ISO-NE projects it will have enough energy resources to maintain the grid throughout mild and moderate weather conditions this winter, the organization announced Dec. 4. Under more severe winter conditions, ISO-NE indicates some capacity deficiency actions may be required, but shortfall remains “unlikely.”
While the RTO said it does not anticipate the need for controlled power outages, it cautioned that even in a mild winter, extended cold snaps still could stress the grid.
The organization forecasts a peak demand of 20,269 MW under average weather conditions, and a 21,032-MW peak under below-average temperatures. This would be an increase compared to last winter’s 19,529-MW demand peak. ISO-NE anticipates winter peak demand increases will accelerate in the coming years due to electrification, surpassing 26,000 MW in 2032 and potentially reaching about 57,000 MW in 2050.
For this winter, ISO-NE noted the National Oceanic and Atmospheric Administration projects above-average temperatures in New England, with more precipitation than usual in Southern New England and average precipitation in Northern New England.
Temperature and weather patterns can impact both supply and demand on the grid, making weather “the largest driver of energy use and resource availability in New England,” according to the RTO. The organization touted its 21-day energy supply forecast, which it uses to anticipate and preempt supply constraints.
“Seeing what’s coming is crucial to navigating any potential power system challenges, and our 21-day energy supply forecast is an operational tool that serves this very purpose,” ISO-NE CEO Gordon van Welie said in a statement. “It gives us situational awareness on energy adequacy over the operating horizon, allowing us to identify potential energy shortfalls while there’s still time to prevent them or lessen their impact.”
The RTO has several out-of-market mechanisms in place intended to ensure grid reliability. This winter will feature the rollout of the Inventoried Energy Program (IEP), which will compensate generators for keeping up to three days of stored fuel on-site.
The IEP is intended to be a short-term reliability solution, set to run for just two winters. It has been criticized by environmental groups as an unnecessary handout to fossil generators, while ISO-NE has argued it is an important reliability backstop for the region. (See FERC Upholds Ruling on ISO-NE’s IEP Payments.)
This winter also will be the second and final year of the Mystic Cost-of-Service Agreement (COSA), which has delayed the retirement of the Mystic generation station. Mystic is the main customer of the Everett LNG import terminal, and Mystic’s retirement would necessitate a new source of funding to keep the import terminal open. The generator is set to retire when the COSA expires at the end of May 2024, after which the future of Everett is uncertain.
According to an ISO-NE report released in September, the agreement has cost ratepayers in the region over $572 million from its start in June 2022 through August 2023. Over this period, Mystic’s operational conditions have been characterized by the RTO as “in-merit operation” for just one month, compared to nine months of “tank congestion management” and five months where the facility was characterized as “predominantly offline.”
In the coming years, the region could see several new clean energy resources come online that likely will boost winter reliability. The 806-MW Vineyard Wind 1 project aims to achieve commercial operation by the end of 2024, while the 1,200-MW New England Clean Energy Connect transmission project expects to be in service by 2025.
In the longer-term, ISO-NE’s ongoing Resource Capacity Accreditation project is intended increase capacity revenues for resources that provide reliability attributes to the grid, particularly during periods of winter stress. Under the RTO’s current schedule, these updates will be implemented in time for the winter of 2028/29.
New York is moving quickly to keep its renewable energy development queue viable, launching solicitations for new onshore and offshore large-scale projects.
This new round is designed to move more quickly than previous New York solicitations, with hopes of restoring momentum to struggling projects and replacing any projects that are withdrawn.
Proposals under the state’s fourth competitive offshore wind solicitation (ORECRFP23-1) are due by Jan. 25, and award announcements are expected in February. Onshore developers have until Dec. 21 to establish eligibility for the seventh annual Renewable Energy Standard solicitation (RESRFP23-1). They must then submit proposals by Jan. 31, with award announcements also anticipated in February.
The Nov. 30 solicitation announcement followed a Public Service Commission decision in mid-October to not increase the reimbursement for several dozen contracted projects totaling more than 12 GW of nameplate capacity.
Developers had said they might not be able to start construction of the projects without more money, and there was speculation the PSC ruling would gut the clean energy portfolio the state is trying so hard to build.
But immediately after the PSC ruling, Gov. Kathy Hochul promised an expedited effort to help blunt its impact. The New York State Energy Research and Development Authority (NYSERDA) followed through with the solicitations for land-based and offshore projects.
The developers who had sought financial relief for projects awarded contracts under previous solicitations will be able to rebid those projects into this new solicitation.
This is key for offshore wind, given the lengthy timeline involved in planning and review of each project — a complete reset could set the state back years as it pursues statutory goals for emissions-free power.
The inflation-index option that was absent from early solicitations will be available to bidders in this latest request for proposals. Also, NYSERDA said it is streamlining the solicitation by removing certain bid requirements that were labor intensive to comply with but provided minimal value to officials evaluating the bids.
Offshore wind is a key component of the clean energy transition, promising gigawatts of emissions-free power.
A few projects are under construction or preparing to start construction in U.S. waters, having locked in their finances before spiraling costs clobbered the industry. But most are struggling with their financials.
New York’s neighbors are in the same position: New Jersey, Connecticut and Massachusetts have seen projects stalled or outright canceled, and a Rhode Island proposal was rejected as too expensive.
But all of the states have pressed forward — the southern New England states, New Jersey and now New York each have issued new solicitations in recent months.
Also, New York in late October announced conditional contract awards for three offshore wind projects totaling 4 GW of capacity.
The renewable energy industry had criticized the PSC for its decision and Hochul for an unrelated veto. But it welcomed the new solicitations.
Fred Zalcman, director of the New York Offshore Wind Alliance, said in a news release: “Actions speak louder than words, and we applaud the Hochul administration for providing, through this expedited RFP, a clear and unambiguous statement of support for offshore wind as an essential part of New York’s evolution towards a carbon-free grid.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York, said: “I applaud New York’s fast action, because this sense of urgency is exactly what is needed to bring infrastructure projects to construction and achieve clean energy and climate goals.”
In the face of a yawning gap in efforts to reduce global greenhouse gas emissions, 118 nations at the 28th United Nations Climate Change Conference of the Parties (COP28) in the United Arab Emirates pledged on Dec. 2 to triple renewable energy capacity and double energy efficiency savings by 2030.
COP28 President Sultan Ahmed al-Jaber announced the Global Renewables and Energy Efficiency Pledge, which will target expansion of global renewable capacity to 11,000 GW by 2030, while also raising the global annual rate for energy efficiency improvements from 2% to 4% per year.
The pledge states that “renewable deployment must be accompanied this decade by … a phasedown of unabated coal power, in particular ending the continued investment in unabated new coal-fired power plants, which is incompatible with efforts to limit warning to 1.5 degrees C.”
The pledge specifically commits nations to “put the principle of energy efficiency as the ‘first fuel’ at the core of policymaking, planning and major investment decisions.”
Countries signing onto the pledge are encouraged to adopt “ambitious national policies on renewable energy,” including accelerating permitting of renewable projects and infrastructure, expanding grid connections and improving energy system integration, and providing clarity on market design and investment frameworks for renewables.
“The world does not work without energy,” al-Jaber said in the COP28 press release on the pledge. “Yet the world will break down if we do not fix [the] energies we use today, mitigate their emissions at a gigaton scale and rapidly transition to zero-carbon alternatives.”
But European Commission President Ursula von der Leyen framed the pledge as a first step toward a fossil fuel phaseout. “With this global pledge, we have built a broad and strong coalition of countries committed to the clean energy transition ― big and small, north and south, heavy emitters, developing nations and small island states,” she said. “We are united by our common belief that to respect the 1.5 degrees C goal in the Paris Agreement, we need to phase out fossil fuels. We do that by fast-tracking the clean energy transition, by tripling renewables and doubling energy efficiency.”
The EU will invest $2.5 billion in the energy transition over the next two years, she said.
Lisa Jacobson, president of the Business Council for Sustainable Energy, hailed the pledge as “a milestone to be celebrated. It signals that the global community is united in its goal to advance the clean energy transition ― and is aware of the enormous level of deployment needed to do so quickly. To reach this goal, the business community has an essential role to play in directing investment and deploying technologies ― in all sectors and all geographies.”
Climate activists were more critical. While welcoming the renewables pledge, Janet Milongo, senior officer at the International Climate Action Network, said it “still falls short of what is required to achieve global climate goals. Prolongation of fossil fuel lifelines is evident. Dangerous distractions like carbon capture and storage have no place in an energy transition plan,” referring to the pledge’s mentions of “unabated coal power.”
The pledge was part of a series of announcements Dec. 2, made under an umbrella initiative, led by al-Jaber and the U.A.E., dubbed the Global Decarbonization Accelerator.
The U.A.E.’s Hydrogen Statement of Intent drew support from 27 countries, pledging to “endorse a global certification scheme and to recognize existing certification schemes … to unlock global trade in low-carbon hydrogen.”
Fifty companies, representing 40% of global oil production, have signed an Oil and Gas Decarbonization Charter, committing to zero methane emissions and the end of “routine” flaring by 2030 and total net-zero operations by 2050.
A Global Cooling Pledge will target a 68% cut in GHG emissions from refrigeration and space cooling technologies by 2050. Space cooling and refrigeration now account for 7% of global emissions but are expected to increase as more nations expand their use of air conditioning. According to the announcement, 52 nations have signed the pledge thus far.
A $1 billion effort to cut methane and other non-carbon greenhouse gas emissions will be announced Dec. 5. A key question now is whether the renewables pledge will be included in the final official agreement from the conference.
‘Urgency of the Moment’
With President Joe Biden deciding not to travel to the U.A.E., the U.S. presence at the COP28 initially was more muted than in the past, starting out with a widely criticized $17.5 million pledge to the new loss and damage fund approved on the first day of the conference.
The U.A.E. pledged $100 million and the EU pledged $245 million for the fund, which is intended to compensate developing countries for damages they already have sustained from extreme weather events made worse by climate change.
Speaking at the conference Dec. 2, Vice President Kamala Harris announced a $3 billion U.S. pledge to the Green Climate Fund, which helps developing countries invest in clean energy and resilience. As part of the Paris climate accords, industrialized countries including the U.S. pledged to raise $100 billion per year for the fund by 2030. The fund hit $89.6 billion in 2021, according to the Organization for Economic Cooperation and Development.
The U.S. also is launching an international Clean Energy Supply Chain initiative to expand and diversify the supply chains critical to the U.S. and global energy transition. Harris said the U.S. is going to provide $568 million for low-cost loans to expand clean energy manufacturing.
“The urgency of this moment is clear,” Harris said, according to a White House release. “We cannot afford to be incremental. We need transformative change and exponential impact. As nations, we must have the ambition that is necessary to meet this moment.”
The U.S. also joined more than 20 other nations in signing the Declaration to Triple Nuclear Energy by 2050, according to an announcement from the Department of Energy. The declaration commits signers to ensuring they operate nuclear facilities responsibly, with “the highest standards of safety, sustainability, security and non-proliferation, and that fuel waste is responsibly managed for the long term,” while mobilizing financing for new plants.
“We are not making the argument to anybody that [nuclear] is absolutely going to be the sweeping alternative to every other energy source — no, that’s not what brings us here,” said Special Presidential Envoy John Kerry, as reported in The New York Times. But, he said, “You can’t get to net-zero 2050 without some nuclear.”
The other major initiative from the U.S. on Dec. 2 was the release of the EPA’s final rule aimed at slashing the nation’s methane emissions 80% between 2024 and 2038..
Announced by EPA Administrator Michael Regan and White House National Climate Advisor Ali Zaidi, the new rule gives oil and gas companies two years to end routine flaring of natural gas from new oil wells and one year to phase in zero emissions standards for key equipment such as pumps and storage tanks. It requires close monitoring for leaks, while also opening the way for oil and gas companies to use new technologies, such as satellite monitoring and aerial surveys, to detect leaks.
The final rules were developed with feedback from nearly 1 million public comments EPA received on proposed regulations issued in 2021 and 2022, according to the agency announcement. Regan said the standards were developed “to advance American innovation and account for the industry’s leadership in accelerating methane technology.”
EPA also plans to enlist “third-party expertise” to find the large leaks, known as “super emitters,” which account for close to half of methane emissions from oil and gas.
Statements in the EPA announcement signaled broad support for the rule from industry and environmental groups.
Orlando Alvarez, chairman and president of bp America, said the final rule was “well designed” and would “help drive material methane emission reductions this decade and beyond.”
Fred Krupp, president of the Environmental Defense Fund, called the rule “a vital win for the climate and public health, dramatically reducing warming pollution and providing vital clean air protections to millions of Americans.”
COP28’s Two Narratives
The wave of new pledges and commitments comes as the conference faces the first Global Stocktake of how well the nations that signed the Paris Agreement in 2015 have lived up to their commitments to reduce their GHG emissions to limit climate change to 1.5 C.
The outlook is not encouraging. The UN’s Emissions Gap report, released prior to the conference, said even if all countries were to meet their commitments, the world still would be headed for 2.5 to 2.9 C of warming by the end of the century.
Adding to the sense of urgency, the World Meteorological Organization rolled out its provisional State of the Climate report on the opening day of the conference, confirming that 2023 has been the hottest year on record, with ongoing increases in GHG emissions, record sea level rise and record low Antarctic sea ice.
Even before the opening of COP28, two narratives had emerged about how the world should respond to the challenges ahead and what official actions the conference might endorse.
The dominant narrative, advanced by al-Jaber, the oil and gas industry and other oil-producing countries, is that, along with more renewables and energy efficiency, new technologies — like carbon capture and storage — can mitigate the worst effects of the ongoing combustion of fossil fuels.
The alternative narrative, advanced by a range of environmental groups and some nations, envisions a global commitment to a full, fair, fast and well-funded phaseout of all fossil fuels. At yet another event Dec. 2, Colombian President Gustavo Petro announced his country would be the 10th to join the call for a fossil fuel nonproliferation treaty.
The first calls for such a treaty came from Pacific Island nations in 2015, according to the initiative’s website, and supporters now include a range of cities and environmental and other nonprofits. Colombia is the second oil-producing country to support the treaty; the first was the Pacific Island nation of Timor-Leste.
Petro acknowledged the paradox of a fossil fuel-dependent country supporting nonproliferation but argued that preventing the “omnicide” of the planet itself must be avoided, as reported in the Guardian. “There is no other formula, no other path. Everything else is an illusion,” he said.
The critical question now is whether any of the pledges and commitments being rolled out in Dubai will find their way into the final conference agreement. Wide support for a fossil fuel phaseout is unlikely, and even official sanction for a phasedown may be difficult or significantly watered down, as has occurred in the past.
Al-Jaber once again fueled controversy Dec. 3 when the Guardian reported that during a pre-COP interview, he said there is “no science out there, or no scenario out there, that says that the phaseout of fossil fuel is what’s going to achieve 1.5 C.”
Responding to those comments, Kerry pivoted the argument, saying the focus for limiting climate change to 1.5 C must be on “a phasing out of unmitigated fossil fuel emissions,” as reported by CNBC.
At a press conference on Dec. 4, al-Jaber said his comments were misrepresented and taken out of context, according to the Guardian.
“I respect science in everything I do,” he said. “I have said over and over the phasedown and the phaseout of fossil fuel is inevitable. In fact, it is essential.”
Massachusetts on Friday issued its first-ever “Climate Report Card,” finding that all of the state’s sectors are “on track” for their 2025 decarbonization targets.
The inaugural report from Gov. Maura Healey’s (D) administration measured decarbonization efforts in the transportation, buildings, electricity, and natural and working land sectors. The finding is based on some unexpected progress in the deployment of clean energy technologies and the assumption that will continue to accelerate in the coming years.
But the report also highlighted the challenges to cutting emissions. According to the state’s greenhouse gas inventory, transportation and buildings are the two largest sources of carbon emissions in the state, responsible for 37% and 35%, respectively, of the state’s total emissions.
The report card noted there were more than 70,000 light-duty electric vehicles in the state in 2022. Massachusetts’ Clean Energy and Climate Plan (CECP) models the state will need 200,000 total EVs by 2025 and 900,000 by 2030.
The state also has a long way to go on public vehicle charging infrastructure: It has nearly 6,500 charging ports but will need to increase this number to 15,000 by 2025 and 75,000 by 2030, according to the CECP estimates.
The report cited high interest rates, inflation and supply chain constraints, along with grid capacity limitations, as some of the challenges to rapidly electrifying transportation in the state. Other barriers include EV affordability, access to home chargers and public transportation accessibility.
For the buildings sector, the report card found heat pump deployment has accelerated in recent years, noting nearly 30,000 heat pumps have been installed through the state’s Mass Save energy efficiency program from the start of 2020 through the first half of 2023. The CECP estimates the state needs to install 100,000 heat pumps between 2020 and 2025, increasing to an average of 100,000 annual installations between 2025 and 2030.
But the report card noted installations through Mass Save have surpassed expectations, and the state is “at about 30% of [its] 2025 target even before accounting for installations outside of Mass Save such as those done within municipal light plant territories.”
“Despite these early successes, sharp increases are needed to meet the state’s building sector targets,” the report added. It noted that energy efficiency and demand-control measures are essential to limiting the pressures electrification puts on the grid.
The report card said Mass Save’s focus on cost savings may need to be reformed to increase the number of customers switching from natural gas heating to heat pumps. It also highlighted the difficulties of building decarbonization for old buildings and rental units, along with the need for a larger HVAC and weatherization workforce.
While the power sector is responsible for increasingly less emissions in the state, the report called it “the linchpin of all other GHG-reduction strategies,” adding that “without substantial additions of clean energy, the transition to electric vehicles and building heating and cooling will not result in adequate GHG reductions.”
Although natural gas remains the dominant source of power in the region, the report said clean energy sources accounted for 48.2% of the state’s electricity. It noted there was 113 MW of wind capacity and 3,325 MW of solar capacity in the state in 2020. The CECP estimates wind needs to increase to 180 MW by 2025 and 3,650 MW by 2030. The 2030 target likely will rely heavily on the successful deployment of offshore wind.
The state cited the same challenges to transportation electrification as barriers to offshore wind deployment, along with the need for additional transmission to interconnect new renewables. Other issues highlighted include permitting and siting, infrastructure cost allocation and increasing peak demands.
Additionally, the report noted “revenues that can be earned through existing energy market structures are not certain enough to facilitate long-term financing of new generation outside of state-run procurements for clean energy.”
It added that utility incentives may need to be reconsidered to get the most out of the existing infrastructure. “Utilities are incentivized to build new infrastructure as opposed to optimizing use of the existing electric grid, managing demand or encouraging distributed resources.”
“As Massachusetts makes progress and faces challenges in implementing our climate vision, it’s important that we follow the science and stay transparent about our progress,” Secretary of Energy and Environmental Affairs Rebecca Tepper said in a press release.
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.
