NESCOE

Reply Comments on FERC’s Advance Notice of Proposed Rulemaking (ANOPR) on Transmission

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Dated: November 30, 2021

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UNITED STATES OF AMERICA

BEFORE THE

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”),[1] 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.[2]

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.”[3]  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.”[4]  The Commission is undoubtedly aware of its obligation to make “appropriate findings… under Section 206 of the FPA,”[5] 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.[6]  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.[[7]]

Some commenters argued that because the Commission previously found in Order No. 890[8] that independent transmission monitor-like entities were not necessary over a dozen years ago, it must be the case that they remain unnecessary.[9]  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.[10]  Yet, impediments exist to achieving a just and reasonable energy transition, notwithstanding the Commission’s more recent efforts at reform through Order No. 1000.[11]  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.”[12]  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”[13]  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.”[14]

EDF Renewables further stated:

In Order No. 719,[[15]] 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.[[16]]

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.[[17]]

The Edison Electric Institute (“EEI”) echoed these comments,[18] 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.”[19]  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.”[20]  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.”[21]

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.[[22]]

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.[23]

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.[24]  Over $2 billion in “asset condition” projects have been placed in service in New England as of October 2021.[25]

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.”[26]  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…[[27]]

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.”[28]

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.[29]

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.[30]  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.[31]  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.”[32]

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.[33]  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.[34]  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.[35]

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.[[36]]

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.”[37]  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.”[38]  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.”[39]  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.”[40]  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.[41]

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.[42]

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.”[43]  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.”[44]  They cautioned that courts have rejected attempts “to delegate an agency’s Congressionally-granted oversight authority to a private actor.”[45]

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.”[46]

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.”[47]  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.”[48]  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.”[49]

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.[[50]]

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.”[51]

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.[52]  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.”[53]  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.”[54]

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,[55] despite the Commission’s duty to review ISO-NE’s FPA section 205 filings to ensure that consumers are not overcharged.[56]

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.[57]  This process is described in Planning Procedure No. 4, “Procedure for Pool-Supported PTF Cost Review.”[58]  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.[59]

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.”[60]

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.”[61]  Others ostensibly expressed concern about consumers, arguing there is “no need for further oversight at increased consumer expense and further project delay.”[62]

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.[63]  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.[64]  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.”[65]  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.”[66]  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.”[67]  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.[[68]]

Unfortunately, for the most part, the Notice of Proposing Rulemaking that the Commission issued in March 2020[69] 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.[70]

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.[71]  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[72] as well as a proposed framework for narrowing the presumption based on suggested criteria.[73]  Those comments described how the Commission’s current policy was borne out of “administrative convenience,”[74] emphasizing that such convenience must be subordinate to the Commission’s obligation to ensure that rates are just and reasonable.[75]

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.[76]  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.”[77]  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.[78]

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.[79]  Consistent with the Commission’s concern in the ANOPR that “ratepayers are not saddled with costs for transmission facilities that are unneeded or imprudent[,]”[80] 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.[81]

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.[82]  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”).[83]  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.[84]  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,[85] collaboration has suffered,[86] and competition already exists when incumbents bid out services and materials.[87]

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.[88]  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.[89]  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.[90]

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.[91]  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,[92] 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.[93]  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.”[94]  A number of New England transmission owners provided qualified support for greater use of such approaches.[95]  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.[96]  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.[97]  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.[98]  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.[99]  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.

II.            CONCLUSION

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.

Respectfully Submitted,

 

/s/ Jason Marshall                 

Jason Marshall

General Counsel

New England States Committee on Electricity

424 Main Street

Osterville, MA 02655

Tel: (617) 913-0342

Email:  jasonmarshall@nescoe.com

 

/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

Email:  pkimmel@pgklawoffice.com

 

Attorneys for the New England States Committee

on Electricity

 

Date:  November 30, 2021

Document Source Citations

[1]     Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, Advance Notice of Proposed Rulemaking, 176 FERC ¶ 61,024 (2021).

[2]     Initial Comments of the New England States Committee on Electricity, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“NESCOE Initial Comments”).

[3]     ANOPR at P 163.

[4]     Id. at P 164.

[5]     Initial Comments of National Grid PLC (“National Grid”), Docket No. RM21-17-000 (filed Oct. 12, 2021) (“National Grid Initial Comments”), at 43.  See also Comments of WIRES, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“WIRES Initial Comments”), at 21.

[6]     S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 56 (D.C. Cir. 2014) (affirming in connection with finding Order No. 1000 lawful that “[t]he authority and obligation that Congress vested in the Commission to remedy certain practices is broadly stated”).

[7]     Initial Comments of the California Public Utilities Commission, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“CPUC Initial Comments”), at 65 (quoting 16 U.S.C. § 824e).

[8]     Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 118 FERC ¶ 61,119, order on reh’g, Order No. 890-A, 121 FERC ¶ 61,297 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

[9]     See, e.g., Comments of the California Independent System Operator Corporation [(“CAISO”)] on Advance Notice of Proposed Rulemaking, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“CAISO Initial Comments”), at 116-17 (citing Order No. 890 at P 567).

[10]   See NESCOE Initial Comments at 7-9.

[11]   Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 136 FERC ¶ 61,051 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g and clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014).  See NESCOE Initial Comments at Section V.A.

[12]   CAISO Initial Comments at 120 (citing Cal. Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395, 403 (D.C. Cir. 2004)) (“CAISO”) (“The Commission cannot dictate the choice of ‘CEO, COO, and the method of contracting for services, labor, office space’ or remove or replace a board of directors”).

[13]   S.C. Pub. Serv. Auth., 762 F.3d at 74.

[14]   Comments of Advanced Energy Economy, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“AEE Initial Comments”), at 40.  See Comment of the Harvard Electricity Law Initiative, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“Harvard Electricity Law Initiative Initial Comments”), at 61-62 (“Like RTO market monitors, ITMs will ‘assist[] the Commission’ in ensuring just and reasonable rates.”) (quoting Order No. 719 at P 354 (2008) (cleaned up)).

[15]   Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, 125 FERC ¶ 61,071 (2008), order on reh’g, Order No. 719-A, 128 FERC ¶ 61,059, order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).

[16]   Comments of EDF Renewables, Inc., Docket No. RM21-17-000 (filed Oct. 12, 2021) (“EDF Renewables Initial Comments”), at 18-19 (quoting Order 719 at P 354) (cleaned up)).

[17]   Motion to Intervene and Initial Comments of the Entergy Operating Companies (“Entergy”), Docket No. RM21-17-000 (filed Oct. 12, 2021) (“Entergy Initial Comments”), at 25-26.

[18]   Initial Comments of the Edison Electric Institute, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“EEI Initial Comments”), at 42-43 (“while it is appropriate to have independent market monitor for the capacity, energy, and ancillary services markets as we have today, transmission does not present the same issues.  Unlike generators that the Commission determines to not have market power and able to sell services at market-based rates, transmission is a cost of service regulated service.  Prior to making a change to their rates, TOs are required to make a section 205 filing with the Commission that is then subject to review by other stakeholders, including discovery.  Plans to expand are public through the Order Nos. 890 and 1000 planning processes, the standards by which TOs plan are public, as are the models.  This differs from the energy markets where the bids are confidential and plans for expansion are not known or subject to public process.”).

[19]   Id. at 43.

[20]   S.C. Pub. Serv. Auth., 762 F.3d at 56.  See also Trans. Access Policy Grp. v. FERC, 225 F.3d 667, 687 (D.C. Cir. 2000) (holding that the FPA’s antidiscrimination provisions give FERC broad authority to remedy unduly discriminatory behavior).

[21]   Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (1999) (cross-referenced at 89 FERC ¶ 61,285, 65 Fed. Reg. 809, 904 (Jan. 6, 2000), order on reh’g, Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 (2000) (cross-referenced at 90 FERC ¶ 61,201), 65 Fed. Reg. 12,088 (Mar. 8, 2000), aff’d sub nom. Pub. Util. Dist. No. 1 of Snohomish Cnty., Wash. v. FERC, 272 F.3d 607 (D.C. Cir. 2001) (emphasis added).

[22]   Comments of LS Power Grid, LLC in Response to the Commission’s Advanced Notice of Proposed Rulemaking, Docket No. RM21-17-000 (filed Oct. 12, 2021), at 31-32.

[23]   See, e.g., EEI Initial Comments at 6, 18-24; WIRES Initial Comments at 11-12; Comments of Exelon Corporation, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“Exelon Initial Comments”), at 28.  See also Section I.E, infra.

[24]   NESCOE Initial Comments at n.44.

[25]   See October 2021 ISO-New England Asset Condition Update, available at https://www.iso-ne.com/static-assets/documents/2021/10/final_rsp_asset_condition_list_oct2021.xlsx.

[26]   Motion to Intervene and Comments of the National Association of Regulatory Utility Commissioners, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“NARUC Initial Comments”), at 48.

[27]   CPUC Initial Comments at 2-3.

[28]   Harvard Electricity Law Initiative Initial Comments at 43.

[29]   See NESCOE Initial Comments at 32-35.

[30]   See, e.g., Initial Comments of Avangrid, Inc., Docket No. RM21-17-000 (filed Oct. 12, 2021) (“Avangrid Initial Comments”), at 30 (“the transmission formula rate protocols of most transmission developers and owners provide for a robust stakeholder process whereby information is provided to stakeholders, stakeholders ask data requests, and stakeholders can make informal challenges to the transmission owner. If the informal challenge does not satisfy the stakeholder concern, then the stakeholder can make a formal challenge to FERC.”); Entergy Initial Comments at 25-26 (“when … all transmission costs are subject to formula rate protocols and ultimate acceptance by the Commission, an independent monitor is entirely duplicative of the Commission.”).

[31]   Entergy Initial Comments at 26 (“…the Commission’s proposed formal enhancements to transmission oversight are unnecessary….any transmission customer or stakeholder that believes the transmission provider is running afoul of Commission policies or rules, or the filed rate, can file a complaint under FPA section 206 or FPA section 306 and Rule 206 of the Commission’s Rules of Practice and Procedure.  Where there is uncertainty or some controversy, a utility or an affected stakeholder may also file a petition for a declaratory order under Rule 207 of the Commission’s Rules of Practice and Procedure.”).

[32]   CAISO Initial Comments at 121.

[33]   NESCOE Initial Comments at 33-35.

[34]   See Motion to Intervene and Initial Comments of the New England Consumer-Owned Systems, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“Consumer-Owned Systems Initial Comments”), at 30 (“It is also doubtful that even a substantial increase in funding and other resources [to NESCOE, as the Regional State Committee] would provide a successful counterweight to the information asymmetry that inevitably characterizes any regional transmission planning process, including New England’s.”).

[35]   See Harvard Electricity Law Initiative Initial Comments at 2-4, 45-49.  As noted therein, the CPUC recently pointed out that it found only a single instance in the past twenty years of the Commission having found a transmission expense imprudent.  Id. at n.8 (citing CPUC, Brief on Exceptions, Docket ER16-2320-002 (filed Oct. 31, 2018)).  See also Paul L. Joskow, MIT Center for Energy and Environmental Policy Research, Working Paper, Competition for Electric Transmission Projects in the U.S.: FERC Order 1000, Mar. 2019, available at https://ceepr.mit.edu/workingpaper/competition-for-electric-transmission-projects-in-the-u-s-ferc-order-1000/, at 13 (“In principle [the Commission] applies prudent investment and reasonable cost standards to the capital and operating costs presented to it by a transmission owner. Costs that are determined to be imprudent or unreasonable can be disallowed and excluded from the revenue requirement.  However, at best, such exclusions are rare.”).  NESCOE has not undertaken a further search for examples and welcomes learning of any other instances where transmission costs were determined to be imprudent.

[36]   EDF Renewables Initial Comments at 19.

[37]   Comments of Transmission Access Policy Study Group (“TAPS”), Docket No. RM21-17-000 (filed Oct. 12, 2021) at 50.

[38]   Id. at n.105.

[39]   CAISO Initial Comments at 121.

[40]   Harvard Electricity Law Initiative Initial Comments at 58 & n.239 (citing Monongahela Power, et al., 156 FERC ¶ 61,134 (2016)).

[41]   Comments of the Indicated PJM Transmission Owners, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“Indicated PJM TOs Initial Comments”), at 44-45 (citing Atlantic City Elec. Co. v. FERC, 295 F.3d 1, 10-11 (D.C. Cir. 2002)).

[42]   S.C. Pub. Serv. Auth, 762 F.3d at 76-81 (finding that FERC supported with substantial evidence its conclusion that the ROFRs were unjust or unreasonable).  See also Okla. Gas & Elec. Co. v. FERC, 827 F.3d 75, 77 (D.C. Cir. 2016) (“nothing in the Mobile-Sierra doctrine requires its extension to the anti-competitive rights of first refusal at issue here”); MISO Transmission Owners v. FERC, 819 F.3d 329, 335 (7th Cir. 2016) (holding that “FERC’s abrogation of the right of first refusal in the MISO Transmission Owners Agreement was lawful”); Emera Maine v. FERC, 854 F.3d 662 (D.C Cir. 2017) (upholding FERC’s finding that the public interest was harmed by the inclusion of the ROFR in the transmission owner agreement and that the Mobile-Sierra burden was, therefore, met).

[43]   National Grid Initial Comments at 44 (citations omitted).

[44]   Indicated PJM TOs Initial Comments at 45.

[45]   Id.

[46]   Perot v. FEC, 97 F.3d 553, 559 (D.C. Cir. 1996).

[47]   ANOPR at P 173 (emphasis added).

[48]   CPUC Initial Comments at 54 (quoting ANOPR at P 173) (emphasis added).

[49]   WIRES Initial Comments at 23.

[50]   Order No. 2000, 65 Fed. Reg. at 905.

[51]   Order No. 2000-A, 65 Fed. Reg. at 12,102.

[52]   See, e.g., Avangrid Initial Comments at 28 (“existing transmission planning stakeholder processes, along with the stakeholder review process contained in the transmission formula rates of most transmission developers and owners, provide for adequate oversight to ensure that unnecessary transmission does not get built and imprudent investments are not made.”); Comments of Eversource Energy, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“Eversource Initial Comments”), at 14-15 (“In New England, ISO-NE already provides strong, independent oversight of both transmission planning and cost allocation processes.  Additionally, the stakeholder process already provides significant transparency into transmission planning decisions and opportunities for validation of ISO-NE’s decisions.  Most of the activities proposed in the ANOPR to be undertaken by an independent transmission monitor are already performed by ISO-NE or incorporated into the ISO-NE stakeholder process.); National Grid Initial Comments at 43 (asserting that ITMs are not needed because RTOs/ISOs are sufficiently independent and they “already perform the functions that the Commission appears to contemplate for ITMs, including assessing and determining which facilities represent the most efficient or cost-effective solutions to meet regional transmission needs.”).

[53]   Comments of Potomac Economics, Ltd., Docket No. RM21-17-000 (filed Nov. 12, 2021) (“Potomac Economics Reply Comments”), at 2.

[54]   EDF Renewables Initial Comments at 19.

[55]   See ISO-NE Transmission, Markets and Services Tariff, Section I.1.3

[56]   FERC v. Elec. Power Supply Ass’n, 136 S. Ct. 760, 781 (2016) (one of the FPA’s core objectives is “to protect against excessive prices”) (cleaned up); NAACP v. FCP, 425 U.S. 662, 666 (1976) (FPA includes “the legislative command to the Commission . . . to establish just and reasonable rates for the transmission and sale of electric energy, . . . and, consequently, to allow only such rates as will prevent consumers from being charged any unnecessary or illegal costs.”) (cleaned up); NextEra Energy Res. v. FERC, 898 F.3d 14, 21 (D.C. Cir. 2018) (“The Commission must protect . . . consumers from excessive rates and charges.”) (cleaned up); TransCanada Power Mktg. Ltd. v. FERC, 811 F.3d 1, 12 (D.C. Cir. 2015) (“It is indisputable that, under established ratemaking principles, rates that permit excessive profits are not just and reasonable.”); City of Detroit v. FPC, 230 F.2d 810, 817 (D.C. Cir. 1955) (the Commission can increase rates to promote consumer benefits, but “it must see to it that the increase is in fact needed, and is no more than needed, for the purpose.”).  See also Jersey Cent. Power & Light Co. v. FERC, 810 F.2d 1168, 1207 (D.C. Cir. 1987) (Starr, J., concurring) (“The Commission stands as the watchdog providing a complete, permanent and effective bond of protection from excessive rates and charges.”) (cleaned up).

[57]   This stands in contrast to the oversight role that the SPP indicated it plays.  See Comments of Southwest Power Pool Inc., Docket No. RM21-17-000 (filed Oct. 12, 2021), at 22 (“The SPP Tariff currently requires SPP to track the costs and schedules related to all projects approved for construction under the SPP Tariff….If at any time the cost projection varies from the estimated baseline cost by more than the bandwidth defined by SPP in its business practices, SPP shall investigate the reason for the change in cost and report to the SPP Board. To facilitate this process, SPP established the Project Cost Working Group…”).  Should the Commission take a region-by-region approach to proposing ITMs, regions such as ISO-NE that lack any specific cost oversight role have a more pressing need for ITMs.

[58]   See https://www.iso-ne.com/static-assets/documents/2020/02/pp_4_rev9.pdf.

[59]   See supra n.35 and accompanying text.  NESCOE supports the Commission revisiting this presumption of prudence, as discussed below in Section I.C.

[60]   Potomac Economics Reply Comments at 4.

[61]   Entergy Initial Comments at 27.

[62]   Indicated PJM TOs Initial Comments at 46.  See also id. at 39 (“Changes to the PJM process to add an additional layer of regulation or oversight would only bog down the process in bureaucratic mire, increase cost and inefficiency, and could jeopardize the continued success of the planning process.  These burdens would directly contravene the Commission’s goals of planning for and building needed transmission.”).

[63]   NESCOE Initial Comments at 14-16.

[64]   Id. at 32-33.

[65]   Initial Comments of Massachusetts Attorney General Maura Healey, Docket No. RM21-17-000 (filed Oct. 12, 2021), at 34-35.

[66]   Id. at 35.

[67]   ANOPR at P 61.

[68]   Initial Comments of Massachusetts Municipal Wholesale Electric Company, New Hampshire Electric Cooperative, Inc., Connecticut Municipal Electric Energy Cooperative, and Vermont Public Power Supply Authority, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“Municipal Power Initial Comments”), at 29.

[69]   Electric Transmission Incentives Policy Under Section 219 of the Federal Power Act, Notice of Proposed Rulemaking, 170 FERC ¶ 61,204, errata notice, 171 FERC ¶ 61,072 (2020) (“March 2020 NOPR”).

[70]   Electric Transmission Incentives Policy Under Section 219 of the Federal Power Act, Supplemental Notice of Proposed Rulemaking, 175 FERC ¶ 61,035 (2021).

[71]   Harvard Electricity Law Initiative Initial Comments at 3-4, 44-57; NARUC Initial Comments at 51; CPUC Initial Comments at 47-48; Comments of the Institute for Policy Integrity at New York University School of Law, Docket No. RM21-17-000 (filed Oct. 12, 2021), at 20-21; Comments of Public Interest Organizations, Docket No. RM21-17-000 (filed Oct. 12, 2021) (“PIOs Initial Comments”), at 62.

[72]   See Harvard Electricity Law Initiative Initial Comments at 3, 53-57.

[73]   Id. at 49-52.

[74]   Id. at 45.

[75]   Id. at 45-46.

[76]   Post-Technical Conference Comments of the New England States Committee on Electricity, Docket No. AD16-18-000 (filed Oct. 3, 2016), at 2, 5; Comments of the New England States Committee on Electricity, Docket No. AD16-18-000 (filed May 31, 2016), at 10.

[77]   Comments of the Massachusetts Department of Public Utilities and the Massachusetts Department of Energy Resources, Docket No. 10-23-000 (filed Sept. 29, 2010) (“Massachusetts Order 1000 Comments”), at 30.

[78]   Id. at 28.

[79]   See, e.g., ANOPR at P 5 (“[W]e seek comment regarding 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.”) and P 159 (“As part of this package of potential reforms, we are considering whether reforms may be needed to enhance oversight of transmission planning and transmission providers’ spending on transmission facilities to ensure that transmission rates remain just and reasonable.”).

[80]   Id. at P 159 (emphasis added).

[81]   See Harvard Electricity Law Initiative Initial Comments at 49-52.

[82]   Dr. Robert D. Bullard, Introduction: Environmental Justice—Once a Footnote, Now a Headline, The Harvard Environmental Law Review, Vol. 45, 2021, No. 2, at 243.

[83]   FERC, Office of Public Participation (stating that, among its functions, the OPP will “[e]ngag[e]with the public through direct outreach and education to facilitate greater understanding of Commission processes and solicit broader participation in matters before the Commission”), available at https://www.ferc.gov/OPP.

[84]   See Comments of the State Agencies, Docket No. RM21-17-000 (filed Oct. 12, 2021), at 26; PIOs Initial Comments at 5.

[85]   See, e.g., EEI Initial Comments at 6, 21-22; WIRES Initial Comments at 11-12.

[86]   See, e.g., Exelon Initial Comments at 3, 10, 26; National Grid Initial Comments at 22.

[87]   See, e.g., Eversource Initial Comments at 14; EEI Initial Comments at 6.

[88]   See, e.g., NESCOE Initial Comments at 25-28; Consumer-Owned Systems Initial Comments at 4-5, 27; Municipal Power Initial Comments at 7-8, 25-26; CPUC Initial Comments at 31-34; Comments of the R Street Institute, Docket No. RM21-17-000 (filed Oct. 12, 2021), at 8.  See also AEE Initial Comments at 44 (stating that the low percentage of regional transmission investments resulting from competitive processes should prompt the Commission to “conduct a closer examination of whether the exceptions it allowed in Order No. 1000 to the right of first refusal continue to be just and reasonable, or whether they are discouraging investment in needed regional transmission projects to integrate new sources of generation, resulting in unjust and unreasonable rates, and allowing for discrimination in the provision of transmission service and in the opportunity to build transmission projects.”).

[89]   See NESCOE Initial Comments at 26; Consumer-Owned Systems Initial Comments at 27.

[90]   Municipal Power Initial Comments at 8-9.

[91]   The transmission solution that ISO-NE selected following its only competitive solicitation to date, the Boston 2028 Competitive Solutions Process, included a cost containment feature: “Eversource and National Grid are proposing return on equity (ROE) reductions if the companies exceed $48.6 million of installed cost of the [project] (the “Cost Cap”). If the Cost Cap is exceeded by more than 5%, the ROE for that increment will be reduced by 25 basis points. The ROE will continue to be reduced by 25 basis points for each incremental 5% overrun.”  ISO-NE, Boston 2028 Solutions Study – Mystic Retirement – Preliminary Preferred Solution, Planning Advisory Committee, Aug. 27, 2020, at Slide 14, available at https://www.iso-ne.com/static-assets/documents/2020/08/a2_boston_2028_solution_study_mystic_retirement_preliminary_preferred_solutions.pdf.

NESCOE is not aware of any cost containment commitments for “time-sensitive” or other projects not subject to ISO-NE’s competitive solicitation process.

[92]   Executive Order 14036, Promoting Competition in the American Economy, 86 Fed. Reg. 36,987 (July 9, 2021), at Section 1 (“A fair, open, and competitive marketplace has long been a cornerstone of the American economy, while excessive market concentration threatens basic economic liberties, democratic accountability, and the welfare of workers, farmers, small businesses, startups, and consumers.”).

[93]   See Comments of the New England States Committee on Electricity, Docket No. EL19-90-000 (filed Jan 27, 2020), at 13-18 (explaining how replacing the “time sensitive” exemption in New England with a Competitive Bidding model to meet immediate needs, while maintaining the Sponsorship model for meeting longer-term needs, would enhance competition while addressing concerns about delays that could risk reliability).

[94]   ANOPR at P 49.

[95]   See, e.g., Comments of Vermont Electric Power Company and Vermont Transco LLC (“VELCO”), Docket No. RM21-17-000 (filed Oct. 12, 2021), at 3; Eversource Initial Comments at 8; National Grid Initial Comments at 17-18.

[96]   See, e.g., Comments of the United States Department of Energy to Advance Notice of Proposed Rulemaking, Docket No. EM21-17-000 (filed Oct. 12, 2021), at 25-26; PIOs Initial Comments at 70-72.

[97]   Comments of the Midcontinent Independent System Operator, Inc., Docket No. RM21-17-000 (filed Oct. 12, 2021), at 15-16.

[98]   IPSAC materials are available at https://www.iso-ne.com/committees/planning/ipsac/.

[99]   See Joint Federal-State Task Force on Electric Transmission, Order Establishing Task Force and Soliciting Nominations, 175 FERC ¶ 61,224 (2021); Notice Inviting Post-Meeting Comments, Docket No. AD21-15-000 (Nov. 22, 2021).

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