CARMEL, Ind. — MISO announced April 24 that 123 GW of new generation spread across 600 applications are vying to enter its generator interconnection queue under the 2023 cycle.
The 2023 intake, composed nearly exclusively of renewables and storage facilities, is almost 50 GW smaller than the 2022 application cycle MISO has been processing. MISO said while the number of proposed megawatts is still “significantly higher than historical averages,” 2023’s submittals were tempered due in part to its new, FERC-approved suite of tougher conditions on entrants.
Of the 123 GW of 2023 entrants, MISO said 115 GW (93%) represent wind, solar, storage or a combination of renewables and storage facilities. New solar projects account for 50 MW, storage projects total 29 GW, wind projects clock in at 19 GW, and hybrid renewable and storage projects about 17 GW.
MISO said if all the 2023 submittals are certified and accepted, the MISO queue will grow to 348 GW.
MISO required developers of the latest submittals to pay double in entrance and staged queue study fees, be subject to automatic and escalating penalty charges, and confirm they’ve obtained land for projects. The RTO had delayed opening its 2023 queue application window until March to obtain FERC approval to implement the new requirements. (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.)
MISO said its stricter requirements will allow for quicker network upgrade studies because it cuts down on the number of speculative projects entering the queue and then dropping out. It said it expects “higher-quality and more viable projects entering the queue.”
“Although these changes have resulted in a reduction from the previous cycle, it still represents a large number of projects for the team to study,” Director of Resource Utilization Andy Witmeier said in a press release. “We will continue working with our stakeholders to refine the queue process.”
Witmeier also pointed out that MISO is awaiting about 50 GW in approved generation projects that have yet to complete construction due to “financing, supply chain issues, delays in permitting and power purchase agreement negotiations.” (See MISO: Reliability Risk Upped by 49 GW in Approved but Unbuilt Generation.)
At an April 24 Planning Advisory Committee meeting, MISO staff said the RTO still plans to file again to implement an annual megawatt cap on project submittals to the interconnection queue. FERC rejected MISO’s first attempt to cap its queue entries annually based on a formula. (See MISO to Try Again for Interconnection Queue MW Cap, Open Window for 2023 Requests.)
The RTO has said annual queue entries as large as 2022’s 171 GW aren’t sustainable for a system that peaks at about 125 GW in the summer.
At the Gulf Coast Power Association MISO-SPP conference in March, MISO’s Scott Wright said the RTO worries about the queue “getting killed by volume,” where it’s nearly impossible to process projects because the queue is in essence “sabotaged” by scores of low-quality projects that aren’t fully fleshed out before being entered.
UNION, N.J. — Innovation and in-state project development by engineers and thinkers will be key to New Jersey’s offshore wind future as the state advances its groundbreaking initiative to create an offshore power center that can connect to homes and businesses onshore, according to speakers at the Wind Institute Research Symposium.
The extensive scale of the task, and the lack of history in creating such a major transition, will mean the work of problem-solving engineers, entrepreneurs and academics will be critical to overcoming the expected and still-unknown hurdles, speakers told the audience at Kean University on April 12.
Leading a panel on OSW research and collaboration, Kris Ohleth, executive director of the Special Initiative on Offshore Wind, said that after working for 25 years in the sector, she sees the state at a critical juncture, sitting on the cusp of bringing OSW to reality.
“We said 20 to 25 years ago, ‘OK, we know these are going to be the challenges, and once we get through this development phase of offshore wind and we move to this phase of implementation that we are at today, someone’s going to figure it out,’” she said. “And those someones are you — you folks sitting here today.”
Present in the audience, and among those outlining their work, were many of the 40 participants in the institute’s fellowship program started last year. Among the topics tackled by fellows, and showcased at the forum, were the socioeconomic and policy implications of OSW projects, how to secure public support, the development of a weather station that could predict wind energy generation, and how to make more effective and quieter turbine blades.
Unknown Future
New Jersey is seeking to revitalize its OSW sector after Danish developer Ørsted in October withdrew its two projects planned for the Jersey shore: Ocean Wind 1, the state’s first OSW venture, and Ocean Wind 2, one of two projects awarded in the state’s second solicitation.
The withdrawal left the state with just one active project: Atlantic Shores. The Board of Public Utilities approved two more Jan. 4: Leading Light Wind and Attentive Energy Two. If they come to fruition, the three projects would have a capacity of 5,252 MW, a major step toward the state’s goal of 11 GW by 2040. But getting there is no easy task, Tim Sullivan, executive director of the New Jersey Economic Development Authority, told the group.
“This is not like flipping a switch and it’s going to happen,” he said. “There are big known unknowns that we are counting on innovation to bail us out of, of how we are actually going to deliver on the promise of offshore wind.
“No one’s ever done this before. No one’s ever put an 11-GW power plant off the coast of a major industrial state and plugged it into a grid that is not particularly new and made it come out of people’s houses,” said Sullivan, whose agency helped organize the event and provides financial support for OSW projects. “We don’t know exactly how that’s going to work. You all, and others around the world, are working on those challenges.”
Public Concern
Key to the success of the projects will be the public reaction as construction gets underway and the cost of transitioning to coastal wind generated power becomes clearer.
The most vigorous opposition to the projects has emerged from the commercial fishing industry, local residents and tourist businesses, who fear that turbines in the ocean will damage the local quality of life. Several presenters at the symposium focused on the issue and where the opposition stemmed from.
Dylan Irmiere, a Stockton University student and a fellow of the wind institute, said that in the two public opinion surveys he commissioned and conducted in New Jersey as part of his research, 46% of those polled — including residents in the shore area and the rest of the state — had no knowledge at all of the wind projects, and 41% had slight to moderate knowledge of them.
The research showed positive public support among respondents for OSW as a solution to fight climate change, he said. Only one in five believed there would be environmental harm, and about 58% thought the projects would help the environmental, while about 60% said they believed the farms would help the economy.
However, when the respondents were given additional facts — what Irmiere called “surface-level knowledge” — about project distance from shore, the predicted economic benefits and the background of developers, only 33% said they wanted the projects to continue, and nearly a quarter said they did not support the continuance of the projects.
The fact that nearly a quarter of people had concerns after the intervention “could mean that they are still lacking sufficient information to form an educated opinion,” Irmiere said. He added that even after survey respondents were given information about federal actions to protect marine animals, 31% were neither satisfied nor dissatisfied, suggesting they “could need” more information.
“Learning that providing information to respondents about the environment and the economy helps to form sentiments of offshore wind gains should be something that companies developing these projects, as well as the governments in local communities, focus on,” he said. “To encourage the public to think more positively, sentiments about offshore wind should be constructed in a way that demonstrates their effectiveness on the environment and the economy.”
The surveys also showed how turbine distance from the shore can affect public support: While about 33% agreed that three miles offshore was a “reasonable distance” to site turbines, that figure grew to 55% for 12 miles and 59% for 20 miles.
Aparna Varde, associate professor in the Montclair State University School of Computing, said she and a graduate student, Isabele Bittencourt, studied social media posts about the projects. Their work focused on sentiment analysis, looking at whether the prevailing sentiments expressed are positive or negative to offshore wind; and topic modeling, to see what issues were raised most in posts about the wind projects.
The pair used three different methods of analysis, and all three found that between 37 and 40% of the comments were positive and between 26 and 36% were neutral, Varde said. Between a quarter and a third of the posts were negative, according to her presentation. Still, the positive slant to the comments was far from overwhelming, she said.
Tracking Mammals Underwater
The impact on marine life of wind farms emerged as a potent issue early in 2023 when a series of dead whales washed up on New Jersey shores. Opponents have raised concerns that preliminary work on the wind farms contributed to the deaths, even though no construction has started and federal investigators have found no connection between the deaths and the wind projects.
State officials told the symposium they are taking steps to minimize any harm. Offshore wind developers pay a fee of $10,000/MW to the state Research and Monitoring Initiative (RMI), which to date has been awarded $65 million for research projects, according to speakers from the New Jersey Department of Environmental Protection and the BPU. The RMI has awarded $13 million of that money to research projects, including one that sends “ocean gliders” into the sea to collect data on water temperature, and the level of chlorophyll and pH in the water.
“These gliders are autonomous mobile platforms that are outfitted with a suite of sensors that collect really high spatial and temporal resolution data on water chemistry and physical ocean processes, like the seasonal formation and breakdown of the cold pool,” said Caitlin McGarigal, a research scientist at the DEP, referring to the seasonal stratification of cooler water close to the ocean bottom.
“This just sort of exemplifies the type of data that’s being collected on this project and how these data can be really useful for understanding wildlife movement and behavior,” she said.
Another RMI-backed project is using acoustic telemetry — “like an underwater E-ZPass” — to set up receiver listening stations that can rack species that have been tagged, she said. A third project is helping the National Marine Fisheries Service to expand a project that uses aerial tracking from planes to study the movement of whales in New Jersey waters, she said.
Staff Reveals Error in GI Queue Studies; Clearing Backlog Still on Course
AURORA, Colo. — SPP staff publicly alerted stakeholders last week that it failed to conduct a tariff-required analysis of several generator interconnection queue study clusters as they reduced the backlog of GI requests dating back to 2017.
SPP’s Casey Cathey, senior director of asset utilization, quoted his late father, a salesman, as he broke the news some members already were aware of during the Markets and Operations Policy Committee on April 16. He said SPP discovered it “inadvertently” failed to conduct a contingent facility review for five clusters, beginning with the 2017-001 grouping through the 2020-001 collection.
“[My father] would say, ‘You don’t lose customers by making mistakes; you lose customers in how you handle those mistakes,’” Cathey said. “We made a mistake. That’s just plain and simple.”
SPP plans to handle this mistake using two processes dependent on the cluster study’s progression. Once SPP has determined which interconnection requests in the affected clusters are contingent on previously assigned network upgrades, it said generator interconnection agreements will have to be amended to include the contingent facilities.
Until then, GI requests in the affected clusters that were not identified by SPP during the study process may be contingent. Those projects may be subject to limited operations until the contingent facilities are in service. Additionally, requests in the clusters in question could be assigned the cost of those facilities should higher-queued GI requests not build them.
“This is a big deal, and it’s a big deal with a number of tentacles to it,” the Advanced Power Alliance’s Steve Gaw said. “When this first came out, it really did send shock waves through the developer community. We are still in the mode of dealing with, ‘What does this do?’
“What we want we don’t know yet, and what’s going to be yet to develop is what the ultimate impacts are to the generation that’s in this queue, and to the investments that have already occurred,” he added.
The grid operator includes clearing the GI backlog of all requests submitted through 2022 by the end of the year as a priority for 2024. According to a timetable, it would post the last contingent facilities remedy, for the 2020-001 cluster, in August. The active queue contains 421 requests for 87 GW of capacity; it numbered 1,139 requests for 221 GW when the backlog-clearing effort began.
“We’re still very much pushing to make that goal by the end of this year,” Cathey said. “We have to resolve this. We recognize how important this is and we have to resolve that in a way that minimizes the impact to the customers.”
He said SPP will post contingent facilities cluster study reports and amend GIAs as required. Developers with GI requests should review all their projects, especially those in affected study groups, he said. Those nearing commercial operating dates or subject to 0 MW due to contingent facilities can request the RTO perform a limited operation system impact study (LOSIS), with a group LOSIS offered to those in service or expected to be in service within 18 months.
“This is a serious error and we’re working with the developer community to come up with a very tight remedy plan to rectify this,” Cathey said, adding that he welcomes other novel ideas to accelerate the plan.
Record Tariff Changes?
Members took up 26 tariff revision requests during the two days, leading MOPC chair and ITC Holdings’ Alan Myers to posit that the number may be a record. The committee took no action on one of the RRs, but the other revisions and voting items passed with an average 96% approval.
A proposed revision incorporating western entities into SPP’s resource adequacy process when they join the RTO’s markets failed initially, securing only 53.4% of approving votes. When the motion’s language was amended to clarify that deliverability across the DC ties would only include firm transmission service, the motion passed with 83.1% approval.
MOPC also delayed action on RR620, which would implement SPP cost-allocation policies for Joint Targeted Interconnection Queue (JTIQ) projects. However, the RTO’s staff, transmission owners and SPP’s JTIQ partner, MISO, have been unable to reach consensus over the rate template in pursuit of a more efficient “direct billing” approach. The committee agreed to a conference call April 26 to wrap up the tariff revision, but the meeting was cancelled April 22. Staff said the work to finalize RR620 is ongoing.
SPP and MISO have agreed to assign 90% of the JTIQ portfolio’s $1.06 billion in costs for its five projects to generation. Load will cover the remaining 10%. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)
The committee endorsed five other RRs that, if approved by the board, would:
RR600.8: Add an incremental market-efficiency use charge to provide revenue offsetting incremental DC tie operations costs due to their market dispatch. The charge would be levied proportionally to all market participants’ activity, including those with export and virtual transactions.
RR605: Define an authorized outage and criteria, add requirements for resources’ availability during both the summer and winter seasons (unless on an authorized outage), help load-responsible entities and generation owners better understand when to submit resource adequacy (RA) capacity when providing workbooks to meet the RA requirement.
RR608: Allow new generation resources to operate with fewer restrictions during seasons where interconnection studies did not identify transmission constraints prior to the completion of all network upgrades, while still restricting those generators in seasons where interconnection constraints were identified.
RR612: Modify the multiday economic commitment to allow long-lead resources to receive market commitments for purposes beyond reliability.
RR616: Ensure any outage not approved by the SPP balancing authority and not an outside management control event is accounted for in performance-based accreditation (PBA).
MOPC also approved separate measures imposing resiliency options and correlated changes to the 2025 Integrated Transmission Plan and removing the voltage stability analysis from the 2024 ITP study. It also endorsed a price-formation policy to dispatch resources based on the true obligation and price the system using the obligation without the impact of the load shed and emergency pricing assistance.
SPC OKs Forecasting Task Force
Meeting after MOPC, the Strategic Planning Committee endorsed staff’s recommendation to create a task force to improve regional load forecasting that tends to come up short.
Staff said even its lowest scenarios for peak load in winter forecasts exceed members’ load expectations for resource adequacy. Summer load forecasts during ITP submissions exceed the lowest growth assumptions and remain below trends for more rapid growth, they said.
“Can we be better?” SPP’s Cathey asked, drawing responses of agreement from several members. “From a regional perspective, it’s 100% driven by the responsible entities and populated by members, so it’s fully through member input. The question is, how can we put a little bit more attention to this to get a little bit more accuracy in the use cases and providing better data with changing, unconventional loads?”
Pointing out that some members have more sophisticated tools than others, “depending on the size of their shop,” Cathey said staff has reached out to some members as well as SPP’s fellow grid operators to gather data for the task force. He said SPP intends to keep the task force’s membership small, but open, and focused on employees with planning responsibilities.
Cathey said staff believes defining improvements to regional planning would take eight months. He promised a checkpoint at year’s end, with some long-term solutions handed to other stakeholder groups.
The SPC meeting was conducted with a somewhat unusual seating arrangement. The committee’s leadership headed a U-shaped arrangement with SPP’s rostered members. Behind the main table, another U-shaped arrangement gave interested onlookers a view of the backs of the committee leadership’s heads.
“Sorry, I have worked my way up from coach in the back,” quipped SPP’s Robert Fox, director of enterprise architecture, as he belatedly joined the main table to comment.
Last MOPC for Dowling
The MOPC meeting was the last for Midwest Energy’s Bill Dowling, who is retiring after 39 years sitting in the committee and other SPP meetings — or, as Midwest’s vice president of engineering and energy supply said in referring to the number of years he has spent with the RTO, “a lot.”
Myers began the meeting by singling out Dowling for recognition. Like Myers, Dowling has served as the committee’s chair.
“I’ve gotten to know a lot of really great people,” he said. “It’s been a pleasure working with some really smart people. It makes me look good.”
Committee Consents to 19 RRs
MOPC’s unanimous approval of the consent agenda endorsed 19 RRs, 10 of which will go to the board for further consideration:
RR555: Adds requirements to the operating criteria addressing FERC cold-weather recommendations.
RR600.7: Integrates western entities seeking RTO membership under SPP’s terms and conditions with updates that include a DC tie access charge.
RR600.9: Adds a separate balancing authority area on the western side of the DC ties to the SPP BA.
RR600.10: Awards auction revenue rights and transmission congestion rights to the alternating current portion of transmission service that cross DC ties between the Western and Eastern Interconnections. Settling the rights will occur in two stages, with the AC portions settling in the respective interconnection.
RR600.11: Renames the tariff’s Attachment AN to Addendum 1 and adds language specific to western entities joining SPP as members of the West BAA.
RR600.12: Includes a separate BAA on the western side of SPP’s DC ties and other necessary market design clarifications adding policies necessary to integrate western parties into SPP.
RR600.13: Bases some rates for point-to-point and network service on the western side of the DC ties and the associated revenue distribution on the amount of annual transmission revenue requirement specific to the facilities in an interconnection. This accommodates Western Area Power Administration’s Upper Missouri and Rocky Mountain Region zones, which have facilities in both interconnections.
RR600.14: Adds language clarifying West DC ties as constraints, similar to other transmission constraints that are part of the market power test and frequently constrained areas validations.
RR600.16: Revises contract services agreements with WAPA-Upper Great Plains by removing language related to the Western Energy Imbalance Service market and narrowing the list of WAPA-UGP facilities to only those that are and will remain in the NorthWestern Energy BAA.
RR607: Implements the Regional State Committee’s change to the tariff’s safe harbor provisions, from 125% to 100% plus the higher of summer or winter season planning reserve margin plus 10% (but not less than 125%).
NEW YORK ― In recent years, fossil fuel industry leaders have been extremely careful and strategic with the words they use when talking about the role that, in their view, the industry should play in the global energy transition. Public messaging has argued for a “low-carbon” future, rather than no carbon or even net zero.
A series of presentations and panels on the second day of the annual BloombergNEF Summit last week provided a measure of the industry’s success in crafting a narrative based on a “balanced” and well-paced transition that includes cutting its most egregious emissions ― methane ― and scaling carbon capture and storage technologies.
For methane, the focus is first on accurately measuring emissions that clearly have been underestimated and then developing best practices that will allow the industry to certify that its natural gas is “responsibly sourced.”
Scaling carbon capture is simultaneously a more pressing and difficult challenge. BNEF predicts the still-emerging sector for direct air capture (DAC) must be able to suck 1 billion tons of carbon dioxide out of the atmosphere by 2050, but the current pipeline of projects will capture only 11 million tons by 2030.
CCS, used for capturing emissions from fossil fuel plants and other hard-to-abate industrial facilities, has a stronger pipeline, with federal and private backing for a range of projects, from a demo at a U.S. Steel plant in Indiana to a major multistate effort gathering emissions from 57 ethanol plants.
The subtext throughout was that the industry’s approach to decarbonization is bottom-line-driven and based on its traditional business models.
The Industry Argument
Her job title notwithstanding, Anna Mascolo, executive vice president of low-carbon solutions at Shell, deftly avoided the term “low carbon,” talking instead about a “balanced” transition to “lower-carbon” technologies. Similarly, she spoke of Shell’s “traditional business,” not fossil fuels, oil or gas.
The energy transition “is not a switch you can do on [or] off,” Mascolo said in an onstage discussion April 17 with Alix Steel, co-anchor of Bloomberg Markets. “We need to deliver energy today for our customers and then help them transition towards the lower-carbon options.”
Joining Mascolo and Steel, Jeff Gustavson, president of Chevron New Energies, argued for a longer-term, all-of-the-above energy transition. “The energy system has always been in transition, and typically, it’s not one energy source completely replacing another source,” he said.
Both Shell and Chevron have set targets for becoming net-zero businesses by 2050.
But as the demand for energy and the global population continue to grow, so will the need for reliable, affordable and “ever cleaner” power, Gustavson said. “To grow these new global businesses, we need collaboration; we need to lower the cost of these resources; and we need all of the capabilities that companies like ours have today and more to make this successful.”
He pointed to CCS projects Chevron has in the works ― often partnering with other companies, including Shell ― where the company can use its “deep … technical, commercial [and] operating capabilities.”
Shell is looking for markets in transition where “we feel we can play [to] our strengths,” Mascolo said; for example, the niche market for lower-carbon aviation fuel. “We won’t be everything for everyone, and we’re looking for products as well as customers in sectors where we can really have a competitive advantage and … [can] build on the current customers we have today.”
The company also is focused on “making sure [it] gets the pace right,” Mascolo said. “So, then you are investing as your customers progress and as society progresses, as the regulatory environment progresses, and then the utility position is different in different places.”
Last year, Shell invested $5.6 billion in low-carbon solutions, or about 23% of its capital spending, Mascolo said.
Gustavson said Chevron continues to be “inundated with opportunities” in the low-carbon sector, but to invest billions in any new technology, the company expects to see “attractive returns. So, for us, that’s double-digit returns. …
“We look for two things,” he said. “Will it scale? Is it a solution that works? And that comes down to cost primarily. And do we offer something that adds value,” where the company can use its capabilities for competitive advantage?
Right now, the answers to those questions are “yes” for renewable fuels, hydrogen and CCS, he said.
“Scaling CCS is the next challenge, and I see that happening in the years to come,” Gustavson said. “Hydrogen is the most exciting. It’s also the hardest to effect because you’re changing an entire energy system and entire value chain, from production [and] transport to consumption.”
Methane
With 84 times the warming power of carbon dioxide but a much shorter lifespan, methane sets the pace of global warming and could have a major impact on whether the world’s nations can limit climate change to 1.5 to 2 degrees Celsius, said David Doherty, BNEF head of oil and renewable fuels research.
The problem, he said during his April 17 talk, is that methane emissions are difficult to measure and therefore almost universally underestimated.
EPA has produced two different measurements of methane emissions, one from its Greenhouse Gas Reporting Program (about 3 million metric tons (MMT)), and another from its inventory of greenhouse gas emissions (close to 9 MMT), according to BNEF.
Those figures may not include outliers, such as super emitter events in which significant amounts of methane are emitted in a short period of time. Super emitters account for only 5% of emission events but as much as 50% of emissions, Doherty said.
Similarly, low-production, or marginal, wells pump out just 7% of the nation’s oil and gas but make up 80% of total wells, and they also produce “a disproportionately large amount of methane,” Doherty said. He cited a study from the Department of Energy, which found that marginal wells produce an estimated 1 million tons of methane emissions per year, 60% from natural gas and 40% from oil.
BNEF estimates that super emitters make up 5% of methane emitting events but about 50% of methane emissions. | BNEF
The reason for this wide range of figures is that counting methane “is very complicated,” Doherty said. “It works off of a series of very simplistic estimations and assumes that business is operating as normal, continuously, with minimal methane leakage. We know this is actually not the case. …
“You can have a barrel of oil with very similar specifications but completely different methane emission profiles,” he said.
Getting a solid grip on methane emissions will require a set of best practices, such as the standards developed by the U.N.’s Oil and Gas Methane Partnership (OGMP) 2.0, which includes 95 oil and gas companies producing 35% of the world’s oil and gas.
The partnership has developed a five-phase, measurement-based reporting system, going from country or state level to specific site level, backed up with satellite or other monitoring systems, Doherty said.
Using OGMP figures, BNEF estimates that in 2024, 45% of U.S. gas will be certified as “responsibly sourced” or gas with a low methane footprint, which could provide a price premium as “emission-savvy and emission-sensitive buyers” seek out low-emission gas, Doherty said.
Certainly, greater scrutiny of methane emissions is coming, and companies that have yet to do so might want to get to work on measuring their methane footprints, he said. “Because if you don’t, somebody else is apt to do it for you.”
Direct Air Capture
Getting a clear idea of 1 billion tons of CO2 requires a serious exercise of the imagination, according to Brenna Casey, a BNEF carbon capture analyst.
BNEF’s target for DAC by 2050 is “equal to roughly 175 million male African elephants,” Casey said during her April 17 presentation. Lining them all up, trunks to tails, “you could stretch from the Earth all the way to the moon and then some.”
Right now, the sector is nowhere near on track for that target, she said. “All the direct air capture capacity is limited to these small-scale plants,” Casey said. The largest is Climeworks’ Orca plant in Iceland, which is capturing 4,000 metric tons (MT) of CO2 per year, she said.
The largest in the pipeline is 1PointFive’s Stratos project in Texas, which broke ground in June 2023 and will be able to capture 500,000 MT of CO2 per year when it is slated to come online in 2025. 1PointFive is a subsidiary of Oxy, formerly Occidental Petroleum.
According to Casey, scaling DAC likely will depend, first, on developing technologies that bring down cost and, second, building a market for the carbon credits produced by the monetization of the carbon captured and stored.
Early DAC projects have used amine and absorbent technologies, while other developers are working with metal oxides and zeolites, Casey said. Used in the Orca plant, amines are based on a derivative of ammonia and can capture carbon molecules. Zeolites combine silicon, aluminum and oxygen and can be used to absorb CO2.
The main difference between older and new DAC technologies is their energy use. Metal oxides and zeolites require about a third less power than amines and other older absorbent methods, according to BNEF.
BNEF pegs the average price for DAC right now around $1,100/MT. The target price point for reaching that 1 billion ton scale by 2050 is $100/MT, Casey said, with economies of scale and lessons learned through construction and operation playing a vital role in moving down the cost curve.
BNEF predicts that by 2050, demand for direct air capture projects will outstrip demand and prices will fall to about $100/MT. | BNEF
Most of the early, first-of-a-kind plants, like Stratos, are “large, fully integrated … like oil refineries in the sky,” she said. “So, they’ll achieve economies of scale naturally, but at the same time, this forfeits the ability to be highly modular, and we’re likely to see [lower] learning rates.”
Casey predicted prices for such projects to be about $200 to $300/MT. At least one obstacle to further cost cuts is a lack of a “leading technology,” she said. “So maybe the industry has to pick a winner and coalesce around one or two technologies and develop those supply chains in tandem.”
CCS, Make or Break
The case for CCS is rooted in the need to cut emissions from “hard to abate” industries such as cement and steel and has therefore been a focus for both federal and private funding. Technologies that can help move the sector down the cost curve will be vital for CCS as projects face make-or-break points, as detailed in another April 17 panel.
Kelly Cummins, acting director of DOE’s Office of Clean Energy Demonstrations (OCED), ran down a list of CCS projects that have received federal funding. Three of the seven hydrogen hubs OCED announced in October will be using “large-scale carbon capture,” she said.
OCED also recently announced $6 billion in funding for 33 industrial decarbonization projects, and “a large swath of those projects … are going to be using CCS,” she said. For example, Ørsted received funding for a carbon capture project that will turn the CO2 from an industrial plant into ethanol to be used to make an alternative fuel in the shipping and transportation sector, she said.
Projects in the private sector include U.S. Steel’s efforts to decarbonize its plant in Gary, Ind., which produces 5 million tons of steel per year, and the associated emissions, said Erika Chan, the company’s head of sustainability.
The company recently signed a memorandum of understanding with CarbonFree, a carbon capture developer focused on the industrial sector. According to CarbonFree, its technology will capture 50,000 MT/year at the Gary plant, turning it into nontoxic calcium carbonate that can be used for a range of manufacturing applications, from paper and plastics to building materials.
Summit Carbon Solutions has grabbed national headlines with its plans for a CCS project gathering CO2 emissions from 57 ethanol plants across Iowa, Minnesota, Nebraska and the Dakotas and transporting them via pipelines to an underground storage site in North Dakota.
CEO Lee Blank emphasized that local education and community engagement have been critical to getting the project close to shovel-ready, with 2,100 public meetings across the region. Summit now has about 75% of the rights of way it needs for the entire project, including 80% in North Dakota, he said.
But beyond cost and technology, Claude Letourneau, CEO of Canadian CCS developer Svante, said the industry needs a shift in perspective from the energy transition to an industrial transition that takes the whole CCS process into account, from collecting and transporting emissions to storing or reusing them.
The industry should focus on measuring and reducing the carbon intensity of emissions, he said. “Every single industry needs to have a carbon intensity target that is regulated, and then you’ve got to go down that curve over time,” he said. “You’ve got to manage the CO2 emissions associated with industries and … until we do this, it will be very difficult” to scale CCS.
FERC once again has said it needs more information on clearing price caps before MISO can proceed with sloped demand curves in its capacity auctions.
The commission issued a second deficiency letter April 23 on MISO’s plan to swap in sloped demand curves for its current vertical curve in its seasonal capacity auctions (ER23-2977).
FERC asked about the sloped demand curve design’s opt-out provision to preserve state authority and lack of clearing price caps, among other details, late last year. (See FERC Wants More Detail on MISO Sloped Demand Curve Plan.)
This week, the commission again zeroed in on MISO’s removal of its annual price cap for auction clearing prices as part of the move to sloped demand curves. It said it needs more explanation behind the RTO’s proposal to eliminate the yearly cap.
MISO has said once it implements the new curve design, the total annual price for a local resource zone could reach as high as four times the cost of new entry (CONE), depending on whether capacity shortages occur in all four seasons of the auction. However, the RTO has not explicitly listed an annual price cap in its new tariff language, telling FERC it is not necessary because its plan is clear that clearing prices will be capped at the seasonal CONE. It also said there’s only a small chance a zone would experience shortage conditions in all four seasons and if that occurred, the more-than-$1,300/MW-day prices that ensue would properly reflect an “extreme” situation.
MISO’s current auction design employs a 1.75-times-CONE price cap for a local resource zone. This year’s CONE averages $330/MW-day. The RTO has said its sloped demand curves would not allow prices to jump automatically to CONE values for small capacity shortages below reserve requirements, unlike the current, unyielding vertical demand curve.
Nevertheless, FERC asked MISO to shed more light on why it believes it is appropriate for prices to go as high as four times the cost to build new generation and how those price signals could incent more generation to show up.
FERC also asked for MISO to better explain why its current CONE cap would “degrade market efficiency and transparency when implemented with price-sensitive demand curves” like its sloped demand curve. The commission said it needed to hear more justification for the four-times-CONE construct versus the existing annual cutoff. It also questioned MISO’s stance that any “ex post adjustment of prices could lead to suboptimal resource adequacy outcomes.”
Projected load growth nationwide from data centers, electrification and increased domestic manufacturing will drive increasing demand for renewables through the next decade, NextEra Energy CEO John Ketchum said during the company’s first-quarter earnings call April 23.
“We believe the U.S. renewables and storage market opportunity has the potential to be three times bigger over the next seven years compared to the last seven, growing from roughly 140 GW of additions to approximately 375 to 450 GW,” Ketchum said.
Ketchum said the domestic solar supply chain is “much improved from two years ago,” asserting that manufacturing capacity has increased and inflationary pressures are easing.
“The U.S. will need a significant and growing amount of electricity over the next decade and beyond, a large part of which will be powered by new renewables and storage,” Ketchum said.
Ketchum said the ability to put solar and battery resources wherever needed will make them especially valuable in meeting demand from data centers in coming years.
The company reported that subsidiary Florida Power & Light placed in service 1,640 MW of solar in the first quarter, while NextEra Energy Resources had its best quarter for solar and storage origination, adding 2,765 MW to its backlog.
CFO Kirk Crews said FPL now owns and operates more than 6,400 MW of solar resources, “the largest utility-owned solar portfolio in the country.”
FPL’s 2024 10-year plan also doubled its battery storage deployment target compared to 2023, with the target now totaling 4 GW. The utility also plans to deploy 21 GW of solar over 10 years.
Crews also announced NextEra Energy Partners plans to repower an additional 100 MW of wind capacity, increasing its wind repowering target to about 1,085 MW through 2026.
Responding to a question about the potential of small modular reactors to help meet data center demand, Ketchum said he is “a real skeptic in SMRs coming into the picture to satisfy data center demand anytime in the near future. … SMRs are still a decade to 15 years away.”
NextEra reported GAAP net income of $2.27 billion ($1.10/share) for the quarter, an 8.72% increase over the same quarter last year. This was off a 14.67% decrease in total revenue for the quarter from last year’s $6.716 billion.
Citing “significant new headwinds” to securing energy resources, participants in the Western Resource Adequacy Program (WRAP) are seeking to delay the program’s “binding” penalty phase by one year, to summer 2027.
Members of the voluntary program run by the Western Power Pool (WPP) face a May 31 deadline to commit to binding operations for summer 2026.
Once committed, participants will be at risk of incurring significant penalties for coming into a binding season with capacity deficiencies compared with their “forward showing” of promised resources for that season. The penalties are based on a formula set out in the WRAP tariff, which FERC approved in February 2023.
“Some WRAP participants have expressed concerns about their ability to meet WRAP forward-showing requirements in the next few years,” members of the WRAP’s Resource Adequacy Participants Committee (RAPC) said in an April 22 letter addressed to “Western Stakeholders.”
“They are understandably concerned, due to the reasons outlined [in the letter], about moving into binding operations given the potential magnitude of deficiency charges currently included in the tariff,” the RAPC wrote.
Those reasons include:
“supply chain issues and other challenges” that “have slowed our ability to deliver and interconnect new resources”;
regional peak load growing at a rate “faster than previously expected, driven primarily by electrification and data center expansion”; and
“extreme weather events” that have “further challenged” the region’s assumptions about the volume of resources necessary to maintain reliability.
The RAPC wrote that the WRAP “remains a critical tool” for addressing those challenges, having “shown its value by helping quantify where we stand and where we need to go.”
“We plan to continue our best efforts to acquire and interconnect sufficient new resources to meet load growth as we strive to meet WRAP’s regional resource adequacy metrics,” it said. “We have been actively engaged in conversations with each other and Western Power Pool about when a critical mass of participants can enter binding operations of WRAP together.”
The WRAP tariff gives the WPP the flexibility to begin binding operations between 2025 and 2028. That means the RAPC’s request to shift the start date to 2027 is subject to stakeholder approval but would not require a tariff change.
“Once the revised transition plan is ready, we will submit the plan for consideration by stakeholders and the WRAP Board of Directors, following the WRAP governance process,” the RAPC wrote.
Seeking ‘Critical Mass’
In a statement responding to the RAPC letter, WPP CEO Sarah Edmonds said her organization has “worked closely” with WRAP members as they’ve considered their decision and will continue to work with them on a proposal for transitioning to binding operations.
“Our goal has always been to have a critical mass of participants in a binding program so that the West will be able to address urgent reliability needs,” Edmonds said. “That has not changed, though when and how we get there may look different than planned. Like the participants, our efforts will be focused on gaining commitment from a critical mass of participants for summer 2027.”
In a March 2023 briefing of the WECC Board of Directors, Edmonds said she hoped to see the WRAP become binding as soon as possible, but she acknowledged the binding phase still could be years away. (See WPP CEO Looks to ‘Earliest Possible’ Binding Season for WRAP.)
“To be candid, some load-serving entities are in better shape to go binding than others. Others need a little more time to adjust their procurement strategies and their positions relative to what they see coming at them,” she had said.
The WRAP participants’ move for a one-year delay indicates the RA situation in the West likely has deteriorated significantly since then.
“There is a legitimate question about whether the West will have adequate resources in the years to come. WRAP is the only regional program that specifically addresses that question,” Edmonds said in her April 22 statement.
She said WPP now will focus on how to “collect more and better data from participants” for use in “more transparent regional discussions about events where capacity is constrained as we work toward going binding.”
Role in Broader Markets
While the WPP developed the WRAP and oversees its governance, the program’s technical operations fall to SPP, whose Markets+ day-ahead offering is competing for Western participants with CAISO’s Extended Day-Ahead Market (EDAM).
Under the tariff SPP filed with FERC last month, Markets+ participants would be required to participate in the WRAP. That integration was cited by Bonneville Power Administration staff in their recommendation this month that the federal power marketing administration choose the SPP-run market over EDAM. (See BPA Staff Recommends Markets+ over EDAM.)
“WRAP has become the dominant resource adequacy program outside of California,” BPA staff said in their recommendation. “The EDAM proposal does not propose a uniform adequacy metric or require EDAM entities to participate in a resource adequacy program. Bonneville staff supports and prefers the clear and consistent requirement that all Markets+ [load-responsible entities] must participate in WRAP, which better supports regional reliability.”
The WPP has not weighed in on the competition between Markets+ and EDAM, instead emphasizing the need for the West to have a sound platform for reliability.
“We welcome the various markets in development or under discussion in the West, but their benefit comes with the efficient and economic dispatch of resources at times of need,” Edmonds said in her statement. “That only works if there are adequate planned resources available to dispatch.”
President Joe Biden on April 22 announced $7 billion in funding from the Inflation Reduction Act, to be used by states and nonprofits across the country to install solar in low-income and disadvantaged communities.
The Solar for All grants, part of the IRA’s Greenhouse Gas Reduction Fund, will fund 60 programs aimed at installing solar on low-income single-family and multifamily homes, as well as building community or shared solar programs that target consumers, such as renters, who cannot put solar on their roofs.
EPA, which is administering the program, estimates that Solar for All projects could save more than 900,000 households in low-income and disadvantaged communities $350 million annually.
Consumers who sign up for community solar programs typically receive credits on their utility bills. The selected awardees all have committed to providing at least 20% savings on utility bills for all households served by their projects, according to a senior administration official speaking on background.
Speaking in Prince William Forest Park in Virginia, Biden estimated households benefiting from Solar for All projects would save about $400 per year on utility bills.
“Energy costs are among the biggest costs for families … particularly for middle-income families,” he said. “In fact, low-income families can spend up to 30% of their paycheck on their energy bills. It’s outrageous.
“Solar for All will give us more breathing room and cleaner breathing room.”
The program also could add about 4 GW of distributed solar to local electric systems while cutting the equivalent of 30 million metric tons of carbon dioxide, according to EPA.
EPA Deputy Administrator Janet McCabe provided a breakdown of the funding during an April 19 press call: $5.5 billion will go to 49 state-level awards, $500 million to projects in tribal communities and $1 billion to multistate organizations serving low-income communities not well served by the private market.
Grant amounts range from $43.7 million to $249.8 million.
The multistate grants will “focus on low-income communities; communities around historically Black colleges and universities, Hispanic-serving institutions, and tribal colleges and universities; households served by rural and municipal electric co-ops; families in the industrial heartland; and low-income customers who are unable to build rooftop solar but could still benefit from community solar,” McCabe said.
The Clean Energy Fund of Texas will partner with the Bullard Center for Environmental and Climate Justice at Southern Texas University to provide technical assistance and grants for community solar projects in “low-income and disadvantaged communities on the frontlines of energy policy and grid vulnerability challenges,” according to EPA.
These projects also could include energy storage, to deliver “grid and community benefits by powering community resilience centers,” EPA said. While based in Texas, the program will fund projects in 19 Mid-Atlantic and Southeastern states, from Pennsylvania to Texas.
“EPA’s Solar for All awards will mean that low-income communities, and not just well-off communities, will feel the cost-saving benefits of solar,” John Podesta, White House senior adviser for international climate policy, said in a statement.
“Residential solar electricity leads to reduced monthly utility bills, reduced levels of air pollution in neighborhoods and ultimately healthier communities,” said Adrianne Todman, acting secretary of the Department of Housing and Urban Development.
Biden noted that Prince William Forest Park, now part of the National Park System, originally was developed by the Civilian Conservation Corps, a jobs program President Franklin D. Roosevelt launched in 1933.
The CCC was part of the inspiration for the American Climate Corps, which Biden also announced would accept applications for its initial 2,000 positions via a new website. First proposed in 2021, the initiative aims to provide corps members with jobs and training to mitigate climate change.
As part of the corps, they also will be able to access the North America’s Building Trades Unions’ (NABTU) apprenticeship-readiness program, Biden said. And the U.S. Office of Personnel Management will expand eligibility for federal employment to individuals who have completed qualifying career or technical education through Climate Corps programs.
Reactions
Clean energy and environmental advocates were mostly supportive of Solar for All while also warning of potential obstacles ahead.
Jeff Cramer, CEO of the Coalition for Community Solar Access, said the $7 billion in federal funds could “unlock multiples of private capital. … Community solar is a critical tool in the broader toolbox of distributed solar options for American households.”
Chelsea Barnes, director of government affairs and strategy for the nonprofit Appalachian Voices, called the program “a game-changer for so many under-resourced and environmental justice communities seeking a more sustainable, reliable, democratized energy system.”
“For vulnerable households that depend on electricity for their health and security, the solar and battery storage systems resulting from Solar for All could act as a literal lifeline during times of emergency,” said Marriele Mango, project director for the Clean Energy Group, which will receive funding from Solar for All as part of the Community Power Coalition.
But “smart state energy policies and streamlined implementation will determine whether American families ultimately see the savings from Solar for All on their electric bills,” said Harry Godfrey, managing director at Advanced Energy United. He pointed to “lengthy and burdensome interconnection requirements, bureaucratic permitting processes, and state energy policies and regulations that undervalue or simply obstruct community and distributed solar.”
In addition, awardees still must negotiate and finalize agreements with EPA before they can access the funds. EPA estimates all contracts will be finalized by Sept. 30.
FERC is set to vote on its long-awaited proposed rule on transmission planning and cost allocation for regional lines at a special open meeting May 13, the commission announced last week ahead of this month’s usual meeting (RM21-17).
Parties who have worked on the rule spoke with RTO Insider and in other venues April 22 about what they expect to see from the commission.
“I want to make sure that it’s sufficiently strong so that planners really do plan for the anticipated resource mix; so they actually are required to consider all the factors of what that future resource mix looks like,” Grid Strategies President Rob Gramlich said in an interview. “I want to make sure there’s an actual decision that gets made about cost allocation.”
States should obviously participate in the cost allocation process, Gramlich said, but if they cannot agree, the process should not end there; FERC should do something to move the ball forward.
The two biggest precedents in FERC’s allocation regime can often come into conflict, former Arkansas Public Service Commission Chair Ted Thomas said on a webinar hosted by the Conservative Energy Network (CEN). The ideas that beneficiaries pay, and costs are commensurate with benefits, can often clash.
If a group is having dinner at a restaurant and only one diner orders dessert to share with the table, that person effectively caused the cost, but anyone who has a morsel will be a beneficiary, said Thomas, who runs a consulting firm.
“These two principles are in conflict,” Thomas said. “Because it’s really hard to get everybody on board in the same way on the front end so that they’re all the cost-causers. But with 20/20 hindsight, when you can see that somebody benefits — well, under this other principle they’re supposed to pay. But at the end of the day cost allocation is always about negotiation.”
The rule will not change the fact that ultimately, states and other stakeholders need to negotiate over transmission cost allocation, Thomas said, but hopefully it will add guidelines to simplify that process.
The issue of cost allocation is one area where FERC’s internal debates have spilled out into public somewhat, with Commissioner Mark Christie repeatedly saying he does not want to see one state pay for another’s policies, most recently in response to a letter from a group of congressmen led by Rep. Andrew Garbarino (R-N.Y.).
“It would be grossly unfair for FERC to force consumers in other states to pay for projects implementing the policies of politicians they never got the chance to vote for, when their own states’ policymakers have not agreed to pay for those projects,” Christie said in his response. “Such an imposition is contrary to American principles of democracy, a core principle of which is that the people have the right to elect the policymakers who impose costs on them, so the people can hold them accountable.”
Commissioner Allison Clements wrote less in response to Garbarino, but she argued that the costs of failing to invest in the grid, from customers facing huge bills from last-minute reliability needs to economic development going elsewhere, need to be considered.
“The risks and costs of declining to plan holistically for a modern grid may far outweigh the short-term lure for states to ‘go at it alone’ from a transmission planning perspective,” Clements wrote.
While public policy has generated plenty of debate beyond two of FERC’s three commissioners, Clean Energy Buyers Association Senior Director Bryn Baker told the CEN webinar that is not a focus of the proposed rule.
“Public policy — I think we need to be clear that unless there’s a dramatic reversal, is not in the list of things to evaluate the need for these lines,” Baker said. “It’s not in the goal as one of those metrics. I think that was a smart decision.”
State renewable portfolio standards are not driving as much of the need for new transmission as the corporate renewable energy buyers that CEBA represents are, she added. Coupled with growing demand, getting enough supply online to secure new industries that face international competition should be key goals when considering building out the grid, she said.
MISO’s Multi-Value Project lines have helped bring online many new renewable generators, but those were much less focused on policy than reliability and economics, Gramlich told RTO Insider.
“The state policies, even in MISO, weren’t even really binding,” Gramlich said. “They would have had the same results even if they completely ignored them. So, the point is, look at the economics of generation and anticipated additions and retirements over this 20-year period. And then design the network that achieves the lowest delivered costs for consumers; and any region should be able to do that.”
Thomas said that Arkansas did give up some of its authority when it pushed Entergy into MISO, but he said that the deal was worth it.
“Do I worry about state jurisdiction? I really don’t,” Thomas said. “Particularly if you’re in a … market already, there’s some jurisdiction you give up to save $50 million a year. … You’ve bound yourself to work with other states that share these resources. But for $50 million a year that goes straight into ratepayers’ pockets, it’s worth it.”
MISO might be ahead of the other RTOs when it comes to planning, but Thomas said it was in a class of organizations that could all use improvements.
While the devil is in the details, the broad strokes of FERC’s proposal requiring proactive planning have wide support, as 174 organizations, including 59 consumer groups, supported the rule in their comments to the commission, Gramlich said.
The Future of Transmission Competition
Another issue dividing stakeholders is FERC’s proposal to pull back on Order 1000’s elimination of the federal right of first refusal for regional transmission lines, finding it caused incumbents to focus on local projects not subject to competition.
Many utilities want to see FERC at least stick with that proposal, while supporters of competition are going to appeal if the commission follows through with it.
“So, No. 1: FERC has got to tackle the competitive transmission issues they’ve teed up and re-examine rights of first refusal,” WIRES Group Executive Director Larry Gasteiger said in an interview. “I think if that’s not in there, it would kind of be a major disappointment.”
FERC has acknowledged that Order 1000 is not working correctly and the policies around ROFRs need to be reformed, he added.
The opposite needs to happen, according to Paul Cicio, chair of the Electricity Transmission Competition Coalition, made up of firms engaged in competitive transmission development and consumer groups.
“If [FERC] doesn’t embrace competition; if it doesn’t enforce Order 1000, this will be most likely the most costly consumer rule in history,” Cicio told RTO Insider. “And it’s because of the sheer magnitude of the amount of capital that is and will be spent on transmission going forward.”
Competition can serve to contain the costs of transmission, which has granted very healthy returns that stay in place for decades, he added. The price of electricity has outstripped the Consumer Price Index in terms of inflation, and in cheap natural gas and other forms of generation, transmission and distribution costs have been rising, Cicio said.
The returns on investment of 10 to 12% are very high when compared to the manufacturing industry, which Cicio also represents, and he would like to see FERC tackle cost-containment issues more generally.
Cost containment came up in many of the comments, but Gasteiger said it was not really addressed in the proposed rule.
“We’re hoping that they don’t try to add it in now, given that they haven’t really provided notice on it,” Gasteiger said. “But I know there was a lot of pressure from different commenters for FERC to weigh in on that issue.”
Any rule of this scope from FERC is guaranteed to be challenged in court; ETCC has already said it would appeal the final rule if the commission reinstates the federal ROFR, which Cicio reiterated. (See Pro Competition Group Plans to Sue if FERC Reinstates Federal ROFR.)
The Reserve Certainty Senior Task Force (RCSTF) is considering two proposals from PJM and the Independent Market Monitor aimed at improving the performance of reserve resources.
Stakeholders have been tackling reserve performance since the response rate for committed resources has fallen after a market redesign consolidated the Tier 1 and 2 synchronized reserve products and lowered the offer cap from $7.50/MWh to 2 cents. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)
The PJM package would allow operators to modify the procurement targets for 30-minute reserves without having to do so for synchronized and primary reserves and create a formula for dynamically changing the 30-minute reliability requirement, PJM’s Emily Barrett told the RCSTF during its April 17 meeting. The calculation would use the larger of the primary reserve requirement, the largest active gas contingency and the average load forecast error, plus the average forced outage rate. The requirement is set at 3,000 MW, which was double the largest contingency when the requirement was established.
The changes would align the 30-minute reserve requirement with the breadth of operational risks dispatchers face and would grant flexibility to increase those reserves during periods of increased risks, such as harsh weather conditions, Barrett said.
PJM’s Lisa Morelli said staff will draft manual language and more details to present to stakeholders for a potential first read during the May 15 RCSTF meeting, with the intention of holding a vote June 12.
Monitor Focuses on Communications
The Monitor’s proposal would focus on getting reserve dispatch signals to generators in a manner that they can act on as quickly as possible. Joel Luna, of Monitoring Analytics, said the Monitor and PJM have been speaking with generation owners about the root causes of poor reserve performance since last spring and found that lags in communication can lead to generators not initiating their response until minutes after PJM has begun a reserve deployment.
Pointing to a synchronized reserve event Feb. 24, 2024, Luna said about 61% of the 1,882 MW resources deployed did not meet their assignment, of which he said 1,041 MW underperformed due to communication issues. Some units were waiting for a phone call from PJM to confirm their deployment. Others experienced lag between when the all-call signal was initiated by PJM and when it was received on their end due to how those generation owners relay signals between their control centers. And some experienced lag from the required switch to manual ramp from automatic dispatch signal.
The Monitor’s proposal would replace all phone communications used to convey deployment orders with automatic electronic signals and would include the deployment MW generators are being assigned through the existing security constrained economic dispatch (SCED) signals.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said many generators are being asked to run at a loss when providing reserves and compensation needs to be addressed alongside the communication issues.
“Prices need to reflect the system conditions, and clearly that’s not the case here,” he said.
Tom Hyzinski of the GT Power Group said adopting the Monitor’s recommendations could resolve some of the issues in the reserve market and clear the air to simplify addressing any remaining design issues. So long as all other options remain on the table should the proposal be endorsed, he argued there are no downsides to advancing the Monitor’s changes.
