal-State Task Force on Electric Transmission (“Joint Task Force”) Meeting, “We shouldn’t just be thinking in terms of longer-term planning relative to what’s in the queue or what has appeared in the queue in the past. I think we should be really anticipatory and visionary in addressing future queue problems or anticipating future queue problems that might arise, not just reacting to what’s in the queue.”
There are likely a number of reasons why interconnection related upgrades are not being built, and many reasons why generator interconnection requests are withdrawn. These issues raise broad areas of inquiry. The Joint Task Force’s third meeting was devoted to discussion of issues related to generator interconnection queue processes and current backlog, along with cost allocation issues related to generator interconnection-related upgrades. Additionally, the Commission’s recent notice of proposed rulemaking will likely address problems with backlogs in the queue and withdrawals from the queue, and it would be premature to determine how these issues will be incorporated into long-term regional transmission planning processes before the Commission acts on this rulemaking.
The proposed requirement in the NOPR risks oversimplifying the complex issues related to interconnection, and in so doing, could lead to opposition on cost allocation later in the process. A more productive approach would be to permit transmission providers to consider the factors the NOPR sets forth as mandatory.
a. A Final Rule Should Provide a Path to Codify the States’ Role in Evaluation of the Benefits of Regional Transmission Facilities Intended to Address State Public Policy Requirements.
NESCOE generally supports the NOPR’s proposal that after identifying transmission needs and facilities, transmission providers must evaluate “the benefits of regional transmission facilities to meet identified transmission needs driven by changes in the resource mix and demand, identify which benefits they will use in Long-Term Regional Transmission Planning, explain how they will calculate those benefits, and explain how the benefits will reasonably reflect the benefits of regional transmission facilities to meet identified transmission needs driven by changes in the resource mix and demand.” But transmission providers should not evaluate the benefits of regional transmission facilities in isolation. Transmission providers have the technical expertise to identify, calculate, and explain the various benefits that a given facility that may provide. It is appropriate for transmission providers to lead such discussions initially to inform states and stakeholders of the potential benefits of facilities. However, there must be an interplay with the states where state laws and policies are the project drivers. As the Commission recognizes, “state laws, utility integrated resource plans and resource procurements, and other regulatory actions necessarily implicate the resource mix and demand for Commission-jurisdictional services.”
Above, NESCOE asked the Commission to include in a final rule in this proceeding a requirement that transmission providers either (1) elevate and codify the states’ role in the tariff for all four phases of Long-Term Regional Transmission Planning, or (2) explain how and why, following consultation with the relevant state entities, the transmission provider developed a different approach. This includes ensuring that states, if they so elect, have a defined role in the project evaluation phase of the planning process. For example, a final rule could require that transmission providers confirm with states their quantification of certain benefits in connection with state policies such as carbon reduction.
b. The Commission Should Establish a List of Benefits but Allow Flexibility to Adapt the List Following Consultation with States
The Commission declines to propose any particular definition of “benefits” or “beneficiaries,” or to require the use of any specific benefits in the evaluation process. Rather, the NOPR acknowledges the benefits of regional flexibility, and consistent with Order No. 1000 on this issue, proposes to consider such matters on review of compliance proposals. The Commission proposes a list of Long-Term Regional Transmission Benefits that transmission providers may consider in Long-Term Regional Transmission Planning and cost allocation processes and proposes that transmission providers have the flexibility to propose other benefits.
NESCOE recommends a change to one aspect of this proposed approach. Instead of providing a list of benefits as a reference, the Commission should establish in a final rule a list of benefits as a required starting point for regional discussion. The list set forth in the NOPR is appropriate for this purpose. The Commission should, however, require transmission providers to obtain input from states—especially as pertains to state public policy requirements—and stakeholders on the range of benefits that might be appropriate for them to evaluate in Long-Term Regional Transmission Planning. Following consultation with the states, transmission providers should have flexibility on compliance to add or subtract from this list of benefits. A final rule reflecting this approach would help to facilitate collaborative approaches in determining the most appropriate set of benefits for a region.
c. NESCOE Supports the Proposal for Compliance but Requests That the Commission Clarify That Transmission Providers May Modify the Identified Benefits in Future Section 205 Filings.
NESCOE supports the Commission’s proposal that on compliance, transmission providers should identify what benefits they will use in Long-Term Regional Transmission Planning; explain the rationale for using them; explain how the benefits will be calculated; and explain how the benefits will reasonably reflect the benefits of regional transmission facilities to meet identified transmission needs driven by changes in the resource mix and demand and explain the rationale for the benefits they will use. It is critical that those in the region are fully aware of the benefits that will be used in evaluating potential transmission facilities in Long-Term Regional Transmission Planning.
Because benefits may change over time—as could the methods of measuring current and future benefits—the Commission should clarify in a final rule that transmission providers may propose additional or modified benefits in future FPA section 205 filings. Such filings could also propose changes to the way existing benefits are calculated.
a. Regions Should Have Flexibility to Determine the Appropriate Time Horizon for Evaluation of the Benefits of Transmission Facilities.
The Commission proposes that transmission providers evaluate the benefits of regional transmission facilities over a time horizon that covers, at a minimum, 20 years starting from the estimated in-service date of the transmission facilities. For the reasons discussed above (see Section IV.A.2), the Commission should allow for regional flexibility on the time frame for evaluation of the benefits of transmission facilities. NESCOE is not strictly opposed to a 20-year time frame; however, if ISO-NE, with input from the New England states and stakeholders, were to determine that the most useful time frame is, for example, a 15-year time frame or a more flexible time horizon, NESCOE would not want a rigid one-size-fits-all rule to force ISO-NE to divert resources away from the region’s priorities. This would be counterproductive and would not necessarily lead to just and reasonable transmission rates.
NESCOE supports a flexible approach to evaluation of benefits on a portfolio-wide basis. NESCOE agrees that transmission providers should be allowed but not required to evaluate the benefits of a portfolio of regional transmission facilities instead of doing so on a facility-by-facility basis. The Commission also proposes that if a transmission provider elects to use a portfolio approach, it must include in their OATT a description of how they would use such an approach and whether it would be used universally or only in certain specified instances. NESCOE supports this transparency.
1. NESCOE Generally Supports the Proposed Selection Criteria, but a Final Rule Should Confirm the Central Role of States.
The Commission proposes that transmission providers must include in their OATTs selection criteria that: are transparent and not unduly discriminatory criteria; seek to maximize benefits to consumers over time without over-building transmission facilities; and identify and evaluate transmission facilities for potential selection in the regional transmission plan for purposes of cost allocation that address transmission needs driven by changes in the resource mix and demand.
NESCOE generally supports the proposed criteria subject to the comments below, as well as the transparency that will be achieved by having the criteria articulated in transmission providers’ OATTs. Of critical importance is the proposal to provide transmission providers with “flexibility to propose the selection criteria that they, in consultation with stakeholders, believe will ensure that more efficient or cost-effective regional transmission facilities” are selected in the regional transmission plan for purposes of cost allocation. While supporting the flexibility espoused in the proposal, here, a final rule must confirm that states have a central role to play, distinct from other stakeholders.
2. A Final Rule Should Clarify That There Is No Obligation to Select Any Particular Transmission Project.
The NOPR explains, “[a]s stated in Order No. 1000, to comply with Order Nos. 890 and 1000 transmission planning principles, the evaluation process must result in a determination that is sufficiently detailed for stakeholders to understand why a particular transmission project was selected or not selected in the regional transmission plan for purposes of cost allocation to address transmission needs driven by changes in the resource mix and demand.” This articulation indicates that the Commission is not contemplating requiring the ultimate selection of a project. NESCOE supports this approach. While NESCOE strongly supports greater visibility into the future grid to inform decisions such as the “amount and type of transmission infrastructure needed to cost-effectively integrate clean energy resources,” there must be opportunities for state officials to exercise judgment regarding potential options for achieving state laws and mandates. There are substantial policy and consumer cost implications involved in such decisions. This was a subtle but important point that NESCOE raised on appeal of the order addressing ISO-NE’s Order No. 1000 compliance filing. In response, the United States Court of Appeals for the D.C. Circuit confirmed that “there is no requirement that ISO-NE must select . . . a transmission solution to address every identified transmission need driven by a public policy requirement.”
To avoid any future ambiguity and unnecessary litigation, the Commission should expressly state in a final rule that regardless of the selection criteria, at the end of the selection process, there is no obligation to select any projects.
3. NESCOE Agrees That Transmission Providers Should Consult with and Seek Support from States in Developing Selection Criteria; However, a Final Rule Should Also Establish a Path for States to Have an Expanded Role with Respect to Projects Needed to Meet State Public Policy Requirements.
NESCOE appreciates and strongly supports the NOPR’s proposal that transmission providers must consult with and seek support from relevant state entities within their transmission planning region’s footprint to develop the selection criteria that they include in their OATTs for potential selection of transmission facilities in the regional transmission plan for purposes of cost allocation. This proposal would help remedy a major flaw in the Order No. 1000 public policy transmission planning process, which did not include such a requirement. A final rule should specify that transmission providers bear the burden on compliance of demonstrating that their proposed selection criteria were developed in consultation with the relevant state entities in their transmission planning region’s footprint.
NESCOE requests that the Commission also go a step further than what is contemplated in the NOPR and provide a path for states to have an expanded role in the selection of projects in the regional transmission plan for purposes of cost allocation where the transmission project is identified as needed in response to state laws or policy goals. For example, this could resemble a process along the lines of what the Commission proposes with respect to cost allocation, where the NOPR sets forth a proposed requirement that transmission providers seek agreement from states. As articulated above, the Commission could include in a final rule a requirement that transmission providers either (1) elevate and codify the states’ role in the tariff for all four phases of Long-Term Regional Transmission Planning, or (2) explain how and why, following consultation with the relevant state entities, the transmission provider developed a different approach.
4. Providing Relevant State Entities the Opportunity to Voluntarily Fund All or a Portion of Long-Term Regional Transmission Facilities Is a Reasonable Approach.
The Commission inquires whether relevant state entities should have the opportunity to voluntarily fund the cost of, or a portion of the cost of, a Long-Term Regional Transmission Facility to enable such facility to satisfy the transmission provider’s selection criteria, and if the answer is yes, whether a final rule should include requirements to facilitate such an opportunity for the relevant state entities. It would be reasonable to provide an opportunity (but not an obligation) for states to voluntarily fund a portion (or all) of a Long-Term Regional Transmission Facility to enable the facility to satisfy the transmission provider’s selection criteria. NESCOE likewise would not oppose expanding this funding opportunity to include interconnection customers.
The PJM Interconnection, L.L.C. (“PJM”) State Agreement approach provides a readily available example of how states could volunteer to fund some or all costs. As explained by one state regulator, this approach:
is based on the principle that authorized state governmental entities in one or more states, individually or jointly, may agree voluntarily to be responsible for the allocation of all costs of a proposed transmission expansion or enhancement that addresses state public policy requirements identified or accepted by the participating state(s). The costs of such transmission enhancements or expansion shall be recovered only from the customers of the participating state(s).[]
A final rule could reference that approach but need not prescribe it as the only potential mechanism and could allow regions to propose other approaches on compliance.
NESCOE believes it would be reasonable to require detail on how a state or states would commit to such funding and how to ensure that such a commitment is binding. States may have different processes and requirements for these types of financial commitments, and the Commission should leave those types of details to the compliance phase, rather than prescribe them in a final rule.
It is crucial that any final rule establish the principle that a state must not be obligated to pay for the policy choices of another state. As NESCOE has previously expressed, these concerns are not hypothetical: one New England state, for example, has enacted a law that seeks to protect its electric ratepayers from costs related to the policies of other New England states. The Vision Statement noted that, in conjunction with NESCOE’s recommended transmission planning framework, “[t]here is no intent to modify the New England Governors’ agreement dated March 15, 2019 that States will ensure consumers in any one State do not fund the public policy requirements mandated by another State’s laws.” Additionally, as noted above, the New England states are addressing cost allocation as part of the regional work following ISO-NE’s implementation of its longer-term transmission planning process earlier this year, and that work is expected to be ongoing through the remainder of 2022. NESCOE respectfully requests that the Commission allow the ISO-NE region to continue its discussions and not to adopt any requirements in a final rule that would disrupt progress on these complex issues.
1. A Final Rule Should Require Transmission Providers to Explain How the Timing of Long-Term Regional Transmission Planning Interacts with Existing Regional Planning Without Being More Prescriptive.
The NOPR’s proposal to require transmission providers to explain on compliance how the initial timing sequence for their Long-Term Regional Transmission Planning efforts will interact with existing regional transmission planning processes appears reasonable. As the Commission notes, there could be overlaps in the timeline for proposed Long-Term Regional Transmission Planning and near-term regional transmission planning. However, it is unnecessary for the Commission to dictate the initial timing of new processes in order to coordinate them with existing planning processes, and doing so could be counterproductive. There are many factors at play in implementing new planning processes. A periodic forum for transmission providers, transmission experts, relevant federal and state agencies, and other stakeholders to share best practices in implementing Long-Term Regional Transmission Planning could be useful, particularly in the initial years of implementation.
G. Consideration of Dynamic Line Ratings and Advanced Power Flow Control Devices in Long-Term Regional Transmission Planning
1. NESCOE Supports a Requirement That All Types of Grid-Enhancing Technologies Be Considered in Long-Term Regional Transmission Planning.
The NOPR asks if a final rule should impose a requirement on transmission providers to more fully consider in long-term regional transmission planning and cost allocation processes two specific technologies: (1) the incorporation into transmission facilities of dynamic line ratings, and (2) advanced power flow control devices. As explained in the Vision Statement, “NESCOE supports the efficient use of existing transmission facilities and the construction of new facilities, where necessary and appropriate, to ensure the transmission grid’s reliability, efficiency, and ability to integrate clean energy resources, consistent with certain States’ legal requirements and other mandates.” Grid-enhancing technologies can play a valuable role in deferring the need for, and intensity of, new infrastructure.
NESCOE is supportive of a requirement that transmission providers more fully consider grid-enhancing technologies in regional planning, but that requirement should not be limited to the two specific technologies listed. The two identified technologies could be listed as a minimum requirement for consideration by transmission providers in long-term regional transmission planning, but the final rule should allow additional technologies to be included for consideration. As technology evolves, there will be innovations that are not currently reflected in the marketplace. NESCOE commends the Commission for recognizing that planning for the future grid cannot happen effectively without integrating grid-enhancing technologies, some which may not have even been developed yet.
NESCOE also commends the Commission for crafting this proposal as a requirement to consider the technologies, which stops short of a requirement to employ those technologies. A final rule should require transmission providers to explain why they have decided not to implement certain technologies under the circumstances.
a. NESCOE Strongly Supports the Opportunity for Central State Involvement and Flexibility Afforded to Regions in Development of a Transmission Cost Allocation Method for the Region.
The Commission proposes that transmission providers must revise their OATTs to include (1) an ex ante Long-Term Regional Transmission Cost Allocation Method; (2) a State Agreement Process, which results in an ex post cost allocation method; or (3) a combination thereof.
NESCOE strongly supports the opportunity for central state involvement in developing regional cost allocation methods for Long-Term Regional Transmission Facilities. Accordingly, NESCOE supports the proposal that to comply with the proposed requirement for regional transmission cost allocation, transmission providers would need to seek the agreement of relevant state entities within the transmission planning region regarding which cost allocation method to adopt.
NESCOE appreciates the flexibility the NOPR’s proposal would afford regions and states in developing such cost allocation methods. As explained above, in response to the New England states’ request, ISO-NE has allocated resources to developing Tariff revisions related to cost allocation as a follow-up to the longer-term transmission planning Tariff changes. This would include provisions for how states may pursue options based on the transmission analyses, including cost allocation. One-size-fits-all planning or cost allocation directives could pause the momentum on this initiative in New England or unintentionally derail them, and NESCOE greatly appreciates the flexibility built into the proposed rule to allow this collaborative effort to continue without disruption.
The flexibility that the NOPR proposes, in conjunction with the requirement that transmission providers must seek the agreement of relevant state entities regarding the cost allocation method that the transmission provider wishes to use, should help to foster partnership and trust on regional cost allocation. In New England, the cost allocation method proposed after the Commission rejected the original Order No. 1000 proposal became adversarial and split the New England states. The NOPR provides an opportunity to broker a new agreement and achieve support of all of the states. The timing of this reform is critical, as the region is in the process of embarking on efforts to understand what infrastructure is needed to support the transition to a future grid.
b. It Is Reasonable to Require Either the Long-Term Regional Cost Allocation Method or Cost Allocation Methods Stemming from a State Agreement Process to Comply with Order No. 1000’s Regional Cost Allocation Principles.
NESCOE supports the NOPR’s proposal that the Long-Term Regional Transmission Cost Allocation Method and any cost allocation method resulting from the State Agreement Process must comply with the existing six Order No. 1000 regional cost allocation principles.
a. NESCOE Supports Requiring Transmission Providers to Attempt to Obtain Agreement from States Regarding Whether the Region Should Have an Ex Ante Long-Term Regional Transmission Cost Allocation Method, an Ex Post State Agreement Process, or a Combination Thereof.
To effectuate the proposal described above, the Commission proposes to require that transmission providers in each transmission planning region (1) seek the agreement of relevant state entities within the region; and (2) explain how the proposed cost allocation method—whether an ex ante Long-Term Regional Transmission Cost Allocation Method, an ex post State Agreement Process, or combination thereof—reflects agreement of the relevant state entities or, if such agreement could not be obtained, what good faith efforts were taken to seek state agreement.
NESCOE generally supports this proposal subject to certain recommended modifications and requested clarifications discussed below.
b. The Definition of Relevant State Entities Should Be Expanded to Accommodate the Composition of Regional State Committees.
The NOPR proposes to define relevant state entities for the purpose of the Long-Term Regional Transmission Planning cost allocation requirements as “any state entity responsible for utility regulation or siting electric transmission facilities within the state or portion of a state located in the transmission planning region, including any state entity as may be designated for that purpose by the law of such state.” NESCOE opposes the proposed definition because it would exclude NESCOE managers designated by each New England Governor to represent that state’s interest as part of an RSC recognized by the Commission. NESCOE believes this omission is unintentional, as the Commission expressly refers to NESCOE’s bylaws as one possible way to measure “agreement” among the states. NESCOE respectfully requests that the definition of relevant state entity be amended in a manner that would accommodate a region’s RSC composition.
For NESCOE, a Board of Directors representing the six New England states directs NESCOE’s activities and affairs. Each New England Governor appoints their state’s NESCOE manager, which could be, for example, the chair or commissioner at a public utilities commission or at the state’s energy policy agency. Regardless of the number of individuals each Governor appoints as a NESCOE Manager, each New England state has one undivided vote in arriving at NESCOE determinations.
NESCOE recognizes that other RSCs in different regions may operate differently. The definition of relevant state entity should be broad enough and flexible enough to accommodate these differences, and to accommodate regions without RSCs.
The Commission proposes (1) to afford transmission providers in each transmission planning region flexibility in the process by which they seek agreement from the relevant state entities, and (2) to require transmission providers to provide the relevant state entities with flexibility regarding defining what constitutes “agreement” among the relevant state entities on the cost allocation approach for Long-Term Regional Transmission Facilities. NESCOE strongly supports the latter, i.e., relevant state entities should determine the definition of “agreement.” NESCOE appreciates the Commission’s reference to NESCOE’s bylaws as an example that states in ISO-NE could consider in defining the threshold of agreement among relevant state entities.
d. NESCOE Supports the Proposed Approach in the Event States Forgo a Role in Determining the Cost Allocation Approach for All or a Subset of Long-Term Regional Transmission Facilities.
The Commission acknowledges the possibility that some relevant state entities may opt to forgo a role in determining the cost allocation approach for all or a subset of Long-Term Regional Transmission Facilities. NESCOE fully agrees with the Commission that it has no authority to impose requirements on states to participate in processes to establish regional cost allocation methods for Long-Term Regional Transmission Facilities.
NESCOE agrees with the proposal that if states opt to forego a role in determining the cost allocation approach, transmission providers should be required “to propose a Long-Term Regional Transmission Cost Allocation Method consistent with the requirements of Order No. 1000, including the prohibition on relying on voluntary agreement among states or participant funding.” Similarly, NESCOE supports the proposed requirement that transmission providers demonstrate in their compliance filings how the proposed Long-Term Regional Transmission Cost Allocation Method, the proposed State Agreement Process, or combination thereof, reflects agreement of the relevant state entities, or reflects good faith efforts by the transmission provider to seek agreement from the state entities.
e. NESCOE Recommends That a Final Rule Provide Adequate Time for Relevant State Entities to Agree on a Cost Allocation Approach.
The Commission seeks comment on the appropriate outcome if relevant state entities fail to agree on a cost allocation approach for Long-Term Regional Transmission Facilities: whether transmission providers should be required to establish a Long-Term Regional Transmission Cost Allocation Method, whether relevant state entities should be afforded additional time to reach agreement, or whether the Commission should assume the responsibility to establish the Long-Term Regional Transmission Cost Allocation Method.
The Commission should require transmission providers to provide states sufficient time to agree on the cost allocation approach. This time period should be tied to the transmission provider’s compliance obligation. The NOPR proposes that, in order to have sufficient time to coordinate with relevant state entities and other stakeholders, transmission providers be required to submit a compliance filing within eight months of the effective date of a final rule. NESCOE recommends that the Commission give states six months from the effective date of a final rule to agree on the cost allocation approach. If the states cannot reach agreement within the first four months after a final rule’s effective date, they should be given the opportunity to request that the Commission appoint one or more senior staff members to help facilitate an agreement by the six-month mark. NESCOE believes that this time frame is justified given the complexity involved in states reaching agreement on cost allocation issues. And it would afford the transmission providers two months to develop a cost allocation method in the event that the states are unable to reach agreement.
If the states ultimately cannot agree on a cost allocation approach, transmission providers should be required to propose a Long-Term Regional Transmission Cost Allocation Method consistent with the requirements of Order No. 1000. That proposal could be a filing seeking to demonstrate that their existing cost allocation method for public policy projects remains just and reasonable, by showing that their existing regional cost allocation approaches are consistent with or superior to the requirements of a final rule. NESCOE believes that having the transmission provider file a “backstop” cost allocation approach is preferable to the Commission assuming the responsibility to establish the Long-Term Regional Transmission Cost Allocation Method. The Commission should not, as a general rule, be the entity establishing the precise cost allocation method; rather, a more appropriate role for the Commission is to establish general principles under a final rule and evaluate compliance filings made by transmission providers (or subsequent FPA section 205 proposals down the road) for adherence to those principles.
a. NESCOE Agrees that an Ex Post State Agreement Process May Be a Just and Reasonable Approach to Cost Allocation for All or a Subset of Long-Term Regional Transmission Facilities.
NESCOE supports the Commission’s preliminary finding “that a State Agreement Process by which one or more relevant state entities voluntarily agree to a cost allocation method” for Long-Term Regional Transmission Facilities after such facilities have been selected in the regional transmission plan for purposes of cost allocation may be a just and reasonable approach to cost allocation. NESCOE generally supports the reforms proposed in this section of the NOPR, subject to the comments and requests for clarification below, and asks the Commission to adopt these reforms rather than simply requiring transmission providers to include a Long-Term Regional Cost Allocation Method in their OATTs.
NESCOE has consistently urged the Commission over the years to allow states to have a role in determining cost allocation for transmission projects needed to meet state public policy requirements and reaffirms that here. NESCOE greatly appreciates the Commission’s commitment to giving states a role with proposed reforms which are intended to “enable relevant state entities, such as state regulators and siting authorities, who seek greater involvement in cost allocation for Long-Term Regional Transmission Facilities an opportunity to do so.” The Commission’s approach respects the importance of promoting agreement among states and giving states the opportunity to work out compromises on cost allocation without having to be tied to a fixed ex ante cost allocation method.
NESCOE likewise supports the proposal that the State Agreement Process may apply to all Long-Term Regional Transmission Facilities or only a subset thereof. Depending on the types of transmission facilities and the circumstances, relevant state entities may find it unnecessary to have the State Agreement Process cost allocation method apply to all facilities, and retaining the flexibility to apply that to only a subset is a reasonable approach.
b. Transmission Providers Should Include the Details of any State Agreement Process That Will Apply to Long-Term Regional Transmission Facilities in Their OATTs.
NESCOE supports the proposal that if the relevant state entities decide on a State Agreement Process, the transmission provider must “detail the process by which the relevant state entities would reach voluntary agreement regarding the cost allocation…pursuant to the State Agreement Process, including the timeline for such processes.” However, in keeping with the principle that states should have a central role in these matters, if the relevant state entities in a transmission provider’s region opt for a State Agreement Process, the details of how the relevant state entities would agree to funding contributions and the mechanism by which such costs would be allocated should be largely informed by states, and then filed by the transmission providers.
NESCOE strongly supports the proposal that the proposed reforms would apply only to new Long-Term Regional Transmission Facilities and would not provide grounds for relitigation of cost allocation decisions for transmission facilities that are selected in the regional transmission plan for purposes of cost allocation prior to the effective date of any final rule in this proceeding, nor to shorter-term reliability and/or economic projects. There is no legal basis to revisit those cost determinations, and it would be counterproductive to put parties in the position of having to relitigate cost allocation decisions already made.
1. A Final Rule Should Clarify That if a Transmission Provider Files a State Agreement Process, No Ex Ante Cost Allocation Method is Required.
As recounted above, the Commission proposes that transmission providers must revise their OATTs to include (1) an ex ante Long-Term Regional Transmission Cost Allocation Method; (2) a State Agreement Process, which results in an ex post cost allocation method; or (3) a combination thereof. Later in the NOPR, the Commission refers to a “state-negotiated alternate cost allocation method” in the title of one section of the proposal rule. This term had previously not been used in the NOPR. The Commission proposes to require transmission providers to establish processes to provide “a state or states (in multi-state transmission planning regions) a time period to negotiate a cost allocation method for a transmission facility . . . that is different than any ex ante regional cost allocation method that would otherwise apply.”
NESCOE understands the “state-negotiated alternate cost allocation” proposal as offering states in a region that has opted to file an ex ante Long-Term Regional Transmission Cost Allocation Method an opportunity, on a case-by-case basis, to negotiate a potentially different cost allocation method—distinct from the “ex ante regional cost allocation method” that is on file with the Commission. This would be similar to the current cost allocation method for public policy-driven projects in New England, which allows for an alternative cost allocation to be filed with the Commission instead of using the ex ante method in the Tariff.
In contrast, NESCOE understands the State Agreement Process to operate solely as an ex post method for states to reach voluntary agreement on cost allocation for a given project or portfolio of projects. The NOPR explains that “if states agree to a State Agreement Process instead of a Long-Term Regional Transmission Cost Allocation Method, certain Long-Term Regional Transmission Facilities selected in the regional transmission plan for purposes of cost allocation would lack a clear ex ante cost allocation method.” The NOPR further suggests that the State Agreement Process is effectively a participant funding mechanism. If NESCOE’s understanding is correct, in operation, a State Agreement Process would defer cost allocation decisions until after the project selection phase. At that point, using New England as an example, the six states would seek to reach agreement on a cost allocation for the selected project(s). If all states or a subset of states voluntarily agree to fund the project (i.e., allocate costs as to each volunteering state’s load according to the agreement reached), then the project would move forward. However, if states were unsuccessful in agreeing on cost allocation and no state ultimately volunteered to fund the project(s), NESCOE understands that the project(s) would not move forward. NESCOE seeks clarification on this aspect of the proposal.
Furthermore, given the placement of the NOPR section addressing a “state-negotiated alternate cost allocation method” immediately after its discussion of the State Agreement Process, the Commission should clarify whether this proposed requirement would apply to the State Agreement Process, an ex ante Long-Term Regional Transmission Cost Allocation Method, or both. If, however, the Commission confirms that the alternate state-proposed cost allocation process referred to here is synonymous with the State Agreement process, such a statement would appear to be at odds with the NOPR’s definition and explanation of the State Agreement Process as an ex post cost allocation method. As NESCOE understands the proposal, if the states have agreed to an ex post State Agreement Process, that would be instead of an ex ante Long-Term Regional Cost Allocation Method to be filed by the transmission provider for the region. In that case, there would be no default ex ante cost allocation method for a transmission developer to use. Given the potential for confusion, NESCOE requests that the Commission confirm in a final rule that if a transmission provider files a State Agreement Process, the transmission provider is relieved of the obligation to file an ex ante cost allocation method, and the discussion of the “state-negotiated alternate cost allocation method” would not apply.
Given the flexibility that the NOPR provides regions in selecting a cost allocation method—which NESCOE generally supports and appreciates—it is critical that regions have a full understanding of the cost allocation options that are available and are not surprised to learn in a compliance proceeding that the Commission intended something different.
2. The Commission Should Clarify Its Statement Referring to Unanimous Agreement of an Alternate Cost Method.
The NOPR proposes:
During this time period for a state-negotiated alternate cost allocation method, if a state or all states within the transmission planning region in which the selected regional transmission facility will be located unanimously agree on an alternate cost allocation method, the public utility transmission provider may elect to file it with the Commission for consideration under FPA section 205.[]
This statement raises several questions:
- If this section is describing how the cost allocation method is developed pursuant to the State Agreement Process, is the Commission proposing that a State Agreement Process must result in a unanimous decision, with the agreement of each relevant state entity in the transmission planning region?
- Regardless of whether the Commission intends this to be the cost allocation method developed pursuant to the State Agreement Process or a supplemental process to be used if a default Long-Term Regional Cost Allocation Method has been filed, does “unanimity” mean that each opting-in state has agreed to fund the Long-Term Regional Transmission Facility? Or could “unanimity” mean that all of the states in the region have agreed that a subset of states in the region will fund the Long-Term Regional Transmission Facility?
- How does the Commission intend to reconcile a requirement of unanimous agreement with the proposal earlier in the NOPR that gives states the ability to choose the definition of state “agreement” with respect to the choice of an allocation method, where the NOPR expressed a willingness to abide by the bylaws of an individual RSC, which may or may not define agreement as full unanimity?
1. If States Reach Agreement, the Transmission Provider Should Be Obligated to File the State-Chosen Cost Allocation Method.
Regardless of the clarifications the Commission provides, if states reach agreement on an alternate cost allocation method, the transmission provider should be obligated to file this method, along with their preferred method (if different). The NOPR proposes that if the states reach unanimous agreement on an alternate cost allocation method, the transmission provider “may elect to file it with the Commission,” explaining that “we anticipate the public utility transmission provider may elect to file an alternate cost allocation method because doing so increases the likelihood that relevant stakeholders perceive the cost allocation as fair and that the needed regional transmission facilities are actually constructed.”
NESCOE recognizes that transmission providers hold FPA section 205 rights. Because states are not public utilities, there is no way for them to file the cost allocation methods themselves. By allowing the transmission provider to file its preferred cost allocation method with the states’ preferred cost allocation, a final rule would appear to comport with precedent that the Commission does not have jurisdiction to require utilities “to cede rights expressly given to them” in FPA section 205. To accommodate the unlikely situation where a transmission provider disagrees with the state-agreed-upon cost allocation method, the Commission should allow the transmission provider to file its preferred approach but also require the transmission provider to file the state-agreed-upon cost allocation method.
This approach could be modeled after existing provisions in the New York Independent System Operator (“NYISO”) region and the Southwest Power Pool, Inc. (“SPP”). For public policy projects in NYISO, the Commission approved a process whereby if the state and transmission developer “cannot agree upon a cost allocation method, the transmission developer will file its preferred method with the Commission within 30 days of the conclusion of the discussion period and will also include the method supported by the New York Commission.” Under SPP Bylaws, when the SPP RSC makes a determination on a methodology associated with regional proposals under its primary responsibilities—including certain transmission rate design issues—“SPP will file this methodology pursuant to Section 205 of the Federal Power Act” but retains the ability to “fil[e] its own related proposal(s) pursuant to Section 205 of the Federal Power Act.”
2. If States Do Not Reach Agreement, the Transmission Provider Should Be Permitted to Use the Ex Ante Regional Transmission Cost Allocation Method.
Assuming the Commission clarifies that this aspect of the NOPR refers to a supplemental state-negotiated cost allocation method, NESCOE agrees that if the states are unable to reach agreement, or if the states do reach agreement but the Commission rejects the proposal, the default ex ante Regional Transmission Cost Allocation Method should apply.
The NOPR proposes to prescribe a 90-day time period for state-negotiated cost allocation memorialized in writing, which, it explains, is consistent with the period for state cost allocation negotiation that the Commission accepted in NYISO’s Order No. 1000 compliance filing. However, the structure for the NYISO process actually builds in more time:
- The New York Commission will have 150 days to review the transmission developer’s proposed cost allocation method and to inform the transmission developer whether it supports the method.
- If the New York Commission supports the proposed cost allocation method, the transmission developer will file the method with the Commission within 30 days of the New York Commission’s indication of its support.
- If the New York Commission does not support the proposed cost allocation method, the transmission developer will work with the New York Commission over a 60 day period to attempt to develop a mutually agreeable cost allocation method.
- If they agree upon a cost allocation method, the transmission developer will file the method with the Commission within 30 days of the conclusion of the discussion period.
- If they cannot agree upon a cost allocation method, the transmission developer will file its preferred method with the Commission within 30 days of the conclusion of the discussion period and will also include the method supported by the New York Commission.[]
Moreover, the NYISO process involves just one state entity—the New York Commission. In New England, there are six states, with different public policy requirements and renewable goals, and with likely different views as to the extent to which the costs of Long-Term Regional Transmission Projects should be allocated among all or just a subset of the states. Other planning regions have even more states. For these reasons, the Commission should allow the region, with state input, to determine what time period is appropriate.
NESCOE agrees that transmission providers must include in their OATTs a definite time period for state involvement in developing a regional cost allocation method, so long as that time period is informed by the states in the region up front.
D. Identification of Benefits Considered in Cost Allocation for Long-Term Regional Transmission Facilities
1. The Commission Should Allow the Transmission Provider, with Input from States and Stakeholders, to Identify Benefits to Be Considered in Cost Allocation for Long-Term Regional Transmission Facilities.
In its discussion of identifying benefits to be considered in cost allocation for Long-Term Regional Transmission Facilities, the NOPR references the list it proposes for consideration. The Commission proceeds to propose to require that transmission providers “identify on compliance the benefits they will use in any ex ante cost allocation method associated with Long-Term Regional Transmission Planning, how they will calculate those benefits, and how the benefits will reasonably reflect the benefits of regional transmission facilities to meet identified transmission needs driven by changes in the resource mix and demand.”
NESCOE generally supports this proposal. It is critical that costs as well as benefits be clearly identified in connection with project evaluation. However, as NESCOE explained above (see Section IV.D.1.b), the Commission should include a list of benefits in the final rule and allow transmission providers flexibility to add or subtract from this list following consultation with states in their region.
A. NESCOE Supports the Proposal that the Construction Work in Progress Incentive Should Not Be Available for Long-Term Regional Transmission Facilities.
The Commission proposes that transmission providers may not take advantage of the CWIP incentive, largely because of uncertainty over whether the facilities will ultimately be constructed. As the NOPR explains, during the construction phase, ratepayers do not receive benefits of the regional transmission facilities, and if the transmission facilities are ultimately not placed in service, “then ratepayers will have financed the construction of such facilities that were not used and useful, while ultimately receiving no benefits from such facilities.”
NESCOE strongly supports this approach. The proposed reform balances consumer and investor interests by still allowing transmission providers to book costs incurred during the pre-construction or construction phase as Allowance for Funds Used During Construction (“AFUDC”) and recover those costs after the project is in service to customers. Additionally, as NESCOE previously articulated, the Commission should not create new or increased transmission incentives in this rulemaking without conducting an analysis first of whether existing incentives have achieved their intended goals and how new incentives would benefit consumers.
VII. COMMENTS ON Exercise of a Federal Right of First Refusal in Commission-Jurisdictional Tariffs and Agreements
A. The Commission Should Not Reinstate Any Form of Federal Rights of First Refusal at This Time in This Proceeding.
In the NOPR, the Commission proposes a fundamental change to the rule it established in Order No. 1000, which eliminated the ROFR from Commission-jurisdictional tariffs and agreements. The Commission proposes this change “in light of the experience gained since the issuance of Order No. 1000 and the comments received in response to the ANOPR.” However, unlike other aspects of the NOPR, elimination of the ROFR was not a proposal at issue in the ANOPR. Although over 100 pages long, with nearly 100 distinct inquiries by NESCOE’s count, the ANOPR included just one sentence addressing the ROFR: “We seek to better understand how the reforms of the federal right of first refusal in Order No. 1000 have shaped the type and characteristics of transmission facilities developed through regional and local transmission planning processes, such as a relative increase in investment in local transmission facilities or the diversity of projects resulting from competitive bidding processes.”
It is true that several transmission owners seized on the opportunity, as one consumer advocate put it, to seek “to use the ANOPR to roll back the elimination of the federal ROFR—an important competitive measure instituted by Order No. 1000.” But it is also true that a number of commenters, including NESCOE, urged the Commission to “reject the invitation to take a regulatory step backwards by retreating from competition.” It is unfortunate that the Commission inserts into a rulemaking aimed at improving long-term regional transmission planning a proposal that retreats from competition. In so doing, the Commission fails to give meaningful consideration to comments representing state and consumer interests in relation to the ROFR.
Following the Commission’s lead, NESCOE has long been a fierce advocate of competition. Meaningful competition is critical to encouraging new market entrants, a bigger pool of ideas, and cost containment practices that incumbent transmission providers have no incentive to offer outside a competitive process. As NESCOE and others explained in response to the ANOPR, the promise of competition in Order No. 1000 can be fulfilled by eliminating exceptions or “carve outs” that have swallowed the rule. Since Order No. 1000 went into effect in New England, for example, only one transmission solution has to date been open to competition to meet a regional need. ISO-NE has sole-sourced all other regional projects developed under its planning process to incumbent utilities pursuant to an exemption for “time sensitive” projects.
Similarly, incumbent transmission owners in New England initiate “asset condition” projects to maintain reliability of assets on their systems in accordance with national and regional standards. These projects, which are primarily attributed to aging, damaged, or otherwise obsolete equipment, are not part of the regional planning process ISO-NE uses to select reliability projects for inclusion in the Regional System Plan to solve issues identified in Needs Assessments. Almost $2.626 billion in asset condition projects have been placed in service in New England as of June 2022. And as relevant here, none of these projects are subject to competition.
The record is not ripe for the Commission to restore federal ROFRs eliminated in Order No. 1000 as part of a final rule at this time. The Commission should defer consideration of the proposals discussed in this section of the NOPR. To the extent the Commission continues to be inclined to pursue a rollback of ROFR reforms, it should do so in a separate proceeding.
VIII. COMMENTS ON Enhanced Transparency of Local Transmission Planning Inputs in the Regional Transmission Planning Process and Identifying Potential Opportunities to Right-Size Replacement Transmission Facilities
A. Enhanced Transparency of Local Transmission Planning Inputs in the Regional Transmission Planning Process
1. NESCOE Supports Enhanced Transparency of Local Transmission Planning Inputs in the Regional Transmission Planning Process, And a Final Rule Should Not Be Overly Prescriptive.
NESCOE supports the proposal to require transmission providers to revise the regional transmission planning process in their OATTs with “additional provisions to enhance transparency of: (1) the criteria, models, and assumptions that they use in their local transmission planning process, (2) the local transmission needs that they identify through that process, and (3) the potential local or regional transmission facilities that they will evaluate to address those local transmission needs.” Enhanced transparency could help states and ratepayers better understand the proposed facilities and costs associated with them. In New England, the local system planning process is described in the ISO-NE OATT, Attachment K, Appendix 1. Transmission providers should have the opportunity to demonstrate that their existing tariff provisions are consistent with or superior to the reforms adopted in a final rule.
With respect to the other proposals, while NESCOE fully supports the need for stakeholders (and states—not mentioned in the NOPR) to “have meaningful opportunities to participate and provide feedback on local transmission planning throughout the regional transmission planning process,” aspects of the proposal here are too detailed and prescriptive. For example, NESCOE does not believe a final rule should dictate the number of stakeholder meetings. NESCOE recommends that the Commission include broad principles like the ones identified in the NOPR and direct transmission providers to revise their local planning processes on compliance (or demonstrate that their existing planning processes already comply with the principles), with the details of proposed implementation left up to the transmission providers in consultation with states and stakeholders.
1. NESCOE Supports Reforms Requiring Additional Transparency in Consideration of Right-Sizing Transmission Facilities, But Such Reforms Should Be Flexible and Should Not Require Any End Result.
NESCOE generally supports reforms requiring transmission providers to consider right-sizing of transmission projects, with “right-sizing” defined in the NOPR as the process of modifying a transmission provider’s in-kind replacement of an existing transmission facility to increase that facility’s transfer capability. As noted above, NESCOE has asked, and ISO-NE has responded favorably, to including analysis of possible right-sizing initiatives in its upcoming work plan. NESCOE is hopeful that the process ISO-NE has committed to undertaking in New England would align with the Commission’s proposed reforms.
The details of the proposed reforms clarify that at the conclusion of the process the Commission sets out, there is no obligation for transmission providers to actually replace existing facilities. NESCOE supports this flexibility. NESCOE suggests that the reforms should be structured around the need for greater transparency around these types of projects so that informed decisions can be made regarding cost effectiveness, which should benefit the region as a whole.
The NOPR sets forth the proposed logistics of the proposed right-sizing requirement, including that the transmission provider would identify the facility that may need to be replaced with an in-kind transmission facility. While NESCOE believes a final rule need not be overly detailed regarding each required step, it strongly supports the core principle of requiring transparency for these situations. In New England, transmission owners initiate “asset condition” projects to maintain reliability of assets on their systems in accordance with national and regional standards. Asset condition projects, which are primarily attributed to aging, damaged, or otherwise obsolete equipment, are a separate category of projects that are not part of the regional planning process ISO-NE uses to select reliability projects for inclusion in the Regional System Plan to solve issues identified in Needs Assessments.
Although there is less visibility around these projects compared to the planning process that ISO-NE employs, the costs of asset condition projects are nonetheless allocated to consumers in the same way as reliability projects that ISO-NE selects, i.e., on a pro rata basis across regional network load. As noted above, asset condition projects are becoming an increasingly material component of the overall regional network service charge, with over $2.5 billion of such projects placed in service, and $3.122 billion more proposed, planned, or under construction. By way of comparison, ISO-NE-identified reliability projects currently proposed, planned, or under construction are estimated at $1.294 billion. The reforms proposed by the Commission could, at a minimum, shed some light on when such projects are going to be undertaken. Reforms could also result in cost savings to consumers if, after consideration of the potential for right-sizing such projects, it is determined that, for example, incorporating advanced technologies on the project could serve to increase the facility’s transfer capability. Here, too, having an independent transmission monitor for the region can significantly enhance the transparency of the planning and decision-making process.
The NOPR proposes that transmission providers must evaluate whether they can right-size any 230 kV or above transmission facility that they anticipate replacing in-kind with a new transmission facility during the next ten years to more efficiently or cost-effectively address regional transmission needs identified in Long-Term Regional Transmission Planning. NESCOE urges the Commission not to lock in a fixed voltage level for a final rule. This would provide limited usefulness for the proposed reform in New England, where there are many 115 kV transmission facilities.
NESCOE generally supports the proposal that “if a right-sized replacement transmission facility is selected in the regional transmission plan for purposes of cost allocation, only the incremental costs of right-sizing the transmission facility will be eligible to use the applicable Long-Term Regional Transmission Cost Allocation Method.”
NESCOE supports the proposal that transmission providers should amend their regional transmission planning processes to provide transparency with respect to which right-sized replacement transmission facilities have been selected in the regional transmission plan for purposes of cost allocation, and which are included in the regional transmission plan simply for informational (and not cost allocation) purposes. In response to the NOPR’s inquiry regarding whether the Commission should impose any requirements regarding how transmission providers should determine incremental costs of right-sizing the transmission facility, NESCOE recommends that transmission providers be required to explain on compliance the method they intend to use to determine these incremental costs.
The Commission proposes to require transmission providers to revise their interregional transmission coordination procedures (adopted in compliance with Order No. 1000) to apply them to the proposed Long-Term Regional Transmission Planning reforms in the NOPR. Specifically, the Commission proposes to require revisions to “existing interregional coordination procedures (and as needed, to regional transmission planning processes) “to provide for: (1) the sharing of information regarding the respective transmission needs identified in the Long-Term Regional Transmission Planning…as well as potential transmission facilities to meet those needs; and (2) the identification and joint evaluation of interregional transmission facilities that may be more efficient or cost-effective transmission facilities to address transmission needs identified through Long-Term Regional Transmission Planning.”
NESCOE appreciates that the Commission is not undertaking to impose fundamental changes to interregional planning procedures. The NOPR’s proposed revisions, designed to enhance information-sharing, seem reasonable. NESCOE notes that the Interregional Planning Stakeholder Advisory Committee (“IPSAC”), which is the forum for ISO-NE, PJM, and NYISO to identify and address interregional planning issues, already shares information and coordinates on potential interregional projects that may be more cost effective than regional projects. For example, the Joint ISO/RTO Planning Committee (“JIPC”) recently announced that it would participate in a Department of Energy Atlantic Offshore Wind Transmission Study as an alternate means of evaluating interregional transmission to integrate offshore wind across ISO-NE, NYISO, and PJM.
Additionally, NESCOE believes that the Commission should continue its productive collaboration with state officials to explore whether changes to interregional transmission coordination requirements are broadly needed. For example, the most recent Joint Task Force meeting on July 20, 2022 included discussion on this issue.
For the reasons discussed above, 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.
/s/ Jason Marshall
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: August 17, 2022