A recently filed proposal by ISO-NE to increase the collateral requirements for generators with capacity supply obligations (CSOs) has received strong pushback from the New England Power Generators Association (NEPGA), which argued to FERC on Oct. 9 that the proposal would violate the filed rate doctrine (ER24-3071).
The policy changes are intended to reduce risks to the market of generators defaulting on pay-for-performance changes, which are accrued if a generator can’t meet its obligations during a capacity scarcity event.
“There is a significant risk to the New England Markets caused by the fact that many [forward capacity market] participants do not have adequate corporate liquidity to satisfy their contractual, financial obligations related to the CSOs they were awarded,” ISO-NE said.
The RTO filed three updates to the policy last year, which were all accepted by FERC. However, the last set of changes have proven controversial and faced significant pushback in the NEPOOL stakeholder process. Neither ISO-NE’s proposal, nor two amendments proposed by NEPGA, passed the two-thirds approval threshold required for NEPOOL support. (See NEPOOL Participants Committee Votes to Support Hourly GIS Tracking.)
ISO-NE is proposing to introduce a new corporate liquidity assessment that would assign each participant a risk level to determine the collateral requirements. The RTO projects the changes would increase market-wide financial assurance costs by $72 million to $90 million for the 2025/2026 capacity commitment period (CCP).
In response, NEPGA protested the effective date of the proposal but not the underlying changes. The association argued that the changes should not apply to existing capacity commitments and should instead take effect for the 2028/2029 CCP. The auction for this CCP will likely take place in early 2028, depending on the results of ISO-NE’s ongoing capacity auction reform project.
“The [financial assurance policy] changes, if applied beginning on June 1, 2025, as ISO-NE requests, would alter the legal requirements associated with capacity supply obligations assumed years ago in violation of the filed rate doctrine,” NEPGA wrote.
The filed rate doctrine prohibits retroactive changes to rates that have been approved. NEPGA argued that ISO-NE’s proposal would add costs for generators with capacity commitments which were not accounted for in the auction bids.
“Denying the opportunity to reflect the full cost of providing capacity by post facto changing the rules governing the costs of holding a CSO, is not just wrong from a policy standpoint, but could contribute to accelerated retirements,” NEPGA said.
“With announced retirements in New England already outpacing new entry over the coming years, exacerbating this mismatch undermines confidence in the market and consequently risks reliability and the resource adequacy of the region,” the group added.
NEPGA requested that if FERC accepts the changes, it should either direct ISO-NE to adopt a June 1, 2028, effective date or schedule a hearing to determine an adequate effective date.
ISO-NE argued its proposal “does not constitute a retroactive rate change” because the changes would not affect auction prices or capacity supply obligations.
It added that the changes are prospective, not retroactive, because they would take effect in June 2025 and would “not alter prior credit reviews or supplant previously calculated inputs into the formula for the [forward capacity market] delivery financial assurance requirement.”
ARLINGTON, Va. ― FERC Order 1920 eventually may provide a structure for long-term, interregional transmission planning, but the anticipated yearslong implementation of the rule could mean states will have to lead in planning for their nearer-term transmission needs, according to a new report from the American Council on Renewable Energy and The Brattle Group.
Rolled out at ACORE’s recent Grid Forum, the report focuses primarily on PJM’s Mid-Atlantic states, which are developing transmission for offshore wind and other renewables. New Jersey’s state agreement approach (SAA) ― in which the state’s Board of Public Utilities has partnered with PJM on project solicitations ― is seen as a model that could cut costs and interconnection times.
Brattle’s Joe DeLosa III laid out seven options states might pursue, ranging from following New Jersey’s lead with a single-state SAA with a single “driver” ― such as meeting state goals for offshore wind deployment ― to waiting for implementation of 1920.
Other SAA options include a single state agreement covering multiple drivers ― say, reliability and a renewable energy target ― and multiple states with single or multiple drivers. Outside of SAAs or 1920, the report looks at “voluntary solicitations” involving either single or multiple PJM states or interregional, multistate efforts, for example, bringing in New York or New England states.
“Building offshore wind at scale in the next decade is essential to meeting electricity demand in a clean and reliable manner, but transmission planning must start today,” said Evan Vaughan, executive director of MAREC Action, in an ACORE press release announcing the report. States must “set their own direction on transmission planning to address multiple needs — reliability, economic growth, clean energy deployment, extreme weather resilience — in the most efficient way possible.”
MAREC Action is an advocacy group representing utility-scale renewable energy developers in the Mid-Atlantic and Appalachia.
ACORE CEO Ray Long agreed that “time is of the essence, and our report lays out the opportunities for states to maximize the benefits of proactive planning, particularly for offshore wind.”
RTO Insider did offer PJM the opportunity to comment on the report, but a spokesperson said the RTO still was reviewing it and would “defer comment at this time.”
The SAA Options
The report sees state leadership as filling a critical gap in PJM’s planning processes.
“Despite recent stakeholder efforts, PJM’s transmission planning process has not yet evolved to the point where it is cost-effectively meeting multiple system needs, including the public policy goals of PJM states. This would require a more proactive and holistic planning approach,” the report says.
Brattle’s analysis of benefits of each approach comes down squarely on going with an SAA, which DeLosa said provides more flexibility. “We just recommend that if a state or states within PJM seek to lead transmission procurement, it makes a lot more sense for them to use the tariff structure and the experience of New Jersey and go with the SAA.”
To date, New Jersey has completed one solicitation under its SAA with PJM, awarding onshore transmission projects, but put a second solicitation on hold this year, according to a recent update from PJM.
Maryland’s Promoting Offshore Wind Energy Resources Act (SB 781), passed in 2023, required the state’s Public Service Commission (PSC) to ask PJM for an analysis of the transmission upgrades that might be needed for offshore and onshore wind. Meetings between PJM, the PSC and other state agencies are ongoing.
At the same time, the PSC has been talking with New Jersey and Delaware about the possibility of regional collaboration on transmission planning. But according to a recent report from the commission, each of the three states is at a different stage of analyzing and considering their options, making collaboration unfeasible.
DeLosa also sees potential for interregional planning between PJM and non-PJM states. “We believe it could be well utilized for targeted procurements, even over a broad geographic scope,” he said. “We envision so-called ‘low-hanging fruit’ projects … that are either well-known or somewhat advanced in their development that would kind of evidently provide benefits.
“If sufficiently targeted, we also believe a cost-allocation approach, which could be a key underlying element of this, could be developed [and] limited to particular projects and the associated benefits case.”
A major caveat for any of these approaches is the “leadership role that is required of the states, the ongoing project management responsibilities for the projects that have been selected,” he said. “They persist over a long period of time, and they don’t go away. … There needs to be some method of supporting the states so that they can actually meet the needs, the leadership needs … under some of these frameworks.”
FERC received dozens of comments on its advanced notice of proposed rulemaking (ANOPR) that would require broad use of dynamic line ratings across the U.S. transmission grid.
The ANOPR (RM24-6) proposes to require utilities to monitor hourly solar and wind conditions and a requirement to enhance data around transmission congestion outside of organized markets to see where DLRs might be cost effective. (See FERC ANOPR Seeks to Move the Ball Forward on Dynamic Line Ratings.)
Many utilities urged FERC to be cautious in mandating specific and additional requirements around DLRs, as the industry is still working to implement Order 881 on ambient adjusted ratings (AARs), which Edison Electric Institute noted comes with a July 2025 deadline. FERC also recently required transmission planners to consider DLRs as part of their compliance with Order 1920.
“EEI members are committed to deploying DLRs and other grid-enhancing technologies (GETs) where they are proven to be cost-effective and produce identifiable benefits for customers,” the investor-owned utility trade group said. “Where EEI members have implemented DLRs, they have been deliberate in their analysis and careful to ensure that costs do not outweigh benefits.”
The value of DLRs will depend on the accuracy and transparency of the line ratings used in AARs, but the industry lacks that benchmark since Order 881 has yet to go into effect, EEI said. FERC should allow some time for the industry to be comfortable with AARs because complying with two mandates at once would create overlapping deadlines, bottlenecks with limited vendors in the space, and tax utility employees working in the space, EEI said.
While the use of DLRs on the American grid has been largely at a pilot level, other commenters noted that the pilots have so far tended to show promise, and many European grids use the technology much more widely already. A group of clean energy trade associations — the Working for Advanced Transmission Technologies (WATT) Coalition, American Clean Power Association, Advanced Energy United and others — say that DLRs can help the industry deal with its most pressing problems.
“It is imperative that FERC act quickly to proceed to a Notice of Proposed Rulemaking (NOPR) and then a final rule requiring DLR under appropriate circumstances,” they said. “The urgent need for more transmission capacity is even clearer now than when FERC opened its Notice of Inquiry into the Implementation of Dynamic Line Ratings in 2022.”
DLRs would help to address lengthening interconnection queues, growing demand and the need to expand the transmission grid. Expanding the grid means shutting down parts of it as new transmission comes online, and DLRs can mitigate side effects there, the clean energy trade groups said.
“Utilities should use all cost-effective approaches to reduce the impacts of unforced and forced outages on ratepayers and markets,” they said. “Congestion and curtailment due to transmission outages should be straightforward to predict and calculate in production cost modeling (which should also be performed outside of RTOs), so an evaluation of GETs to address those outages should also be straightforward.”
A more exhaustive review of the 60-plus comments in the docket will be published in the coming days.
Dominion Energy’s 2024 Integrated Resource Plan, filed Oct. 15 with Virginia and North Carolina regulators, calls for major expansions of offshore wind, solar power and natural gas to meet surging demand in its territory.
The document lays out multiple portfolios to meet that rising demand through significant investments in new power generation, upgrades to the power grid, energy storage and efficiency. It does not seek approval for specific projects, but offers a long-term plan based on current technology, market information and load projections.
“We are experiencing the largest growth in power demand since the years following World War II,” Dominion Energy Virginia President Ed Baine said in a statement. “No single energy source, grid solution or energy efficiency program will reliably serve the growing needs of our customers. We need an ‘all-of-the-above’ approach, and we are developing innovative solutions to ensure we deliver for our customers.”
The IRP included bill forecasts for Dominion’s residential customers in Virginia, who now spend $142.77 a month for 1,000 kWh and could see their bills grow by between $72.85 and $161.13 by 2035.
Power demand is expected to grow 5.5% annually for the next 10 years and to double by 2039, according to a forecast by PJM, Dominion said.
Just under 80% of the plan’s proposed new generation over the next 15 years is carbon-free, including 3,400 MW of new offshore wind on top of the 2,600-MW Coastal Virginia Offshore Wind (CVOW), 12,000 MW of new solar, 4,500 MW of new battery storage and small modular reactors starting in the mid-2030s.
The CVOW project is proceeding on time and on budget, and Dominion has secured offshore leases nearby to build additional power plants. Those include 176,505 acres off Virginia Beach that could support 2.1 GW to 4 GW of wind power and an additional 38,964 acres off North Carolina that could support up to 800 MW.
The utility asked the Virginia State Corporation Commission in a separate filing to approve 1,000 MW of additional solar, which would bring its fleet to 5,750 MW in the state.
The remaining 20% of the plan’s power generation would come from natural gas, which Dominion said was a “critically important source of back-up power” to keep the lights on when wind and solar plants are not producing energy.
“Winter Storm Elliott showed the need for every generating unit in the company’s fleet to be dispatched to meet the system peak early in the morning when renewable resources were not producing energy,” the IRP said. “This type of extreme weather event threatens reliability and requires resources to ensure the company can meet customer demands.”
The company is modeling additional combustion turbines, which would function as quick-dispatch, balancing resources and combined cycle units that would operate more often, the IRP said.
The proposal to expand coal, which could mean nearly 6 GW of new fossil-fired power plants, drew opposition from some clean energy interests and environmentalists. Advanced Energy United noted that the Virginia Clean Economy Act requires the state to move to renewable energy and a fully clean grid by 2050.
“Dominion Energy’s latest IRP is a step in the wrong direction,” AEU’s Shawn Kelly said in a statement. “Instead of harnessing the potential of advanced energy to more reliably and cost-effectively meet Virginia’s growing energy needs and clean energy goals, this plan threatens to keep the state dependent on fossil fuels for decades. Dominion is missing a critical opportunity to lead Virginia’s clean energy transition, protect households and businesses from rising costs, and provide more resilient clean energy solutions for all Virginians.”
All four of the plans filed with the SCC would increase emissions, said the group Clean Virginia, which called for the IRP to be rejected.
“Dominion’s latest energy plan blatantly disregards the financial well-being and health of Virginia families,” Clean Virginia Deputy Director of Energy and Operations Kate Asquith said in a statement. “By continuing to invest in gas-burning facilities, Dominion is not just raising bills — it’s locking Virginians into a future of higher costs and greater pollution. This is unacceptable at a time when we need to be transitioning to clean, affordable energy.”
Utility-scale solar construction reached record levels across the United States in 2023 and its cost continued to decline, the Berkeley Lab announced in this year’s edition of its annual report on the sector.
A total of 18.5 GWAC of large-scale solar was brought online last year, bringing total installed capacity to 80.2 GWAC in 47 states, the report says, while capacity-weighted average installed costs decreased 8% to $1.43 per watt AC.
The levelized cost of electricity from these utility-scale photovoltaic systems rose slightly to $46/MWh, not counting tax credits, but decreased slightly to $31/MWh once the federal incentives were factored in.
For the first time ever, more than half of new grid capacity nationwide was solar — 17% distributed and 35% utility-scale.
The report predicts that 2024 will be another record year, with more than 35 GW of utility-scale solar and distributed commercial or residential solar installed.
A whopping 1.09 TW of utility-scale solar is stacked up in the nation’s interconnection queues, but historically, only 10% of requests ever advance to construction, the Lawrence Berkeley National Laboratory noted as it announced the new report Oct. 15.
Capital costs of building utility-scale solar generation have steadily decreased over the past decade, as measured by cost per output. | Lawrence Berkeley National Laboratory
The 2023 report and its executive summary drill down on the state of the utility-scale solar sector. Among the details, data points and conclusions:
Average energy and capacity value nationwide was $45/MWh; average market value ranged from $27 MWh in CAISO, where solar has the largest market share, to $67/MWh in ERCOT, where summer heat waves and record electricity demand were seen during peak solar production hours.
Only 4% of utility-scale PV capacity added in 2023 was installed on a fixed-tilt mount; the rest used single-axis tracking. Fixed-tilt is relegated mainly to challenging sites and least sunny regions of the Northeast; tracking mounts add 20 cents per watt to the cost on average but can boost capacity significantly in sunny regions.
Projects larger than 50 MW cost 13% less per megawatt on average than their counterparts rated at 5 MW to 50 MW.
Plant output still declines with age, but more recent projects are showing a slower decline than earlier projects did at the same points in their lifespans.
Projects in the regions with the lowest solar insolation have the highest levelized cost of electricity — ISO-NE and NYISO were $76 and $78/MWh, respectively — while the sun-rich ERCOT, CAISO and non-ISO West ranged from $37 to $42. (Project costs and size contributed to this disparity.)
Solar power purchase agreements have largely closed the gap with onshore wind PPAs — both were much more expensive 15 years ago, but solar PPA prices have declined more sharply than wind. Lower natural gas prices, meanwhile, have given existing combined-cycle gas-fired generators a near-term cost advantage over solar.
Concentrating solar thermal power has been lagging, with no U.S. installations since 2015. The newest of the existing installations have underperformed expectations.
With the recent completion of the first phase of the New Jersey Wind Port, the state’s offshore wind sector looks to take a key role in the East Coast turbine industry despite the closure of the state’s two most advanced projects, speakers said at the state’s annual OSW conference.
A year after Ørsted stunned state officials and abandoned the state’s first two offshore wind projects, New Jersey has adapted to changing circumstances and developers are better prepared to weather the still difficult environment, speakers said at the Time for Turbines conference Oct. 11 in Atlantic City.
Atlantic Shores Offshore Wind, now the most advanced project in the portfolio approved by the New Jersey Board of Public Utilities (BPU), is moving ahead with its previously approved project, Atlantic Shores South 1, and a second one, Atlantic Shores South 2, Joris Veldhoven, the developer’s CEO, told attendees.
The Bureau of Ocean Energy Management (BOEM) on Oct. 1 approved the two projects’ construction and operations plan. And the company is close to awarding the last contracts and subcontracts for the first project, he said.
Veldhoven, in what emerged as a central theme among conference speakers, cited developers’ need to secure a strong supply chain pipeline, and the state’s ability to provide it, as key factors in their ability to move projects to completion, and for the sector to advance.
“In the current market, it is so critical that we locate these packages,” Veldhoven said. “Having that maturity, having the certainty that the supply chain is for you, is absolutely critical.”
In some respects, the state’s OSW sector is better able to get projects done than in the past, because developers such as Atlantic Shores are “more aware of the supply chain risk,” he said.
Likewise, regulators have recognized — and adapted to — the financial pressures that developers can face, among them the rise in interest rates, he said.
“What regulators have done over the last few years, and kudos to them, here in New Jersey and other states, there’s now a bit more of these inflation adjustment mechanisms that take into account various factors, and they started to even take into account cost of money,” he said. “Is that perfect? No, it’s not. But it shares some of the risk.”
‘Miracle’ Port Advance
Tim Sullivan, CEO of the New Jersey Economic Development Authority, which oversees port construction and funds much of the state’s OSW initiatives, said completion of the first phase of the wind port shows the state is a serious player in the East Coast wind sector.
The fact the first phase of the project came in “on time and under budget,” he said, is “close to a damn miracle.”
Other state competitive strengths include a “steady diet” of new project procurements, a “real commitment” from Gov. Phil Murphy (D) and — in the EEW monopile factory in Paulsboro — the only manufacturing facility that’s active in the U.S. for offshore wind components.
“Despite having fallen behind on the generation side a bit, we’re going to catch up,” Sullivan said. “We are still in the best position long term, and we are investing for the long term. … This is not a one-, two-, three-, four-, five-year ambition. This is a 50-year ambition. A century-long ambition.”
Murphy has set a goal for the state to have 11 GW of OSW capacity by 2040. Atlantic Shores is one of three companies awaiting the BPU’s decision in the state’s fourth offshore wind solicitation, which is expected by the end of 2024. The state is preparing to launch a fifth solicitation in early 2025. (See 3 OSW Proposals Submitted to NJ.)
The BPU approved Ørsted’s Ocean Wind 1 in the first solicitation in 2019 and the developer’s Ocean Wind 2 in the second solicitation in 2021, in which the 1,510-MW first part of Atlantic Shores also was approved. The BPU backed two projects — the 1,342 MW Attentive Energy Two and Leading Light Wind, with two phases of 1,200 MW each — in the third phase and is expected to announce the designated projects in the fourth solicitation by the end of 2024.
That fourth solicitation allowed developers awarded contracts in the first or second procurement — of which Atlantic Shores is the only remaining project — to submit a rebid that would enable them to adjust for rising costs. Atlantic Shores took that opportunity and also submitted the second half of the project, Atlantic Shores South 2.
The other applicants awaiting the BPU’s decision are Attentive Energy, with a second project, and Community Offshore Wind, for a 1,300-MW project.
Supply Chain Building
Yet the sector still is challenging, as shown by the difficulty Leading Light Wind has experienced in finding an economically viable turbine. On Sept. 25, the BPU approved a request by developer Invenergy to delay the project by three months because none of the three turbine manufacturers initially selected by the developer — GE Vernova, Siemens Gamesa Renewable Energy or Vestas — are able to supply suitable new turbines.
Abby Watson, president of The Groundwire Group | Christian Fiore
Some projects are moving to mitigate risk and create key elements of their own supply chain, conference speakers noted.
Attentive Energy, which hopes to begin construction in two to three years and complete the project by 2031, is vying for space in the wind port, said Karen Imas, the company’s senior external affairs manager. If Attentive’s bid is successful, the company plans to execute project marshaling and work with a manufacturer to build a factory there, she said.
Attentive also has committed $58.85 million into the third phase of EEW’s Paulsboro factory building monopiles, part of the foundations of offshore turbines, Imas said in an interview with NetZero Insider after her panel.
The arrival of Attentive and other developers in a second OSW wave may make them better placed to handle future challenges, she said.
“We are able to maybe anticipate a little bit more supply chain, timelines, projections,” she said. “We bid in with a certain price that we think is realistic today, and you know, maybe that sets us up with a little more stability than those awarded two, three years ago.”
Mitigating Risk
Imas pointed to the developer’s recent partnership with the New Jersey Manufacturing Extension on a policy paper published in October analyzing the readiness of the state’s manufacturing sector to adapt to the needs of the offshore wind sector. The extension interviewed 18 manufacturers about their capacity and interest in shifting gears.
The study found the companies can “pivot and provide some of the materials, the widgets, the products that would be needed for the larger Tier One, Tier Two manufacturers,” she said. Yet the study also found that 66% of the companies interviewed would require “targeted funding for process or technology upgrades” to take part in the sector.
“They need some technical assistance,” she said. “They may need increased staffing. They may need some special certifications and trainings. And that pivot will take some work. So we as a developer are taking note of this survey and what’s been reported, because we want to work hand in hand with these companies and really help arm them with the tools they need to participate.”
Those kinds of supply chain challenges are enhanced by the steady advance of a wave of OSW projects from different states all moving head and seeking the same resources, said Abby Watson, president of The Groundwire Group, a consultancy that focuses on sustainable energy.
“We have a lot of projects now that are all looking at building within a fairly short period of a couple of years,” Watson said, speaking on a panel entitled “Navigating Choppy Financial Waters.” “And that is an incredibly challenging commercial environment in which to build a successful business case for a manufacturing facility that’s going to be viable in the long term.
“I think we’re seeing that in some of the ways that different states are kind of redesigning some of their procurements to emphasize viability” and looking for ways to “de-risk that project.”
NYISO on Oct. 16 presented its updated modeling for combined-cycle gas turbines that employ duct firing to produce additional electricity and advanced a motion to recommend that the Management Committee revise the tariff in accordance with the model.
Stakeholders were unhappy that NYISO did not factor multiple “ramp rates” into its model, which they fear could result in improperly applied penalties for over- or under-generating in response to dispatch. NYISO had included multiple ramp rates in its original considerations but dropped them during model development.
“Generators should not have to waste a lot of time and expense fighting an improperly applied penalty that results from … NYISO not recognizing the ramp rate that a generator has already given the ISO,” said stakeholder representative Mark Younger of Hudson Energy Economics.
“Let me be clear upfront: I have no assurances that resources that are dispatched in their duct from a less-than-feasible ramp rate reflection will not be subject to penalties,” said Shaun Johnson, director of market design for NYISO. “I will point out that there are some wrappers around those penalties that make it less likely.”
“I totally agree it’s less likely,” Younger said. “The problem I’m having is that it’s totally inappropriate if it ever happens.”
When the motion was raised, the New York Power Authority seconded but encouraged NYISO to figure out a way to satisfy the concerns. Younger voted in opposition, noting that the dropped multiple ramp rates was effectively “moving the goalposts” to say the project had been completed, when it hadn’t.
East Coast Power and two other stakeholders abstained from the vote. The overall motion passed with a “vote by exception.”
Background
NYISO has been working since 2022 to improve modeling it uses to better accommodate combined-cycle gas turbine generators equipped with duct firing. Current models don’t account for the additional power generated by plants that use the technology.
Combined-cycle gas turbines burn gas to spin combustion turbines. Exhaust gas is directed to a heat recovery steam generator to pressurize steam and generate power in a steam turbine. Plants with duct burners may burn additional fuel to heat the exhaust gas, which can help maintain the generation of the heat recovery steam generator.
In 2020, according to the U.S. Energy Information Administration, about 75% of the U.S. combined cycle plant capacity used duct burners. In New York, about 79% of the power generated from natural gas plants came from plants with duct burners.
Johnson said the tariff revisions represented an incremental improvement in the way NYISO models ramp rates for duct firing combined-cycle plants.
“It doesn’t address all scenarios, and we need to keep working on that,” Johnson said. “I understand your frustration that not all scenarios were fixed, but this is an improvement, and we want to proceed forward with the incremental improvement where we continue to work on future improvements.”
Clarification: A previous version of this article mentioned JERA Americas as abstaining from the vote. Marie Pieniazek, director of regulatory affairs for JERA Americas, said she was voting for East Coast Power, which is a NYISO market participant. JERA Americas is not a NYISO market participant.
CARMEL, Ind. — MISO maintains that a member request to create a multiday gas purchase requirement for use during extreme cold is unnecessary but offered financial assurances for resources whose commitments are canceled.
MISO’s Jason Howard said instead of a multiday fuel purchase requirement for market participants, MISO wants to develop two new financial guarantees to resources committed days in advance of upcoming grid situations.
The first would be a canceled startup cost provision, where a resource would be guaranteed a portion of startup costs depending on when MISO cancels within the startup window. The second would be an “as-committed/as-dispatched” lesser of settlements rule, which would move multiday commitments into the day-ahead solution of an effective operating day and allow generators to earn make-whole payments based on the lesser of a real-time or day-ahead offer cost.
“We feel these are ideal to provide more security and assurance to resources,” Howard said at an Oct. 10 Market Subcommittee meeting. He said the rules are simpler than instituting a multiday market and that they help members feel more comfortable when they must contract for gas.
“When you compare this solution to doing the necessary software changes in our settlements system, that’s a huge cost benefit,” Howard said.
Howard also said the rules’ wording will establish assurances that extend beyond gas units.
MidAmerican Energy Co. — which serves natural gas customers in Iowa, Illinois, Nebraska and South Dakota — had argued that owners of natural gas units “undertake significant risk in purchasing or not purchasing natural gas when natural gas supplies are very tight” and are faced with either capacity loss or financial loss. MidAmerican said on rare occasions, there isn’t any natural gas available to buy after next-day trading in some portions of MISO. (See MISO’s MSC to Debate Multiday Gas Requirements.)
While some stakeholders have said the time is right for such a requirement, others said they worried about over-procurement of gas and whether the requirement would lead to pricing spikes at hubs.
Howard has said MISO already runs a multiday reliability assessment and commitment engine — the RTO’s Forward Reliability Assessment Commitment process — every day to position generation owners for upcoming obligations.
MidAmerican representative Dennis Kimm said he was happy with MISO’s compromise. He asked if the guarantees could be in place for upcoming cold weather.
“It might be a tough sell for this winter,” Howard said, referencing the settlements and tariff changes the rules will require.
Kairos Power and Google have reached a first-of-its-kind power purchase agreement involving several units of the small modular reactor Kairos is developing.
The two companies announced Oct. 14 that Kairos would deploy the first of its small molten-salt reactors for Google’s benefit by 2030 and a fleet totaling 500 MW by 2035.
Google said the power purchase agreements are part of its larger effort to develop and commercialize advanced clean electricity technologies to run its offices and energy-intensive data centers.
Kairos said the deal will support the iterative process through which it is pursuing its first commercial deployments, with each reactor contributing learnings that will optimize subsequent plants.
This year, California-based Kairos began construction of a low-power demonstration version of its reactor design at Oak Ridge, Tenn.
It is the first non-light-water reactor permitted for construction in the United States in more than half a century. The U.S. Department of Energy will invest up to $303 million to support construction and commissioning of the reactor, which is expected to be operational by 2027.
Many companies have committed to renewable energy or signed purchase agreements for new generation. One of the largest such consumers is Google, which has signed more than 100 agreements totaling over 14 GW since 2010.
A few companies have begun negotiating supply agreements with operators of existing nuclear plants, eager for the reliable flow of zero-emissions electricity they can supply.
The Google-Kairos deal is on a different level, pinned on a developing technology long on promise but short on operational experience.
Advanced nuclear technology is gaining increasingly broad support as a potential solution to the dual need to produce electricity with less environmental impact. Small modular reactors (SMRs) add the tantalizing prospect of faster, more nimble, less expensive deployment.
SMRs potentially could be collocated with a large power user as a behind-the-meter power source and avoid the costs and delays that accompany grid interconnection.
However, SMRs still must complete their development cycles and emerge in a form that is affordable and commercially scalable, and will pass muster with regulators, investors and host communities.
The Google-Kairos announcement did not specify a price tag or location for the reactors.
Large-scale nuclear power has become extremely expensive to build in the United States, in part because so few reactors have been built in the past three decades.
If each project is a “first-of-a-kind,” or first-in-a decade, it is hard to develop the economies of scale and institutional knowledge that would be expected to benefit an “nth-of-a-kind” project.
The Department of Energy addressed the differences between FOAK and NOAK in the September update of its “Pathways to Commercial Liftoff: Advanced Nuclear” report. There are more than 50 unique designs among the 94 operating commercial reactors in the United States, almost all of which came online before 1990.
The report indicates SMRs are likely to cost more per MW to build than large reactors and have smaller overall price tags.
It flags the potential to achieve what Kairos is attempting to accomplish with its iterative development approach and vertical integration: “An SMR could complete FOAK construction and implement cost-saving learnings on the second-of-a-kind reactor.”
In a news release, Kairos CEO Mike Laufer said the agreement will help propel the company he co-founded in 2016:
“Our partnership with Google will enable Kairos Power to quickly advance down the learning curve as we drive toward cost and schedule certainty for our commercial product. By coming alongside in the development phase, Google is more than just a customer. They are a partner who deeply understands our innovative approach and the potential it can deliver.”
In its announcement, Google said its power procurement from multiple reactors will help Kairos bring costs down and speed up development and is part of a broader effort Google is making with other advanced energy technologies.
Kairos is designing a low-pressure, high-temperature reactor that will operate with molten fluoride salt heated to 650 degrees Celsius. Its KP-X demonstrator will be a single unit rated at 50 MWE, and the KP-FHR commercial version will be dual units rated at 75 MWE each.
They are sized to ease manufacturing and construction of components.
The Union of Concerned Scientists released a paper Oct. 15 arguing the electric industry should focus on expanding renewable energy aided with storage rather than keeping natural gas plants running with hydrogen, biomethane or carbon capture and storage (CCS).
“Beyond the Smokestack: Assessing the Impacts of Approaches to Cutting Gas Plant Pollution” noted that gas plants are the largest source of carbon dioxide emissions produced by the electric industry.
“Every path to addressing our nation’s climate commitments and public health priorities calls for a cleaned-up power sector — and that makes reducing CO2 and other harmful emissions from gas plants an urgent priority,” the scientists group said in its paper.
CO2 emissions from power plants are just one way gas plants exacerbate climate change, according to the report, which notes that natural gas itself – methane – is a more potent greenhouse gas, trapping 28 times more heat over 100 years than carbon.
Co-firing hydrogen can cut smokestack emissions, but how the hydrogen is produced has major impacts on the emissions created and can lead to higher emissions than just burning methane, the report said. And because hydrogen is less energy dense than methane, three times as much of it must be burned to produce the same amount of electricity.
“Hydrogen production is energy intensive, making its production method a major factor in determining the overall change in carbon emissions from using hydrogen in gas plants,” the paper said. “Virtually all hydrogen used in the United States today — overwhelmingly for petroleum refining and in the chemicals industry — is produced via steam methane reforming (SMR), the main byproduct of which is CO2.”
That so-called gray hydrogen is not what the industry, or DOE hubs, are trying to promote. They’re pushing so-called blue or green hydrogen, which can be produced via CCS or from water using electrolyzers — though they must be run with zero-carbon power to achieve a carbon-free “green” hydrogen. Even green hydrogen comes with built-in inefficiencies compared to just using renewable electricity directly, according to the report.
“Producing hydrogen by using solar or wind energy to power an electrolyzer with a typical efficiency of 75% and then using that hydrogen in a gas power plant with an efficiency of 45% would result in only one-third as much electricity as that originally supplied by the renewable sources,” the report said. “That is, it would take three times as many wind turbines or solar panels to supply the same amount of electricity via hydrogen blending as from wind or solar directly.”
Hydrogen can be stored but is less efficient than technologies that store electricity outright. It could make sense if other options to capture and store electricity do not work, or in a system that has enough excess renewable electricity to make hydrogen, according to the report, which concluded that direct use of renewable power has a much bigger impact on cutting emissions.
Another option for cleaner gas plants is to keep burning the fuel with a CCS system, an approach the paper claims does not address upstream emissions of methane and introduces other challenges.
“Any CO2 leaking from the pipelines, or the storage would undo the carbon capture effort, at least in part,” the paper said. “Over time, CO2 can slowly leak into the atmosphere if storage reservoirs are not carefully monitored; abandoned oil and gas wells intersecting with CO2 storage sites also increase the risk of leakage.”
CCS technology requires energy to work, and it can take away between 10 to 20% of the electricity produced at the plant, according to the paper, which concluded would exacerbate upstream emissions. The third option cited by the paper is “biomethane” or “renewable natural gas.” It is produced from the anaerobic breakdown of organic matter such as manure, sewage or landfill waste. Smokestack emissions when it is burned are the same, but it avoids emissions in production of the fuel.
The assumption that CO2 produced at the smokestack has a lower climate impact than just venting methane from a farm or dump “is not reasonable in a net-zero framework, where every source of pollution counts; with the United States committed to achieving a net-zero economy by 2050, there is no credibility to a baseline assumption of unmitigated methane venting,” the paper said. “Instead, if biomethane can be captured for use, at minimum, the appropriate baseline climate comparison is flaring, such as is now required at certain regulated landfills.”
It would make more sense, according to the report, to compare biomethane to the best alternative for the climate, which would be to avoid those initial methane emissions through climate-smart farming techniques or avoiding organic waste in landfills.
