The 3rd U.S. Circuit Court of Appeals on Dec. 1 rejected three petitions seeking to overturn FERC’s approval of PJM’s tightened minimum offer price rule (MOPR) (21-3068, et al.).
The latest MOPR design eliminated a requirement that resources eligible for receiving any state subsidies be mitigated to their cost-based offers, a change the commission mandated in 2019. Later, PJM proposed limiting the application of the rule to resources with the “ability and incentive to exercise buyer-side market power” or when a resource receives state subsidies that are likely to be pre-empted by the Federal Power Act.
PJM submitted the tariff revisions in July 2021, and they went into effect automatically two months later after the commission deadlocked 2-2 (ER21-2582). (See P3 Seeks 3rd Circuit Review of PJM MOPR.)
In its ruling against the PJM Power Providers (P3) Group, the Electric Power Supply Association (EPSA), and the Ohio and Pennsylvania public utility commissions, the 3rd Circuit rejected arguments that FERC acted arbitrarily and capriciously by allowing the rule to go into effect, establishing for the first time since the enactment of the America’s Water Infrastructure Act of 2018 the courts’ authority to review the commission’s “action by inaction.”
The law was mostly focused on improving drinking water quality and financing improvements to flood-control infrastructure, but it also contained provisions pertaining to when FERC deadlocks. Previously, tariff changes that went into effect by operation of law were not reviewable by the courts because there was no action by the commission.
The law added Section 205g to the FPA to allow for such review. It also required that each FERC commissioner submit a written statement into the record explaining their vote.
The petitioners argued that in the absence of an order supported by the majority of the commission, there are “no institutional findings of fact or conclusions of law” that the courts can consider.
The court rejected that argument, saying the new section “unambiguously instructed that we construe FERC’s inaction as an affirmative order” for the purposes of review.
P3 and EPSA also argued that there was no evidence of FERC’s decision for the court to review, as required elsewhere in the FPA.
But the court said that in granting it jurisdiction over deadlocked orders, Congress intended for the commissioners’ statements to serve as evidence. Without such a record, the court wrote, it would be required to consider any orders by operation of law to be arbitrary and capricious, as it would have no way of evaluating how the commission arrived at its answer.
“The statements of the deadlocked commissioners do more than record each person’s individual rationale for affirming or rejecting the rate filing,” the court wrote. “Collectively, they illuminate the agency’s reasons for inaction, which Congress has instructed us to construe as an affirmative order.
“Because FERC must accept a Section 205 rate filing absent ‘a finding that the existing rate was unlawful,’ our thorough consideration of the entire record must ensure that the commissioners who did not find the 2021 MOPR unlawful engaged in ‘decision-making [that was] reasoned, principled and based upon the record.’”
In a joint statement after the deadlock in 2021, former FERC Chair Richard Glick and Commissioner Allison Clements argued that the previous MOPR resulted in the reliability contribution of resources receiving state subsidies potentially not being recognized, inflating the amount consumers paid by as much as $3.4 billion. Commissioners James Danly and Mark Christie opposed PJM’s proposal, arguing that it would ignore the impact of subsidies on wholesale markets and produce uncompetitive outcomes. (See ‘Good Riddance’ to Old PJM MOPR, Glick Says.)
Environmental groups applauded the court’s decision, saying the previous MOPR that FERC required in 2019 forced renewable resources to enter artificially inflated capacity offers and prevented them from being competitive with fossil-fired resources.
“The rule upheld today eliminates the anticompetitive treatment of resources supported by state and local policies in PJM,” said Caroline Reiser, senior staff attorney for the NRDC, in a statement. “With this rule in place, consumers will see the full benefits of state investments in clean power. Fossil fuel interests were trying to use the courts to do something they could not do in the market: slow the clean energy transition.”
It’s been a year since the Southeast Energy Exchange Market (SEEM) began pairing offers and bids, with detractors certain as ever the market is dysfunctional and the utilities involved insisting they will push through the launch difficulties to long-term success.
SEEM began operations in early November 2022, a year after its foundational agreement passed a deadlocked FERC. (See SEEM to Move Ahead, Minus FERC Approval.) The market’s founding members, including Duke Energy, Southern Co., the Tennessee Valley Authority and Dominion Energy, promised that the expansion of bilateral trading in 11 Southeastern states — now 12 after the addition of utilities in Florida — would reduce trading friction while promoting the integration of renewable resources.
But Southern Environmental Law Center (SELC) Senior Attorney Nick Guidi thinks SEEM is a far cry from what Southern Co., TVA, Duke, Dominion and other utilities promised when designing the marketplace.
“We have one year’s worth of operations to reflect on and assess, and based on that, I think we can say SEEM is failing. The information that we do have shows SEEM is not performing as the utilities expected,” Guidi said in an interview with RTO Insider.
Before the market went live, SEEM participants hired consultants to prepare an analysis showing the market could deliver anywhere from $37 million to $46 million worth of benefits in its first year. But the SELC estimates SEEM has yielded just $3.3 million in savings over its first year, barely covering operating costs. The figure was derived from SELC analysts’ interpretation of the limited data that SEEM publishes on its website under the “Public Data” tab (which requires user registration to view).
SEEM also estimated it would have an average hourly trade volume of 1,323 MWh; however, in the first year of operations, it averaged about 72 MWh in hourly activity.
“We’re looking at about a tenth of what was promised one year in,” Guidi said. “The benefits are marginal, and we’re not seeing any uptick in renewable energy through this.”
Erin Culbert, a spokesperson for Duke, acknowledged to RTO Insider that despite “a lot of activity of bids and offers … we have seen a lower number of successful trades than we would like.” However, she said the market has witnessed a growth in the number of successful matches month to month, particularly after four utilities based in Florida began participating in June.
According to SEEM’s most recent monthly audit report, prepared by Potomac Economics, the market had 24 members in October. Participants traded 76,000 MWh of energy that month, up from 66,000 MWh in September and above the market-to-date monthly average of 52,000 MWh.
Culbert said more than 100,000 transactions have been performed in the first year of operations, representing more than 2.5 TW of 15-minute power.
SEEM’s sponsors are working to increase the number of successful trades, she continued, through means such as Duke’s development of automated tools to improve matches. Market participants, as well as SEEM’s independent auditor, also have suggested making additional training available next year to help participants craft bids and offers “that are a little bit closer to their actual cost.”
“At this point in time, in some cases the bids and offers are too far apart to make a successful match,” Culbert said. “So we would love to be able to continue to share best practices, maybe look and explore to see if others on the platform want to consider having some more automation on their sides to make it very simple and easy to identify the right bids and offers that have the highest success rate for a match.”
TVA and Southern deferred to Duke’s comments on the value of the exchange.
Volumes of matched bids and offers on SEEM for October | Potomac Economics
Expected Benefits and Regulatory Limbo
Since before the market’s launch, SEEM’s critics, which include the SELC, the Carolinas Clean Energy Business Association (CCEBA), the Sierra Club and the Southern Alliance for Clean Energy, have argued it would entrench the power of monopoly utilities while providing limited benefits to customers compared to alternatives. (See SEEM Critics Repeat Call for Technical Conference.) The performance of SEEM over the past year hasn’t done much to change their minds.
“I don’t know that we should call SEEM a failure yet, but it certainly needs dramatic reform if it’s going to be successful,” CCEBA Executive Director Chris Carmody said in an interview.
Carmody said that even the $40 million in savings SEEM initially estimated was a low bar to accomplish. He pointed out that Vibrant Clean Energy’s research showed that establishing a competitive wholesale electricity market in the Southeast could save $384 billion by 2040.
But Southeastern utilities avoid organized markets “like the plague,” he said.
Guidi said SEEM has a structural problem and lacks the attributes necessary to improve meaningfully. The market should develop an open-access transmission tariff and extend participation to entities outside of its footprint. Currently, he said “only a small subset of entities in the region can participate,” with approximately 65 entities that participated in bilateral trading before SEEM’s establishment now ineligible to participate because of their location outside the footprint.
The D.C. Circuit Court of Appeals this summer vacated FERC’s denial of requests to rehear its approval of SEEM, largely on procedural grounds. The court found the commission inappropriately denied requests for rehearing as filed late because it failed to take into account two federal holidays when determining the deadline. It remanded the rehearing requests back to the commission. (See DC Circuit Sends SEEM Back to FERC.)
While it did not rule on the merits of SEEM’s tariff, the D.C. Circuit did agree partially with petitioners’ requests for rehearing of individual market members’ revisions to their tariffs implementing the non-firm energy exchange transmission service used for SEEM transactions, which the FERC majority had approved. These also were remanded back to the commission, with a directive to better explain its reasoning.
“There’s not a broadly applicable SEEM tariff,” Guidi argued. “We need some transparency. There is very little to go on, and what’s out there, is a black box.”
Guidi said outside parties can’t access pricing data or know who is transacting with whom. “There’s not much for us to assess.”
Carmody advised FERC and SEEM participants to closely examine the D.C. Circuit’s ruling. If FERC and the utilities take the concerns to heart, Carmody said he thinks SEEM’s design will resemble an energy imbalance market.
From SEEM’s perspective, Duke’s Culbert said, FERC had already decided that it was “not unfair or discriminatory,” and the D.C. Circuit’s decision amounts to a request for the commission “to justify its decision-making.” She said trades are continuing on the platform under the current filed tariffs, and the focus for now is on continuing to “optimize the performance of the market.”
Problematic Governance?
Carmody agreed that parties other than utilities should be involved in SEEM governance. He said SEEM appears to have been set up to prevent competition from independent, clean sources of energy, as well as grant Southern Co. the opportunity to sell its output more easily.
“It was never really explained to us how it was going to promote renewable energy other than it would reduce solar curtailment,” Carmody said of SEEM.
Guidi said SEEM’s governance design is problematic, where member utilities can choose who they transact with and exert complete control over governance, operations and market rules.
“Independent entities have no role in SEEM governance, which raises concerns that they could be systematically excluded,” he said.
To date, no independent power producers have engaged in SEEM trading.
Guidi said the market needs a more ambitious design that emulates the Western Energy Imbalance Market with a real-time dispatch component. He blamed the slow pace of trading on the fact that SEEM completes transactions only if there’s enough of an overlap between bid and offers.
“Competitively priced offers give generation owners no guarantee that they’ll be dispatched, unlike in standard organized wholesale markets. This uncertainty would likely dissuade IPPs from participating. It also means the market is not competitive,” he said.
Culbert pushed back on these complaints about the market’s design, saying SEEM has “a very broad net of folks who can qualify to participate,” including utilities of all sizes.
She emphasized IPPs that meet the minimum qualifications are welcome to join and “entities with generation or load that can participate in other kinds of wholesale bilateral markets also can participate in SEEM … and certainly any [entities] who would be interested that are in the same footprint would be welcome to reach out for more details.”
Critics Recommend EIM Structure
Guidi said he believes that SEEM was formed in response to calls for broader market reform to bring lower energy prices and more customer choice to the South. He suggested bringing IPPs to the table would have a disciplining effect on prices and utility behavior and “better align electricity service with customer expectations and desire for cheaper prices and cleaner energy.”
“You’re looking at cheaper prices; you’re looking at more solar energy, which is exactly what people are looking for,” he said.
Carmody said SEEM lacks the transparency and the regulatory involvement of the WEIM.
“Everyone who has a computer has a transparent view into how the Western EIM is functioning,” Carmody said. He said even though an energy imbalance market is voluntary, it still would produce significant savings, though not as much as having an RTO setup.
“It seems to me that if SEEM were improved, it would be a happy medium between utilities maintaining control but also saving ratepayers a lot of money,” he said. “I really don’t think it’s rocket science to do that.”
Carmody said ultimately, SEEM’s simplest fix would be to allow more parties to participate. He agreed that including IPPs and large customers would help the market take on some of the best characteristics of an EIM.
Culbert suggested that SEEM “shares some of the same principles as an EIM, such as … assisting with imbalances and reducing energy costs.” However, she said the goal of SEEM is to be less complex, costly and time-intensive than an EIM. While the team always is looking for improvements, she said they would need to perform cost-benefit analyses to see whether adding “additional levels of complexity and cost” would bring enough value to customers.
Reliability Concerns
Finally, Guidi said reliability under SEEM is a point of concern, exemplified by the market’s futility during last December’s widespread winter storm, during which TVA and Duke were forced to order rolling blackouts.
“SEEM just went dark during Winter Storm Elliott. There were no trades for that three-day window. You want a centralized entity that has situational awareness at their disposal,” Guidi said.
Culbert observed that “energy is a seasonal product,” and that SEEM has weathered only a single example of each season in its operations so far. She said the sponsors are optimistic additional experience will enable designers to improve performance.
“We will continue to be able to gather new learnings as we go out through subsequent years — the operational team is really still considering this part of launch — to be able to craft the kind of training and the additional best practices that will keep adding value,” she said.
Guidi said he does see value in SEEM because it brought together nearly every load-serving entity in the Southeast.
“That’s a lot of different perspectives and different interests. So, that’s the hard part,” he said.
With significant structural changes, he said SEEM could become integral to the Southeast’s electricity supply.
“I think it’s worth salvaging. I think with some pretty substantial tweaks it can be a positive, but it’s not there yet,” he said.
Texas regulators last week set aside further discussion and consideration of an ERCOT protocol change that one commissioner said was “totally discriminatory” to energy storage resources (ESRs).
The nodal protocol revision request (NPRR1186), approved by stakeholders and the ERCOT board, sets a one-hour state of charge (SOC) for energy storage resources participating in two ancillary services (ERCOT contingency reserve service and non-spinning reserve). It also includes penalties of up to $25,000 per violation.
Calling the rule change a “proposed solution in search of a problem,” Public Utility Commissioner Jimmy Glotfelty said in a memo that NPRR1186 “sets operational limits and potential compliance fines upon storage resources even as those resources are making outsized contributions to ERCOT reliability.”
“There have been no reliability problems from batteries, and there’s been no evidence provided by ERCOT that this has been a problem,” Glotfelty said during the PUC’s open meeting Nov. 30. “This the most flexible resource that we have on our system today, and one that will likely get us through the cold winter, which we’re fearful about.”
He said that because ERCOT hasn’t adopted similar protocols regarding the real-time state-of-fuel availability for coal or gas plants, “it would be discriminatory to adopt burdensome operational requirements on storage devices when no such requirements are placed upon thermal plants.”
“We should be able to understand the benefits of these flexible resources without having penalty structures that are disproportionately challenging to that resource,” Glotfelty said.
ESRs proved invaluable Sept. 6, when ERCOT entered emergency operations for the first time since the disastrous 2021 winter storm. Storage contributed a record 2.17 GW of energy during the event. (See ERCOT Voltage Drop Leads to EEA Level 2.)
“We’re also getting tremendous value from storage facilities at a time when we have really no other dispatchable generation resources coming onto the system,” Commissioner Lori Cobos said. She noted ERCOT is expecting about 1 GW of gas generation over the next few years, but about 8 GW of ESRs.
Commissioner Lori Cobos | Admin Monitor
ERCOT’s vice president of system operations, Dan Woodfin, told the PUC the grid operator is trying to clarify rules to ensure it has enough reserves “to manage that system that’s much more uncertain than what it’s historically been.”
The change represents a compromise in that it reduced the original SOC requirement from two hours to one. That has done little to assuage storage developers who say the revision would chill the resource’s growth.
“ERCOT has not provided any evidence to show that the additional discriminatory restrictions and penalties on ESRs are founded upon a substantial and reasonable ground of distinction between ESRs and other resource types,” Eolian said in a pre-meeting filing (54445).
The PUC will resume discussion on NPRR1186 during its next regularly scheduled open meeting Dec. 14. It is expected to then approve, reject or remand back to ERCOT the change.
The commission did approve NPRR1184 and a system change request (SCR824). The NPRR clarifies ERCOT’s management of the interest it receives and is owed to counterparties for posted cash collateral and requires staff to credit counterparty collateral accounts for interest every month. The SCR increases the attachment file size and quantities allowed within the resource integration and ongoing operations system.
PUC Recognizes Jones, Bivens
The commissioners opened the meeting with words of praise for Brad Jones, the former ERCOT interim CEO who passed away Nov. 8.
Jones, who previously served as ERCOT’s COO, came out of retirement following the disastrous 2021 winter storm and helped the grid operator pick up the pieces after it nearly collapsed during the event. He is widely credited with restoring confidence in the ISO and its ability to manage the grid. (See Brad Jones, Former ERCOT, NYISO CEO, Dies at 60.)
“Brad did a great service to the state under extraordinary circumstances. He came back in from the sidelines, brought the organization together, helped us pick ourselves up and make things better,” Commissioner Will McAdams said. “Brad’s in a better place. He will be missed.”
“We’re forever grateful for his selflessness and tireless leadership at ERCOT,” interim PUC Chair Kathleen Jackson said. “Brad took on an incredibly difficult task with great enthusiasm and urgency. He immediately rolled up his sleeves working to strengthen the Texas grid, [reestablish] confidence in ERCOT and speak to Texans frankly and honestly about our state’s power needs.”
Glotfelty said there was “zero choice” other than Jones to step in at ERCOT following the storm. He also praised Jones’ work during the state’s deregulation efforts in the late 1990s.
“There were few that could bridge the divide between technical engineering and policy and legislative language. [Jones] could and he could do it fluently and he could do it with ease,” Glotfelty said. “Clearly, he’s done a great service, and he will be missed by, I know, everybody here in this commission and ERCOT.”
“He has been a tremendous contributor to our industry for many years. His charisma, his intellect and humor will always be missed,” Cobos said, recalling the time she compared Jones’ rugged good looks to Texas actor Matthew McConaughey.
The commissioners also recognized Carrie Bivens, who recently stepped down after 3½ years as ERCOT’s Independent Market Monitor, and her ability to raise issues few others would. (See Bivens Resigns as ERCOT’s Market Monitor.)
“This is a tough role that has tough responsibilities right now, but it’s very important. It’s crucial,” McAdams said. “[Bivens] embraced that, that mantra of independence, and did so by maintaining credibility and enhancing it with key policymakers, and that’s something that is invaluable right now. It was more than just a contract. It was service, as well.”
“Carrie was not afraid to give her points, although they weren’t always in line with everybody else’s in this dynamic system that we have. She was bold enough to step out there,” Glotfelty said.
“She exemplified a very strong will to stand behind her positions, and whether we agreed or not with all Carrie’s positions, she made her independent voice heard,” Cobos said. “It’s important that you all hear perspectives, even if you don’t agree with them, and that’s what the IMM is there for.”
Glotfelty Named to NARUC Team
Glotfelty was one of six state regulators named Nov. 22 to a National Association of Regulatory Utility Commissioners (NARUC) working group that will “zero in” on one of the grid’s biggest reliability risks: the “misalignment of the gas and electric power systems.”
The Gas-Electric Alignment for Reliability (GEAR), composed of regulators and industry officials, will conduct a 15-month effort to develop solutions that “better align the gas and electric industries to maintain and improve the reliability of both energy systems.” The lack of such coordination between the two industries has been singled out as one of the primary reasons for load shed events during the 2020-21 and 2022-23 winters.
Glotfelty is joined by Georgia’s Tricia Pridemore, New Hampshire’s Carleton Simpson, Michigan’s Daniel Scripps, Arizona’s Lea Márquez Peterson and Minnesota’s Katie Sieben. Pridemore and Simpson will serve as GEAR’s chair and vice chair, respectively.
Officials from gas and electric utilities and operators will be added to the group later.
Glotfelty also chairs the Texas Advanced Nuclear Reactor Working Group, which was created by Gov. Greg Abbott (R) in August to help position the state as the “national leader on advanced nuclear energy” (55421). (See Texas Seeking Lead Role in Nuclear SMRs.)
The group will next meet Dec. 5 in the PUC hearing room. David Wright, a Nuclear Regulatory Commission commissioner, will discuss regulatory and licensing procedures with the group.
University of Texas at Austin associate mechanical engineering professor Derek Haas, Zachry Sustainability Solutions’ Mike Kotara and Natura’s Doug Robison share the group’s leadership responsibilities.
Legislation Becomes Rules
The PUC approved a change to ERCOT’s emergency pricing program (EPP), reducing the amount of time the high system-wind offer cap (HCAP) remains at $5,000/MWh (54585).
Wholesale prices will be reduced to a $2,000/MWh emergency offer cap should they hit the $5,000/MWh HCAP threshold for 12 hours within a rolling 24-hour period. The $2,000 cap will remain in effect until 24 hours after the EPP is activated, or, if ERCOT is in emergency operations while the EPP is active, 24 hours after the grid operator exits emergency operations.
Generators are eligible to be reimbursed for any marginal costs they incur above the $2,000 offer cap while the EPP is active. To recover marginal costs above the HCAP, generators must submit to ERCOT additional attestations and information justifying any exceedances. Cobos added language to the rule that denies reimbursement to resource entities that fail to provide the necessary information to ERCOT.
ERCOT must notify market participants when the EPP is activated and when it ends.
“This puts iron in the glove of ERCOT to gather this information,” McAdams said. “It reassures the system that somebody is going to be checking to see what exactly is going on in the event of an emergency. It’s just one more measure that allows us to gauge the overall impact to the system and the root causes.”
The change is a result of 2021’s Senate Bill 3 and is designed to limit consumer exposure to high prices during emergency events.
The commission adopted a rule stemming from this year’s legislative session that creates a temporary solar-only renewable energy credit (REC) trading program. The program replaces the PUC’s renewable portfolio standard that is being phased out and will terminate on Sept. 1, 2025. ERCOT will continue to maintain an accreditation and banking system to award and track voluntary RECs generated by eligible facilities, as required by House Bill 1500 (55323).
The PUC also approved a proposal for publication that establishes an allowance for a transmission service provider’s (TSP) interconnection costs for connect resources at transmission voltage to ERCOT’s system (55566).
Renewable interests said the allowance, applied equally across all TSPs, would encourage continued interconnections that keep pace with load growth. Glotfelty agreed, calling the policy non-discriminatory while allowing that it might affect renewable resources more than others.
“This will force some financial discipline on siting for renewables and other facilities,” he said. “If it moves them closer to interconnecting facilities, then they’re going to be OK. These numbers will allow them to interconnect if they move far away, per their decision. They may have to pay more, but it’s all laid out in these rules.”
Foundation Set for $10B Loan Program
The commission approved several proposals for publication that will lay the foundation for the Texas Energy Fund Program, beginning with giving PUC Executive Director Thomas Gleeson permission to solicit and hire a contractor to manage the fund (55562).
The PUC issued a request for proposal for the fund’s manager in October. It hopes to have the contractor on board by the second quarter of 2024.
The TEF fund will provide $7.2 billion in low-interest loans and is intended to incent the development of up to 10 GW of natural gas plants. Some $5 billion will be set aside for 20-year, 3% interest loans to build new generation with at least 100 MW of fully dispatchable capacity. Power plants that come online before June 2029 are eligible for bonus payments.
Another $2.8 billion will be dedicated to grants for infrastructure improvements in non-ERCOT regions and to strengthen resiliency by setting up microgrids at hospitals, fire stations and other critical facilities.
Other proposed rules for publication include:
Procedures for loan applications in ERCOT, evaluation criteria, repayment terms and the performance standard a generator must meet to obtain the loan (55826).
Procedures to apply for completion bonus grant awards, terms for requesting the annual grant payment and performance standards necessary to obtain a completion bonus grant payment (55812).
The new framework for the New Jersey Board of Public Utilities’ dual-use solar pilot program drew support at a public hearing Nov. 30 from farming representatives and developers, who nevertheless urged the state to move more quickly and boldly so struggling farmers would benefit from the program sooner.
Some of the more than 20 speakers at the two-hour hearing held by the BPU to solicit public input into the plan said the program could provide a much-needed revenue flow for the state’s farms, many of which barely get by amid rising costs and as a result allocate land solely for solar without a farming component.
“This is critical that we get this going, because we are losing farmland left and right with a lot of the solar projects that have already been implemented,” said Teri Rhodes, a sheep farmer in Warren County who said she is “solar grazing approximately 1,000 head of sheep up and down the eastern seaboard.” She urged the BPU to make the program as simple as possible in order to make it accessible to as many farmers as possible.
Other speakers questioned whether the state’s community solar program could be part of the dual-use program, the BPU could increase the solar capacity that it planned to award, and the program could prioritize the most commonly grown crops in New Jersey so they get the most support.
Lyle Rawlings, co-founder of the Mid-Atlantic Solar Energy Industries Association (MSEIA) and a solar developer, said the BPU should simplify the proposal requirements for farmers wherever possible because otherwise it could discourage smaller family farms from participating in the program.
“An agro-voltaic project is a marriage typically of a solar company and a farmer or a farming family,” he said. “The solar guys are used to handling the red tape and the complexity of the process of getting approval and have the expertise in designing the solar to work with an agricultural program. The farmers generally are not. But they’re going to have to be an integral part of putting a proposal together, because they have the expertise in farming.”
Public comment on the straw proposal will be accepted until 5 p.m. on Dec. 13, and the BPU expects to vote on final program details in 2024.
Promising Research
The Legislature mandated the program’s creation in the Dual-Use Solar Energy Act, which was enacted in July 2021 and required that the BPU create a dual-use solar — also known as agrivoltatics — program within six months. The BPU’s resulting program seeks to install 200 MW of generating capacity in the first three years and could be extended by 50 MW a year. Individual projects in the pilot can be no more than 10 MW in size. (See New Jersey Plans Dual-Use Solar Pilot Launch for mid-2024.)
Once the pilot is complete, researchers will analyze data collected on issues such as the crops cultivated, crop performance, solar array performance and the environmental impact on soil, biological diversity, wildlife and other factors. Then the BPU will develop a permanent program.
The pilot proposal comes as the New Jersey Agricultural Experiment Station and Rutgers University are midway through a $2 million state-funded study looking into whether crops and cows can thrive next to bifacial vertical and rotating solar panels (See NJ’s $2M Agrivoltaics Study Advances.)
“This is an emerging technology, but the research on it so far is promising,” Ethan Schoolman, an associate professor in the Department of Human Ecology at Rutgers University, said at the hearing.
“It suggests that when you combine the yield in crops and energy, the overall revenue for the farm can be equal or greater to what it would be for just growing crops,” he said. “And we hope the research that is conducted through the pilot program will help us to better understand how strong and under what conditions we can encourage productive agriculture under dual-use solar.”
Ethan Winter, national smart solar director for the American Farmland Trust, which works to save farmland, said the program could be an important one for New Jersey farmers. The trust estimates the state could lose 16% of its farmland in the next 15 to 20 years, “and that’s the highest percentage of any state in the country,” he said.
“We’d be especially interested in seeing the incentives for the pilot program prioritize vegetable, melon, fruit, nursery flora-culture and strawberry operations,” he added, saying that those account for “almost 80% of the total value of New Jersey crops.”
Rawlings said he sees a conflict in two elements of the program. On one hand, he noted, program rules do not allow dual-use proposals on “prime agricultural soils and soils of statewide importance.” But the program also is seeking to work out “how do we optimize the production of crops,” he said, suggesting the project allow prime soil to be used.
“If you have to do this in poor soil, it hampers the goal of doing real agricultural production,” he said.
Increased MW Allocation Urged
Several speakers questioned the proposal’s requirement for a “control” area in the pilot. It requires that each pilot project create a similar area to the one with the solar panels that conducts the same farming functions but does not include the solar panels. That way, the BPU argues, the data collected from the two land plots could be compared, demonstrating the impact farming beneath the panels.
But some farmers and developers said setting aside a significant piece of land for a control area could be too burdensome for some farmers and would dissuade some from taking part.
Ed Wengryn, research associate for the New Jersey Farm Bureau, said the agency had concerns about the proposal if it required the control and project use the same sized piece of land.
“As long as there’s some flexibility in the research size thing, I think we are more comfortable with the proposal,” he said.
Lucy Bullock-Sieger, vice president of strategy for Lightstar Renewables, a Boston-based community solar developer, said when the company analyzed all their projects under the requirement that the control area and the project use equally sized pieces of land “it killed all of [their] projects,” and made them unfeasible.
She also urged the BPU to increase the “megawatt allotments” in the proposal. Given the amount of time and effort needed to conduct a project, with permitting alone taking more than two years, the company says the award size in the projects “aren’t sufficient, given the lengthy timelines for the development of these kinds of projects.”
MISO has chosen Ameren Transmission Company of Illinois and Dairyland Power Cooperative to build the third and fourth competitive transmission projects emerging from its long-range transmission plan (LRTP).
Ameren will be responsible for the estimated $23 million, 345-kV line segment from the Iowa-Illinois border to the Ipava substation in Illinois. Dairyland will handle construction on the $12 million, 345-kV Deadend-to-Tremval project in Wisconsin.
In both cases, the selected developers were the only ones to submit a complete proposal to MISO. Both projects are expected to be in service by June 1, 2028.
MISO said it plans to collaborate with both developers to “successfully execute project[s] that will benefit MISO’s stakeholders.”
Before the pair of announcements last week, MISO already had two competitive developer selections under its belt this year.
The grid operator in May selected LS Power’s Republic Transmission to build the $77 million, 345-kV Hiple line at the Indiana-Michigan border. The line is MISO’s first competitive project surfacing from the LRTP. (See MISO Picks Republic Transmission for 1st LRTP Competitive Project.)
The grid operator is managing another active selection. Proposals were due in mid-November on the $556 million, 345-kV Denny-to-Zachary-to-Thomas Hill project, part of which will link up with the Fairport-Denny project. (See MISO Begins LRTP’s 2nd RFP Process.)
MISO’s developer announcement on the Deadend-to-Tremval project comes as the Wisconsin State Assembly and Senate decided last month not to act on a bill that would have installed a right of first refusal in the state for incumbent utilities to build transmission lines.
MISO’s Independent Market Monitor is condemning the modeling software MISO uses to plan its second long-range transmission portfolio.
MISO held another long-range transmission planning (LRTP) workshop Dec. 1, during which it rehashed its analyses pointing to a need for more backbone transmission. Meanwhile, IMM David Patton criticized the resource expansion tool MISO uses to plan transmission as unsophisticated and not up to the job of helping develop a collection of multibillion-dollar transmission lines.
Patton said MISO’s modeling software continues to decide to hypothetically “build an enormous amount of generation that goes beyond states’ plans,” distorting the amount of new transmission facilities needed in the future.
He said MISO’s capacity expansion tool used in modeling, the Electric Generation Expansion Analysis System (EGEAS), might not be the best fit to plan LRTP portfolios. Patton said EGEAS prioritizes economics above all, choosing to add intermittent renewable energy and ignore the reliability benefits and attractive higher capacity accreditations of battery storage and hybrid resources.
Patton said MISO should test transmission projects under different sensitivity cases before moving ahead with recommendations.
“The LRTP is not a generation expansion plan. It’s a transmission expansion plan,” WEC Energy Group’s Chris Plante said, requesting that MISO run a sensitivity that doesn’t use EGEAS’s resource expansion predictions.
Minnesota Public Utilities Commission staff member Hwikwon Ham thanked MISO for not trying to assume the role of resource planner and not second-guessing utilities’ and states’ resource planning and decarbonization goals.
“When a utility makes those announcements, they’re not making those announcements for fun,” Ham said, adding that intensive analysis goes into resource plans.
MISO Vice President of System Planning Aubrey Johnson said MISO continues to hold discussions with the Independent Market Monitor about his vision of resource expansion in MISO.
“I think we have some different views about EGEAS and modeling tools,” Johnson said.
Johnson said MISO will strive to build a portfolio of the least-cost solutions that work under a variety of scenarios, including a smaller-sized resource expansion.
Last month, MISO said it found significant overloads, voltage violations and congestion on the system absent a second LRTP portfolio when it applied its envisioned 2042 resource mix in studies. Those conclusions stemmed from MISO’s initial economic and reliability analyses under its second LRTP portfolio. (See MISO Says Overloads and Congestion Loom Without 2nd Long-range Tx Portfolio.)
MISO’s reveal of which lines it may pursue is pending. Results from the economic and reliability analyses will set the stage for which lines MISO will recommend.
MISO will host additional LRTP workshops Jan. 26 and March 15. It will open an LRTP submission window for stakeholders to suggest project needs in late January.
Executive Director of Transmission Planning Laura Rauch said the grid operator is reassessing its goal to finalize the second LRTP portfolio for approval in the first half of 2024. Rauch said if it appears MISO’s recommended portfolio needs more “robustness testing,” MISO will take time to conduct more analyses.
A recently retired Washington State Department of Transportation (WSDOT) economist has filed a claim against the state alleging he was ordered not to include cap-and-trade costs in an early 2023 revenue forecast, leading to him to leave his position with the agency.
But Washington officials have quickly contested the allegations in the complaint, saying the staffer had only a limited role in developing the forecasts.
Represented by the Citizen Action Defense Fund (CADF), Scott Smith filed a claim Nov. 30 against the Transportation Department, the state’s Office of Financial Management (OFM) and the governor’s office seeking $750,000 in lost income because he felt pressured to leave the agency before he was ready to retire. A claim must be filed 60 days prior to the filing of a lawsuit seeking damages from the state. CADF is a conservative organization that opposes Washington’s cap-and-trade program.
CADF in January filed a lawsuit in Thurston County Superior Court arguing the Washington Legislature violated the state constitution by cramming multiple subjects into its 2022 transportation bill, including tackling the nuts and bolts of the cap-and-trade program. The judge in that case rejected the suit and CADF is appealing the ruling to the state Supreme Court. (See Wash. Judge Rejects Cap-and-trade Lawsuit.)
In Thursday’s complaint, CADF said Smith worked as WSDOT’s gasoline tax revenue and price forecaster for at least five years, following decades in a similar role with the New Mexico government.
The complaint alleges that when Smith prepared his gas revenue and price forecasts at the beginning of 2023 for WSDOT’s revenue forecast council, he calculated that the cap-and-trade program — which went into effect on Jan. 1, 2023 — would have significant effects on gas prices and gas tax revenue. The complaint alleges that WSDOT and OFM told him to remove those calculations from his forecast.
“He was approached by a supervisor and told not to include what the impacts of cap-and trade will be. … They were asking him to lie, and he wouldn’t do that,” Jackson Maynard, CADF’s executive director, said in an interview.
Maynard and the complaint contend that Smith was told for the first time that he would need OFM approval on future calculations, that he was denied a promotion and that he was denied leave to see his sick mother — alleging retaliation. Smith recently retired because of what he perceived to be hostilities toward him, Maynard said.
“It’s very disturbing to hear that executive agencies under the governor’s oversight are pushing staff to misrepresent facts and figures,” state Senate Minority Leader John Braun (R) said in a press release. “This is especially upsetting if it was done to hide the full impact of the governor’s [cap-and-trade program] and manipulate the people of Washington into accepting the spike in gas prices without knowing the true cause. The projections by the state employee who is at the center of this lawsuit have been proven to be correct — not because oil companies or gas station owners got greedy, but because the state of Washington did.”
‘Complex and Highly Variable’
The political controversy around the cap-and-trade program ramped up in June when Washington posted the highest gasoline prices in the nation. Republicans have seized on the development as a major political issue, while Democrats have defended the program.
Gov. Jay Inslee (D) is taking political heat because he said the cap-and-invest program would add “a few pennies” per gallon to gasoline prices when the Legislature approved the program in 2021 along party lines. Various analyses have shown numerous factors beyond the program are contributing to Washington’s high gas prices.
The program is on track to raise close to $2 billion in 2023, with most of the money going to mitigate the effects of climate change.
Inslee’s office first became aware of Smith’s complaint on Nov. 30, Inslee spokesperson Mike Faulk said in an email to NetZero Insider. The governor’s office receives its gasoline price and revenue information from the state’s Ecology Department and not from WSDOT, Faulk said.
“The Washington Legislature directed the Washington Department of Ecology to develop and implement the cap-and-invest program — not the Department of Transportation,” Ecology Department spokesperson Andrew Wineke said in an email. “Ecology used its own economists to conduct the regulatory analysis for the cap-and-invest program, with support from a respected independent economics firm. No one from the Department of Transportation provided input on that analysis.”
OFM spokesperson Hayden Mackley added that the transportation revenue forecasts are important in developing the state’s budget.
“It’s important that this complex work is completed by professional forecasters. We rely on staff in other agencies who have this expertise to fill this role.” Mackley said.
WSDOT spokesperson Kris Abrudan told NetZero Insider: “Transportation revenue forecasts are complex and highly variable. … Data integrity, transparency and consistency are integral to this process and any changes to that model to include incorporating [the cap-and-trade program] would be a much broader determination than any one employee or agency.”
In the evening on Dec.1, Faulk sent out an email to several news organizations, including NetZero Insider, saying the appropriate OFM official does not recall discussing this matter with Smith and does not recall declaring that Smith’s work needed to be reviewed by OFM.
The email also said:
The Legislature eliminated Smith’s position last session, with his functions transferred to the state’s Economic Revenue Forecast Council. Therefore, his position was not eliminated by WSDOT.
WSDOT was considering Smith’s request to be able to work remotely, but he did not complete the process for that decision-making.
Smith’s request to take time off to be with his mother around Thanksgiving conflicted with a presentation that he was scheduled to give.
Earth is living through its hottest year on record, and global efforts to curb human-generated greenhouse gas emissions driving those high temperatures are not keeping up with commitments to cut emissions, which individual countries made under the Paris Agreement signed eight years ago.
New directions, new actions and higher ambitions are urgently needed if the increase in the global average temperature is to be held to the 1.5 degrees Celsius set in Paris.
The opening day of the 28th U.N. Climate Change Conference of the Parties (COP28) in Dubai, United Arab Emirates, offered multiple opportunities for speakers to repeat these rallying cries — and put their own spin on what those statements mean and what actions should be taken.
“The world has reached a crossroads,” said Sultan Ahmed al-Jaber, COP28’s president, who is also CEO of UAE’s state-run Abu Dhabi National Oil Co.
“Yes, since Paris we have made some progress, but we also know that the road we have been on will not get us to our destination in time,” al-Jaber said. “The science has spoken loud and clear. It has confirmed that the moment is now to find a new road, the road wide enough for all of us.”
Calling on participants to adopt a different, more flexible mindset, al-Jaber argued for his “bold choice to proactively engage with oil and gas companies,” many of which he said “are committing to zero methane emissions by 2030 for the first time, and many … oil companies have adopted net-zero 2050 targets for the first time.”
“I know there are strong views about the idea of including language for fossil fuels and renewables in the negotiated text,” al-Jaber said, referring to whatever official agreement is hammered out at the end of the conference. “We collectively have the power to do something unprecedented; in fact, we have no choice but to go the very unconventional way. I ask you all to be flexible, find common ground, come forward with solutions.”
Al-Jaber’s strong ties to the fossil fuel industry have been a flashpoint since January, when the UAE named him to lead the conference.
Controversy flared again Nov. 27, when the BBC reported that the UAE was planning to use the conference for business meetings with more than a dozen countries to promote oil sales, citing documents that included specific talking points for each country. At a press conference Nov. 29, also reported by the BBC, al-Jaber denied any knowledge of the talking points or ever using them in COP-related discussions.
Al-Jaber is also one of the leaders of an international drive to have countries at COP28 commit to triple renewable energy capacity and double energy efficiency by 2030.
‘Teach Climate Action to Run’
Expectations for COP28 — and U.S. leadership at the conference — have been mixed.
After bringing the U.S. back into the Paris Agreement early in his term, President Joe Biden is not attending the conference, sending Vice President Kamala Harris in his stead.
But the opening day saw a major success with the approval of a loss and damage fund, to be used to compensate developing countries for damages they have already sustained from extreme weather events made worse by climate change. Developing countries have been pushing for years for this fund, which was initially approved at COP27 last year in Egypt.
Thursday’s vote actually created the fund, and the UAE immediately pledged $100 million, with the EU announcing a pledge of $245.39 million, including $100 million from Germany, according to a report from Reuters. The U.K. will contribute $51 million; the U.S. $17.5 million; and Japan $10 million.
Rachel Cleetus, energy and climate policy director at the Union of Concerned Scientists, called the loss and damage fund “a significant step forward” but still “deeply flawed.” Speaking at a press conference held by the Climate Action Network, a global consortium of nonprofits and community groups, Cleetus said the recommendations approved for the fund “represent richer countries exercising power and getting their way, for example, through ensuring that the fund’s interim host is the World Bank.”
Rachel Cleetus, Union of Concerned Scientists | United Nations
But the centerpiece of the conference will be the first Global Stocktake (GST), an evaluation of countries’ performance on their climate commitments, in preparation for new commitments to be submitted in 2025, as mandated by the Paris Agreement.
The U.N. 2023 Emissions Gap report, released Nov. 20, found that even if all nations deliver on their original commitments under Paris, the average temperature could rise 2.5 to 2.9 C by 2050. Limiting warming to 1.5 C would require a 42% drop in GHG emissions by 2030, the report says.
“We are taking baby steps, stepping far too slowly from an unstable world that lacks resilience, to working out the best responses to the complex impacts we are facing,” said Simon Stiell, executive secretary of the U.N. Framework Convention on Climate Change. “We must teach climate action to run.”
Taking a stronger line on fossil fuels than al-Jaber, Stiell said the GST will provide two options.
Simon Stiell, UNFCCC | United Nations
“Either we can note the lack of progress, tweak our current best practices and encourage ourselves to do more at some other point in time; or we decide at what point we will have made everyone on the planet safe and resilient,” Stiell said. “We decide to fund this transition properly, including response to loss and damage, and we decide to commit to a new energy system. If we do not signal the terminal decline of the fossil fuel era as we know it, we welcome our own terminal decline, and we choose to pay with people’s lives.”
Following the GST, countries will have to submit transparency reports at the next COP in 2024, ensuring that “the reality of individual progress can’t be concealed,” Stiell said. New, higher commitments for emissions reductions will be due in early 2025, before COP30, where “every single commitment on finance, adaptation and mitigation has to be in line with a 1.5-degree world,” he said.
A Fast, Fair and Full Phaseout
Jim Skea, IPCC chair | United Nations
Jim Skea, chair of the U.N. Intergovernmental Panel on Climate Change, gave the opening session a short but brutal summary of the current state of global warming and its likely impacts and called for climate action based on science.
“Our planet has warmed by more than 1 degree Celsius since the preindustrial era as the result of burning fossil fuels, deforestation and the unsustainable use of resources,” Skea said. “Human activity has led to changes in the Earth’s climate of a magnitude that are unprecedented over centuries and thousands of years. Climate impacts, some of them irreversible, are widespread, rapid and intensifying, from the poles to the tropics and from the mountains to the oceans.
“Without immediate and deep emission reductions across all sectors, we will not meet the goals of the Paris Agreement,” he said. While options exist for reducing greenhouse gas emissions now, “they need to be scaled up and mainstreamed through policies and increased financing.”
Tasneem Essop, Climate Action Network | United Nations
“Ambition levels have to increase fivefold to be able to put us back on track to address this climate crisis,” said Tasneem Essop, executive director of the Climate Action Network. Speaking at the press conference, she called for a just and equitable “phaseout of fossil fuels” while also criticizing the presence and influence of fossil fuel companies at past COPs.
Romain Ioualalen, Oil Change International | United Nations
Al-Jaber’s calls for inclusion notwithstanding, a recent report found, for example, that Shell has sent 115 staff members to the annual climate conference over the years.
Romain Ioualalen, global policy campaign manager for Oil Change International, a research and advocacy group, said the success of COP28 could rest on “whether it delivers a decision on the phaseout of fossil fuels … which is a fast, fair, full and funded phaseout.”
“That being said, we cannot ask all countries to phase out fossil fuels at the same pace, and in particular rich countries … with diversified economies have a responsibility to phase out fossil fuels first,” he said.
NYISOreleased its 2023/32 Comprehensive Reliability Plan (CRP) on Nov. 29, finding no “actionable reliability needs” for the next decade, but warning of narrowing reliability margins.
The biennial-CRP serves as the ISO’s 10-year strategy map for New York’s electric system, outlining emerging risks and recommending actions the state can take to ensure grid reliability. It encompasses demand forecasts, resource adequacy, infrastructure development and renewable energy integration. The CRP is the culmination of NYISO’s reliability planning process and assesses the feasibility of solutions proposed in the annual Reliability Needs Assessment (RNA).
The draft CRP, which received NYISO stakeholder approval earlier this month, was presented throughout the year. (See “Comprehensive Reliability Plan,” NYISO Operating Committee Briefs: Oct. 11, 2023.)
The CRP concludes that the system should be reliable, assuming demand and weather conditions align with NYISO’s forecasts. However, delays in key projects like the Champlain Hudson Power Express (CHPE), increased electric demand, additional generator deactivations due to state regulations, unplanned outages or extreme weather events could necessitate new reliability measures in next year’s RNA.
The critical risk outlined in the CRP is the on-time completion of the 1,250-MW HVDC CHPE project, which will bring hydropower from Québec to New York City. If delayed beyond its expected May 2026 completion, reliability margins could become “deficient for the ten-year planning horizon,” leaving New York City unable to meet demand from 2026 onwards.
Without CHPE, statewide summer reliability margins become deficit by 2025. | NYISO
The plan also anticipates a notable increase in peak demand driven by the electrification of transportation and buildings, along with the addition of large loads, especially in upstate New York.
This growing demand becomes even more pressing since about 3,300 MW of fossil fuel plants, which tend to meet demand during extreme conditions, are expected to retire due to the Department of Environmental Conservation’s peaker rule starting in May 2025. This is a particular concern for New York City, which heavily relies on natural gas.
NYISO recently announced plans to extend the operation of two natural gas peaker plants beyond their 2025 retirements to address a 446-MW shortfall in New York City identified in the second quarter Short-Term Assessment of Reliability. (See NYISO to Keep Gas Peakers On.)
The CRP cites the 2023 Fuel and Energy Security study, which predicts that New York will transition from a summer to a winter peaking system as electrification increases and become increasingly reliant on dual-fuel generation resources in winter. This poses a future challenge, especially as many fossil fuels plants expected to retire soon would have been key to meeting peak winter demand.
The CRP recommends introducing new dispatchable emissions-free resources (DEFRs) and inverter-based resources (IBRs), constructing additional transmission, integrating more distributed energy resources (DERs), and expanding demand response and energy efficiency programs.
In an Oct. 23 memo commenting on the draft CRP, Potomac Economics, the ISO’s Market Monitoring Unit, recommended market design changes to encourage the development of flexible resources and the integration of intermittent renewables to maintain reliability. (See Providers See ‘Mixed Signals’ on Demand Response in NYISO.)
Summer extreme weather events represent a risk to statewide system marginal deficiency. | NYISO
Risk Factors
While identifying no immediate reliability needs requiring action, the CRP says that generation retirements could outpace resource additions, which it says could result in a transmission security deficit exceeding 600 MW in New York City by 2033. It says the state’s 2019 Climate Leadership and Community Protection Act, along with other public policy initiatives, significantly accelerated generator retirements.
Even with projects like CHPE, meeting peak demands during extreme winter conditions could become a challenge as early as the winter of 2027/28 due to increased building electrification, electric vehicle growth and the addition of large energy loads like data centers and microchip fabrication plants.
The CRP warns of potential power deficits in future winters, with a projected shortfall of 6,000 MW by winter 2032/33, which could be compounded by gas shortages and extreme cold snaps.
Extreme weather events such as heat waves and storms also represent significant risks, potentially leading to increased electrical demand and more frequent generator outages. An extreme heat wave could cause a statewide deficiency of over 2,500 MW by 2025.
The plan encourages continued interregional collaboration, predicting NYISO will likely have to increasingly rely on its neighbors to meet demand during above-average loads.
Road to 2040
New in this year’s report is a section titled “Beyond the CRP — Road to 2040,” which assesses the impacts of public policies on New York’s electric grid and fuel mix, outlining steps needed to meet the state’s climate targets amidst reliability, generation and transmission risks.
NYISO estimates New York will require between 111 GW and 124 GW of capacity by 2040, with at least 95 GW coming from new generation projects or modifications to existing plants. However, the CRP says this may not even be enough, warning “the sheer scale of resources needed to satisfy system reliability and policy requirements within the next 20 years is unprecedented.”
The section notes a significant portion of this new generation will be IBRs, which are subject to meteorological conditions and also willl need to be supplemented with other resources like energy storage and DERs.
The section emphasizes the need for DEFRs to provide energy and capacity over long durations, especially during low output from intermittent resources, and to replace the attributes of retiring synchronous generation. Resources with the attributes needed for DEFRs are not yet commercially available, prompting the New York Public Service Commission to explore potential technologies such as hydrogen, bioenergy, nuclear power and carbon capture (15-E-0302).
And although NYISO has identified several major public policy transmission projects to deliver renewable energy efficiently across the state, further development is needed to serve renewable generation pockets.
The Road to 2040 also discusses the need for a more resilient power system against climate change impacts and extreme weather, appropriate market price signals and ensuring new resources can provide essential grid services like operating reserves, ramping or voltage support.
The section acknowledges the need for New York to adapt its planning strategies to guarantee future reliability and maintain energy markets flexible enough to respond to evolving grid and environmental conditions.
The Bonneville Power Administration is pulling back from its ambitious schedule for choosing which Western day-ahead market it will join, officials with the federal power marketing administration said during a workshop Nov. 29.
But those officials also indicated BPA still plans to issue a decision on whether it will sign up with either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+ sometime early next year.
When BPA launched its process for deciding between the markets in July, staff said it would propose a “policy direction” in the form of a “record of decision” on the issue shortly after SPP filed its Markets+ tariff with FERC in February, following a series of five stakeholder workshops.
The decision would cover two points: whether BPA would participate in a day-ahead market, and which of the two it would join, staff said. (See Regulators Propose New Independent Western RTO.)
Some industry stakeholders criticized the timeline for being overly aggressive and expressed concerns that the timing of the decision suggested an implicit bias in favor of Markets+. Others said the pacing was necessary to ensure that BPA — and the Northwest at large — had a strong influence on the direction of electricity market developments in the West. (See NW Stakeholders Divided on BPA Timeline for Day-ahead Decision.)
The critics may have partly gotten their wish during BPA’s fourth workshop on the issue, when agency officials revealed that while they’ll be sticking to the original timeline for issuing a decision in the first quarter of 2024, they intend to alter the content of that decision.
That record of decision is now likely to cover whether BPA has the statutory authority to join a day-ahead market, while potentially conveying a “leaning” on what market the agency is favoring by that time, Russ Mantifel, the agency’s director of market initiatives, said during the workshop.
Mantifel acknowledged the level of uncertainty around the issue and said BPA still has “limited information” on which to base a decision.
“I would say that the timing of this is still up in the air, right? Like, there’s literally no market that somebody could join. Right now, EDAM has not been approved. There’s no tariff yet for Markets+,” he said, pointing out that SPP is still surveying potential participants on “even what it would look like to start making the commitment” to that market.
Mantifel pointed to other, internal matters that BPA must deal with before making a decision on whether to join a market, including the impact on its rates, tariffs and contracts with power and transmission customers.
“I think it’s fair to expect that that policy direction will establish our authority to join a market and will establish the business case for pursuing a market,” Mantifel said.
“Our customers and regional leaders have expressed to us the importance that our market engagement needs to be consistent with our statutory obligations. We’re right there with you,” said Suzanne Cooper, BPA senior vice president of power services.
Cooper pointed to another factor that might be prompting BPA to ease up its timeline: stakeholder requests that the agency more deeply evaluate the “cost advantages” of a single Western market.
In that vein, she said, the agency continues to monitor developments around the West-Wide Governance Pathways Initiative (WWGPI), which seeks to establish an independent entity to oversee an RTO that would include CAISO and build on the grid operator’s existing market services without subjecting non-California members to the ISO’s state-run governance. BPA has not been participating in that effort. (See West-Wide Governance Pathway Group Digs into its Work.)
“We have heard and definitely acknowledge the requests that we’ve heard for taking some more time for additional analysis and to allow the Pathways concept to develop,” Cooper said. “We’ve heard also from many entities, including within our public power customers, that desire for BPA to maintain our current timeline.”
To Lean or Not to Lean
A representative from a key group representing many of those public power customers asked BPA for more clarity on the process that will follow the first record of decision.
Lauren Tenney Denison, director of market policy and grid strategy at the Public Power Council (PPC), noted that in the “multiphase” process that BPA followed in its decision to join CAISO’s Western Energy Imbalance Market, “it was pretty clear what was being decided and what was still open for discussion.”
“What is the expected action that will happen after the leaning is issued at the end of this process?” Denison asked.
“I think that is still up in the air,” Mantifel said. “The processes for joining the markets themselves are still somewhat fluid as opposed to EIM.”
Fred Heutte, senior policy associate at the Northwest Energy Coalition, advised BPA not to include a “leaning” in the first record of decision. NWEC has been a consistent advocate for a single Western market that includes California.
Reading from comments that NWEC submitted to BPA a day earlier, Heutte said, “The BPA day-ahead market policy should provide principles and a road map for assessment, analysis and modeling to inform BPA’s decision about joining a day-ahead market. Given the wide range of implications for market selection, we strongly urge BPA not to proceed with a leaning on day-ahead market choice at this time.
“We feel that any leaning, whichever direction this goes, not be included with day-ahead market policy, because it really belongs with the decision process.”
Mike Linn, director of market analytics at the PPC, took the opposite view.
“We think that because of the nature of Bonneville’s system, Bonneville’s decision or leaning would be very informative to other Western prospective participants, and [I] just want to kind of re-emphasize that we do think that is a key element and something to include.”
Mantifel defended BPA’s inclusion of the leaning.
“I worry that just making a statement generally about a day-ahead market without recognizing the reality of the fact that there are two options that people are making decisions on … might not reflect the practical reality that entities are facing at this point in time in terms of needing to be in a position to make commitments,” he said.
The Nov. 29 meeting left lingering question about exactly what BPA will provide to stakeholders in the first quarter of 2024.
“BPA is on track to issue a proposed policy decision with respect to participation in day-ahead markets early next year,” agency spokesperson Doug Johnson told RTO Insider. “BPA indicated that it would continue to address stakeholder comments in its public process to evaluate day-ahead market participation.”
Johnson said BPA has“committed to provide a timeline of what decisions would be made and when because some decisions would take place in different processes, such as our rates and tariff proceedings.”
BPA tentatively plans to hold its final day-ahead workshop Feb. 1, but the date is subject to change.
(Editor’s Note: This article was originally titled “BPA Delays Decision onDay-ahead Market Choice.” BPA requested the title be changed to reflect the fact that the agency still intends to issue a proposed policy direction related to day-ahead markets in early 2024.)
