MISO and SPP staff on Friday told stakeholders that this year’s coordinated system plan (CSP) study will focus on “potential solutions to historical, persistent congestion issues” on the RTOs’ seam.
The study, which is not dependent on other regional or interregional planning processes, will analyze historical market-to-market (M2M) congestion problems and look for transmission solutions that benefit both grid operators.
The M2M process has resulted in SPP accruing almost $255 million in settlements from MISO since the RTOs began it in March 2015. Under the process, the grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.
“We’re looking at sort of near-term planning horizon,” MISO’s Ben Stearney told the Interregional Planning Stakeholder Advisory Committee (IPSAC). “We want to target solutions that can be implemented quickly. So really, we’re not looking for large expensive, greenfield projects. We’re targeting kind of a low-hanging-fruit, quick-hit type of projects.”
In their scope document, staff said they have been jointly exploring ways to address M2M congestion where a long-term planning horizon study “may not effectively capture certain existing day-ahead or real-time market conditions.” They raised the concept of a targeted market efficiency project, similar to that conducted by MISO and PJM, before formally agreeing to use the process in the CSP. (See MISO, SPP Take on 2nd Interregional Planning Effort.)
MISO and SPP seams | MISO and SPP
The RTOs’ staffs hope to develop a repeatable process to effectively study persistent congestion on the seam, including a set of appropriate project criteria for inclusion in their joint operating agreement’s (JOA) language. They also plan to recommend transmission upgrades using a yet-to-be-determined cost allocation methodology.
The grid operators’ JOA requires a CSP be conducted every couple of years to find interregional projects. However, previous, more comprehensive studies have come up empty over cost allocation issues. The MISO-SPP Joint Planning Committee, comprising representatives from each RTO, agreed in March to pursue the new study process.
Asked whether the CSP analysis might find projects that have already been identified by the RTOs’ long-term transmission planning efforts already underway, Stearney said those latter studies have longer lead times.
“I don’t see that as an issue,” he said.
WEC Energy Group’s Chris Plante offered his company’s support for the CSP study.
“I think when we look back at the process that MISO and PJM followed when evaluating targeted market efficiency projects, I think we found that to be a very successful process in terms of identifying extremely near-term, low-dollar cost upgrades that can address some of this congestion,” he said.
The RTOs are working to compile two years of historical M2M data and establish a list of candidate flowgates for consideration. They intend to develop the study process and complete the initial assessment this year. However, they pointed out, because the study will require JOA updates to formally recommend any resulting projects, the final tariff language and FERC filings are not expected to be completed until midway through 2023.
Staff will wait until next year to begin the always sticky development of regional cost allocation.
Future IPSAC meetings are scheduled for July 22 and Sept. 23. Additional meetings will be held as needed while the study progresses.
Establishing accurate facility ratings is a significant challenge both in Texas and across the ERO Enterprise, according to participants in a webinar hosted by the Texas Reliability Entity on Thursday.
The webinar, part of the regional entity’s regular Talk with Texas RE series, was focused on the FAC-008 series of reliability standards, the most recent of which, FAC-008-5 (Facility ratings), took effect last October. Violations of the FAC-008 family are frequent both across the ERO Enterprise and in Texas RE; for example, last year the RE assessed a $192,000 penalty against Oncor for infringing the standard. (See FERC Approves $536K in Penalties from WECC, Texas RE.)
“It’s a pretty significant opportunity, [and] a pretty significant risk in this interconnection, to get the proper ratings out there for ERCOT to make the right decisions [and] for you to make the right decisions, and so we need to have reliable operations,” said Curtis Crews, Texas RE’s director of operations and procedures compliance and risk assessment.
A major focus of the webinar was FAC-008-5’s requirement that registered entities establish a “documented methodology for determining facility ratings” of relevant equipment, or facility ratings methodology (FRM). The lack of an adequate FRM is a common cause of FAC-008 violations; utilities may also face penalties for having a methodology but not following it, as in the case of a settlement between WECC and Arizona’s Salt River Project approved by FERC last month. (See NERC Hits SPP, SRP for $406K in Penalties.)
Crews also emphasized that even with a suitable FRM, it is not enough for utilities to rate their facilities once. He said registered entities should review their equipment regularly because repairs and upgrades can introduce new equipment that changes the overall rating for the facility. He warned that utilities “don’t want to wait for me to do that.”
“Texas RE shouldn’t be the one that provides you that periodic review … because if we find something, we’d have to report it, and there have been quite a few facility ratings non-compliances over the last several years,” Crews said.
To help attendees understand how Texas RE assesses a utility’s approach to ratings, Crews shared a list of evidence that auditors look for during their reviews. In addition to a detailed FRM, the RE aims to verify the results against the utility’s facility ratings database using manufacturer specifications and nameplate photos, one-lines and elevation drawings, and any other information that may help to independently establish the rating.
The presentation also contained a list of issues commonly identified during audits, including change-management process gaps — that is, failure to make sure that changes to field equipment are reflected in the ratings database — or omitting an element from the FRM. Crews acknowledged the latter error “doesn’t happen too often, but it has happened across the ERO Enterprise.”
Other issues include failure to maintain the one-line and elevation drawings, or inconsistencies between different records containing the same drawings; failure to account for jointly owned facilities; insufficient processes for keeping track of series elements; and lack of clarity in documentation.
In addition to technical evidence, auditors may look for indications of lax culture at the entity. These could be lifting language directly from the standard to use in the FRM with no modification for the case at hand, or not being able to demonstrate consistent application of the FRM in practice. Another sign that an entity has not done a thorough job is the use of the same ratings for normal and emergency situations.
Crews emphasized that while REs sometimes must penalize utilities as a result of compliance audits, their goal is to help build a reliable grid, rather than to punish wrongdoers.
“That is part of our role, to help ensure reliable operations through effective compliance monitoring, and I think that’s the heart” of what Texas RE does, Crews said. “I used to be at a registered entity, so I understand the ramifications of an audit, and I understand the implications of trying to operate in a reliable situation, given the complex issues like facility ratings.”
FERC and state regulators embraced cluster studies but gave mixed reviews to “fast track” processing as potential solutions to clogged interconnection queues Friday during the third meeting of the Joint Federal-State Task Force on Electric Transmission.
The task force, which includes FERC members and 10 state regulators, was created by FERC Chairman Richard Glick in June to unleash transmission expansion to improve resilience and connect new renewable generation (AD21-15).
FERC Commissioner Willie Philips laid out the first problem at the beginning of the five-hour meeting, noting that interconnection costs, which used to be less than 10% of generators’ total project costs, can now exceed 50%.
“The serial, first-come-first-serve study process incentivizes developers to enter into the queue before they are ready. They do this so that they can snag a spot in line. Interconnection customers also submit multiple interconnection requests at different locations even though they know that not all of them will reach commercial operation,” he said. “They do this to find where they can get the least amount of network cost upgrades. Then there are often late-stage withdrawals or material modifications to projects, which means that transmission providers must conduct restudies. Ultimately this is harming the ability of transmission providers to timely process the queue.”
Jonathan Raab — president of consultancy Raab Associates and facilitator of the meeting — cited data from Lawrence Berkeley National Laboratory showing that the typical duration from connection request to commercial operation has nearly doubled, from 2.1 years in 2000-2010 to 3.7 years for 2011-2021. Only 23% of projects that requested interconnection in 2000-2016 have reached commercial operations, with only 20% of wind projects and 16% of solar completed.
In contrast with the first two meetings, “we’re not just asking questions this time,” Raab said. Instead the meeting sought feedback on five potential improvements:
tighter applicant requirements to enter or remain in the queue;
clustering of applications and areas for studies;
faster tracks for different generator categories (e.g. state solicitations or smaller resources with limited impacts);
tighter study deadlines for RTOs and other transmission providers; and
minimizing restudies.
FERC Warned Against Undermining State Efforts
Several state regulators urged FERC not to issue a sweeping rule that could undermine progress some jurisdictions have made.
Chair Thad LeVar, Utah Public Service Commission | Utah Public Service Commission
Utah Public Service Commission Chair Thad LeVar said that while the interconnection queue process is “easy … to criticize,” policymakers should recognize “the significant reform efforts that many transmission providers across the country have been engaging in in recent years.”
“The specific issues that we’ll be talking about over the next couple hours aren’t new concepts that nobody’s been trying,” he added.
“I’ve heard from the SEARUC [Southeastern Association of Regulatory Utility Commissioners] states as well as some RTOs like PJM,” North Carolina Utilities Commissioner Kimberly Duffley said. “And they request that FERC allow queue reforms to move forward regionally without the disruption of possibly inconsistent requirements.”
Duffley said North Carolina officials are optimistic about recent changes to the queue procedures of Duke Energy Carolinas and Duke Energy Progress.
Commissioner Kimberly Duffley, North Carolina Utilities Commission | North Carolina Utilities Commission
The state has been a leader in utility-scale solar, Duffley said, but beginning about 2014, the first-come-first-serve interconnection queues began experiencing backlogs and queue-squatting complaints.
The addition of new financial security requirements in 2015 provided some relief, she said, but proved insufficient. Additional changes were approved by FERC last August (ER21-1579), following endorsements by the NCUC and South Carolina Public Service Commission, replacing the serial study process with a first-ready-first-served, cluster-based study process.
Duffley said the impact of the new rules, which were based on those of Public Service Company of Colorado, won’t be known until the first quarter of 2023.
“I believe that the RTO and the system planners are best positioned to structure interconnection rules for their individual regions, and that prescriptive one-size-fits-all interconnection rules are not necessary,” said Gladys Brown Dutrieuille, chair of the Pennsylvania Public Utility Commission. “That being said, I think that FERC is in a position that they can encourage interconnection efficiencies throughout the country by promoting best-in-class processes, such as variations in ways to cluster projects.”
Support for Cluster Studies
There was wide support for cluster studies, which allow transmission providers to consider many projects in one study. Supporters say restudies are less frequent and disruptive because generators in a cluster can share the cost of network upgrades.
Phillips said cluster studies should be considered a best practice.
“Almost all RTOs and ISOs have used a cluster approach for years, and PJM is currently working on a cluster proposal right now,” he said. “Several transmission providers outside of the RTO regions have also started moving to a cluster approach in recent years.”
PJM will file with FERC later this month a proposed interconnection queue process that moves away from the first-come-first-served model to a first-ready-first-served concept. “That will make the process somewhat quicker, maybe as quick as 450 days … and that would cut down from an average of somewhere in about 700 days,” said Jason Stanek, chair of the Maryland Public Service Commission. (See PJM Stakeholders Endorse New Interconnection Process.)
Vermont Public Utility Commissioner Riley Allen said clustering can help identify “backbone or … trunk facilities” that provide efficiencies in the system for ratepayers’ benefit.
LeVar said cluster studies also have been helpful in Western states’ review of utility integrated resource plans that result in solicitations for new resources. “There’s usefulness to best practices. But these best practices are going to operate differently in each RTO and particularly between the RTO and non-RTO areas,” he cautioned.
California Public Utilities Commissioner Clifford Rechtschaffen said CAISO’s use of cluster processes has been “very helpful” but “is not a panacea.”
“Last year in CAISO, in one cluster in two weeks, there was 100 GW of applications filed in a single window, which is 10 times the amount of authorized procurement,” he said. “So clustering absolutely helps … but it has to be accompanied by the other reforms that we’re talking about.”
Fast Track
There was less unanimity over fast-track proposals.
Stanek called clustering and fast-track processes “Siamese twins. They’re very different, but they have some similarities that lead to overall efficiencies.”
He suggested fast tracking generation seeking to locate at the sites of retiring plants such as the Oyster Creek nuclear plant in New Jersey and the Indian River coal facility in Delaware, saying it could reduce the need for expensive reliability-must-run agreements.
“Perhaps the standard interconnection process would not be as arduous if we’re using existing switchgear and existing substations behind the fence,” he said. “Taking advantage of the fact that these points have already been modeled, it shouldn’t take 1,000 days or four years for … some generator to step into the shoes of an existing generator.”
Arkansas Public Service Commission Chair Ted Thomas said he agreed “conceptually” with using milestones such as financing and site control to prioritize the queue. “But while we work on those solutions, I also think that we need to be conscious that we not make this a game that only large players can play.”
Glick said any fast track would have to be crafted carefully to ensure it does not violate the Federal Power Act’s prohibition on “undue discrimination.”
“If you start saying small resources have a separate category and make it some expedited approval, that actually might, I think … come across as discriminatory.”
Tighter Requirements
Task force members also expressed concerns over tightening queue eligibility requirements.
Michigan Public Service Commission Chair Dan Scripps | Michigan Public Service Commission
Dan Scripps, chair of the Michigan Public Service Commission, said increasing applicant requirements “could ultimately delay projects that we’re going to need, even if we don’t know who the specific off-taker is today.”
“If I go back to the old … saying that ‘all regulation is incentive regulation,’ in some ways we’re getting the system that we’re encouraging here,” he said. “When you talk to developers, they say the length of the time to get through the queue processes encourages the speculative or placeholder nature of a lot of the projects.”
Transmission Providers’ Accountability
Commissioner Allison Clements said she had concluded that FERC’s attempt at “incremental reforms” in Order 845 in 2018 “hasn’t worked.” The order sought to increase the transparency and timeliness of the interconnection process. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)
She solicited feedback on ways FERC can ensure transmission providers are meeting their obligations, noting that PJM reported to the commission that 99% of its facilities studies failed to meet tariff deadlines in 2021. She said it is unfair that queue participants are held to strict deadlines while transmission providers are only required to make “reasonable efforts” to meet deadlines.
“Interconnection customers facing steady delays have little recourse when a transmission provider misses a deadline, because the reasonable-effort standard is not a particularly high bar,” she said. “We need to make some sort of modification to the … reasonable-effort standard.”
Among the options are penalties, for which “we’d have to think about the specifics of force majeure exemptions; waivers; amount of the penalty,” she said. “What would we use the penalty for? When [would] the penalty start?”
She said transmission providers also could be required to devote more staff, software and other resources to interconnection, or subject to additional public reporting requirements — “a scorecard relative to performance.”
LeVar said regulators should consider “what barriers might exist to individual generators [and focus on transmission provider] outliers, the ones that aren’t trying to engage in reform and are making the good-faith efforts that many are.”
Affected-system Studies
Scripps urged FERC to set standards regarding cross-RTO affected-systems studies, which, he said, “have the ability to destroy project economics” and have become “a growing source of delay and cost uncertainty for interconnection customers.”
“We expect the affected-system study process to become increasingly critical as more renewable resources come online in renewable-rich areas and transmission capacity becomes ever more scarce,” he said.
In 2018, a FERC technical conference resulted in a September 2019 order requiring MISO, PJM and SPP to improve the transparency of their affected-system studies. (See Affected-system Rules Unclear, FERC Says.) But Scripps noted the commission declined to open a generic proceeding to address broader affected-system coordination issues.
“We saw in the filings from MISO, SPP and PJM that were done in 2019 and 2020 [that] the delays continue to persist and often due to the underlying issues that were brought to light in that technical conference. Namely each RTO’s process and study times are different and tailored to the region.
“It may be time to revisit the commission’s 2019 decision not to initiate a proceeding to better coordinate affected-system studies. Specifically, there may be an opportunity to create a general framework that would be consistent across RTO seams,” he said. “Fully addressing these cross-RTO issues are inherently beyond any one RTO’s or ISO’s ability to fully control.”
Arkansas’ Thomas said he agreed “word for word” with Scripps. “The most effective place that FERC can operate is in the area where you have two RTOs, and the real issue is getting them on the same page. I think that FERC should start gently and move towards less gentle as needed.”
Transmission Planning
Maryland’s Stanek said reform of the generator interconnection process is interlinked with that of transmission planning. “They’re both interdependent elements of developing needed transmission infrastructure and share many of the very same principles and challenges,” he said. “A very key difference here is that the generator interconnection needs are much more focused and much more immediate. This is an issue that we can tackle now and not have to wait 20 years to see if the fruits of our labor yield success. How well these new processes are implemented will determine that success.”
Andrew French, chair of the Kansas Corporation Commission, said the queue backlog is “a symptom of queue-based planning.”
“While we need to, in the interim, try to address the demand for those resources and addressing what’s in the queues now, we can’t lose sight of the fact that the ultimate long-term solution is better long-range planning,” French said.
Vermont’s Allen said, “There’s a growing body of evidence, especially from PJM and MISO, that we can actually interconnect much more capacity going forward if we do it in a very anticipatory long-term planning framework than on a serial or even a … cluster-by-cluster framework that is the prevailing paradigm.”
On April 21, FERC issued a Notice of Proposed Rulemaking that would require transmission providers to use scenarios and probabilistic techniques to identify potential infrastructure needs 20 years into the future based on decarbonization policies and industry trends. (See FERC Issues 1st Proposal out of Transmission Proceeding.)
Cure for What Ails Us
French said the queue backlogs may not be quite as bad as they seem because so many queue entries are “placeholder projects” used for cost discovery on required transmission upgrades.
“If we were able to create some good large amounts of backbone capacity on the transmission system … and put it in the optimal place, you might actually see quite a bit of generation be able to be interconnected, and the backlogs could clear perhaps more quickly than we would think,” he said.
He added, “I know it’s never easy to just snap your fingers and [create] backbone transmission.”
The second half of Friday’s meeting of the Joint Federal-State Task Force on Electric Transmission started off with a touch of irony.
“Now we’ll move on to the much less controversial issue about funding and cost allocation” of transmission projects, Jonathan Raab — president of consultancy Raab Associates and facilitator of the meeting — said about a topic that has sparked sharp disagreements in organized electricity markets across the country.
The first part of Friday’s conference of federal and state regulators focused on clogged generation interconnection queues in RTOs and ISOs. (See related story, FERC-State Task Force Considers Clustering, ‘Fast Track’ to Clear Queues.) The next half delved into the even thornier issue of who should pay for the needed transmission network upgrades spurred by the interconnecting resources piling up in the queues.
The issue of cost allocation has grown in controversy as the grid integrates increasing volumes of renewable resources. Developers must often site renewables far from load centers, other generating resources and existing high-voltage transmission lines in order to cover enough ground to capture economies of scale and locate in areas that offer higher capacity factors resulting from more consistent winds or sunlight.
“In recent years, I think we’re at a point where the changing resource mix has already triggered a number of challenges, and the solutions required are effectively transmission solutions,” Michigan Public Service Commission Chair Dan Scripps said in opening remarks.
“It’s not that we’re building out backbone transmission projects in order to simply accommodate generators, but really to keep the lights on. And whether we continue to allocate a disproportionate share of the cost to interconnecting generators in order to fulfill this reliability imperative, I’m not convinced that the current model strikes the right balance,” he said.
Not ‘From All to Nothing’
Friday afternoon’s discussion aimed to get closer to that balance. Raab framed the session by outlining four cost allocation approaches for the regulators to consider, including:
participants (i.e., the generators) paying for 100% of the costs for network upgrades in RTOs/ISOs;
participants and load sharing the costs for upgrades;
load picking up 100% of the cost for certain types of upgrades; and
costs for new or upgraded facilities being covered by generator subscriptions.
State regulators have generally supported the first option, with some flexibility — and some notable deviations.
In its comments on FERC’s 2021 Advance Notice of Proposed Rulemaking to improve regional transmission planning, cost allocation and interconnection processes (RM21-17), the National Association of Regulatory Utility Commissioners urged the commission to “retain the core tenet of participant funding, while exploring the as yet untapped potential economies of scale that could result from increased coordination among participants,” such as through clustering of projects. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)
On Friday, FERC Commissioner Allison Clements encouraged industry stakeholders to be flexible in their thinking about cost allocation.
“I don’t think the solution is going from all to nothing. I don’t think that, while interconnection customers currently pay off needed upgrade costs, the solution should be jumping to having them pay nothing. That doesn’t jive with [FERC’s] cost allocation principles,” Clements said.
“I’ve never had a project sponsor suggest to me that they’re unwilling to pay their fair share, and I’ve also never had a transmission provider suggest to me that in all, or even in most cases, the whole of network upgrade benefits accrue only to the interconnection customer customers paying for them,” she added.
“I am a believer that when we make certain high-voltage upgrades as part of the [generator interconnection] process, there are real benefits that flow to load,” Kansas Corporation Commission Chair Andrew French said.
Changes to cost-sharing models should not be a “one-way street” directed only at electricity customers, according to French.
“This is not just about getting load to pay more, or to chip in more of the cost to help interconnect generators. It’s to try to find the most accurate cost allocation over all of our investments,” he said.
French pointed out that SPP’s regional planning process can produce a “big backbone” project on which generation developers can “basically free ride for a few years” without dealing with many upgrades.
“They don’t have to pay anything for them, and that’s the situation we were in for maybe the last 10 years before we ran out of capacity,” French said. “I just want to make the point that, ultimately, we need to get to a more holistic, consolidated planning process.”
The intertwining relationship between transmission planning and cost allocation was a recurring theme during the discussion.
Michigan’s Scripps encouraged fellow regulators to avoid “siloing” the cost allocation issue “because it really does connect with a number of other concerns, and I’d argue that participant funding reform should go hand-in-hand with interconnection key reforms.”
Pennsylvania Public Utility Commission Chair Gladys Brown Dutrieuille noted that there isn’t a consensus of support for a 100% participant funding model within the Mid-Atlantic Conference of Regulatory Utilities Commissioners, which she was representing during the meeting. But she also emphasized the support for that model in her own state, which deregulated its electricity market to offload generation investment risks from ratepayers.
“The participant-funding model is based on the tried-and-true ratemaking principle of cost causation. And I just want to highlight what I believe its benefits include: and that would be promoting efficient siting of generation projects, as well as allowing parties that are best positioned to control the interconnection costs to bear the costs.”
North Carolina Utilities Commissioner Kimberly Duffley said there’s a “strong consensus” within the Southeastern Association of Regulatory Utility Commissioners and the industry at large for maintaining the participant-funding model. Duffley cautioned that straying from that model could saddle ratepayers with costs for transmission projects they neither want nor need.
“Enjoyed listening to Commissioner Dutrieuille. Enjoyed listing to Commissioner Duffley,” FERC Commissioner Mark Christie said. “All I can say is, ‘What she said — twice.’”
FERC Chair Richard Glick and Commissioner Willie Phillips both reminded their fellow regulators that judicial precedent requires the commission to look beyond participant-driven costs to consider wider system benefits.
“There’s a number of cases where the courts have essentially said cost-causation really is benefits, and you have to look at who benefits in terms of who pays,” Glick said.
Sharing the Cost
“I believe that cost sharing might actually be more cost-effective for consumers overall, because it could provide some incentive for [transmission owners] to proactively plan and build the optimal transmission lines in the first place,” Phillips said when the subject turned to an allocation approach that splits costs between generators and load.
Phillips pointed favorably to CAISO’s model in which TOs are required to refund upgrade costs back to generators within five years of a project’s operation date, as well as the MISO model where load pays 10% of transmission upgrade costs for lines rated at 345 kV or above.
California Public Utilities Commissioner Cliff Rechtschaffen said that CAISO’s practice was designed to ensure that generators have financial “skin in the game” before seeking interconnection.
“The generator still covers the cost between the generation facility and the point of interconnection. The costs that are covered by this policy are the reliability, substation and deliverability backbone upgrades,” Rechtschaffen said, adding that CAISO caps the level of reimbursement.
“Only upgrades that are needed to meet resource adequacy requirements are reimbursable. So that ensures that the load that’s charged for the upgrades is benefiting and adhering to the beneficiary-pays principle that is so important,” he said.
“I think to the extent that we’re looking for something with relative simplicity, and something with a framework that FERC is familiar with and has approved in the past, a voltage threshold [as in MISO] would seem to make sense,” Maryland Public Service Commission Chair Jason Stanek said.
Dutrieuille called the MISO cost-sharing mechanism “intriguing” and “easy to understand,” but she was reluctant to endorse it. “I would make sure that we understood what the benefits were … [and that] you can quantify them, and they’re not speculative in nature.”
Arkansas Public Service Commission Chair Ted Thomas said as the electricity grid continues to undergo its transition, the “right transmission plan” should function as the shared cost. “Doing that right, there shouldn’t be that many remaining shared costs. That’s a critical point,” he said.
‘Relatively Agnostic’
An allocation approach in which load bears 100% of the costs for transmission upgrades found no support among the commissioners, but a model in which generator subscriptions supported the development of new or upgraded infrastructure sparked some interest.
Stanek pointed out that FERC has used the subscription model in the past for natural gas pipelines and some merchant transmission projects.
“I think some of the benefits that could flow from this would be a faster interconnection process, efficiency and, probably most important to this afternoon’s conversation, making sure that the costs of this upgrade would be paid for in a fair and equitable manner,” Stanek said.
“It’s a framework that I think addresses some of the big thorny knots that we’re dealing with when we talk about free ridership, lumpy and large payments, cost uncertainties — some of the big things that we can’t seem to kind of get around,” Vermont Public Utility Commissioner Riley Allen said.
Allen likened the subscription model with ISO-NE’s cluster interconnection process, in which the RTO assigns the costs for major transmission upgrades to clusters of interconnecting resources. He envisioned a way of scaling up that process for “superclusters” of resources in allocating costs for upgrading a larger backbone system. Instead of being responsible for incremental upgrades to a network on an individual basis, interconnecting generators could be allocated costs based on a per-megawatt fee.
He also proposed the further step of adopting Vermont’s system of using a cost “adjuster” to steer development to areas of the system that already have existing capacity. “So it kind of checks a number of boxes, at least for me, in terms of getting around the problem, working our way past the kind of participant-pays versus load-pays, because this is relatively agnostic,” he said.
“I think the proposal that Commissioner Allen just outlined would be very helpful when in terms of offshore wind if you build a collector system. That’s probably the fairest way of allocating the cost,” Glick said.
Speaking as the lone representative from the “non-RTO West,” Utah Public Service Commission Chair Thad LeVar noted that issue of participant funding is not something the region currently wrestles with. But LeVar cautioned FERC about developing cost allocation rules that could “chill” the West’s efforts toward increased regionalization and — “hopefully” — an RTO.
“I would hate to see the RTO rules that don’t currently apply to us evolve in a way that would scare off stakeholders from the work that’s happening across the West,” he said.
‘A Little Less Consensus’
In wrapping up the meeting, Glick said it was evident there appeared to be “a lot of consensus” on how to address logjams in RTO interconnection queues, and “a little less consensus” on cost allocation for transmission upgrades.
Glick said the lack of agreement was “not surprising” given NARUC’s comments on FERC’s ANOPR last year and the divergent opinions among states on the need to “reform” cost allocation rules.
“So that’s something we need to consider as well, and we’re certainly cognizant of all the actions that are going on at the state level,” he said. “And whatever actions we take at FERC, I think we certainly will, at least from my perspective, take into account what the states are doing and certainly not try to reverse or impede the progress that the states are making.”
PPL reported a positive first quarter during its earnings call on Thursday after announcing earlier in the week that it will raise its default electricity rates by 38% for residential Pennsylvania customers on June 1.
The company reported first-quarter earnings of $273 million ($0.37/share), compared with a first-quarter 2021 net loss of $1.84 billion (‑$2.39/share). Adjusting for special items, PPL’s earnings were $305 million ($0.41/share), compared with $219 million ($0.28/share) a year ago. Some of those items included integration expenses from the planned acquisition of Narragansett Electric from National Grid and last year’s non-cash net loss from its discontinued operations associated with PPL’s former U.K. utility business, Western Power Distribution.
PPL’s rebound comes after the company cut its dividend in half and missed earnings and revenue targets in the fourth quarter of 2021. (See PPL Announces Losses, Dividend Cut in Q4 Call.)
This year’s rate increase will add about $34/month to the average bill. The residential rate will rise to 12.366 cents/kWh, while small businesses will pay 11.695 cents/kWh.
CEO Vincent Sorgi said PPL is “very focused” on making sure customers are familiar with programs to help lower their rates and to also “provide flexible payment plans” like those instituted at the height of the COVID-19 pandemic.
“Commodity prices are way up this year versus last year,” Sorgi said. “That’s a pass-through cost for us, but it’s upwards this year versus last. It could be as much as 50 to 60%, so it is very significant. We are actively reaching out to our customers to help them.”
Narragansett Deal
PPL continues the acquisition process of Narragansett, Sorgi said, with the company receiving approval in late February from the Rhode Island Division of Public Utilities and Carriers. (See RI Agency Approves PPL Acquisition of Narragansett Electric.)
The Rhode Island attorney general’s office appealed the division’s decision to the state Superior Court, receiving a stay of the approval. PPL and other stakeholders provided oral arguments on April 26, with the AG’s office contending that the division misapplied the statutory standard for approval and failed to adequately consider Rhode Island’s Act on Climate in its analysis.
“We disagree and believe the extensive record and evidence in this case demonstrate that the division properly applied the statutory standard and correctly approved the transaction,” Sorgi said. “We continue to believe Narragansett Electric is an excellent fit for PPL and that PPL is an excellent fit for the state of Rhode Island. We remain confident that we will reach a positive outcome in the proceeding.”
Kentucky Operations
Sorgi also highlighted PPL’s Kentucky segment, which earned 25 cents/share for the first quarter, a 7-cent increase over a year ago and attributable to higher base retail rates that took effect July 21.
Ford Motor Co.’s announcement that it will build a $6 billion battery manufacturing complex within PPL’s service territories in Glendale, Ky., “will help put the state at the forefront of the auto industry’s transformation to electric vehicles,” Sorgi said. To support the project, PPL subsidiary Kentucky Utilities has requested regulatory approval to build two 345-kV and two 138-kV transmission lines and two new substations at an estimated cost of up to $200 million.
Sorgi said Kentucky Utilities is continuing to look for opportunities to advance clean energy technologies, including joining the state’s new hydrogen hub initiative in February. “We’re excited to join this new hydrogen hub initiative, and we will continue to engage with the Kentucky administration and other stakeholders as the state’s clean energy strategy evolves.”
He also said that based on PPL’s current coal plant retirement schedule, the company expects its coal capacity to be reduced from just over 4,700 MW to about 550 MW in 2050. The remaining capacity is the Trimble County 2 plant in Kentucky, which was completed in 2011.
“There are any number of technology developments, regulatory mandates or circumstances that could impact the timing of the end of this plant’s economic life,” Sorgi said. “We believe that research and development is key to our clean energy future and fully expect that innovation, technological advances and the relative economics of other cleaner energy sources will support the company’s commitment to not burn unabated coal at this facility by 2050.”
The U.S. Commerce Department’s probe into tariff evasion by Chinese importers of solar panel components has prolonged the life of one northern Indiana coal plant by two years.
NiSource said during its May 4 first-quarter earnings call that it will postpone retirement of the R.M. Schahfer plant’s remaining two units from 2023 to 2025 because the investigation is stalling its development of solar facilities meant to replace the 877-MW facility.
The retirement raincheck is one of the first ripple effects since the federal government began its investigation in April. (See Solar Sector Braces for Tariff Probe Impact.)
In a press release, NiSource explained that the probe has “brought uncertainty and delays to the solar panel market.” It said it was working with its renewable energy developers to “better understand the potential project impacts.”
Shawn Anderson, NiSource chief strategy and risk officer, said the utility’s 10 solar and energy storage projects slated to come online over this year and next now face delays of six to 18 months.
“Our focus has been to accelerate savings for our customers to benefit from the renewable transition, and delays resulting from this investigation may ultimately delay the timing of when our customers could begin receiving these benefits, especially in the current energy cost inflationary environment,” Anderson said during the call.
The utility plans to idle all its coal plants by 2028 and cut its carbon emissions 90% from 2005 levels by 2030. Despite the deferral, NiSource said its clean-energy goals remain unchanged. The company said it expects to retire its Michigan City Generating Station sometime between 2026 and 2028.
NiSource also said despite solar development delays, it remains on track to spend $10 billion in capital investments, including $2 billion on renewable projects, between 2021 and 2024. The utility said it has planned “flexibility in the timing of other gas and electric infrastructure capital investments that can allow adjustments to compensate for delays in renewable generation projects.”
Vistra executives expressed confidence in their hedging strategy Friday, telling financial analysts during their first-quarter earnings call that the company is “very well positioned” to take advantage of a tight natural gas market.
“In a nutshell, the U.S. natural gas complex is already tight and likely to be increasingly tied to world gas economics,” CEO Curt Morgan said in his prepared comments. “As an expanding pivotal supplier on the world stage, we expect U.S. supply and demand to tighten even further. Higher natural gas prices in turn lead to higher power prices, and Vistra is long power and natural gas equivalents.”
Vistra’s retiring CEO said the company “is in the right position to capitalize on the strong forward curves” and that its “prudent” hedging strategy has locked in value through 2025.
“The forwards have also risen materially out to 2030. The market clearly believes there has been a fundamental shift in the energy commodity complex,” Morgan said. “This shift … offers continued opportunities to hedge more while remaining mindful of the potential liquidity requirements against further commodity price moves.”
The Irving, Texas-based company released first-quarter adjusted EBITDA from ongoing operations of $547 million. That is a more than three-fold improvement over the same period the year before, when Vistra reported a loss of $1.2 billion following the February winter storm disaster. (See Vistra’s Winter Storm Loss Deepens to $1.6B.)
Vistra uses adjusted EBITDA as a performance measure, saying it believes that outside analysis of its business is improved by visibility into both net income prepared in accordance with GAAP and adjusted EBITDA.
The company reaffirmed its previously announced guidance of adjusted EBITDA from ongoing operations of $2.81 billion to $3.31 billion. Morgan noted that Vistra, the largest generator in the ERCOT market, still has the summer months ahead of it and “carries a little more open position than in the past for risk management purposes.”
“We reaffirm this guidance with increased confidence given the favorable energy commodities markets we continue to experience,” he said.
Wall Street reacted favorably Friday, driving the company’s share price to its 52-week high of $27.10. Vistra’s stock closed at $26.62, a $1.21 (4.8%) gain on the day. The share price has gained 65.9% over the last year, when it stood at $16.05.
Vistra continues “sensibly progressing” its zero-carbon generation fleet, having completed construction of two solar facilities totaling 158 MW of capacity and a 260-MW energy storage facility, all in Texas. In California, it is installing replacement connectors in the water-based heat suppression safety systems at its Moss 300 and Moss Landing 100 storage facilities.
The earnings call was Morgan’s last at CEO. He announced his retirement in March and is transitioning his leadership role to CFO Jim Burke. (See Burke to Succeed Morgan as Vistra’s CEO.)
“I’m proud of all that we’ve accomplished, and [I] believe Vistra is well positioned to drive continued industry leadership,” Morgan said.
If half of the nation’s heavy duty regional-haul tractor trailers were electric rather than diesel, annual carbon dioxide emissions would be slashed by more than 29 million metric tons, a new report concludes.
The report released by the North American Council for Freight Efficiency (NACFE) on Thursday also endorsed the immediate feasibility of electrifying some short-haul fleets — from beverage and grocery delivery trucks to general freight — despite their shorter range of about 200 miles and a freight “penalty” of 3,000 to 4,000 lbs. compared with diesels because of their batteries.
NACFE projected the emission reductions using data collected electronically in real-time last fall from four new battery-electric tractor trailers running their usual routes in California.
“The vehicle operations were continuously digitally tracked, and their metrics updated daily via a public website with the ability to view results by day or over a span of days,” NACFE said in the report.
“Metrics such as daily range, speed profiles, state of charge, charging events, amount of regenerative braking energy recovery [recharging the battery], weather and number of deliveries were shown in near real time. Information on weather conditions was also observed,” the report states.
NACFE found that “many people mistakenly assume Class 8 heavy-duty tractors are used in mostly long-haul disparate routes. In fact, only 40% are used in long-haul and 30% are vocational trucks and regional haul tractors respectively. These regional haul tractors are good candidates for electrification due to their shorter daily distances and return-to-base operations.”
Large battery-electric heavy trucks making daily regional round-trip deliveries of 200 miles per day or less could replace traditional diesel rigs immediately, concludes an analysis of data collected during over-the-road testing by the North American Council for Freight Efficiency. | NACFE
And while the sticker price on the trucks can be more than twice that of a comparable diesel, the annul fuel costs of the electrics are drastically lower — $11,200 for electricity versus $20,500 for diesel fuel.
The bottom line of the report?
“Heavy-duty regional haul battery electric trucks are viable solutions today for improving fleet freight efficiency and helping achieve sustainability goals on short and some medium length routes where daily mileage is 200 miles, with one shift return-to-base operations, where overnight vehicle dwell time allows for lower cost overnight charging.”
In other words, about half of the short-haul big trucks on the nation’s highways making daily runs amounting to a total of 200 miles or less could be replaced today.
Despite the overall favorable finding of the test runs and analytical conclusions, the report cautions that the technology underlying electric trucks — and the scarcity today of public fast-charging stations — is a limiting factor on an immediate transformation of trucking fleets.
The analysis is based on the performance of four Class 8 trucks built either by traditional diesel truck makers Freightliner, Volvo VNR and Peterbilt, or newcomer BYD, according to the report.
“All performed as expected but as of 2021 did not have the range to complete the full day’s work of their diesel incumbents,” the report cautions.
If fast-charging stations were built, as more than 50 utilities have pledged as a goal along the nation’s interstate system, these electric trucks could be more quickly adopted, the report adds.
“We … consider this market segment to be 50% electrifiable today,” NACFE said.
The Northeast Power Coordinating Council (NPCC) expects to have adequate supplies to meet an anticipated 104,601 MW of demand for this summer’s peak week of July 24, according to its summer Reliability Assessment released Thursday. Generation and transmission facilities are also believed to be sufficient.
NPCC’s demand prediction is up slightly from last year’s projection of 104,075 MW for the peak week of Aug. 8. (See NPCC Predicts Lower Peak in Summer 2021.) Ambient weather conditions including heat and humidity are once again “the single most important variable impacting the demand forecasts,” though the ongoing return of currently remote workers to their offices, coupled with continuing remote status for other employees, is expected to “translate to a small increase” in peak demands for the summer.
Total capacity for the region — which includes the six New England states, New York, Ontario, Québec, New Brunswick and Nova Scotia — is slated at 163,668 MW. The total includes 159,401 MW of installed capacity, down about 1,530 MW from last summer; 1,954 MW in net interchange, representing purchases and sales with areas outside NPCC; and 2,313 MW in dispatchable demand-side management assets, which help meet electricity needs by reducing consumption.
Resource fuel type for NPCC during the week beginning July 24
The overall peak demand is based on a 50/50 system load forecast for peak week, representing a prediction with a 50% chance of being exceeded. NPCC’s assessment also includes a 90/10 forecast — with a 10% chance of being exceeded — and a “low probability, high impact composite scenario [based] heavily on individual area risk assumptions,” which the report refers to as “above 90/10.”
In the 90/10 forecast, total demand rises to 111,643 MW, while the above 90/10 scenario projects demand of 117,653, resulting in net margin of 3,753 MW for the former scenario. For the latter, a rise in maintenance and derates results in a net margin of -5,478 MW.
Also included in the assessment is a snapshot of regional forecasts with their own 50/50, 90/10 and above 90/10 scenarios:
NYISO: peak demand of 31,764 MW (50/50) and 33,747 MW (90/10), down from 32,327 MW and 34,321 MW last year. Total installed capacity for peak week is planned at 37,431, down from last year’s peak of 37,785 MW. NPCC said no transmission-related reliability issues are expected this summer, though multiple outages will likely result from “New York public policy projects.”
ISO-NE: peak demand of 24,817 MW (50/50) and 26,624 MW (90/10), a decrease from 24,810 MW and 26,711 MW last year. Installed capacity for peak week comes to 28,626 MW, with the decrease from last year’s 30,133 MW attributed to retirements of multiple natural gas facilities.
Ontario: peak demand of 22,546 MW (50/50) and 24,675 MW (90/10), up from 22,500 MW and 24,228 MW in 2021. The installed capacity of 38,239 MW is 865 MW lower than last year because of retirements and delays in commissioning new resources.
Québec: peak demand of 22,271 MW (50/50) and 23,122 MW (90/10), up from 21,436 MW and 21,886 MW. In part from reductions in wind and biomass capacity, total installed generation for the province is down from 46,529 MW last year to 46,512 MW this summer.
New Brunswick and Nova Scotia: peak demand of 3,475 MW (50/50) and 3,702 (90/10), down slightly from 3,479 MW and 3,726 MW. Installed capacity for peak week is projected at 7,686 MW, a net decrease of 23 MW from last year because of the retirement of two generating stations.
“Our assessment estimates that the … region’s spare operable capacity … will be quite sizable. Simply put, that means that the region has extra insurance against unforeseen events and demands on the grid,” NPCC CEO Charles Dickerson said in a press release accompanying the report. “Against the stress tests of our assessment, the region has a reliable bulk supply and transmission capability of electricity throughout the summer months.”
Dominion Energy (NYSE:D) announced Thursday during its first-quarter earnings call that it filed with the Virginia State Corporation Commission to suspend its rider through the Regional Greenhouse Gas Initiative (RGGI) as the state moves to withdraw from the environmental program.
CEO Robert Blue said Thursday’s filing also included a request that RGGI compliance costs incurred through July 31 and not yet recovered, which total about $178 million, be recovered through Dominion Energy Virginia’s current base rates.
The SCC in August approved Dominion’s request to recover RGGI costs from ratepayers, which the utility estimated would cost the typical residential customer $2.39/month. According to figures supplied by Dominion to the SCC, cited in a report released by Gov. Glenn Youngkin (R) in March, the utility expected RGGI participation will cost customers a total of $3 billion through 2045. (See Youngkin Report: RGGI a ‘Direct Carbon Tax’ on Va. Ratepayers.) Youngkin signed an executive order just hours after taking office Jan. 15 to remove Virginia from RGGI, fulfilling a campaign promise.
Blue said Dominion’s new proposal filed with the SCC will “provide a meaningful reduction to customer bills” that still allows the company to achieve Virginia’s ambitious decarbonization goals.
The RGGI documents were not available on the SCC website as of press time.
“While we are committed to the ongoing transition to cleaner and lower carbon-emitting resources, we’re concerned that Virginia’s linkage to the RGGI program through the Virginia carbon proposal would result in a financial burden on customers with no real mitigation of greenhouse gas emissions regionally,” Blue said.
Blue said contracts for the primary offshore equipment suppliers were completed and signed in late 2021, including for the foundations, transition pieces, substations, transportation of components, installation, and subsea cabling and turbine supply.
“Offshore wind, zero fuel costs, and transformational economic development and jobs benefits are needed now more than ever,” Blue said. “The project will also propel Virginia closer to achieving its goal to become a major hub for the burgeoning offshore wind value chain up and down the country’s East Coast.”
Blue was asked about the status of the SCC approval process and the “back-and-forth” between the company and regulators in the proceeding.
Dominion is “pleased” with the project’s progress, Blue said, and expects to have a final order from the SCC in early August. The company’s rebuttal testimony showed under different scenarios that the project is beneficial to customers, he said, pointing to PJM’s load forecast showing increased energy sales in Virginia.
“I feel even stronger, as now that all the testimony is in, we have a very strong case on offshore wind,” Blue said. “The legislation, the Virginia Clean Economy Act, lays out the parameters for spending that is presumed prudent, and we’ve clearly met all of those.”
Blue was also asked if there was an opportunity to settle any disputes with the concerned parties before the SCC’s decision in August. He said Dominion is always open to finding a “constructive settlement” on regulatory issues.
“If there were an opportunity to settle in a constructive way, we’d obviously do that,” Blue said. “I expect you to hear that from every party to every litigated matter. But we’ve got a schedule, and that’s what we’re following.”
Earnings
Dominion reported first-quarter net income of $711 million ($0.83/share), compared with net income of $1 billion ($1.23/share) for the same period in 2021. Operating earnings for the first quarter were $1 billion ($1.18/share), compared to $893 million ($1.09/share) last year.
The company affirmed its full-year 2022 operating earnings guidance range of $3.95 to $4.25/share and its long-term earnings and dividend growth guidance. Dominion expects second-quarter operating earnings in the range of 70 to 80 cents/share.
Dominion’s stock was up 53 cents (0.64%), finishing at $83.04 on the same day the Dow Jones Industrial Average lost more than 1,000 points for its worst day since 2020.
MISO and SPP seams | MISO and SPP
