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
REPLY COMMENTS OF THE
NEW ENGLAND STATES COMMITTEE ON ELECTRICITY
Pursuant to the Advance Notice of Proposed Rulemaking issued by the Federal Energy Regulatory Commission (“Commission” or “FERC”) on July 15, 2021 (“ANOPR”), and the Commission’s September 3, 2021 Notice of Extension of Time, the New England States Committee on Electricity (“NESCOE”) files these reply comments on the Commission’s inquiries about potential reforms to electric regional transmission planning and cost allocation and generator interconnection processes. NESCOE filed initial comments in this proceeding.
I. REPLY COMMENTS
A. The Commission Has Ample Authority to Propose Reforms Establishing Independent Transmission Monitors and Should Do So.
1. The Commission’s Authority to Remedy Unjust and Unreasonable Transmission Rates and Unduly Discriminatory and Preferential Transmission Planning Practices Under Federal Power Act Section 206 Is Broad.
The Commission sought comment in the ANOPR “on whether, to improve oversight of transmission facility costs, it would be appropriate for the Commission to require that transmission providers in each [regional transmission organization (“RTO”)/independent system operator (“ISO”)], or more broadly, in non-RTO/ISO transmission planning regions, establish an independent entity to monitor the planning and cost of transmission facilities in the region.” NESCOE strongly supports the Commission developing this concept further. For states and others to be able to comment meaningfully on the merits of independent transmission monitors (“ITMs”), there is a need for specificity regarding the potential functions of ITMs, which could well vary to account for regional differences.
Commenters arguing that the Commission has failed to satisfy the Federal Power Act (“FPA”) section 206 burden at this stage ignore what is readily apparent: the ANOPR is an initial step toward potential Commission action and its concepts remain under development. With the ANOPR, the Commission is seeking early comment prior to proposing concrete action, including comment “on the Commission’s authority to require an independent entity to monitor transmission spending in each transmission planning region, as well as the role that such monitor(s) would play.” The Commission is undoubtedly aware of its obligation to make “appropriate findings… under Section 206 of the FPA,” before proposing any reforms, including the establishment of ITMs.
The Commission’s authority to remedy unjust and unreasonable or unduly discriminatory and preferential transmission rates is broad. As recognized by the California Public Utilities Commission (“CPUC”):
Section 206 of the FPA gives the Commission both the authority and responsibility to ensure that any “rate, charge, classification” related to the transmission or sale of electricity is not “unjust, unreasonable, unduly discriminatory or preferential.” Appointing ITMs in each RTO/ISO, which will help the Commission ensure that transmission investments are cost-effective and result in just and reasonable rates, falls squarely within the Commission’s authority.[]
Some commenters argued that because the Commission previously found in Order No. 890 that independent transmission monitor-like entities were not necessary over a dozen years ago, it must be the case that they remain unnecessary. Such arguments ignore that the Commission must continually assess whether structures are in place to ensure that transmission services and rates continue to be just and reasonable and not unduly discriminatory or preferential. Much has changed in the fourteen years since the Commission issued Order No. 890. For example, in New England, there has been a drive toward integrating cleaner resources. Yet, impediments exist to achieving a just and reasonable energy transition, notwithstanding the Commission’s more recent efforts at reform through Order No. 1000. NESCOE supports the Commission’s current initiative in revisiting whether its prior transmission reforms are adequate in ensuring just and reasonable transmission rates.
CAISO expressed concern that “directing public utilities to retain an independent transmission monitor to oversee transmission planning functions may be perceived as intruding on how public utilities manage their own corporate affairs.” NESCOE expects that the Commission will address this concern in any proposed rulemaking. The D.C. Circuit’s decision upholding Order No. 1000’s elimination of the federal right of first refusal (“ROFR”) is instructive on this point. The Court explained that “[u]nlike the corporate governance matters at issue in CAISO, a generally accepted principle of economics directly connects rights of first refusal to rates” If the Commission determines based on the record developed in the ANOPR proceeding that requiring RTOs/ISOs to retain ITMs is necessary to ensure that transmission rates remain just and reasonable, undoubtedly this reform would be tied to jurisdictional rates.
2. Arguments that the Commission’s Authority Over Market Monitoring of Wholesale Power Markets Cannot Extend to Transmission Are Misguided.
NESCOE agrees with comments that recognize the parallels between potential ITMs and market monitors, such as independent market monitors (“IMMs”), that are already well established in RTOs/ISOs. As Advanced Energy Economy stated: “In many ways, the Independent Transmission Monitor concept mirrors the independent market monitors that the Commission required be implemented in RTOs/ISOs to ensure that the markets they operate do not result in transactions or operations that are unduly discriminatory or preferential or provide opportunity for the exercise of market power. There is a clear link between the implementation of independent monitoring functions and just and reasonable rates.”
EDF Renewables further stated:
In Order No. 719,[] the Commission explained that Market Monitors “monitor organized wholesale markets to identify ineffective market rules and tariff provisions, identify potential anticompetitive behavior by market participants, and provide comprehensive market analysis critical for informed policy decision making.” The ITM could perform a similar role with respect to transmission and interconnection rules, policies, and processes so as to promote just and reasonable outcomes.[]
Several commenters argued that while the Commission has the authority to require market monitors for wholesale power markets in RTOs/ISOs, it lacks the authority to require ITMs for transmission planning and costs. For example, one utility argued that:
any assertion that an Independent Transmission Monitor is analogous to the market monitors that currently exist within RTOs/ISOs is . . . misguided for the simple reason that transmission rates are still set through traditional cost-of-service regulation. Market monitors may be justified when wholesale electricity rates are set by markets, where bids and offers are confidential and market participants may exercise market power, but when transparent planning processes already exist, transmission models are shared, and all transmission costs are subject to formula rate protocols and ultimate acceptance by the Commission, an independent monitor is entirely duplicative of the Commission.[]
The Edison Electric Institute (“EEI”) echoed these comments, adding, inexplicably, that another reason ITMs are not needed is that “all public utilities are also regulated at the state level and subject to oversight and scrutiny from their state commissions.” On this last point, the reforms at issue here are related to transmission costs regulated by this Commission, not by state commissions. The fact that state regulators oversee costs subject to their jurisdiction has no bearing on the need for scrutiny and oversight of transmission costs subject to FERC’s jurisdiction.
As discussed below, none of these arguments demonstrate that the Commission lacks authority to implement ITMs. They ignore structural concerns in connection with today’s planning processes and the Commission’s need to guard against excessive consumer costs.
a. The Commission’s authority to require ITMs is not restricted because transmission is subject to cost-of-service rate regulation, and arguments that the Commission’s authority is limited to addressing market power are premised on faulty assumptions and otherwise inaccurate.
The Commission’s authority to require the establishment of ITMs is not tied to whether transmission rates are cost-of-service as opposed to market-based rates. Nor is the Commission’s authority limited to taking action to mitigate the exercise of market power. In upholding the Commission’s reforms to transmission planning in Order No. 1000, the D.C. Circuit affirmed that “[t]he authority and obligation that Congress vested in the Commission to remedy certain practices is broadly stated.” In requiring market monitoring as a function of RTOs, the Commission did not rest only on the need to curb market power but also to ensure that there was no unduly discriminatory, anti-competitive conduct: “Market monitoring is an important tool for ensuring that markets within the region covered by an RTO do not result in wholesale transactions or operations that are unduly discriminatory or preferential or provide opportunity for the exercise of market power.”
Commenters arguing that monitoring is not needed for transmission ignore that unduly discriminatory conduct can occur in the context of cost-based transmission services. As one competitive transmission developer explained, its experience is that incumbent public utility transmission owners routinely seek to undermine the elimination of the ROFR on as many transmission projects as possible:
Before the ink was dry on Order No. 1000, as former Commissioner Moeller predicted, self-interested transmission owners began looking for ways to circumvent the competition requirement, which Order No. 1000 tied to regional cost allocation. This would mean changing cost allocation where feasible and planning locally where a change in cost allocation was not feasible. . . . [I]ncumbent transmission owners have spent the last 10 years working to circumvent Order No. 1000. These efforts have taken the form of shifting cost allocation from regional allocation to local allocation, gaming Form No. 715 criteria, generally expanding local planning, ignoring all regional planning outside of RTOs.[]
The argument made by some transmission owners and their representatives that there is no need for enhanced oversight in the provision of transmission services is further undermined by their pleas for the reinstatement of the ROFR.
b. The existence of regional transmission planning processes does not limit the authority of the Commission to require ITMs, especially for the substantial amount of self-selected transmission projects.
The premise that “transparent planning processes exist” does not support the conclusion that the Commission lacks the authority to require ITMs. As a starting point, ITMs could support and complement existing regional planning processes through recommendations for improvements, such as ways to enhance transparency and discipline costs. Moreover, as discussed in NESCOE’s and others’ comments, many transmission projects are not selected by RTOs/ISOs, yet their costs are regionalized. In New England, transmission owners 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. Over $2 billion in “asset condition” projects have been placed in service in New England as of October 2021.
Others identified the same issue but by a different name. The National Association of Regulatory Utility Commissioners (“NARUC”) explained that “[t]he decision to undertake an asset replacement project, or whether a feasible alternative solution would be more cost-effective, involves a significant amount of discretion, yet is typically delegated to incumbent utilities with no scrutiny in regional transmission planning processes. These utility self-approved projects currently comprise approximately half of IOUs’ transmission spending in FERC-jurisdictional RTOs/ISOs.” Similarly, the CPUC explained:
incumbent investor owned utilities (“IOUs”), in many instances with the approval of [RTOs] and [ISOs], have deliberately contravened the intent of Orders 890 and 1000 by shielding at least half of total transmission investment across the country from meaningful stakeholder review in regional transmission planning processes, and insulating the vast majority, i.e., approximately 97%, of such investment from competition.
Incumbent IOUs have prioritized investment in asset repair or replacement projects, referred to here as “utility self-approved” projects, because they can develop such projects without being subject to any oversight in regional transmission planning processes, as is the case in the [CAISO’s] control area, or wholly inadequate oversight, as is the case in many other regions of the country…[]
One commenter added that public utilities “are splurging on local transmission projects, with little oversight or accountability. Regional planning entities claim that they are powerless to interfere, and the Commission does not review utilities’ capital spending. Many projects do not even need state siting permission, leaving billions of dollars of capital expenditures essentially unregulated.”
At a minimum, there is more than ample authority for the Commission to implement ITMs to facilitate the Commission’s oversight over projects that escape or receive less scrutiny in regional transmission planning processes. Nonetheless, for the reasons NESCOE discussed in its initial comments, there is a need for the Commission to develop the ITM concept more broadly, particularly on cost containment issues, for all transmission projects.
c. The fact that many transmission costs are subject to formula rates and protocols accepted by the Commission does not render ITMs unnecessary or limit the Commission’s authority to require them.
Several transmission owners argued that the existence of formula rate processes obviates the need for ITMs. One transmission owner argued that there is no need for ITMs because customers and other interested parties have the right to file a section 206 complaint if there is a problem with transmission planning processes or costs. The argument is that “the stakeholders participating in transmission planning processes are sophisticated and capable of submitting a formal dispute, informing the Commission, or filing a complaint, if a transmission provider is not following its tariff or the principles of Order Nos. 890 and 1000.”
As NESCOE explained, the formula rate process is resource-intensive, and absent an interested party bringing a formal challenge, the Commission is not likely to review the costs being recovered. The issue is largely not whether state regulators, consumer advocates, and smaller transmission customers are sophisticated or capable of filing challenges. It is a matter of resources. This lack of resources is exacerbated by the profound asymmetry in access to information that exists in annual updates of transmission formula rates and even, some argued, in the regional planning processes themselves. With respect to formula rate updates, transmission owners are in sole possession of all of the data, while consumer-interests endeavor to ask the right questions (which may be met with objections) to unearth information that might demonstrate that the transmission owner has inaccurately calculated costs, not complied with the tariff, or imprudently incurred costs. Indeed, on the last point, the burden that the Commission places on entities seeking to demonstrate that costs are imprudent is nearly insurmountable, as discussed thoroughly by the Harvard Electricity Law Initiative.
EDF Renewables detailed some of the impediments that exist in scrutinizing specific projects:
At present, in the absence of an ITM, it is difficult for the Commission or stakeholders to engage on transmission-related issues at the project level. The rules are complicated and vary from one market to the next. The planning processes themselves often lack transparency. The Commission and stakeholders may not have access to the data or models needed in order to assess whether or not even to file a section 206 complaint. Moreover, from a stakeholder’s perspective, filing a complaint is costly, time consuming, and risks antagonizing an RTO or transmission provider with whom the stakeholder strives to have a positive working relationship.[]
NESCOE agrees that “[i]n RTOs with formula transmission rates, an ITM could . . . provide valuable review and oversight of [transmission owner] implementation of those rates to
the extent the RTO does not do so.” As TAPS noted, “[s]ome RTOs (e.g., [the Midcontinent Independent System Operator (“MISO”)]) provide some oversight over formula rate inputs today, but others (e.g., [the Southwest Power Pool, Inc. (“SPP”)]) provide none, leaving all the work and expense to customers.” ISO-NE does not provide any such oversight. Having an ITM to provide review and oversight support of New England transmission costs—some of which, as noted above, result from asset condition projects that incumbent utilities self-select—would fill a notable gap in the ISO-NE planning process.
One system operator suggested there is no need for ITMs because “[t]he Commission may submit data requests to transmission planners, audit whether transmission planning processes adhere to existing rules or regulations, or initiate and/or entertain section 206 proceedings relating to public utility transmission planning processes. The Commission itself can hire employees and consultants to help address questions or concerns or fulfill the functions the ANOPR contemplates an independent transmission monitor might perform.” NESCOE understands that the Commission does not do this on a regular basis: “Currently, the Commission does not routinely assess compliance with its planning principles, and [the Harvard Electricity Law Initiative is] aware of only one Commission investigation into utility-controlled planning processes.” NESCOE further recognizes the resources implicated if the Commission were to regularly initiate such investigations. The reforms that the Commission contemplates with ITMs could provide needed support to the Commission in fulfilling its obligations under the FPA to ensure that rates are just and reasonable. The Commission’s consideration of moving to a system with such support is well-timed in light of anticipated future transmission infrastructure needs.
3. Requiring Independent Transmission Monitors Would Neither Infringe on Public Utility Transmission Owners’ FPA Section 205 Rights Nor Be an Unlawful Delegation of the Commission’s Authority.
Requiring ITMs would not infringe on public utility transmission owners’ FPA section 205 rights, as some commenters suggested. Certain public utility transmission owners argued that their exclusive right to establish and change tariffs governing the rates, terms, and conditions over their transmission service under FPA section 205 extends to transmission planning processes, and that in turn, having an independent entity monitor any aspect of these planning processes is at odds with their FPA section 205 rights.
Public utility transmission owners, of course, have exclusive FPA section 205 rights over their tariffs including rates, terms, and conditions of transmission service. If the Commission ultimately does propose reforms requiring ITMs, and if the form that the ITM were to take requires modifications to any existing contracts, such as certain transmission owners’ agreements, the Commission would need to demonstrate under FPA section 206 that the existing agreements are unjust and unreasonable without ITMs, and that the addition of ITM oversight support is just and reasonable. This is the approach that the Commission took in Order No. 1000 in requiring the elimination of the ROFR contained in various transmission owners’ agreements, which multiple Courts upheld.
There is no merit to the contention that “Congress provided no role in this process for a ‘middleman’ entity, such an ITM, to review and pass judgement on the justness and reasonableness of a public utility’s rates, and the Commission cannot compel public utilities to participate in such a structure.” The Commission, as discussed above, has broad authority under the FPA to determine how to ensure just and reasonable rates, and prescribing, for example, that an independent entity monitor and report on a public utility’s transmission rates falls squarely within that authority. Nothing in this approach suggests in the least that public utility transmission owners would be ceding any FPA section 205 rights by having their transmission rates and planning practices monitored by an independent entity.
Indicated PJM Transmission Owners also argued that the Commission may be limited in “its ability to delegate authority to an independent transmission monitor without express Congressional authorization.” They cautioned that courts have rejected attempts “to delegate an agency’s Congressionally-granted oversight authority to a private actor.”
The cases that the Indicated PJM Transmission Owners cited in discussing their objections to ITMs as falling under the “unlawful delegation doctrine” are not applicable to what the Commission appears to be considering for ITMs. The doctrine, as articulated in Perot v. FEC, is “the general proposition that when Congress has specifically vested an agency with the authority to administer a statute, it may not shift that responsibility to a private actor.”
In the ANOPR, the Commission has taken care to explain that “[a]n independent transmission monitor would not replace the Commission’s rate jurisdiction but instead could provide the Commission with an additional means of ensuring that rates are just and reasonable.” Nothing in the ANOPR suggests that the Commission is considering shifting the responsibility of ensuring just and reasonable rates to ITMs. As the CPUC pointed out, ITMs can serve as “an additional means of ensuring that rates are just and reasonable.” Adding oversight support does not mean the Commission is relinquishing its statutory obligation. To the contrary, it appears that the Commission is seeking additional tools to better enable it to perform its statutory obligation of ensuring that rates are just and reasonable.
Grasping at straws, WIRES argued that “[e]ven if an independent transmission monitor were not expressly vested with binding decisional authority over rates, terms and conditions of service, such an entity, essentially deputized by the Commission with authority to review transmission provider spending on transmission facilities, conduct necessary analyses, and to make preliminary determinations and recommendations to the Commission regarding transmission facility costs, would be inherently vested with the veneer of the exercise of federal authority given the role’s ability to inhibit, interfere, coerce, and influence transmission planning processes and decisions.”
Similar arguments were made and rejected when the Commission first required market monitoring as a core function of RTOs in Order No. 2000. There, the Commission held:
In response to commenters arguments that RTO market monitoring results in an impermissible shift of Commission authority to other entities, we emphasize that performance of market monitoring by RTOs is not intended to supplant Commission authority. Rather it will provide the Commission with an additional means of detecting market power abuses, market design flaws and opportunities for improvements in market efficiency. Further, because market monitoring plans will be required to be filed with and approved by the Commission as part of an RTO proposal, we will retain the ability to determine what, how and by whom activities will be performed in the first instance.[]
In Order No. 2000-A, the Commission affirmed that by rejecting pleas of several utilities to eliminate the market monitoring function of RTOs, it was “not delegating our statutory authority and responsibility; … we believe RTOs can help us understand and identify market problems.”
The “unlawful delegation” concerns are smoke and mirrors. So long as the Commission takes care to clearly delineate the responsibilities of ITMs as distinguished from that of the Commission, the “unlawful delegation” argument is a non-issue.
4. Arguments that the Functions of Independent Transmission Monitors Would Be Duplicative of RTOs/ISOs or Market Monitors are Overstated.
A number of utilities assert that ITMs are unnecessary because they would duplicate existing RTO/ISO functions or those of the RTO/ISO market monitors. These commenters are effectively arguing that the forest is more than sufficiently logged where cost oversight is concerned. NESCOE strongly disagrees.
Potomac Economics—the IMM for MISO and external market monitor for ISO-NE and the New York ISO (“NYISO”)—explained in reply comments that “while market monitors do monitor transmission issues in the operating horizon, our scope is generally limited in the planning horizon. Although there may be a small overlap between the two, it is not accurate to argue that the current market monitoring scope includes the ITM scope proposed by the Commission.” Similarly, EDF Renewables noted that “the work of ITMs will not duplicate the work of IMMs, as IMMs seldom weigh in on the more technical aspects of transmission or interconnection rules, processes, or policy.”
Regarding the work of RTOs/ISOs, while it may be appropriate for the scope of ITMs to vary by region, in our region, ISO-NE does not review individual New England transmission owners’ transmission formula rate updates. As discussed above, this is left to individual customers, states, and other consumer-side interests. Furthermore, ISO-NE’s mission does not reference “consumers” or “ratepayers” once, let alone mention any cost monitoring or oversight function, despite the Commission’s duty to review ISO-NE’s FPA section 205 filings to ensure that consumers are not overcharged.
Any suggestion that ISO-NE monitors specific transmission project costs is also misleading. ISO-NE’s sole role in “monitoring” project costs is limited to cost allocation. This process is described in Planning Procedure No. 4, “Procedure for Pool-Supported PTF Cost Review.” As the title suggests, ISO-NE’s review only involves determining whether costs should be pool supported, i.e., regionalized in New England and allocated across states on a load-ratio share basis. ISO-NE’s finding that costs are not eligible to be regionalized does not mean that they are disallowed. Transmission owners can seek to localize those costs and charge them to local customers through Local Network Service (“LNS”) rates. ISO-NE does not have authority to determine that costs cannot be collected through the LNS rate. Indeed, as discussed above, the Commission presumes costs to be prudently incurred, and those seeking to challenge such costs face a high, if not insurmountable, bar.
Moreover, even if there were some overlap between an ITM’s oversight support in connection with the regional planning process and the roles that an RTO/ISO performs, there would be a benefit to involving an ITM. Oversight functions related to the planning process may not be appropriate to leave solely to the very entities running that process. In response to comments by RTOs/ISOs on this issue, Potomac Economics observed that planning processes “are subject to concerns bias and efficiency” and that “RTOs have relatively strong incentives to satisfy its customers, particularly its Transmission Owners, given that RTO membership is voluntary, and that membership is generally decided by the Transmission Owners. Therefore, an ITM can provide a valuable check on the decisions and assumptions made by the RTO in the planning process and provide additional transparency for the market participants.”
Ultimately, whether or not an ITM’s responsibilities would be duplicative of those of an RTO/ISO would be dependent on the scope of the ITM’s activities and the particular regional planning processes in each RTO/ISO. The Commission can develop these proposed scopes mindful of this consideration, recognizing that regions may have varying oversight needs, but that should not prevent the Commission from further developing this critical concept.
5. The Commission Should Not Succumb to Threats About Delays that Would Result from Requiring Independent Transmission Monitors.
It is no surprise that much of the opposition to the concept of ITMs comes from those companies that would be subject to enhanced oversight. A number of transmission owners described a parade of horribles that would result from reforms the Commission may implement with respect to ITMs. For example, under the bold heading that “Enhanced Transmission Oversight is Bad Policy,” Entergy argues that “the practical effect of any formal increased oversight is that it will increase the risk and difficulty associated with building transmission, thereby delaying an already long process.” Others ostensibly expressed concern about consumers, arguing there is “no need for further oversight at increased consumer expense and further project delay.”
NESCOE recognizes that the details of implementation may be complex and urges the Commission to be deliberate in developing scopes of responsibility for ITMs. The Commission must be mindful of the costs for additional oversight by ITMs that would inevitably end up being paid by consumers. But the Commission should not give into threats of delay and litigation as the basis for not pursing what otherwise could be a very important consumer protection.
The oversight support that ITMs can provide to the Commission is closely linked to reforms the ANOPR contemplates that seek to remove barriers to transmission needed to support the needs of a future grid. As NESCOE explained, strong transmission cost transparency and oversight would help build consumer confidence in infrastructure decisions and support for incremental investment, which is particularly needed in New England where transmission costs have escalated dramatically over the past twenty years. ITMs could be tasked with examining structural and rate design issues that require careful reconsideration to guard against unwarranted consumer costs and could shed light on complex ratemaking processes. As articulated by the Massachusetts Attorney General, “[i]f thoughtfully designed and implemented, we believe a requirement for ITMs has the potential to provide significant benefits to consumers.” NESCOE agrees that additional independent checks on transmission spending would be “particularly appropriate if the Commission adopts planning or cost allocation process reforms that introduce greater risk to ratepayers.” The refinement of the ITM concept should feature prominently in any proposed rule that follows the ANOPR.
B. The Commission Should Not Create New Transmission Incentives as Part of These Reforms.
The ANOPR asked “whether and, if so, how to expand or improve any incentives to incent the development of regional transmission facilities.” NESCOE strongly agrees that:
the inefficiencies in the transmission planning and interconnection processes are not the consequence of a lack of incentives, nor would they be remedied by expanding the universe of potential incentive options. The solution is to remedy those inefficiencies through process reforms, and not by offering additional, cost-increasing incentives. Using financial inducements to fix a problem caused by process failures and deficiencies will only increase consumer costs without any guaranteed benefit or improvement.[]
Unfortunately, for the most part, the Notice of Proposing Rulemaking that the Commission issued in March 2020 proposed “reforms” that would vastly expand the incentives available to utilities without regard for whether the incentives are narrowly tailored to achieve their intended goal or their impact on consumer costs. To the extent the Commission pursues any action on incentives associated with the reforms in the ANOPR, NESCOE urges the Commission not to adopt proposals to increase or implement new transmission incentives without analysis of whether existing incentives have achieved their intended goals and how new incentives would benefit consumers. Additionally, NESCOE urges the Commission to pursue any incentives reforms in the context of another supplemental rulemaking to the March 2020 NOPR, similar to the approach the Commission took with the Supplemental Notice of Proposed Rulemaking issued in April 2021.
C. The Commission Should Revisit and Revise an Outdated Policy that Presumes All Transmission Investments are Prudent.
Several commenters asked the Commission to revisit its policy of presuming that all transmission investments are prudent. The Harvard Electricity Law Initiative filed the most detailed comments in this area, providing both a legal demonstration of the need to adjust this policy as well as a proposed framework for narrowing the presumption based on suggested criteria. Those comments described how the Commission’s current policy was borne out of “administrative convenience,” emphasizing that such convenience must be subordinate to the Commission’s obligation to ensure that rates are just and reasonable.
NESCOE agrees that it is timely for the Commission to propose changes to its default presumption that all transmission investments are prudently made. In fact, such changes are long overdue. Five years ago, shortly after the implementation of Order No. 1000 reforms in New England, NESCOE asked the Commission to explore changes to its presumption of prudence in the case of time-sensitive projects. Additionally, in comments on the proposed rule preceding Order No. 1000, Massachusetts agencies stated that “the time may be ripe for the Commission to alter its practice of presuming prudence in its review of project costs” and asked the Commission to “reconsider its presumption of prudence and either remove the presumption altogether or ensure that sufficient resources, access and information are available to potential protesters to ensure that a proper prudence review can be conducted.” The Massachusetts Order 1000 Comments identified the need for the Commission to “pay increased attention to rising transmission costs” as it took action to remove barriers to investment.
The ANOPR signals clearly that the Commission is paying close attention to consumer costs alongside new transmission planning reforms. NESCOE greatly appreciates the Commission’s invitation for comment in this area. Consistent with the Commission’s concern in the ANOPR that “ratepayers are not saddled with costs for transmission facilities that are unneeded or imprudent[,]” it should ensure that transmission planning for a future grid does not leave consumer protections behind. Along with developing further the concept of ITMs, discussed above, the Commission should pair any proposed planning changes with a proposal to revise its presumption of prudence for transmission investments. The suggested criteria that the Harvard Electricity Law Initiative proposed are a reasonable starting point in considering how to modify the current default presumption.
D. The Office of Public Participation Is Critical to Ensuring that Equity and Environmental Justice Are Accounted for in Interstate Electric System Planning.
Environmental justice has appropriately gone from being a “mere footnote” decades ago to garnering headline attention today. The Commission has taken a critical step to increase public participation and enable engagement across its range of regulatory activities by establishing the Office of Public Participation (“OPP”). NESCOE agrees with other commenters that the OPP can and should have a central role to play in incorporating equity and environmental justice as transmission planning evolves. To support these efforts, NESCOE recommends that the OPP’s activities—from the earliest point possible—include a focus on providing engagement opportunities and support for disadvantaged communities in regional electric transmission planning and development processes.
E. The Commission Should Give Competition a Genuine Chance to Succeed.
Incumbent transmission utilities and their representatives echo common themes in asking the Commission to revisit the federal ROFR removal it directed through Order No. 1000. Their complaints read like shared talking points: elimination of the ROFR has led to delays, collaboration has suffered, and competition already exists when incumbents bid out services and materials.
Reinstating the ROFR would chart a course for the future grid using yesterday’s regulatory model. The Commission should reject the invitation to take a regulatory step backwards by retreating from competition. There is, instead, a clear path forward. As NESCOE and others explained, the promise of competition in Order No. 1000 can be fulfilled by eliminating exceptions or “carve outs” that have swallowed the rule. In New England, for example, since Order No. 1000 went into effect in our region, 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. NESCOE agrees that “reliance upon competitive processes is especially opportune as the region moves to a longer-term, forward-looking planning” structure.
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. The Commission’s seriousness about protecting consumers from excessive costs, a key feature of the ANOPR, should drive not only a retention of its Order No. 1000 ROFR policy but also new reforms to the rule recalibrating carve-outs and exemptions that have impeded competition.
The Commission should not be swayed by incumbent transmission owners’ attempts to justify scaling back the ROFR’s elimination. Bidding out services and materials for sole-sourced projects, while generally a sound business practice, is a false equivalency and does not achieve the same scale of potential cost savings, innovation, or discipline as a competitive process for transmission solutions. Regarding collaboration, competitive processes allow—and may even incentivize—transmission developers to partner in developing and proposing projects. For example, the only project that ISO-NE has selected through the Order No. 1000 competitive process is a project that Eversource and National Grid jointly sponsored. Moreover, collaboration is, of course, not an end in itself. The public interest in competition, recently articulated in a Presidential Executive Order, outweighs any diminution of dialogue that is necessitated by the need to maintain fairness in a competitive process.
There does not appear to be factual support for claims that competitive processes are delaying transmission from being placed in-service by an identified “need” date. As far as NESCOE is aware, ISO-NE has not expressed any concerns about reliability risks stemming from the only competitive solicitation it administered to date. The Commission should not credit unsubstantiated comments suggesting a purported nexus between competition and risks to reliability. In fact, as NESCOE explained in a separate proceeding, frameworks exist to enhance competition without compromising reliability. The Commission should require transmission providers to explore the adoption of alternative frameworks that would, unlike some current structures, foster competition while accounting for time-sensitive reliability needs.
F. The Commission Should Encourage RTOs/ISOs to Explore the Further Use of Probabilistic Planning Approaches.
The ANOPR asked whether “greater use of probabilistic transmission planning approaches may better assess the benefits of regional transmission facilities.” A number of New England transmission owners provided qualified support for greater use of such approaches. NESCOE would support ISO-NE exploring further application of probabilistic planning methods as a complement to current reliability planning practices. As part of stakeholder discussions in this area, ISO-NE could identify any system reliability benefits that may not be measured through existing planning standards or study criteria.
G. The Commission Should Work with the Joint Federal-State Task Force on Electric Transmission to Explore Potential Changes to Interregional Planning Rules.
Some commenters urged the Commission to move away from the current interregional transmission planning coordination framework to require interregional—or even nationwide—transmission planning. NESCOE respectfully cautions the Commission against proposing a generic rule that prescribes interregional planning before understanding more fully if those changes are truly needed. The current coordination framework provides important flexibility, recognizing that regions are differently situated with respect to exploring transmission needs and options with their neighbors. For example, MISO described having pursued various approaches to interregional coordination with different neighboring RTOs/ISOs based on the unique circumstances and needs at the seams. The Interregional Planning Stakeholder Advisory Committee (“IPSAC”), which is the forum for ISO-NE, PJM, and NYISO to identify and address interregional planning issues, began discussions last month regarding potential joint analysis on integrating offshore wind. All of these planning initiatives are taking place under the Commission’s current interregional coordination framework.
In the first instance, the Commission should leverage its collaborative work with state officials as part of the Joint Federal-State Task Force on Electric Transmission (“Joint Task Force”) to explore whether changes to interregional transmission coordination requirements are broadly needed. That discussion could identify practices relating to interregional coordination that are working well and inform changes that neighboring regions can adopt in the near-term to improve coordination, potentially without the need for Commission action. However, to the extent the Joint Task Force identifies a need for broader reform, any Commission proposal would be better tailored to address impediments to interregional planning and help promote greater support for a later proposed rule.
For the reasons discussed above, NESCOE respectfully requests that the Commission consider these reply comments along with the NESCOE Initial Comments in developing any proposed rule or taking further action on the potential reforms discussed in the ANOPR.
/s/ Jason Marshall
New England States Committee on Electricity
424 Main Street
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