UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

Advanced Notice of Proposed Rulemaking:
Building for the Future Through Electric
Regional Transmission Planning and Cost
Allocation and Generator Interconnection

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Docket No. RM21-17-000

 

Reply Comments of the R Street Institute

  1. Issue Summary

On July 27, 2021, the Federal Energy Regulatory Commission (Commission) published an Advance Notice of Proposed Rulemaking (ANOPR) on potential reforms to improve generator interconnection processes, regional transmission planning and cost allocation. [1] The ANOPR outlined the potential need to reform these policies, seeking comments structured by regional transmission planning and cost allocation processes; identification of cost; responsibility for regional transmission facilities; interconnection-related network upgrades; and enhanced transmission oversight and transition. Initial comments were due on October 12, 2021 and the Commission provided an opportunity for reply comments.

The R Street Institute (RSI) filed initial comments and submits these reply comments to provide a summary and specific comments on common themes filed by other parties in initial comments. [2] As in initial comments, RSI is also filing separately as part of the Electric Transmission Competition Coalition.

  1. Summary of R Street Position

RSI emphasizes four main points in its reply to initial comments:

  1. The case for transmission competition is stronger than ever.

  2. Proactive, transparent and more independent oversight in transmission planning supports competition and inclusive collaboration.

  3. Increased independence would improve transmission planning processes.

  4. Generator interconnection warrants reform, including in participant funding.

 

  1. The Case for Transmission Competition is Stronger than Ever

The Edison Electric Institute (EEI) and other incumbent transmission owners (TOs) argue for eliminating competition via reinstatement of federal ROFR. [3] But the evidence in support of competition and for eliminating state and federal ROFR is stronger than ever. Although sparingly used, competition under Order 1000 has been a success in the eyes of consumers and independent economists, including independent market monitors (IMMs).

The Electric Transmission Competition Coalition formed this year and filed in this proceeding; dozens of consumer groups have witnessed the cost and innovation advantage of competition and its potential to expand. The oft-cited evidence comes from a Brattle Group report, which has withstood scrutiny, that found major cost and innovation advantages for competitive projects between 2013 to 2017. [4] The Commission should recognize this and seek additional evidence on projects since 2017. The PJM IMM summarized the competitive experience well: “competitive transmission development… should build upon FERC Order No. 1000 to create real competition between incumbent transmission providers and nonincumbent transmission providers.” [5]

Since 2017, evidence continues to prove the advantage of competition. The most recent development came last month, as the Southwest Power Pool (SPP) approved its third competitive transmission project under Order 1000, with the winning $85 million bid coming in at 27 percent less than the next closest bid of $116 million. [6] For comparison, bids went as high as $151 million. [7] Indeed, the resulting $31 million in customer savings is likely less than the potential savings in the absence of competition: incumbent costs would probably surpass the runner-up bid given their tendency to exceed initial RTO cost estimates. A more relevant inquiry on the SPP experience is to ask why this was just the third competitive project awarded in a region that has seen incumbent TOs engage in pervasive regulatory evasion. [8]

Domestic transmission competition is now even encouraging competition in international transmission policy. A 2021 assessment in the United Kingdom identified a range of 22 percent to 42 percent cost savings from competition based on projects in the Midcontinent Independent System Operator, with the former serving as the base assumption in an analysis for transmission projects in the United Kingdom. [9] The report concludes that the potential savings from implementing competition are “likely to far exceed the estimated development costs.” [10]

Given the growing body of evidence in support of transmission competition, it is clear that the underperformance of Order 1000 results from incomplete implementation. For example, the reply comments of Northeast state utility regulators, attorneys general and ratepayer advocates emphasized the benefits of open and transparent competition and that the only competitive transmission procurement in New England “was done quickly and cooperatively with no discernable delay and has widely been considered effective.” [11] The competitive carve-outs permitted under Order 1000 have been exploited by incumbent TOs in technical processes—often by building more local projects exempt from competition—and through lobbying campaigns to secure state ROFR over the objections of consumer and pro-market voices. [12] There is a common misperception that preemption of state ROFR would prompt universal blowback from states, which fails to recognize that some states seek relief from the higher costs imposed by other states’ ROFRs. [13]

The comments of the National Association of Regulatory Utility Commissioners made clear that transmission cost containment is critical and that “the Commission should investigate how to encourage the use of current competitive processes and discourage overinvestment in local transmission facilities where the development of more competitively priced projects will maximize regional (and interregional) benefits.” [14] The single most impactful way to accomplish this is to eliminate all ROFRs, followed by closing technical competitive carve-outs to the extent practical under Order 1000 as delineated by the Electric Transmission Competition Coalition.

EEI argues for federal reinstatement of ROFR because it would allow the “entities with the expertise, the knowledge of the existing system, the relationship with customers and regulatory agencies and the obligation to provide safe reliable service to build the lines selected in the regional process.” [15] This advantage may often be true, but it provides no rationale for eliminating competition. If incumbent transmission owners have an expertise, information or relationship advantage, then it should provide them an edge in competitive solicitations. Further, hoarding some of these “advantages” like transmission system information and rights-of-way access underscores the problematic black box of transmission planning today and why enhancing transparency, independent oversight and truly inclusive collaboration reforms are needed.

  1. Proactive, Transparent and more Independent Oversight in Transmission Planning Supports Competition and Inclusive Collaboration 

A wide chorus of parties agreed with the desire for more proactive transmission planning, while the evidence and comments of transmission consumers and IMMs clearly support the need for greater transparency and independent oversight. These features combined would improve productive collaboration and support more robust implementation of competition between suppliers and technologies, including incorporating grid-enhancing technologies early in the planning process. For example, access to better information on existing transmission assets is the key to unlocking non-wires alternatives in the planning process, which are yet to materialize under Order 1000.

The Commission must distinguish inclusive collaboration between all stakeholders from exclusive collaboration between TOs only. Inclusive collaboration encourages all stakeholders to participate in a proactive and efficient process that leverages independent expertise. For example, the National Association of State Utility Consumer Advocates (NASUCA) commented that planning processes should provide the opportunity for active—not passive—public participation from inception through the planning phases rather than after solutions have been selected. This could be especially beneficial for community input that affects siting considerations. [16] NASUCA also asserts that planning parameters should be transparent and subject to independent verification. [17] This kind of transparency and validation would be the proper way to incorporate the information, expertise and relationship “advantages” of incumbent TOs into a platform that optimizes transmission solutions, reduces controversy and feeds into a competitive solicitation process.

This stands in stark contrast to the exclusive collaboration sought by incumbent TOs, whose primary argument against competition is that it stifles “cooperation and collaboration that has historically existed among transmission owners.” [18] This contradicts the precise historic context that led the Commission to enact Order 888 to require open access transmission service to address the “fundamental generic problem in the electric industry” that monopoly TOs engage in “unduly discriminatory practices in the provision of transmission services.” [19] This formed the subsequent basis under Order 1000 for the Commission to eliminate a federal ROFR in the first place, on grounds that “the economic self-interest of electric transmission monopolists lay in denying transmission or offering it only on inferior terms to emerging competitors.” [20] Reinstating a federal ROFR would not only violate the historic findings that lead to Orders 888 and 1000, but it would endorse cartelization without any mitigating measures. This may run afoul of the antitrust guidelines for collaborations among competitors established by the Federal Trade Commission (FTC) and U.S. Department of Justice (DOJ). [21] For example, the FTC flagged federal ROFR as creating barriers to trade under Order 1000, and the DOJ recently raised anti-competitive concerns recently regarding state ROFR. [22]

Contrary to the claims of incumbent TOs that competition deters collaboration and transmission development, both forms of competition—between firms and technologies—should increase transmission development by lowering the cost of solutions in the planning process. That is, transmission development is a direct function of cost, and competition unequivocally lowers costs. In fact, the cost differential between competitive and uncompetitive projects is large enough to materially tilt cost-benefit analysis in favor of more development. In addition, the conditions that make inclusive collaboration thrive—proactive inclusion, transparency and independent oversight—should be pursued in their own right and happen to facilitate conditions for competition to thrive.

  1. Increased Independence would Improve Transmission Planning Processes

The Commission should note a key distinction between enabling independent planning exercises to influence processes and shifting transmission planning authority to independent third parties. Many commenters appear open to the former, while perspectives are mixed on the latter. Should the Commission retain current planning authority, it is worth considering why previous independent planning exercises, such as various independent techno-economic assessments of interconnection-wide long-term transmission planning, have been largely devoid of influence on authoritative planning processes and outcomes. This highlights the need for complementary reforms that ensure robust counterfactual analysis can influence enforceable mechanisms to alter flaws in embedded regional planning processes.

At a minimum, the Commission should pursue new planning accountability measures that are reviewable and enforceable. This would pair well with a role for an independent transmission monitor (ITM) to “serve as an effective check against current planning processes” with referral filing authority, as noted by consumer advocates. [23] The ITM could evaluate the inputs and process, make recommendations and, if necessary, file before the Commission if a flaw warranted referral.

The Department of Energy (DOE), national laboratories or other third parties with sophisticated modeling expertise could offer technical assistance to the ITM and other stakeholders. This could take the form of running alternative scenarios or solutions and explaining technical concepts to stakeholders. The DOE could convene independent planning sessions and file plans before the Commission under Section 403 of the Federal Power Act, which would ensure a counterfactual mechanism existed on the record.

Modest expansions to the role of existing IMMs to encompass ITM functions may prove workable for regional planning in RTOs. The SPP IMM notes that it already performs activities that would fall under the ITM’s purview. [24] However, a more fundamental institutional question remains for interregional planning and regional planning outside of RTOs. The Commission could pursue a base framework under Section 206 of the Federal Power Act to require compliance with a uniform set of technical parameters. In the event TOs do not comply, the Commission may need to assertively deny Section 205 filings that are not part of a regional process and use Section 206 to show that refusal to engage in broader planning is not just and reasonable. This could serve as a path to transparency and inclusive collaboration by requiring incumbent TOs to disclose transmission information about their systems and participate in a joint planning process. It would also ensure improvement in the regions that need it most—those outside of RTOs—while eliminating concerns that TOs would leave or avoid joining an RTO because they face less scrutiny outside them.

  1. Generator Interconnection Warrants Reform, including in Participant Funding 

The record shows widespread agreement that the current generator interconnection process erects significant barriers to entry for new resources and requires urgent reform. Some ideas to reduce informational and procedural barriers can be implemented with only limited controversy. But views diverge markedly on financial barriers, namely reforming participant funding (PF) for network upgrades. The record shows fair differences on how to reform participant funding, but no convincing evidence was provided to suggest that the status quo is just and reasonable.

As the Commission considers its next steps on PF, it is important to flesh out the problem statement to inform the reform pathway. Given areas of disagreement on the record, it is worth examining how PF and potential reforms affect certain issues:

  1. Net benefits to load, with an eye towards direct and indirect costs.

  2. Dynamic investment decisions, not static assumptions of who pays for the inevitable.

  3. Siting decisions of generators.

The record indicates that the benefits of a network upgrade are not confined to a single generator, suggesting that the current PF practice violates the beneficiary pays principle. The evolving resource mix is exacerbating this problem. The economics of network upgrades are becoming more characteristic of a positive network spillover than a pure private investment.

Importantly, if the full benefits are not made capturable to the private party, the overall level of investment will be below the social optimum. This results in underinvestment that lowers net benefits. Inefficiencies in the process are either passed through to load by regulated utilities, typically in retail rate adjustment mechanisms, or they put upward pressure on power purchase agreements paid by off-takers. These dynamic effects and indirect impacts on load are ignored by numerous commenters who defend the status quo.

Part of the challenge in characterizing the problem, as noted by the PJM IMM, is that the interconnection process lies at the intersection of generation markets and transmission planning. [25] This has led one IMM to suggest improvements in the planning process and another to introduce a new market concept. Specifically, Potomac Economics offers a market-based solution to make benefits capturable to the private party by establishing capacity transfer rights. [26] This would set a much larger precedent with extensive changes throughout the ecosystem of transmission property rights, which exceeds the scope of this proceeding. Irrespective of the merits of the solution, Potomac Economics’ recognition of incomplete property rights provides validation of the PF problem statement; the status quo is not economically efficient and not just and reasonable.

The PF problem statement appeared to be recognized by some consumers, including transmission-dependent utilities. The Transmission Access Policy Study Group (TAPS) noted possible approaches to partially reduce direct assignment of network upgrade costs in concert with changes to make transmission planning proactive. [27] TAPS did not support full PF elimination based in part on the desire to ensure interconnecting generators retained interest in incentivizing efficient generation siting. [28]

Siting incentives for network cost minimization was a common concern among commenters. This underscores why the Commission should pursue reform on the basis of the incentive compatibility of market participants. A variety of elements influence siting considerations, many of which may correlate with network upgrade costs, including interconnection delays, higher export-constrained congestion and increased curtailment risk. The Commission should seek comments on the marginal incentive effect of reform options on siting motivations—such as expected impact on net revenues—as well as observable evidence, such as practices in RTOs with PF and outside RTOs without PF.

Siting incentives also underscore the need for reform that deters socialization of speculative network upgrades, which was a common concern in the record. Shifting all costs for upgrades to load upfront without review would socialize investment risk. This is an important consideration in incorporating upgrades into regional planning processes like clustering analyses; however, the problem is avoidable in PF reform. For example, the California Independent System Operator (CAISO) employs a participant financing mechanism that reimburses generators for upgrades upon achieving commercial operation, which results in generators retaining upfront investment risk. CAISO’s comments note that this approach provides developers with “strong incentives to site their projects where they will not incur high interconnection costs” unlike frameworks where developers have no “skin in the game.” [29]

PJM requested that the Commission take interconnection process reforms on a regional basis and offered six possible alternatives to PF. [30] This raises the question of whether the Commission should let regional stakeholders pursue reforms, which may permit customization to regional circumstances and hold experimental value in the absence of a clear best practice. Some procedural variances across regions in interconnection management are workable, but variances in PF would result in an inefficient patchwork that would distort investment patterns between regions. Further, leaving regions with discretion over matters of barriers to entry tends to delay reform because incumbent interests hold outsized influence in stakeholder processes and seek to insulate their assets from competition. The Commission still needs to enact reform that defines uniform objectives that clarify minimum expectations for regions. This will ensure regional incumbent interests do not undermine removal of barriers to entry.

  1. Conclusion

RSI respectfully requests the Commission consider the comments contained herein.

Respectfully submitted,

/s/ Devin Hartman
Devin Hartman
Director, Energy and Environmental Policy

R Street Institute
1212 New York Ave. NW, Suite 900
Washington, D.C. 20005
(202) 525-5717
[email protected]
November 30, 2021

[1] 86 Fed. Reg. 15512 (July 27, 2021). https://www.govinfo.gov/content/pkg/FR-2021-07-27/pdf/2021-15512.pdf.

[2]  “Comments of the R Street Institute on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021. https://www.rstreet.org/wp-content/uploads/2021/10/ANOPR-Initial-Comments-FINAL.docx.pdf.

[3]  “Comments of the Edison Electric Institute on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, p. 6. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211012-5582&optimized=false.

[4]  Johannes Pfeifenberger et al., “Cost Savings Offered by Competition in Electric Transmission,” The Brattle Group, April 2019, p. 11.  https://brattlefiles.blob.core.windows.net/files/15987_brattle_competitive_transmission_report_final_with_data_tables_04-09-2019.pdf.

[5]  “Comments of the Independent Market Monitor for PJM Interconnection on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, p. 8. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211101-5267&optimized=false.

[6]  Tom Kleckner, “SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021,” RTOInsider, Nov. 1, 2021. https://www.rtoinsider.com/articles/28966-spp-board-directors-mc-102621.

[7] Ibid.

[8]  Devin Hartman, “Plenty of low-hanging fruit: How FERC can catalyze transmission infrastructure,” UtilityDive, April 9, 2021. https://www.utilitydive.com/news/plenty-of-low-hanging-fruit-how-ferc-can-catalyze-transmission-infrastruct/598088/.

[9]  “Impact Assessment on developing arrangements to allow for early competition to be applied to future projects on the onshore electricity transmission network,” Ofgem, August 2021, p. 5. https://www.ofgem.gov.uk/sites/default/files/2021-08/Transmission_Early_Competition_IA_Final.pdf.

[10] Ibid.

[11]  “Reply Comments of the State Agencies on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Nov. 26, 2021, pp. 11, 14.  https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211126-5115&optimized=false.

[12]  Testimony of Devin Hartman, Michigan House Energy Committee, “Testimony in opposition of Senate Bill No. 103,” Nov. 3, 2021. https://www.rstreet.org/wp-content/uploads/2021/11/Final_Michigan-testimony-SB-103-Devin-Hartman.docx.pdf.

[13] Josiah Neeley, “Right of First Refusal Laws for Electric Transmission are Anti-Competitive in Interstate Commerce,” The R Street Institute, June 2021, pp. 1-2. https://www.rstreet.org/wp-content/uploads/2021/06/explainer27-1.pdf.

[14] “Comments of the National Association of Regulatory Utility Commissioners on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, p. 56. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211012-5536&optimized=false.

[15] Ibid., p. 7.

[16] “Comments of the National Association of State Utility Consumer Advocates on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, pp. 3-4, 8. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211012-5726&optimized=false.

[17] Ibid., p. 3.

[18] EEI, p. 5. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211012-5582&optimized=false.

[19] Federal Energy Regulatory Commission, Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities, Docket No. RM95-8-000, April 14, 1996, p. 128. https://www.ferc.gov/sites/default/files/2020-05/rm95-8-00w.txt.

[20] 762 F.2d 41, 50 (D.C. Cir. 2014).

[21] See, e.g., “Antitrust Guidelines for Collaborations Among Competitors,” Federal Trade Commission and U.S. Department of Justice, April 2000. https://www.justice.gov/atr/page/file/1098461/download.

[22] Federal Energy Regulatory Commission, Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Docket No. RM10-23-000, July 21, 2011, p. 203. https://www.ferc.gov/sites/default/files/2020-04/OrderNo.1000.pdf; “Comments of the R Street Institute on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, p. 3. https://www.rstreet.org/wp-content/uploads/2021/10/ANOPR-Initial-Comments-FINAL.docx.pdf.

[23] National Association of State Utility Consumer Advocates, p. 7. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211012-5726&optimized=false.

[24] “Comments of the Southwest Power Pool Market Monitoring Unit on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, p. 1. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211012-5565&optimized=false.

[25] Independent Market Monitor for PJM Interconnection, p. 16. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211101-5267&optimized=false.

[26] “Comments of Potomac Economics on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, pp. 5-7. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211013-5052&optimized=false.

[27] “Comments of the Transmission Access Policy Study Group on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, pp. 41, 43, 46. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211012-5388&optimized=false.

[28] Ibid, pp. 46-47.

[29] “Comments of the California Independent System Operator on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, p. 11. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211012-5583&optimized=false.

[30] “Comments of the PJM Interconnection on the Advanced Notice of Proposed Rulemaking: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection,” Docket No. RM21-17-000, Oct. 12, 2021, pp. 47, 55-58. https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20211012-5490&optimized=false.