I concur to this final rule,[1] which represents major progress towards the primary goal we set out to accomplish last year when we issued the NOPR: To move from a system of “first come, first served” to a system of “first ready, first served” by identifying generation projects in the interconnection queues that are commercially more viable and then moving them ahead of requests that are speculative and which have been causing major backlogs. I write separately about four issues contained within:
Evaluation of Alternative Transmission Technologies (Section III.C.2.iii)
Alternative transmission technologies, or grid-enhancing technologies (GETs), is a short-hand categorical term that covers a sweeping array of very different technologies. A GET may hold the potential of squeezing more juice – literally – out of the existing transmission grid. By increasing the capacity of the existing grid, a GET could reduce or even eliminate the need for the future construction of new transmission assets. So the potential for cost-savings from the use of GETs is too important to ignore.
One of the most promising GETs – dynamic line ratings (DLRs) – could potentially save billions of dollars in avoided costs for new transmission assets. DLRs are not covered by this final rule, but are the subject of a separate proceeding,[2] and I hope we will use the record of that proceeding to move forward on a proposed rule to require implementation of DLRs when and where DLRs will be technologically sound and cost-effective.
While DLRs have tremendous potential and should be pursued, there is a problem with any categorical regulatory mandate to use GETs, which is this: Some GETs work somewhere but not everywhere; some work sometimes but not all the time; some only work under certain weather conditions; some don’t work at all, or at least not as advertised; and some are only cost-effective where the congestion costs are greater than the cost of the GET itself.
Given these engineering and economic realities, some knowledgeable transmission planning experts have argued that GETs categorically are not planning tools, but rather are operational applications that should be deployed when and where their efficacy is likely and can be appropriately proven. If they work in the real world as advertised, they could reduce or eliminate the need for future network upgrades or even backbone transmission assets, but they should not be mandated as planning tools or as potential substitutes for network upgrades caused by interconnection requests.[3]
Against this cautious view of GETs, I recognize the counterargument that transmission owners themselves have an economic incentive to favor the construction of costly new transmission assets rather than deploy GETs to squeeze out more capacity. New transmission assets can be rate-based, and the transmission owner can take advantage of the very generous formula rate treatment offered here at the Commission (another issue I have raised concerns about).[4] So to overcome this incentive against GETs deployment, proponents argue that the Commission should require it.
But – as usual – the economic incentives argument has more than one side. The companies that sell GETs (and the organizations they fund) stand to profit from any regulation mandating that their products must be used. And generation developers (and the organizations they fund) have every incentive to lobby for a regulation mandating the use of GETS as a way to avoid paying the costs of the traditional network upgrades made necessary by their interconnections. This incentive is particularly salient in RTOs/ISOs that use participant funding to pay for the costs of network upgrades caused by the interconnecting customers (i.e., developers).
So – again, as usual with sweeping Commission regulations – there is plenty of rent-seeking to go around. Striking the appropriate balance – one that is in the public interest – is a challenge. I believe this final rule – unlike the NOPR – does strike the right balance, in terms of a requirement simply to evaluate GETs in determining the appropriate network upgrade.
Importantly, the final rule makes it explicitly clear that while it is requiring the evaluation of certain listed GETs in the interconnection studies process, it is not requiring – nor even suggesting – that a GET must be deployed as an alternative to a necessary network upgrade. Indeed, the final rule explicitly says:
This final rule does not create a presumption in favor of substituting alternative transmission technologies for necessary traditional network upgrades, either categorically or in specific cases. This final rule is agnostic as to whether, in a specific case, an alternative transmission technology is an acceptable alternative to a traditional network upgrade . . . .
The final rule also makes it explicitly clear that the determination in each case is to be made at the sole discretion of the transmission provider (i.e., RTO/ISOs or non-RTO transmission providers), applying good utility practices, applicable reliability standards, and other applicable regulatory requirements. To avoid continual litigation aimed at the transmission provider’s determination in specific cases when a generation developer does not want to pay the costs of a network upgrade, the final rule explicitly makes clear that it is requiring a process of evaluation, not mandating outcomes in specific cases. And it makes clear that if the transmission provider performs the evaluation as required in the final rule, it has complied with the final rule.
This agnosticism as to outcomes in specific cases is critically important. Transmission providers must require the appropriate network upgrade necessary to fix the reliability issue caused by the interconnection request. If a GET is used instead, and it fails to fix the reliability issue caused by the interconnection, a later network upgrade will be required, one potentially more costly than the network upgrade originally required. And who will pay those costs? Certainly in RTOs/ISOs using participant funding, load (retail consumers) should not. Sticking those costs on consumers would raise a serious question of unjust and unreasonable rates.
In summary though, I believe that this final rule strikes the appropriate balance between requiring the evaluation of GETs, but not mandating the use of a GET in specific cases unless the transmission provider – and only the transmission provider – determines it would work from a real-world applicability standpoint. In all cases, the transmission provider should apply its engineering expertise to come to the right determination as to the necessary network upgrades. This final rule requires nothing less.
Repayment of Affected Systems Network Upgrade Costs (Section III.B.2.c.iii(c))
The final rule essentially codifies existing precedent as to the repayment of affected systems network upgrade costs when a generation developer interconnects at or near a seam between an RTO (which uses participant funding to pay for interconnection costs) and a non-RTO, vertically integrated load-serving utility that uses a crediting mechanism.
Three recent cases involving Duke Energy Progress, LLC (Duke) in North Carolina[5] illustrate my concern about the Commission’s repayment policy.[6] In these cases, generation developers located within the PJM footprint, which extends into a corner of northeastern North Carolina due to Dominion Energy, Inc.’s PJM membership, chose to interconnect very close to the seam with Duke’s North Carolina territory. Duke is a vertically integrated utility regulated by the North Carolina Utilities Commission (NCUC) on an Integrated Resource Plan (IRP) model. Duke builds transmission (and generation) subject to an IRP approved by the NCUC, and the costs of network upgrades caused by that new generation are paid by retail consumers. Since the NCUC approves new generation through its IRP process, which includes the costs to interconnect that new generation, the NCUC decides the generation and interconnection costs that are appropriately paid for by retail consumers.
In these three cases, however, Duke was considered an “affected system” for the interconnection costs caused by the generation developers located just across the seam in PJM’s footprint. So the affected systems network upgrades were not paid by the developer (creating an incentive to locate close to the seam), but by Duke’s retail consumers through crediting pursuant to Commission policy. And unlike the costs of transmission and network upgrades built with the prior approval of the NCUC, no state-approved IRP controls the construction of generation in the PJM footprint in North Carolina. Not surprisingly, the NCUC and the NCUC Public Staff, which represents consumers in North Carolina, filed vigorous – and in my opinion, persuasive – comments in several proceedings on these issues.[7]
While I recognize that the results in these cases were consistent with prior precedent and Order No. 2003,[8] I think that precedent and, if necessary, Order No. 2003 itself, should be revisited as to the affected systems repayment policy. I concur to the issuance of this final rule because this final rule is not the appropriate place to revisit the issue and because the final rule by its own terms does not go beyond existing precedent.
Inappropriate Allocation of Certain Costs to Consumers
As described below, while I support the final rule, I am concerned that study delay penalties on RTOs/ISOs and the costs of transmission provider heatmaps used as a tool for interconnection customers will be inappropriately allocated to consumers even though they both appear to provide much more of a benefit to generation developers than consumers. I address each in turn.
Study Delay Penalties on RTO/ISOs (Section III.B.1.c.x)
The final rule adopts the NOPR proposal to eliminate the reasonable efforts standard from the pro forma LGIP, and it adds a new section to the pro forma LGIP that imposes penalties on transmission providers who miss study deadlines. I have no qualms about assessing penalties on non-RTO/ISO transmission providers and transmission-owning members of RTOs/ISOs. These are generally investor-owned companies and stockholders will bear such costs. On the other hand, I have concerns about assessing study penalties on RTOs/ISOs, as they are not-for-profit entities who do not have stockholders. In my concurrence to the NOPR, I explained:
[T]he penalty provisions do not answer definitively the most important question of all: Who will pay these penalties in an RTO or ISO which has no stockholders? Consumers certainly should not pay, directly or indirectly.[9]
The final rule does not fully address this question and does not provide complete assurance that consumers will be protected.
However, the final rule does have some protections in place to protect against consumers ultimately having to pay for study delay penalties. First, the final rule modifies the NOPR proposal to prohibit non-RTO/ISO transmission providers and transmission-owning members of RTOs/ISOs from recovering study delay penalty amounts through transmission rates.[10] Second, the final rule modifies the NOPR proposal to adopt a new provision in our regulations specifying that, for RTOs/ISOs in which the transmission-owning members perform certain interconnection studies, the study delay penalties will automatically be imposed directly on the transmission-owning member(s) that conducted the late study.
But these provisions still leave open the question of how RTOs/ISOs will recover those study delay penalties that are not automatically imposed on a transmission-owning member. The final rule essentially punts on this question, explaining that RTOs/ISOs may submit an FPA section 205 filing to propose a default structure for recovering study delay penalties and/or make individual FPA section 205 filings to recover the costs of any specific study delay penalties. I urge that any such RTO/ISO filing make protections to consumers paramount.
Cost of Heatmap (Section III.A.1.c.iii)
This final rule requires transmission providers to publicly post a “heatmap” with certain information after the completion of each cluster study and cluster restudy period. The final rule finds that the heatmap will benefit interconnection customers, including prospective interconnection customers, by providing them further transparency as to expected congestion and potential network upgrades and therefore will reduce the number of speculative interconnection requests. I agree that a requirement to post a heatmap will greatly benefit interconnection customers and support the requirement’s addition to the pro forma LGIP.
Where I am concerned, however, is how the heatmap should be funded. The final rule clarifies that transmission providers, not interconnection customers, are responsible for paying the costs associated with the heatmap requirement. Further, the final rule contemplates transmission providers recovering the costs of the heatmap from transmission customers and ex ante determines that such rate treatment is appropriate because interconnection queue efficiency benefits transmission customers. Commission policy may dictate that interconnection queue efficiency benefits transmission customers;[11] however, that should not result in the costs of a requirement that best benefits interconnection customers, and really prospective interconnection customers that may ultimately not seek to interconnect, being recovered from consumers through transmission rates carte blanche. The Commission simply cannot ask retail consumers to foot the bill for every single “efficiency,” especially where many of these “efficiencies” largely benefit generation developers and then get folded into transmission rates and receive an ROE.[12]
I believe this issue merits further scrutiny, and I look forward to future comments on this issue.
“Hold Harmless” Provisions (Sections I, III.A.6.c.iii, IV.C)
In my concurrence to the NOPR, I wrote that while I supported the proposed queue reforms (subject, of course, to comment):
I also caution strongly that we should avoid undermining through this NOPR what the RTOs/ISOs, working through their stakeholder processes, are already doing to fix their own queue problems. We should recognize that each RTO/ISO is different and faces unique local challenges and needs. The queue reforms proposed in today’s NOPR should be seen more as guideposts or general standards rather than unyielding mandates that refuse to take local solutions into consideration. I would allow RTOs/ISOs the opportunity to demonstrate that if their own efforts to enact queue reforms achieve the same goals in a different, but equally effective manner, their individual reform may be acceptable in complying with any final rule. While this NOPR currently recognizes the potential for regional flexibility, I hope the need for such flexibility is explicitly memorialized in any final rule.[13]
This final rule contains language that is intended to recognize the earnest and good-faith efforts undertaken by the RTOs to enact queue reforms. Some RTOs, such as PJM, have already launched extensive queue reforms; others, such as CAISO, are hard at work on developing queue reforms.
I concur because this final rule does contain language that is at least intended to recognize the efforts of RTOs to act on their own queue reforms without waiting on a Commission rulemaking. Whether the language of this final rule adequately recognizes or “holds harmless” those efforts will be an issue for compliance filings.
For these reasons, I concur.
[1] Improvements to Generator Interconnection Procedures and Agreements, 184 FERC ¶ 61,054 (2023) (Final Rule).
[2] Implementation of Dynamic Line Ratings, 178 FERC ¶ 61,110 (2022).
[3] See PJM Initial Comments at 68 (“PJM therefore cautions the Commission not to conflate the operational benefits of alternative transmission technologies . . . with the need to address significant capacity enhancement needs (short and long-term) or long-range transmission needs under rapid growth or changing resource mix scenarios.”); MISO Initial Comments at 121-22 (“Further, although these technologies may be evaluated, the technologies identified by the Commission still may not provide the appropriate solution from a planning perspective. Many of the technologies identified are appropriately considered as operational tools or short-term solutions but are not necessarily appropriate for planning to support a particular generator interconnection.”) (emphases added, footnote omitted).
[4] See, e.g., Sw. Power Pool, Inc., 183 FERC ¶ 61,151 (2023) (Clements, Comm’r, and Christie, Comm’r, concurring at P 4) (“Indeed, the Commission grants formula rate treatment, including a presumption of prudence, to filings from transmission owners seeking cost recovery for transmission projects without regard to whether such projects have been subject to a serious vetting in any proceeding in which both need and prudence of cost must be demonstrated by the transmission developer. We have expressed concerns about this lack of oversight previously, and this filing by SPP illustrates exactly why that is a major problem pertinent to the issue of rising consumer costs for transmission.”), https://www.ferc.gov/news-events/news/commissioner-clements-and-commissioner-christies-joint-concurrence-spp-project; Transmission Planning and Cost Management, Technical Conference, Docket No. AD22-8-000, Tr. 16:4-20:11 (Comm’r Mark Christie) (Oct. 6, 2022).
[5] Duke Energy Progress, LLC, 181 FERC ¶ 61,229 (2022), reh’g deemed denied, 182 FERC ¶ 62,088 (2023); Duke Energy Progress, LLC, 180 FERC ¶ 61,005, order on reh’g, 181 FERC ¶ 61,197 (2022) (Edgecombe Rehearing Order); Duke Energy Progress, LLC, 177 FERC ¶ 61,001 (2021), order on reh’g, 179 FERC ¶ 61,007 (2022) (American Beech Rehearing Order). My concurrences to the Edgecombe Rehearing Order and American Beech Rehearing Order set forth my concerns as well. See Edgecombe Rehearing Order, 181 FERC ¶ 61,197 (Christie, Comm’r, concurring) (Edgecombe Concurrence), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-rehearing-duke-energy-progress; American Beech Rehearing Order, 179 FERC ¶ 61,007 (Christie, Comm’r, concurring).
[6] See Standardization of Generator Interconnection Agreements & Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ¶ 61,103, at PP 693-696, 720-739 (2003), order on reh’g, Order No. 2003-A, 69 FR 15932, 106 FERC ¶ 61,220, at PP 584-586, order on reh’g, Order No. 2003-B, 70 FR 265 (Jan. 19, 2005), 109 FERC ¶ 61,287 (2004), order on reh’g, Order No. 2003-C, 70 FR 37661 (July 18, 2005), 111 FERC ¶ 61,401 (2005), aff’d sub nom. Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007). I note that this policy applies not just to affected systems network upgrades but also network upgrades on the host transmission provider’s system.
[7] See NCUC and NCUC Public Staff Initial Comments at 6; NCUC and NCUC Public Staff, Joint Comments, Docket No. RM21-17-000, at 12 (filed Aug. 17, 2022); NCUC Public Staff, Comments, Docket No. RM21-17-000, at 13-15 (filed Oct. 12, 2021); NCUC Public Staff Reply Comments, Docket No. RM21-17-000, at 6 (filed Nov. 30, 2021) (“[U]nder the crediting policy, ratepayers are left paying the bill regardless of the benefits, or lack thereof, they received from the network upgrades. Further, the [NCUC] Public Staff believes that [interconnection customers] are beginning to ‘game’ the system by placing large merchant plants into the interconnection queue in congested areas to take advantage of the crediting policy and fill what excess capacity is then created with state jurisdictional projects that would normally have to fund the upgrades themselves.”); see also NCUC Public Staff, Motion to Intervene Out-of-Time and Comment, Docket No. ER21-1955-003, at 1-9 (filed Nov. 9, 2021) (generally arguing, inter alia, that Duke customers will not or will only minimally benefit from upgrading its system to accommodate power being interconnected and delivering to PJM; that Duke ratepayers are subsidizing costs that should be paid for by the developer, the party that is both causing the costs to be incurred and reaping the resulting benefits; that given the proliferation of merchant generation trying to locate in this area of North Carolina, the NCUC Public Staff is concerned that Duke ratepayers will be burdened with potentially hundreds of millions of dollars in affected systems network upgrade cost as a result of the Commission’s actions; and that the project in American Beech had not yet received a CPCN from North Carolina so any decision put the “cart before the horse.”).
[8] See, e.g., Edgecombe Concurrence.
[9] Improvements to Generator Interconnection Procs. & Agreements, 87 FR 39934 (July 5, 2022), 179 FERC ¶ 61,194 (2022) (Christie, Comm’r, concurring at P 3) (NOPR Concurrence), https://www.ferc.gov/news-events/news/e-1-commissioner-christies-concurrence-improvements-generator-interconnection.
[10] Final Rule, Section III.B.1.c.ix.
[11] Whether or not I agree with Commission policy is another matter entirely. See, e.g., supra PP 13-16.
[12] Joint Fed.-State Task Force on Elec. Transmission, Technical Conference, Docket No. AD21-15-000, Tr. 37:9-20 (Comm’r Mark Christie) (Nov. 15, 2022) (“Let’s put this in context, and talk about what’s really at stake here. Last year national transmission rate base went up over 9 percent. That’s the third consecutive year it’s gone up over 9 percent. What goes into rate base, goes into consumer’s bills. Every nickel. And in the last decade, national transmission rate base has almost tripled, and . . . at 9 percent it’s going to double again in the next eight years. This is all going into customer’s bills. So this is a hugely important issue. This is a ton of money, this is big, big money.”).
[13] NOPR Concurrence at P 4 (emphasis added, footnote omitted).