RTO, SaskPower Agree to Expand Interconnection’s Capacity
Canadian utility SaskPower said on Wednesday that it has signed a 20-year agreement with SPP to more than quadruple transmission capacity between the province of Saskatchewan and the U.S., effective 2027.
The utility and SPP will expand the 150-MW tie line that connects them to 650 MW. SaskPower said expanding the transmission capacity between the two countries will also improve reliability on its side of the border and allow the utility to export excess power to SPP, creating revenue opportunities.
“Access to this large market ensures reliable energy is available to Saskatchewan to support our own generating facilities,” SaskPower CEO Rupen Pandya said. “This will help to manage the integration of more intermittent renewable power such as wind and solar while keeping costs as low as possible for customers.”
SaskPower’s footprint has three ties with the U.S. | SaskPower
SaskPower will build the necessary transmission facilities on its side of the border over the next five years, and SPP will be responsible for construction on its side.
SPP has been making international transactions with SaskPower since 2015, thanks to Canadian interconnections that came when the Integrated System joined the RTO. (See SPP, SaskPower Make First International Trade.)
Clements Dissents on Accreditation Order
After two deficiency notices, FERC has approved SPP’s request to add capacity accreditation methodology provisions for wind and solar resources to its business practices and planning criteria. The RTO now determines the accredited capacity of qualified run-of-river hydroelectric, wind and solar resources based on historical performance, effective Feb. 15, 2022 (ER22-379).
The commission in its Aug. 5 order directed SPP to make a compliance filing within 30 days. The RTO filed its request in November 2021.
Commissioner Allison Clements partially dissented from the order, tweeting last week that she did so on the condition that SPP submit revised tariff compliance records. She said the RTO “should have submitted tariff revisions that explain what its proposal actually is.”
“Granted, the majority agrees that SPP’s proposal falls short of the commission’s rule of reason,” Clements wrote. “But they take it on faith that SPP will submit satisfactory tariff revisions on compliance, without knowing what those revisions would actually say. I cannot conclude that a tariff change is just and reasonable based solely on its general description.”
M2M Settlements up to $341.9M
SPP staff briefed the Seams Advisory Group on Friday on three months of market-to-market (M2M) transactions that brought the settlement accruals in its favor with MISO to $341.9 million.
More than half of the three months of transactions came in April at $26.5 million, the third-highest month between the seams neighbors. Settlements in May and June pushed the three-month total to $50.6 million. Permanent and temporary flowgates were binding for 5,907 hours during the three months.
M2M settlements for the redispatch of market flows around congested flowgates have now been in SPP’s favor for 16 straight months and 31 of the last 33. The RTOs began the process in 2015.
“The weather wasn’t too crazy,” SPP’s Jack Williamson told SAG. “We’re constantly breaking new peak records all the time. We’re seeing more and more wind on the system.”
Staff also told the stakeholder group that it is developing its first emergency energy exchange agreement with another seams neighbor, Missouri-based Associated Electric Cooperative Inc. The joint operating agreement does not currently have provisions for energy exchanges during energy emergencies, but SPP has similar arrangements with SaskPower, MISO and Public Service Company of Colorado.
PJM to Make Designated Entity Agreement Filing ‘Shortly’
VALLEY FORGE, Pa. — PJM attorney Pauline Foley provided a brief update on the RTO’s plans to make a Federal Power Act Section 206 filing asserting that the Operating Agreement’s provisions on designated entity agreements (DEAs) are unjust and unreasonable.
Foley said the RTO will assert that the OA’s references to DEAs are “overly broad and imprecise.”
PJM “anticipates making the filing shortly,” she said. “I don’t have an exact date.”
News of PJM’s planned filing prompted the cancellation of scheduled votes on competing issue charges on the matter at the July 27 Markets and Reliability Committee and Members Committee meetings. (See “Application of Designated Entity Agreement,” PJM MRC/MC Briefs: July 27, 2022.)
On July 26, a group of load-side stakeholders beat PJM to FERC, filing a complaint asking the commission to force the RTO to require incumbent transmission owners to sign DEAs on “immediate need” projects. The complainants contended the RTO has violated the OA by refusing to do so. (See PJM Challenged on Oversight of ‘Immediate Need’ Tx Projects.)
Generator Deliverability Test Update
Most stakeholders urged PJM to delay a vote on changes to generation deliverability testing procedures until the rules for effective load-carrying capability (ELCC) capacity interconnection rights (CIRs) are considered.
The deliverability test ensures the transmission system can transmit its generating capacity at summer peak load as well as under light load and winter conditions. The proposed changes are in response to increasing system variability caused by growing renewable penetration. (See “Generator Deliverability Education,” PJM Planning Committee Briefs: July 12, 2022.)
CIRs set an upper bound on the amount of installed capacity attributed to a generation capacity resource. ELCC resources such as renewables cannot run at their maximum output for more than 24 hours.
“It could be independent and should be independent,” Exelon’s Pulin Shah said of the two processes.
But other stakeholders — including Apex Clean Energy Group, LS Power, the PJM Public Power Coalition, Old Dominion Electric Cooperative, and economists Paul Sotkiewicz and Roy Shanker — said the issues should be considered together.
“I don’t see how it can be done separately,” said Shanker. “You could have a whole lot of [generation] that’s approved but not deliverable because of changes that happen two months later.”
“They need to go hand in hand,” said Sotkiewicz, of E-Cubed Policy Associates.
Carl Johnson, representing the PJM Public Power Coalition, said coupling the issues “creates the least uncertainty.”
PJM’s Jonathan Kern said the RTO is proposing to merge summer, winter and light load deliverability testing methods.
In June, the PC’s special session on CIRs for ELCCs discussed competing proposals from PJM, LS Power, Global Infrastructure Partners’ Eolian subsidiary and Sotkiewicz. The group originally planned a final review in July, but the meeting was postponed until late August to allow for more offline discussions to forge compromises. (See “‘Time to Get Involved’ in Capacity Interconnection Rights for ELCC Resources,” PJM Planning Committee Briefs: July 12, 2022.) New rules would be implemented for the 2025/26 Base Residual Auction.
The generator deliverability test changes would be made in Manuals 14A and 14B. They would add a new block dispatch approach to dispatch cases. To ensure a realistic dispatch, the base case would not allow any locational deliverability area (LDA) to import more power than their capacity emergency transfer objective (CETO).
The light load period, currently 12 to 5 a.m., would be redefined to include daytime hours from 10 a.m. to 3 p.m. where the RTO’s coincident peak load is between 40 and 60% of the annual peak. The default light load temperature would be 59 degrees Fahrenheit.
The new rules also will include more wind and solar in base case dispatches, with fixed solar rising from 38% to 47 to 55% of nameplate capacity in summer. Onshore wind would increase from 13% to 16 to 20%, and offshore wind would jump from 30% to 33 to 38%.
PJM wants stakeholder approval of the deliverability changes by December so they can take effect for the 2028 Regional Transmission Expansion Plan.
Load Model Selection Endorsed
Members unanimously endorsed PJM’s proposal to use a 2002-2012 load model for the 2022 Reserve Requirement Study.
PJM’s Patricio Rocha Garrido said the RTO changed its recommendation from the 2000-2010 model after discovering that a Monte Carlo simulation of the model “distorts the total distribution.”
The model selected is based on an analytical method rather than Monte Carlo sampling, he said. “At the 97th percentile and above, the Monte Carlo is not doing a good job.”
Sotkiewicz asked PJM to provide written language describing its algorithms “to avoid … confusion.”
Issue Charge Approved on Day-ahead Zonal Load Bus Distribution Factors
VALLEY FORGE, Pa. — The PJM Market Implementation Committee last week approved an issue charge to consider a new method of determining day-ahead zonal load bus distribution factors.
The RTO’s current rules state that the default distribution of load buses for a zone in the day-ahead energy market is the state-estimated distribution of load for that zone at 8 a.m. one week prior to the operating day. Thus, the share of the zonal load attributed to each node remains constant for all 24 hours, even though the node’s share of total load may vary throughout the day because of nonconforming loads, such as data centers and behind-the-meter solar. This can cause a mismatch between the day-ahead nodal loads and real-time state-estimated load, according to the problem/opportunity statement.
Amanda Martin, who presented the issue at the committee’s meeting Wednesday, said the mismatch is not currently a concern but that PJM expects it to become one with the growth in nonconforming loads.
The committee unanimously approved the issue charge under the “CBIR Lite” (Consensus Based Issue Resolution) process despite the concerns of some stakeholders that the issue is more complicated than portrayed: Martin said it affects a single line in the tariff.
Paul Sotkiewicz of E-Cubed Policy Associates said the issue is not appropriate for CBIR Lite.
“I can think of places in PJM where just a small change [in distribution factors] can change plant commitments. This is not a trivial issue,” he said. “It can change pricing. It can change commitments in real time. I don’t think we can come up with a solution without doing that hard work [to model the impacts of the change]. Otherwise we’re just guessing.”
Independent Market Monitor Joe Bowring said he supported PJM’s proposal but that it should also create an initiative to consider long-term implications.
“Using one hour at 8 a.m. for all 24 hours makes no sense. To me this is clearly and obviously an improvement,” he said.
“If it needs more analysis, fine,” Constellation Energy’s Jason Barker said. “I don’t think we need to make a science experiment out of it.”
To address stakeholders’ concerns, PJM added to the issue charge a requirement that the initiative include an historical analysis to evaluate the impact of proposed solutions relative to the current practice.
The work is expected to take four months, with changes to tariff section 31.7c(i) and updates to Manual 11 and Manual 28.
Variable Operations & Maintenance Cost Development
Members heard a first read on competing proposals by PJM and Constellation Energy on changes to variable operations and maintenance (VOM) cost development that differ over the treatment of nuclear refueling costs and associated major maintenance.
The PJM proposal includes default adders for minor maintenance and operating costs; a new review process and timeline; clarifications to definitions of major and minor maintenance; and clarifications to requirements on supporting documentation.
Barker said that Constellation, the largest nuclear operator in the U.S., treats the projects undertaken during planned refuelings as fixed costs because they are scheduled long in advance, irrespective of the number of starts. As a result, he said, they should be included in capacity offers rather than as VOM in energy offers.
Barker said Constellation generally agrees with PJM’s desire to move most variable costs into cost-based offers. But he said the RTO incorrectly classifies projects associated with planned nuclear outages as major maintenance costs, defined as costs that “vary directly with electric production.”
Nuclear units would not likely have an opportunity to recover costs through a cost-based offer because they are price takers that bid zero into the energy market and are highly unlikely to be dispatched on a cost-based energy offer.
“PJM’s definitions don’t apply well to the nuclear fleet,” he said.
“You’re suggesting a significant change to the definition of what can go into VOM versus what’s allowable in the capacity market,” Bowring said. “This is way beyond the scope of the proposal by PJM. This is about how the review process is conducted, not the definitions of what is VOM.”
Barker insisted he was not seeking a “major change.”
“What we’re trying to do is accurately reflect the nature of nuclear cost accounting,” he said.
MIC Chair Lisa Morelli said she was “not prepared to rule on [the procedural question] now.”
PJM’s Tom Hauske said the RTO considers any cost based on starts and run times as variable and does not distinguish between capital and operating expenses.
PJM’s Glen Boyle said the RTO “wanted the stakeholder process to play out and see where the stakeholders were” on the question.
Heather Svenson of Public Service Enterprise Group said her company “strongly supports” Constellation’s proposal. It is “not a carve out” for nuclear units, she insisted.
The committee will be asked to vote on the proposals at its next meeting.
Manual Revisions OK’d on Reserve Price Formation
Members endorsed revisions to Manual 15: Cost Development Guidelines to conform with FERC’s order approving revised energy price formation rules (EL19-58, ER19-1486).
It will be effective Oct. 1, contingent on FERC approval of PJM’s compliance filing in EL19-58-012.
The changes remove VOM from synchronized reserve offers and eliminate references to Tier 1 and Tier 2 offers to reflect the consolidation of the tiers.
FERC failed to explain why the DFAX method should be used to allocate the costs of two North Jersey transmission projects but not for a similar project in Artificial Island, the D.C. Circuit Court of Appeals ruled last week, partially supporting appeals by Consolidated Edison (NYSE:ED), the New York Power Authority and two merchant transmission operators (15-1183).
The court also rejected PJM’s “de minimis” exemption for applying DFAX, short for “solution-based distribution-factor analysis.”
But the court’s Aug. 9 order rejected a related challenge by the New Jersey Board of Public Utilities, ruling that Public Service Electric and Gas (NYSE:PEG) customers would foot the bill for the North Jersey projects after Con Ed terminated its use of the “PSEG wheel,” an agreement that allowed the utility to deliver power to New York City through PSE&G transmission.
The 43-page order addressed 13 petitions for review challenging 20 FERC orders, “involve numerous parties, implicate a series of related legal issues and arise from a complex procedural history,” the court said.
Bergen-Linden, Sewaren Projects
Much of the case involves $1.3 billion in transmission upgrades authorized by PJM to address short-circuit problems between PSE&G’s Bergen and Linden switching stations and repairs to and around the utility’s Sewaren substation.
To address the short-circuit problem, PJM directed PSE&G to expand the Bergen-Linden corridor into a double-circuit line with higher voltages. The project incidentally also provided additional protection against thermal overloads.
Con Ed and NYPA — as well as Linden VFT and Hudson Transmission Partners, operators of two merchant transmission facilities — challenged FERC’s orders approving PJM’s five cost allocations from 2014 to 2017. Linden and Hudson reroute electricity from New Jersey into the New York market and resell it at a profit when PJM prices are lower than New York’s.
Before they were relieved of liability for the Bergen-Linden and Sewaren projects, the four complainants — which the court labeled the “New York entities” — had been assessed approximately $115 million, which was paid.
PJM allocated most of the costs of the Bergen project ($763 million of $1.2 billion), and all the costs of the Sewaren project ($125 million), via DFAX. In 2014, PJM assigned most of the DFAX costs for Bergen-Linden to Con Ed ($629 million), with the rest allocated to Hudson ($69 million), PSE&G ($52 million) and Linden ($13 million). Sewaren’s costs were split between Con Ed ($64 million) and Linden ($61 million).
The DFAX method models how electricity will flow across a new transmission facility at moments of peak grid use and assigns costs proportionally, based on the projected use of the facility in each transmission zone of the PJM grid. DFAX was designed to apply to “flow-based” projects to increase transmission capacity. But the Bergen-Linden and Sewaren reliability projects were non-flow-based.
The New York entities complained that PJM’s allocations violated the cost-causation principle because the projects were intended to improve PSE&G’s infrastructure, but other parties were assigned most of the costs.
After FERC denied its request for rehearing on the cost allocation, Con Ed notified PSE&G that it would not renew their wheeling agreement. As a result, PJM eliminated Con Ed’s cost liability, reassessing Bergen-Linden’s DFAX costs to Hudson ($634 million), Linden ($132 million) and PSE&G ($128 million). Hudson and Linden responded by converting their firm withdrawal rights to non-firm, absolving them of cost responsibility under DFAX and leaving their costs with PSE&G.
In 2018, FERC reconsidered its use of DFAX on the Artificial Island transmission project, which was designed to address stability problems for three nuclear plants in South Jersey. On rehearing, FERC concluded that the beneficiaries of at least some non-flow-based projects are “not necessarily captured” by the DFAX method and directed PJM to adopt a different cost allocation method for stability-related projects. FERC approved PJM’s revised “stability deviation” method — which identifies which loads would most benefit from projects that address stability issues — in February 2019. (See FERC: Stability Deviation Method Best for Artificial Island.)
But FERC continued to defend the DFAX method for short-circuit projects like Bergen-Linden and Sewaren.
The New York entities contended that because the Artificial Island, Bergen-Linden and Sewaren projects all addressed non-flow-based issues, their costs should all have been allocated similarly.
FERC’s Artificial Island ruling concluded that “stability is analytically unique compared to voltage or thermal overload problems,” which are both flow-based. But the commission did not address whether short-circuit projects should also be treated differently from flow-based, the court said. “Therefore, FERC could not rationally explain its decision to treat Bergen-Linden and Sewaren differently from Artificial Island by simply pointing to its earlier finding that ‘stability is analytically unique compared to voltage or thermal overload problems.’ Instead, FERC needed to explain why stability is ‘analytically unique’ compared to short-circuit issues,” the court said.
In rehearing on Linden’s protest, FERC insisted DFAX should still be used to assign Bergen-Linden’s costs because it was similar to a thermal overload project. But “FERC did not adequately explain why that similarity mattered,” the court said. “Short-circuit issues, not thermal overloads, were the primary impetus for [Bergen-Linden]. While [Bergen-Linden] expanded the grid’s overall capacity, the same is true of Artificial Island.
“Given the similarities between the projects, basic rule-of-law principles required FERC to justify its different treatment of the projects. It needed to explain why, in contrast to Artificial Island, the costs of [Bergen-Linden] and Sewaren should be assigned via DFAX to the utilities whose electricity flows across the upgraded facilities, rather than to the projects’ other beneficiaries,” the court continued. “We do not hold that the use of the DFAX method for short-circuit projects violates the cost-causation principle per se. On remand, FERC may be able to provide a more satisfactory explanation of the distinction between stability-related projects and those that address short-circuit issues and to articulate why DFAX cost allocations are appropriate for the latter but not the former. But the commission ‘must provide an adequate explanation to justify treating similarly situated parties differently.’”
De Minimis
The court rejected the New York entities’ challenges to the use of netting and peak-load assumptions as part of the DFAX model, but it agreed with their complaint over the de minimis threshold, which exempts transmission zones with a distribution factor below 1% of cost responsibility.
Because distribution factors measure a zone’s use of a facility relative to its total load, the de minimis exception depends on the size of the zone, not on the zone’s share of the facility’s total flow, the court said.
A zone with load of 1,000 MW that uses 9 MW of a 30-MW facility — almost one-third of the total flow — would be exempted because the distribution factor would be only 0.9%.
“The de minimis threshold exempts zones from bearing any costs based on their load size — a quality unrelated to the burdens they impose on or the benefits they receive from any individual facility. And in so doing, it unduly discriminates against small zones, which must absorb higher cost allocations after large zones are exempted,” the court said. “Peak load sizes vary greatly across the relevant zones, which makes the de minimis exception border on absurd.”
PSE&G’s peak load is about 11,000 MW versus Hudson’s 320 MW. “So if PSE&G used 100 MW of flow across a transmission facility (yielding a distribution factor slightly under 1%), and if Hudson had 4 MW of flow across the same facility (yielding a distribution factor slightly over 1%), then PSE&G but not Hudson would be exempt from paying any of the facility’s costs, even though PSE&G derived 25 times more of the benefits,” the court said. “And because the large PSE&G would not have to pay any costs of the facility, the small Hudson would have to bear a substantially greater share of those costs.”
NJ BPU Challenge Rejected
The New Jersey BPU challenged FERC’s orders reallocating costs for the Bergen-Linden project from Con Ed, Hudson and Linden to PSE&G.
The court said FERC correctly determined that Con Ed did not have to pay project costs after the termination of the service agreements, noting that the Bergen-Linden project was planned solely by PJM.
The court said the BPU presented a “powerful argument” that Linden’s relinquishment of its firm withdrawal rights and its election of firm point-to-point service allowed it to receive the same benefits from the Bergen-Linden project without any of the costs.
But it said it lacked jurisdiction to consider it because the BPU had not first raised the issue in its rehearing requests with FERC.
The BPU also contended FERC conducted a “siloed analysis” that did not consider the “total effect” of its orders, which it said left New Jersey ratepayers with an “exceedingly disproportionate share” of the costs.
“But FERC did perform the kind of back-end analysis that the New Jersey board claims was required,” the court said. “FERC recognized that the [Bergen-Linden] project was planned by PJM, and [it] relied on PJM’s statement that the project would still be needed in New Jersey ‘even if there were no flows on the transmission facilities interconnecting New York and New Jersey.’”
Orders Vacated
The court vacated FERC’s denial of two Linden complaints and remanded them for further proceedings. It also vacated the commission’s denial of Con Ed’s complaint and remanded it for further proceedings on the de minimis issue.
It also vacated FERC’s 2020 order (ER17-950) reallocating the cost of the North Jersey projects reflecting the end of the PSEG wheel and rejecting Linden’s challenge and remanded it on both the Artificial Island and de minimis issues. (See FERC Rebuffs Challenges to PJM Tx Cost Allocation.)
“FERC did not raise a procedural bar to the New York entities’ challenges there, instead rejecting them on the merits for reasons we have found defective,” the court said. “On remand, FERC may consider in the first instance whether the challenges to PJM’s 2017 cost reallocation are procedurally barred.”
An American Council on Renewable Energy (ACORE) panel last week largely agreed that MISO’s current transmission benefits process could serve as a blueprint for the country.
Industry experts analyzed the RTO’s business case behind its recently approved long-range transmission plan (LRTP) as FERC prepares to issue a rule on regional transmission planning and cost allocation (RM21-17). (See FERC Issues 1st Proposal out of Transmission Proceeding.)
“I usually say cost allocation is the biggest barrier to long-term transmission development, and, of course, the key to cost allocation is to find transmission plans where the benefits outweigh the costs,” Grid Strategies President Rob Gramlich, said. “This is really important, to measure these benefits and get it right.”
Gramlich said during the Aug. 9 webinar that the country could use a standardized method for quantifying transmission benefits.
“There isn’t really a standard of how to do this. Even the categories themselves differ,” he said, adding it would be helpful if FERC created consensus on benefits categories and their metrics.
Gramlich said MISO has been a leader in proactive, multi-benefit planning beginning with its 2011 Multi-Value Project (MVP) portfolio — lines now delivering wind power from the Upper Midwest — and its recently approved LRTP. (See MISO Board Approves $10B in Long-range Tx Projects.)
He said beyond MISO’s recent success, there’s a widespread absence of effective transmission planning. Regions aren’t planning using scenarios or a portfolio approach, he said.
Gramlich said transmission planning has been in decline since 2013, when about 4,000 miles of 345-kV and higher lines were added.
“We did a whole lot of successful transmission planning a decade ago,” he said. “But since then, unfortunately, it’s been sort of going down to a trickle because of the lack of effective transmission planning. Hopefully, we’re in the process of reversing that.”
Gramlich called on grid operators to do “at least an initial screening” of the 12 transmission benefits FERC identified in its notice of proposed rulemaking and pursue the ones that show significant benefits.
He said MISO arrived at a set of benefits that seemed to make sense for its LRTP planning. Other regions can take a similar approach to come up with different menus of benefit categories, he said.
While the LRTP benefit-cost analysis included congestion savings, resource adequacy savings and avoided risk of load shed and transmission and generation investment, it didn’t include seven other benefits FERC suggested in the NOPR. MISO did include decarbonization as a benefit, something the commission hasn’t called for.
The NOPR asks regions to consider the transmission benefits of avoided reliability and aging infrastructure projects, production cost savings, lower transmission energy losses, reduced chances of load shed or lowered reserve margins, diminished congestion, mitigation of extreme events and system contingencies, tempering of weather and load uncertainty, capacity cost benefits from reduced peak energy losses, deferred generation investments, access to lower cost generation, increased competition and increased market liquidity.
MISO’s first LRTP portfolio is expected to deliver $37.3 billion from its defined benefits to ratepayers from 2030 to 2050. The grid operator also estimates that the plan will help facilitate the 56 GW of new renewables it anticipates adding over the next 20 years in its most conservative planning scenario.
MISO’s Jeremiah Doner | ACORE
Jeremiah Doner, MISO’s director of cost allocation and competitive transmission, said it’s “not an easy endeavor” to build a business case for a long-term transmission portfolio.
“There really isn’t a playbook to take from,” he said.
Doner said the LRTP business case has a lot of commonalities with FERC’s categories. He said planners considered how much time it would take to incorporate benefit categories versus how much value they would demonstrate. For example, Doner said the LRTP’s savings from transmission energy losses weren’t promising enough to quantify.
He said it’s important to allow grid planners flexibility in what benefits they choose to quantify. He noted that MISO used different benefit metrics between its multi-value projects and its LRTP portfolio.
ITC Holdings’ manager of federal affairs, Devin McMackin, said his company believes MISO’s business case can be held up as a model for the nation.
“The important thing is that we can now repeat this and double down on these types of regional planning efforts, especially now that we have a climate bill that has passed Congress,” he said.
McMackin said it seemed that FERC’s NOPR was “taking cues” from regional planning MISO performed under its MVP and the LRTP portfolios.
“What we don’t want to see are these 10-year lulls in between regional planning efforts because these needs are only accelerating and it’ll start to get away from us if we don’t keep at it,” he said.
It makes sense for FERC to prescribe a minimum set of benefit metrics and leave some flexibility between regions, McMackin said. MISO’s benefit metrics represent a good starting point for the commission to consider, he said, adding that having planners on the same page is crucial for interregional projects.
“If we want interregional planning to work, there has to be some level of common benefits basis,” he said, “so not only would FERC be aiding the regional planning process, but it would also set the stage for the ability to then move forward and do some interregional planning.”
Michigan Public Service Commission Chairman Dan Scripps said he considers the first set of LRTP projects as above other benefits and key to the future system’s reliability. He characterized long-range planning as a shift from “reactive, near-term” reliability planning to a “forward-looking, proactive” approach to addressing reliability.
“The challenge with the value of lost load is you sort of know the value when you don’t have it,” Scripps said. “Winter Storm Uri was very clear evidence of that, not just in the loss of life, but also in the bills that folks saw after the fact.”
Scripps said there’s a risk with undervaluing transmission reliability benefits. He said the public needs a prepared system with extreme weather becoming more common and severe.
Jennifer Easler, an attorney with the Iowa Department of Justice’s Office of the Consumer Advocate, said regional transmission planners should allow stakeholders access to modeling and planning assumptions early in the process so there’s a broad understanding of benefit analyses.
She said MISO’s set of benefits are appropriate for its backbone transmission buildout.
Gramlich said in a perfect world, all transmission benefits should be compared against all costs.
“It’s almost an obvious point … You have to consider all the benefits and all of the costs,” he said. “It’s a little weird that we’re even arguing about whether one should consider all the benefits and that we have a FERC NOPR that says, ‘Yeah, here are 12 benefits but feel free to ignore a bunch of them.’ That’s obviously inconsistent with good public policy.”
Gramlich also said it’s clear that FERC’s list is limited to its jurisdiction under the Federal Power Act and cannot include a full array of benefits like economic development or local emissions reduction.
“At this point, I like the FERC list of 12,” he said later during the discussion.
In response to a request from FERC Chairman Richard Glick and NERC CEO Jim Robb, the North American Energy Standards Board (NAESB) confirmed Thursday it will launch a forum aimed at addressing concerns raised after the winter storm of February 2021.
According to a press release from NAESB, the organization has not yet settled on a time or agenda for the forum, but an organizational meeting has been scheduled for 2-4 p.m. CT on Aug. 30 to “discuss the next steps the organization will take to host the forum.” The meeting will be held on Zoom and open to any interested parties.
Glick and Robb suggested the forum in a joint letter on July 29 addressed to NAESB COO Jonathan Booe and board Chairman Michael Desselle, citing FERC and NERC’s joint report on the storms. (See FERC, NERC Call for NAESB Forum on Gas-electric Issues.) The report called for FERC to establish “a forum in which representatives of state legislatures and/or regulators with jurisdiction over natural gas infrastructure [can] identify concrete actions” to improve reliability of the natural gas system as it relates to the bulk electric system.
The winter storms led to widespread generation outages, derates or failures to start that caused more than 23 GW of manual firm load shed mostly in Texas, the biggest firm load shed in U.S. history. According to the FERC-NERC report, natural gas facilities accounted for more than 50% of generation failures, both in terms of the number of units and their total nameplate capacity. (See FERC, NERC Release Final Texas Storm Report.)
Stakeholders in the ERO Enterprise have increasingly come to see the interdependency of the U.S. gas system and electric grid as a significant vulnerability, because of natural disasters like last year’s storms and cyber incidents like the ransomware attack on Colonial Pipeline in May 2021. (See Colonial Hack Sparks Competing Recommendations at FERC.) In their July letter, Glick and Robb said NAESB is “uniquely positioned” to organize the needed dialogue between the gas and electric industries; in their press release, NAESB’s leadership said they appreciated the confidence.
“NAESB has a long history of bringing diverse groups together to find consensus-based solutions to industry problems,” Valerie Crockett, vice chair of NAESB’s Wholesale Gas Quadrant, said in the statement. “While NAESB was not necessarily asked to develop specific standards in response to this request, it can serve an important role by recommending activities that appropriate entities within the energy markets may undertake to support grid stability.”
NAESB did announce a standards project aimed at improving gas and electric coordination in December but has not released any subsequent updates about the initiative. Booe told ERO Insider earlier this month that action had stalled after the organization was unable to “find consensus from our groups” about the appropriate direction of the project, but that Glick and Robb’s call for the forum might help reinvigorate the initiative.
The ERCOT Board of Directors could finally unveil its choice to lead the Texas grid operator in its continued recovery from last year’s winter disaster.
The Texas Public Utility Commission has posted an open meeting notice, as it is required to do whenever two or more commissioners meet together, in advance of Tuesday’s board meeting. The notice indicates the commission will “receive information, and may give information and participate in discussion … and possible action regarding ERCOT CEO selection and ERCOT CEO compensation.”
Texas Gov. Greg Abbott is said to be exerting unusual control over ERCOT. | Twitter
However, according to a well sourced article last week by The Texas Tribune, it is Texas Gov. Greg Abbott who wields the power to choose ERCOT’s next CEO. The Tribune reported that the governor, who is locked in a close re-election campaign with Beto O’Rourke and appealing to his base through a heavy reliance on Twitter, has nixed a search committee’s preferred finalist, former CAISO CEO Steve Berberich, and has unsuccessfully urged Phil Wilson, CEO of Lower Colorado River Authority, to take the position instead.
Berberich has been painted as a No. 1 draft pick because of his ISO and information technology experience. A Texan, he served as TXU Energy’s IT vice president before joining CAISO in 2005. He retired from the California grid operator in 2020 and currently lives in McKinney, Texas, according to his LinkedIn profile. (See CAISO CEO Steve Berberich Retiring.)
Those close to the search told the Tribune the only reasons they were given for Abbott’s veto is because Berberich’s last job was in California. Attendees at SPP’s Markets+ development session last week in Portland, Ore., expressed surprise when the story broke; Berberich had a reputation for speaking colorfully and directly, as he did toward the end of his tenure when he warned of California’s reliability problems.
Berberich apparently had strong support from the market and ERCOT’s board. The directors met in an urgent conference call July 29 that turned into a long executive session. They adjourned the call without voting on any matters.
If no announcement comes this week, it may have to wait until the board meets again in October. That would be perilously close to winter and its potential for more extreme weather. That is also about the time the PUC is expected to take up the second phase of its market design.
Alison Silverstein, an Austin-based energy consultant with regulatory experience at both FERC and the PUC, told RTO Insider she was “appalled” by Abbott’s move, which has not been denied. She said her criteria for picking ERCOT’s next CEO would be “someone with proven experience in running the grid.”
“I don’t care if the [next CEO] is from California or one of ours,” Silverstein said. “I want the best possible person with rock-solid reliability and policy experience and management experience, because the safety of all Texans is the most important factor. Can this person run ERCOT to move us all to a better place in terms of grid reliability?”
Beth Garza, a senior fellow with public policy research firm R Street Institute and ERCOT’s Independent Market Monitor from 2014 to 2019, pointed to ERCOT’s statutory status as the “independent organization” responsible for managing the grid.
“There’s a reason for that,” she said Friday. “Most people would say that’s independent from the market participants and the industry. The other part of that independence is you want an organization that is focused on the best and most appropriate technological ways to deal with whatever the problems are.”
And so Brad Jones, who was appointed as ERCOT’s interim CEO in the wake of the February 2021 winter storm that almost collapsed the Texas grid, is left cooling his heels. What was supposed to be a three-month temporary assignment has now turned into a 15-month gig. Jones has consistently said he doesn’t want the job on a fulltime basis; he said in April that he planned to leave ERCOT in June. (See “Jones: Will Stay as Interim CEO,” Overheard at GCPA’s 2022 Spring Conference.)
“I want to ensure they get the right person into this role,” he said during the Gulf Coast Power Association’s Spring Conference.
It is now August, and Jones is still waiting.
According to the Tribune and confirmed by ERCOT staff, the PUC, with its Abbott-appointed commissioners, reviews and approves every piece of communications before the grid operator releases it. “ERCOT does not speak for Gov. Abbott on what, if any, involvement he’s had,” has been staff’s response.
“The work of ERCOT is so important that I want its CEO and staff’s first priority to always be the integrity of the reliability of the ERCOT power system, minute to minute, every single day,” Silverstein said. “They should be able to operate our grid without having to care about the consequences of political agendas. The CEO’s first job is to make all the essential decisions to protect grid reliability … to run the organization that ensure the reliability of the grid and its resilience. If the CEO has to ask permission to take actions to protect the grid, we’ll lose the grid. We cannot have second guessing.”
Garza agreed, saying, “Politics and power system engineering may not be the best combination.”
Energy Advisory Committee OKs Report
The State Energy Plan Advisory Committee (SEPAC), referred to as a “little-known board of energy executives, oil and gas entrepreneurs and power utilities officials” by The Dallas Morning News, also raised consternation with industry observers last week as it held its second meeting.
The committee was created by legislation passed last year and charged with preparing a “comprehensive state energy plan” that evaluates barriers preventing “sound economic decisions” and the ERCOT market’s structure and pricing mechanisms. The plan, due to the state legislature Sept. 1, must also look at ways to improve the grid’s reliability, stability and affordability.
The committee comprises 12 members appointed by Abbott, Lt. Gov. Dan Patrick and House Speaker Dade Phelan. Chaired by LCRA’s Wilson, its members include NRG Energy’s Bill Barnes, Pedernales Electric Cooperative CEO Julie Caruthers Parsley and Oncor’s Daniel Hall, as well as consultant Joel Mickey and Mike Greene, retired staffers from ERCOT and Energy Future Holdings, respectively.
“Conveniently, the governor chooses Phil Wilson as the chair, because he’s got a large organization [behind him],” Garza said, noting SEPAC’s lack of resources.
The other members come from outside the electric industry, with their lack of expertise exhibited when Patrick Jenevein — with some wind development experience at a small Chinese clean energy projects company (Tang Wind Energy) but primarily focused on natural gas — suggested that coal is a renewable resource, according to energy consultant Doug Lewin.
Lewin was among public onlookers during Wednesday’s meeting, when SEPAC approved a draft of its report 7-5. At least one committee member voted against the draft because of a lack of time to review it, Lewin reported.
The report includes a recommendation that renewable resources be required to provide backup energy, despite thermal resources’ well documented contribution to the dayslong power outages after the winter storm. (See FERC, NERC Release Final Texas Storm Report.)
The report itself has not been publicly released, part of a pattern of secrecy surrounding SEPAC. Its meetings have been posted on the secretary of state’s website, which requires a sophisticated expertise with searches, but they were not livestreamed.
“I’m concerned about the legislature getting advice on something as important as electricity and natural gas policy from an organization that has met only twice and whose [members] haven’t had a significant amount of time to review the material that was developed,” Silverstein said, adding that its members were voting “blind.”
SEPAC “took a vote without the members being able to actually review the contents in detail,” she said. “So, if I were in the legislature, I would use this report, whatever it will ultimately contain, as just another piece of paper. I would not attach any significant weight to it.”
Garza was among several subject-matter experts who testified before the committee during its June meeting. She said at the time she thought it was a “check-the-box exercise” and would amount to little. However, Garza said she found the discussion to be “very valuable” and found herself wishing the PUC “would put themselves in a position to hear that kind of input and discourse.”
“There’ll be a report that goes to the legislature. I have every confidence it’s a report and will be written and given to the legislature,” she said. “What will it contain? Will the contents of that report be meaningfully developed with debate back and forth? No. They took input during one meeting and a second meeting to look at the document.
“You can’t just say, ‘I like a policy; let’s do it without doing an extraordinarily detailed analysis,’” Silverstein said. “It is my hope that the legislature will not jump too quickly to adopt any superficially appealing policy path, but rather rely on the kind of research and analysis on implications and alternatives that can truly give us reliability and affordability and resilience, rather than to catchy headlines.”
MISO and SPP said Friday they have numerous constrained flowgates that could become candidates for smaller, cross-border transmission projects.
The RTOs unveiled a list of their congested flowgates ripe for targeted market efficiency projects (TMEPs) during an Interregional Planning Stakeholder Advisory Committee (IPSAC) teleconference. It’s the first time they have searched for TMEPs. (See MISO, SPP Take on 2nd Interregional Planning Effort.)
The grid operators said that based on preliminary day-ahead market data, they have “numerous” constraints that have amassed a half million dollars or more in congestion annually.
SPP’s Neil Robertson said the frequently congested Neosho-Riverton flowgate on the Kansas-Missouri border was unsurprisingly “prominent” on the list of the most chronically congested permanent flowgates. With $71.6 million in market-to-market (M2M) charges since 2015, the flowgate is responsible for 20.9% of the $341.87 million in M2M settlements.
Neosho-Riverton’s $27 million of congestion charges the last two years is second to the Fargo-Sheyenne flowgate in North Dakota, which racked up about $36.5 million in congestion during 2020-2021.
The rest of the six most congested flowgates each accumulated anywhere from $12 million to $19 million in congestion charges during that timeframe. Robertson said staffs “commonly” found congestion in the Dakotas and along the Arkansas-Oklahoma and Kansas-Missouri borders.
Robertson said the RTOs are using their day-ahead market congestion values in their analysis because the “nuts and bolts” of their market clearing engines differ.
MISO and SPP are trying to get the most accurate congestion data, Robertson said, because congestion data determines which flowgates could use transmission improvements and how project costs are split between the RTOs.
He said the grid operators had gathered a “preliminary sampling” of congestion values that will be refined in the coming weeks. He also said staff are considering evaluating certain temporary flowgates for TMEP solutions and that some temporary flowgates could become permanent.
Robertson said the RTOs are borrowing from the MISO-PJM TMEP playbook, which has approved three small portfolios since 2017. MISO and PJM are working on another possible set of projects.
MISO and PJM TMEPs must cost less than $20 million, completely cover installed capital cost within four years of service and be in service by the third summer peak from their approval. The projects are assessed using a shorter time horizon than interregional market efficiency projects.
“We had to start somewhere, as I like to put it … moving the conversation forward,” Robertson said. He added that MISO and SPP could tweak some of the existing criteria.
He said using a $20 million cost cap, a third summer peak in-service date, and drawing on two years’ worth of historical congestion to determine project needs seems to make sense for the RTOs. The thresholds will ensure that a TMEP study doesn’t encroach on other, longer-term interregional planning on the MISO-SPP seam, he said.
Robertson said MISO and SPP have “vast” support to move ahead with the TMEP concept.
American Clean Power Association’s Daniel Hall asked the RTOs to share whether a project candidate barely misses or slightly overshoots the project criteria. He also said while ACP is a “strong supporter” of a TMEP study, he doesn’t want to see the projects become “Band-Aid solutions to more efficient and effective” projects.
Robertson said MISO and SPP are holding off on finalizing any criteria until they have a better picture of congestion data.
The RTOs don’t plan on recommending a list of TMEP projects until the end of the year. They don’t envision designing regional cost-allocation methods or filing with FERC for approval of a TMEP process until the first quarter of 2023.
MISO and SPP will hold another IPSAC teleconference Sept. 20.
With three coal plants slated for closure within the next 10 years, Arizona regulators, utilities and community members are exploring ways to repurpose the facilities, including options for clean energy generation.
Salt River Project (SRP) is launching a study to see which sustainable energy options would be viable at the site of the Coronado Generating Station, which is slated for closure by 2032. Hydrogen generation and solar with battery storage are among the technologies the study might explore.
SRP is in the process of finding an engineering contractor to help with the repurposing studies, a company representative said during an Aug. 1 Arizona Corporation Commission (ACC) workshop.
In addition, the city of St. Johns, near the Coronado facility, wants to investigate the feasibility of converting the coal plant to nuclear power generation. SRP has been working with the Gateway for Accelerated Innovation in Nuclear (GAIN) on the issue. GAIN is a U.S. Department of Energy Office of Nuclear Energy initiative to accelerate the commercialization of advanced nuclear technologies.
Asset Inventory
Amanda Ormond, co-director of the Just Energy Transition Center at Arizona State University, said during the Aug. 1 workshop that she’s hopeful ASU will receive a grant to look at repurposing the Coronado Generating Station and the Cholla Power Plant, which is scheduled to shut down in 2025. Arizona Public Service is part-owner and operator of the Cholla plant.
Ormond said the study would include an inventory of assets at the power plants, including items such as buildings, roads and water treatment systems. The condition of the assets would also be assessed.
The next step, Ormond said, would be to match the assets with types of businesses that could use them. The study would look at possibilities on a regional level, rather than one coal plant at a time. Ormond said she expects a decision on the grants next month.
The third Arizona coal-fired power plant slated for closure is the Springerville Generating Station, operated by Tucson Electric Power. TEP plans to close one unit at Springerville in 2027 and shut down the final unit in 2032.
The upcoming coal plant closures follow the shutdown in 2019 of the 2,250 MW Navajo Generating Station near Page, Ariz., which SRP operated.
Plant Closure Impacts
The ACC opened a docket in January 2021 to take a closer look at the impact of coal plant closures on surrounding communities. The Aug. 1 workshop was the second commission workshop on the topic.
The commission also held 11 town hall meetings in coal plant communities in April, May and June. In addition, a series of virtual town hall meetings took place last week. ACC staff plan to file recommendations in the matter by the end of September.
Repurposing the Arizona coal plants was also discussed during task force meetings organized by the ACC in March and April.
Ormond said during task force meetings that Arizona State University and Joseph City have been discussing potential new uses for the Cholla Power Station. In addition to renewable energy production, ideas included office space, metal and battery recycling, manufacturing, automotive salvage, or railcar and locomotive repair, according to a written summary of the meeting.
Task force participants noted that the coal plant owners will play a large role in determining the facilities’ future.
National Issue
Repurposing shuttered coal plants is an issue that’s being debated across the U.S.
Creative reuses include the conversion of the Blackhawk Generating Station in Beloit, Wis., into a student union athletics facility at Beloit College, Bloomberg reported. In other cases, retired coal plants have been turned into restaurants or offices.
Some of the facilities are being eyed for hydrogen production. In New Mexico, Escalante H2 Power (EH2) wants to convert the Escalante Generating Station, a coal-powered plant shut down in 2020, into a hydrogen production and power facility. (See Clean Hydrogen Interest Builds in New Mexico.)
The federal government has taken an interest in the future of coal plant communities. In January 2021, President Biden established through an executive order the Interagency Working Group on Coal and Power Plant Communities and Economic Revitalization.
The goal of the Interagency Working Group (IWG) is to coordinate federal aid to revitalize the economies of coal, oil and gas, and power plant communities. In an initial report, the working group identified 25 priority regions that have been hard-hit by reductions in coal production and consumption.
IWG created a clearinghouse of federal funding opportunities that may be available to energy communities.
The working group is soliciting public comments on the challenges facing energy communities and recommendations on how the federal government can help address those challenges. Comments will be accepted through Sept. 9 and may be submitted here.
The California Air Resources Board has named Steven Cliff, administrator of the National Highway Traffic Safety Administration, as CARB’s new executive officer.
Cliff will replace Richard Corey, who retired at the end of June after serving in that role since 2013. (See CARB Top Exec Corey to Retire.) Cliff will start work at CARB on Sept. 12.
CARB’s board made the appointment, which Chair Liane Randolph announced on Friday.
“He is the right choice to implement the board’s vision during this crucial decade as we move ahead with the ambitious policies and programs to tackle the state’s climate emergency and continue to prioritize equity both within CARB’s workforce and in the communities we serve,” Randolph said in a statement.
Cliff is a familiar face at the California agency. He has held a variety of positions at CARB, starting as an air pollution specialist in 2008. While serving as CARB’s deputy executive officer from 2017 to 2021, Cliff’s work included overseeing regulations for all vehicles in the state, including passenger cars and medium- and heavy-duty vehicles.
In October 2021, President Biden nominated Cliff to serve as head of the NHTSA. He was confirmed by the Senate on May 26. Before his nomination, Cliff worked at NHTSA as a senior adviser and deputy administrator, according to his LinkedIn profile.
His transportation experience also includes a stint as assistant director for sustainability at the California Department of Transportation from 2014 to 2016.
Cliff returns to CARB at a critical time. The agency this year is finalizing its climate change scoping plan, a roadmap to bring California to carbon neutrality by 2045. After CARB released a draft version of the plan in May, Gov. Gavin Newsom called on the agency to take “even bolder action” to address climate change. (See Newsom Calls for ‘Bolder’ Climate Action in Calif.)
In addition to his professional credentials, Cliff has experienced the impacts of climate change firsthand. The Napa Valley native has been spending time rebuilding his family’s property after it was ravaged by the Atlas Fire — one in a group of October 2017 wildfires that became known as the Northern California firestorm.
Cliff received a bachelor’s degree and doctorate in chemistry from the University of California, San Diego. He completed a postdoctoral fellowship in atmospheric sciences at the University of California, Davis, where he has also worked as a research professor. Cliff lives in Sacramento.
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