FERC on Wednesday reaffirmed its support for NYISO’s 17-year amortization period for demand curves in its installed capacity market, rejecting protests from the New York Public Service Commission and consumer stakeholders (ER21-502).
The commission’s latest order amends but essentially upholds its May ruling, when the commission reversed course and approved NYISO’s proposal to shorten the assumed operational lifetime of a hypothetical natural gas peaking plant from 20 to 17 years. The commission approved the ISO’s proposal after the D.C. Circuit Court of Appeals issued a remand, ordering the commission to reconsider its prior rejection. (See FERC Accepts NYISO’s 17-Year Amortization Period Proposal.)
NYISO’s proposal was in response to New York’s Climate Leadership and Community Protection Act, which mandates strict net-zero emission goals and makes it more challenging for fossil fuel power plants to operate in the state. NYISO had used a 30-year amortization period until 2014, when the commission approved the 20-year term to reflect the technological, market and environmental risks of investing in the proposed proxy plant.
The PSC and consumer stakeholders argued the 17-year amortization period could increase capacity costs by $400 million over the 22-month period from July 2023 through April 2025. They also said the commission’s ruling runs afoul of its previous rulings rejecting the same proposal.
FERC rejected these arguments, saying it provided a “full and rational explanation” for its reversal and emphasized the ISO’s compliance filing was in line with its directives.
The order included a dissent from Commissioner Mark C. Christie that reiterates his previous arguments, which contend FERC’s decision to accept NYISO’s 17-year proposal undermines the commission’s original rulings and ignores expert opinions from industry stakeholders.
A call for FERC to run a technical conference on capacity accreditation ran into a mixed reception in comments filed this week, with the ISO/RTO Council saying it is too regional of an issue for the idea to have an impact (AD23-10).
“While the members of the IRC acknowledge that commission-led technical conferences can often be beneficial and understand the concerns raised by ACP in its petition, the regional variation on matters related to resource adequacy renders the topic of capacity accreditation less well suited for a national forum intended to drive toward ‘consensus,’” the IRC said. “As capacity markets themselves are neither mandatory nor standardized — reflecting regional differences in priorities and reliability needs — so too are the various accreditation frameworks that operate within each capacity market.”
Regions outside organized markets without capacity markets are even more distinct, which means a technical conference applicable to all would have limited value, it added.
Every FERC-jurisdictional ISO and RTO is talking about capacity accreditation modifications for a variety of reasons, and some of those processes contemplate a filing this year or next. Holding a technical conference likely would delay those changes, which are of “vital importance.”
The IRC said it was sympathetic to the issue of ex parte restrictions on commissioners discussing the topic, but it noted that no proceeding was open at this point that would lead to any issues.
“But should one arise, the commission could turn to alternative procedures that would not require a national technical conference to discuss individual ISO/RTO proposals,” IRC said. “For example, commission staff can notice a meeting to gather additional information about the unique reliability concerns facing a particular ISO/RTO to assess proposed capacity accreditation reforms.”
The Electric Power Supply Association told FERC it is not opposed to a technical conference and it supports broad engagement on system planning and resource adequacy. But like the IRC, it cautioned FERC about the idea’s impact on the ongoing stakeholder processes.
“Those processes are the result of extensive stakeholder participation and negotiation and are tailored to the region’s specific needs; for this reason, the commission should take care to both timing and framing a technical conference such that it supports — rather than stymies — this regional progress,” EPSA said.
Colorado Public Utilities Commission Chair Eric Blank wrote to FERC in support of holding a technical conference, saying it would help given all the changes happening on the Western grid. The PUC is working to facilitate a transition that economically reduces greenhouse gases over time while also moving toward more regional cooperation through expanded markets.
“Taken together, these forces will likely result in a significant increase in interregional transfers, an expansion in alternative generator and customer supply structures, and greater investment in intermittent and customer-sited resources, all of which present new challenges for maintaining resource adequacy,” Blank said.
Capacity accreditation may need to change from analyzing a few hours of peak demand in a deterministic way to dynamically evaluating in a probabilistic way the value of individual resources during more frequent tight supply conditions, he added.
The Solar Energy Industries Association told FERC a conference is a good idea given the changes the industry is going through.
“Regions are shifting from a single summer peak to biannual summer and winter peaks, with climate change exacerbating the reliability risks associated with these changes,” SEIA said. “The risk of correlated outages of thermal resources during extreme weather events is becoming more commonplace, and capability during extreme weather events is now the biggest risk to the reliability of the grid.”
Advanced Energy United said it would like FERC to offer guidance on the patchwork of capacity accreditation rules around the country and thus supported the technical conference.
“Existing ongoing efforts — which will continue to be iterated on for years at RTOs/ISOs — point to the need for a technical forum to holistically discuss issues and challenges related to capacity accreditation that have and will continue to arise,” AEU said. “Existing processes to accredit capacity are inconsistent and leave out some of the important issues raised by ACP in its petition.”
Sierra Club, Earthjustice, RMI, the Natural Resources Defense Council and the Sustainable FERC Project filed joint comments arguing a national technical conference on capacity accreditation would be worth FERC’s time.
“This subject is also a matter of substantial public interest as policymakers at all levels strive to maintain affordable electric rates while grappling with increasingly frequent extreme weather that threatens reliable electricity supplies,” the groups said. “Accurate capacity accreditation is key to a successful transition from conventional generation resources to a more decentralized and lower-emitting resource mix broadly supported by consumers and many state and local policies.”
The current patchwork might reflect legitimate regional and operational differences, but FERC hasn’t examined whether that is the case or whether different rules undermine reliability and skew investment decisions in a way that doesn’t benefit customers, they added.
Doubts continue to swirl around which version of MISO’s future fleet mix is appropriate for long-range transmission planning: the RTO’s or the Independent Market Monitor’s.
MISO pledged additional examinations of its fleet prediction during a stakeholder teleconference Monday, but that did little to quell reservations on either side of the debate.
Monitor David Patton said he continues to have misgivings about MISO’s 20-year fleet assumption that’s dominated by nearly 250 GW in anticipated wind and solar additions alongside 53 GW in gas and other flexible generation and 31 GW of standalone battery storage.
MISO is using that fleet assumption to plan the second portfolio of its continuing long-range transmission plan (LRTP). The RTO says recent studies are showing its estimate of the future fleet holds up well and should be used in the multibillion-dollar portfolio.
Now that it has had time to conduct several tests, MISO says it has determined that its middle-of-the-road, 20-year planning future, referred to as Future 2A, “is most aligned with an optimized, least-cost expansion that meets member goals.” Director of Economic and Policy Planning Christina Drake said MISO continues to strive to “make sure we have a least-regrets portfolio.”
Patton, however, countered, “We continue to believe Future 2A is just not a reasonable basis for planning.”
Future 2A underwent an update last year to include members’ more aggressive decarbonization goals. Senior Director of Transmission Planning Laura Rauch said MISO will conduct more sensitivities for 2A based on different variables. The RTO is planning a new sensitivity based around hypothetically reduced incentives from the Inflation Reduction Act to see if its projected resource expansion changes meaningfully.
“We’ll continue to look for answers, but quite frankly, the answers that we get might not be the ones you’re looking for,” MISO Vice President of System Planning Aubrey Johnson told stakeholders.
MISO planners are prepared for contentious LRTP workshops, he said. “There’s a lot at risk. There’s a lot at stake. And we don’t take these meetings lightly.”
Drake said there have been many questions over how MISO arrived at its future fleet assumptions. She said MISO’s envisioned resource mix is “rooted in the reality of member plans” and that the LRTP is developed to optimize the delivery of members’ decarbonized future fleet. She also said MISO developed the second future over 18 months of stakeholder engagement.
Customized Energy Solutions’ David Sapper said numerous stakeholder meetings are not a “proxy” for the actual vetting of the future resource mix used for planning.
MISO: Monitor’s Fleet Vision More Expensive
MISO said it tested both the Monitor’s ask that it study more natural gas and battery storage resources and a scenario in which capacity accreditation is drastically reduced. It said both comparisons showed that its own version of the future resource mix under 2A represents a “least-cost expansion while considering state and member goals and resource economics.”
The RTO found wildly different fleet predictions between its version, the Monitor’s and the low accreditation future. It expects the total installed capacity under 2A to reach 471 GW by 2042 and cost $234 billion. It said if it introduced more gas resources and battery storage in place of renewable generation — as the Monitor recommended — costs would climb to $319 billion for 462 GW of capacity in the same time frame.
According to MISO, the Monitor’s version of the resource mix would include 103 GW of hybrid renewable and storage resources and nearly 96 GW in gas generation, with 83 GW less in wind resources and over 25 GW less in solar generation from the RTO’s prediction. Future 2A calls for 67 GW in natural gas and just 10 GW worth of hybrid resources.
In the reduced capacity accreditation scenario, MISO found a $251 billion resource expansion for 521 GW in installed capacity. That scenario returned a drastic spike in standalone battery storage to 103 GW by 2042.
MISO test results of the three kinds of fleet assumptions | MISO
But Patton said the amounts MISO inferred from his recommendations are faulty.
“The math is obviously wrong. … Your costs are obviously wrong,” Patton told MISO planners. “I don’t want anyone coming away from this thinking this is correct.”
Patton offered to consult with MISO on a joint hypothetical case of his version. He said there’s “no way” his would necessitate more than 100 GW of hybrid resources.
Drake said MISO “triple checked” its cost and capacity conclusions under the Monitor’s fleet predictions with more gas and battery resources. Rauch said MISO worked with the best information from the Monitor and said she was “frustrated” that it disagreed with the RTO’s outcome.
“We’re looking at roughly a 9-GW difference between the two scenarios,” Rauch said of the overall resource totals.
“There are some more sensitivities that we’ll run,” Rauch continued. But she said she hasn’t so far noticed anything that would cause MISO to rebuild its assumption from the ground up. She said more testing of MISO’s fleet assumption will likely “help us solidify and refine what comes out of Future 2A.”
WEC Energy Group’s Chris Plante said he was “disappointed” MISO didn’t work with the Monitor to come up with costs for the high gas and battery model to make certain it was what the IMM had in mind.
Minnesota Power’s Tom Butz said MISO’s current generation expansion tool used in modeling, the Electric Generation Expansion Analysis System, is no longer “cutting edge” and can’t capture all nuances of the future grid. He said MISO filled out the hypothetical resource mix with its own predictions when it didn’t see enough generation in members’ plans.
“The bottom line is that this is 100,000 MW beyond what the members have put in there. It’s troubling, and it’s not indicative of a collaborative process,” Butz said of MISO’s forecasted 471 GW.
Drake said MISO plans to move to the more sophisticated PLEXUS tool for transmission planning in the coming years.
Patton questioned why the nearly 30 GW in unnamed, flexible resources MISO prescribed won’t negate the need for some of the hundreds of gigawatts of renewable energy it is also expecting. He said MISO can’t claim it’s planning the most cost-effective portfolio if it’s not siting more battery storage, especially at constrained transmission points.
“It’s not that we lack for capacity. There’s sufficient capacity,” MISO’s Johnson said. Rather, he said, the RTO aimed for a fleet assumption that will furnish energy adequacy across all hours, even in the riskier dawn and dusk periods. MISO foresees a danger of being unable to meet all demand after sunset on hot summer days and during pre-dawn and post-dusk periods on winter days. The RTO said it may find itself depleting battery storage with not enough dispatchable generation to meet hourly demand at those times.
Patton said he thought MISO simply requires capacity under a tougher accreditation to conquer its reliability risks.
Support for MISO’s Fleet Prediction
MidAmerican Energy’s Dehn Stevens said some members’ “myopic view” that the evolution of the system fleet is only going to be driven by capacity needs is “completely off the mark.” He said the race to decarbonize will drive the bulk of the resource transition.
“We think this approach is very good,” Stevens said of Future 2A.
Otter Tail Power’s Stacie Hebert said load growth and resource transformation is imminent for the footprint and that stakeholders need to put more faith in MISO’s expertise in transmission needs.
“It’s easy to pick out things that might not look right from our worldview right now,” she said. But she said MISO is an industry leader in transmission planning. “Inaction and delay also has a cost, so we really need to be balancing our interest in restudies and restudies against inaction.”
“Obviously a lot of the stakeholders expressed frustration today,” Sustainable FERC Project attorney Lauren Azar said. She said she thinks MISO is doing “all of the analysis it needs to do.”
While she said she respects Patton’s opinion on markets, she said he is not a transmission planner and does not specialize in grid planning.
“MISO needs to use its professional judgment about what changes it needs … for the grid in 2042,” Azar said. She said the RTO’s Environmental sector is already concerned that its planning is not keeping pace with the regional backbone projects it will need to support fleet transformation.
“I think we need to move forward and not let the perfect be the enemy of the good,” she said.
IMM Again Expresses Worry for Market Operations
Patton repeated concerns that MISO’s LRTP fleet assumption stands to affect the markets during a mid-September virtual forum hosted by the Gulf Coast Power Association.
The Monitor said that ordinarily, MISO’s transmission planning doesn’t ring alarm bells, but the enormous amounts of renewable energy coupled with “very little” dispatchable generation mean MISO will try to build a transmission system to absorb the fluctuations of an intermittent fleet.
He said “large, uneconomic” transmission investment can dampen the market’s ability to facilitate new generation investment and retirements. It’s imperative that MISO make sure lines address actual needs, he said.
“Now, the reason we care about this is because transmission investments, by definition, occur outside the market,” Patton said. “They’re not being done in response to market signals, and they’re not being paid for through market revenue … and that’s not necessarily bad. That’s a choice that in this country we’ve made in terms of how we make transmission investments.
“But what is important is the investments be made economically … that we invest in transmission as if we were making them in response to forecasted market signals. Because when we make uneconomic transmission investments, then it will distort the market signals and it will adversely affect the participants in the market, as well as raising costs for transmission customers.”
Patton said he envisions “a very different future” by 2040, in which MISO adds 108 GW less in renewable energy than it’s expecting. He maintains that reduction would save the RTO about $120 billion in renewable energy costs by 2040. He said if MISO adopted his view of the future, it would result in more accurate transmission planning.
“What we believe is more realistic is that batteries and hybrid renewables, which have batteries on-site, will be developed,” Patton said.
He also said he takes issue with MISO modeling and planning for a footprint-wide carbon-reduction target when it doesn’t have one.
Clean energy groups active in MISO told FERC last week that it should rethink its support of a ban on renewable energy in MISO’s ancillary services market because the commission didn’t consider hybrid resources when it made its decision.
The Solar Energy Industries Association, American Clean Power Association, Clean Grid Alliance, Natural Resources Defense Council, Fresh Energy and Sierra Club are seeking a limited rehearing of FERC’s prohibition on renewable energy furnishing ramping needs (ER23-1195-001).
The groups said FERC’s authorization of MISO’s embargo is faulty because it doesn’t explain where hybrid resources — combinations of renewable energy and energy storage — factor into the ban.
FERC this year allowed MISO to exclude renewable resources from providing ramping capability and rejected a challenge from SEIA on the RTO’s practice of precluding renewable resources from providing ancillary services in its markets. (See FERC: MISO Can Ban Intermittent Resources from Providing Ramp and FERC Blocks Solar Group’s Contest of MISO Ban on Renewable Ancillary Services.) In both cases, FERC said renewables are almost never the most economic choice to supply operating reserves because they’re often trapped behind already binding transmission constraints, rendering their output undeliverable.
But the clean energy groups argued that hybrids, unlike standalone renewable resources, are “fundamentally different” in terms of operations and economics.
“Storage paired with renewable resources can relieve congestion and have flexibility that renewables alone do not possess. Because of these differences, the rationale and evidence that MISO provided in support of its prohibition do not apply to hybrids,” they said.
The groups suggested MISO eschew a “blanket prohibition” and, at a minimum, allow hybrid participation in the ancillary services market on a one-year temporary basis with the option to reevaluate. They said MISO used the same open-ended, one-year approach when it allowed intermittent resources into its energy market years ago. They said the same approach “is appropriate to deploy here specifically to hybrids.”
MISO has calculated significant increases in its annual cost of new entry (CONE) values for use in its 2024/25 capacity auction.
The average CONE surged to nearly $330/MW-day, ratcheting up from $275/MW-day a year ago and $243/MW-day during the 2022/23 capacity auction. For the first time, all local resource zones surged beyond a $100,000 annual cost to build a single megawatt.
MISO said the increase is “mainly due to significant increases in base project capital costs and the weighted average cost of capital, both reflecting actual and expected inflation estimates.”
The RTO’s CONE represents the cost of building an advanced combustion turbine. It differs by zone to reflect regional differences in construction costs. The values include capital costs, operations and maintenance expenses, property taxes and insurance costs. MISO South typically has lower costs than MISO Midwest.
MISO’s Zone 5 in parts of Missouri carries the highest CONE of the zones, at $131,725/MW-year, and experienced the highest year-over-year increase at $22,145/MW-year. Zone 5 usually has the highest CONE.
Zone 7, covering Michigan’s Lower Peninsula, came in second at $127,135/MW-year.
Mississippi’s Zone 10 holds MISO’s most inexpensive CONE value at $112,263/MW-year. The zone consistently returns the lowest CONEs.
On average, the zones’ CONE values increased by $19,931/MW-year.
RENSSELAER, N.Y. — NYISO on Monday presented another reformulated proposal to enhance its interconnection study processes and align with the new directives set forth in FERC Order 2023.
During the Interconnection Issues Task Force’s first meeting, NYISO said it will adhere to FERC’s proposed study format but introduce some ISO-specific variations, such as a two-phase cluster study, a rolling optional pre-application and an altered customer engagement window with a physical infeasibility screening. The IITF was established to investigate, refine and implement these directives.
NYISO argues that its proposal strikes a balance between FERC’s guidelines and the unique needs of New York’s energy landscape. FERC’s directive accommodates such variations, recognizing that each RTO and ISO faces its own set of challenges and policies.
The most significant difference between NYISO’s and FERC’s proposals lies in the structure of the cluster studies.
Unlike FERC’s single cluster study that is followed by individual facility studies, the ISO uses a two-phase approach in which routine interconnection studies, like the system reliability impact study or system upgrade study, would be conducted in the second phase.
A new window would be initiated every 18 months, sticking to the commission’s overall timeline but incorporating elements from NYISO’s previous interconnection queue changes. There would be a slight overlap between each cluster study window, but the ISO does not expect this to necessitate any rework.
Thinh Nguyen, NYISO senior manager of interconnection projects, explained that the ISO also wants to include several pre-work phases within the study window to “help organize and provide the appropriate information at the start of each phase to developers and” the ISO.
Theoretical timeline of 18-month sequenced cluster studies | NYISO
NYISO would transition directly to the new cluster study process, bypassing a yearlong transitional study. The move aims to minimize the transition impacts and allow the next cohort of projects sufficient time to adapt to the new procedures.
Stakeholders at the IITF meeting were generally receptive to NYISO’s proposals but urged the ISO to ensure clarity in its revisions to avoid future confusion.
Mark Reeder, representing the Alliance for Clean Energy New York, worried about the window overlap and if conducting project feasibility studies at the end of one window when another starts was the best way to go about things.
Sara Keegan, an attorney with NYISO, responded that conducting these studies later has proved more efficient in other RTO and ISOs interconnection studies and the ISO does not think it would cause any issues.
Howard Fromer, who represents Bayonne Energy Center, expressed concern for how Class Year 2021 projects currently seeking interconnection would be affected. NYISO clarified that because these projects finished class year processes, they are now subject to different standards, but it promised further details in the future.
Doreen Saia, an attorney with Greenberg Traurig, inquired about the treatment of new interconnection requests during this transition period, saying the ISO should try and get ahead of this potential issue to avoid “having a whole bunch of requests coming in because [projects] are afraid of missing out.”
NYISO staff assured Saia that new requests would continue to be accepted and promised to provide a clearer timetable soon.
NYISO, along with other RTOs, filed Order 2023 compliance extension requests with FERC, but if its request is denied, then it must file its compliance by Dec. 5. (See NYISO to Ask FERC for Order 2023 Compliance Extension.)
The IITF will reconvene to discuss the proposal in greater detail Oct. 20.
While a lot of progress has been made, getting to a fully decarbonized economy is going to require new technologies, U.S. Energy Secretary Jennifer Granholm said Tuesday at this year’s Hydrogen Americas Summit.
“It is certainly going to be helpful to decarbonize our hardest-to-abate sectors: obviously heavy industry [and] transportation,” Granholm said. “Hydrogen, as you all know, could lead to clean dispatchable baseload electricity; it can provide options for long-duration energy storage and shore up our energy security, especially during supply chain breakdowns.”
Granholm joked that unfortunately she was not at the conference, hosted by the Department of Energy and the Sustainable Energy Council, to make any major announcements, with the industry waiting for word from her department on the applications to build regional “hydrogen hubs” around the country. (See DOE Opens Solicitations for $7B in Hydrogen Hubs Funding.)
While hydrogen is already used in applications ranging from refining oil to rocket fuel, and legacy firms such as Air Products and Air Liquide were well represented at the conference, the hope is for hydrogen to become what Granholm called the “Swiss Army knife” of the clean energy revolution.
The hubs are meant to help start building the future domestic industry by linking together regional supply and demand, which ideally will help provide a foundation for the fuel to become commonplace in global energy supplies.
“We expect these hubs will marry supply and demand so that we can be producing where the offtake is,” Granholm said. “And as I say, we’re very close to announcing those hubs.”
If the Biden administration’s goals for domestic, clean hydrogen production by 2030 are met, the U.S. would produce enough of the fuel to meet the same amount of energy used by every bus and train in the country, Granholm said. The 2040 goal would double that production to 20 million metric tons, while the 2050 goal would have the U.S. produce enough clean hydrogen to meet the equivalent energy demand of every bus, train, ship and plane in the country, she added.
Other countries around the world are ramping up their production of hydrogen, and Granholm said the U.S. would be happy to work with them.
“We need to develop uniform codes, uniform standards, to maximize safety to minimize harmful leakage,” Granholm said. “We need to ensure that emissions analyses are done consistently across regions and that certification measures are rigorous and practical, as well as transparent.”
Countries also need to work together to help create new markets for the fuel and get new sources of demand comfortable with using the fuel, she added.
The government’s plan to help grow hydrogen into a clean energy industry involves focusing first on strategic, high-impact end uses such as “hard to decarbonize” industries, heavy-duty transportation and energy storage, DOE Hydrogen Program Coordinator Sunita Satyapal said.
“Second is laser focus on reducing the cost,” Satyapal said. “Again, it has to be competitive from a market-sustaining perspective. And then third is focused on regional networks. So that’s where the hubs come in: How do we potentially co-locate large-scale production and use?”
As the industry develops, hydrogen will need to be shipped. One idea to do that is over pipelines, but no regulatory regime to site, construct and oversee that infrastructure has been developed. FERC Commissioner Allison Clements told the conference Wednesday that she has asked Congress to come up with a plan to regulate those pipelines.
“You want to have some sort of one-stop shop or coordinated effort at the federal level that allows for the responsible, effective and efficient facilitation of interstate pipelines,” Clements said.
For now the focus is on intrastate pipelines, with just 1,600 miles transporting hydrogen compared to 300,000 miles of interstate natural gas pipelines overseen by FERC. But as the industry matures, it will want to connect different states, so some kind of regulatory regime will be needed, Clements said.
Hydrogen molecules (H2) flowing through pipelines will be much smaller than methane molecules (CH4) and thus have an easier time escaping, said Steven Hamburg, the Environmental Defense Fund’s chief scientist.
That is an issue even for green hydrogen, which is produced exclusively by zero-emitting generation, let alone blue hydrogen, produced with natural gas and carbon capture, with the industry having to consider upstream methane emissions, Hamburg said.
“We have to remember that hydrogen is a potent, indirect greenhouse gas,” Hamburg said. “It roughly lasts in the atmosphere … about the same length as methane, and its potency is about half of methane. And unfortunately, we don’t know anything about how much is being emitted currently.”
NASA uses hydrogen for its rockets; Hamburg said that when the fuel is transferred to them, it can lose up to 13% of its volume being blown away in the atmosphere, so ensuring such releases are minimized when it becomes much more commonly used is vital. Measurement technology is only being developed now, and it is needed not just to track the small leaks along its supply chain but also to help avoid any accidents with the volatile gas, Hamburg said.
Hamburg has been deeply involved in EDF’s efforts to track natural gas leakage. When that work began, many doubted that it was actually happening, but with actual measurements, leakage has proved common.
“It’s really important to note when I first started talking with companies about this issue 13 years ago, everyone told me, ‘We wouldn’t waste product; we’re not emitting much methane,’” Hamburg said. “That simply isn’t true. I hear a lot of that from the hydrogen industry. I can’t say it’s not true because we don’t have the measurements. But it is a bit of caution.”
Supply-side vs. Demand-side Policies
The U.S. and EU have come at the problem of making hydrogen a major energy source, and addressing climate change, in the opposite directions, said Michel Heijdra, the Netherlands’ vice minister of climate and energy.
“The U.S. for certain reasons, of course, focuses on subsidies in the value chain, whereas Europe focuses on carbon pricing and setting certain obligations for that offtake,” he added.
Both are spending money to help stand up hydrogen and other decarbonization options, and ultimately Europe will need to focus on cutting the cost of the fuel to get wide adoption, while the supply subsidies alone likely will not be enough to have major industries adopt new fuels and equipment, he added.
The international community also eventually will have to come together to make some standards around hydrogen production so that customers can be sure they are getting what they pay for, said David Hart, partner at consulting firm ERM.
“We’ve learned, I think, from previous areas where we have not done this as well, in biofuels and other jurisdictions where it’s quite easy to game markets by taking a biofuel that’s produced somewhere and moving it,” Hart said. International agreements around hydrogen need to be structured carefully so that such gaming is not easy to do, he added.
High Costs Must be Cut
BP already uses hydrogen at refineries it runs around the world, but it uses traditional “gray” hydrogen, produced by natural gas without any carbon capture, said Vice President Tomeka McLeod.
“There still is quite a big gap between … the cost of gray hydrogen under levelized costs versus what you would see for clean hydrogen … even with the Inflation Reduction Act,” McLeod said.
The price gap narrows for blue hydrogen, but it is still big enough that customers might not see the benefit of switching to green hydrogen.
“A number of the industries that use hydrogen have very thin margins,” McLeod said. “If their customers are not willing to pay a premium, it’s going to be pretty tough to incent them to pay a premium.”
Fueling the electrolysis machines that can make green hydrogen is going to be difficult and expensive, leaving that business to a few firms that can actually deliver on the idea, said Intersect Power CEO Sheldon Kimber. Green hydrogen might need to be directly linked to renewable generation, especially given the difficulties of expanding the transmission grid.
“When you look at the scale of these kind of monster behind-the-meter renewables facilities, which is what we think is going to transpire here … 80% of that is the renewables,” Kimber said. “And so, you make a list of people who may have built a 500-MW-plus renewable facility in the U.S., [and] it’s very small list. You make a list of people who have delivered that in the last few years through the supply chain crisis, financing issues and all of that — that’s a much smaller list.”
Hydrogen in Transportation
While much of the focus on hydrogen recently has been on hard-to-decarbonize industries, many are pursuing its use in transportation — even in the light-duty vehicle segment where electric cars have come to dominate the clean space.
BMW has 25 electric vehicles available to consumers around the globe, but it is also considering adding light-duty hydrogen cars to its portfolio, said company representative Thiemo Schalk.
“There are studies coming from the European Union, and from Germany as well, suggesting that once you are coming close to a huge part of the car market being electrified, the costs for the infrastructure for the charging outlets [are] going to be increasing really, really sharply,” Schalk said.
The costs go up as the grid needs to be bolstered and clean resources are added to the mix to serve the new demand from cars, with estimates that Europe would have to spend $1.5 trillion to go 100% electric, Schalk said. But that comes down significantly if some percentage of the light-duty market is served by hydrogen or another alternative, which some customers will wind up preferring over EVs as well.
Going electric in the heavy-duty sector is more difficult because the current battery designs are too heavy, especially for airplanes, said Airbus Americas Vice President of Research and Technology Amanda Simpson. Airbus sees hydrogen as the main option for decarbonizing air travel and hopes to have a plane using it in service by 2035.
But the company is not yet sure whether that plane would use a hydrogen fuel cell or directly combust the gas in its engines, Simpson added. Getting liquid hydrogen on aircraft and doing it safely is also a focus of those developments, but hydrogen has major advantages over the alternatives.
Biofuels still produce pollutants when combusted, and batteries are just too heavy to have any impact outside of short-haul, local flights, she added.
Hydrogen Generation is Possible, but Expensive
The IRA has supercharged interest in hydrogen, with projects before it being much smaller, said Siemens Energy North America President Richard Voorberg. Before the law, Siemens was working on electrolyzers of about 18 MW, but it has scaled up and has plans for projects above 1 GW.
Those major projects are starting to roll out at once and eventually will lead to a backlog as the industry can only do so much at once, Voorberg said.
“The challenge is economics,” Voorberg. “And we don’t see the economics start making sense until probably 2035 at the earliest. So, we think things like decarbonizing industry, steel-manufacturing, chemicals, ammonia, fertilizer, transportation — all those go first [and] pave the way. And then eventually, the high price of hydrogen gets to the right position and then you can burn it in gas turbines for energy production.”
The U.S. solar market saw a 32% drop in new utility-scale megawatts installed across the country in 2022, but it could be heading for a record rebound this year, according to a new report from the Lawrence Berkeley National Laboratory (LBNL).
In the first seven months of 2023, utility-scale solar capacity was up 50% over the same period in 2022, with estimates of total installations hitting 24 GWAC, based on estimates from the Energy Information Administration, the report says.
The report defines “utility-scale” as grid-tied, ground-mounted projects of 5 MWAC or more. In 2022, total installations provided only 12 GWDC of new generation, the report says, citing figures from industry analyst Wood Mackenzie.
Even with the decline, utility-scale solar added the most new megawatts to the U.S. grid, accounting for 27% of new generation versus 22% each for wind and residential rooftop solar.
Those figures reflect the combined impact of evolving technologies and federal and state policies on the utility-scale market.
For example, the report attributes 2022’s decline to the double-whammy of U.S. solar tariffs — which President Joe Biden put on hold for two years in June 2022 — and a slowdown in imports due to the Uyghur Forced Labor Prevention Act (H.R. 6256), passed in December 2021.
The law bans imports from China’s Xinjiang province, where reports had surfaced of minority Uyghurs being used as forced labor. The province provides about 50% of all the world’s polysilicon, a key component of solar panels. Initial implementation of the law resulted in U.S. Customs and Border Protection holding thousands of shipments of solar panels, according to a Reuters report.
Release of the backlog began in March of this year, following a clarification of the rules, according to a subsequent Reuters report.
Looking ahead, the report sees additional market tailwinds, with PPA prices possibly falling as developers take advantage of either the investment tax credit (ITC) or production tax credit (PTC) in the Inflation Reduction Act (IRA). Solar projects previously were limited to the ITC, which the IRA reset at 30%, but the law also makes the PTC available, which in some instances may pencil out better, the report says.
Also, more than half of new utility-scale projects added to the grid through July 2023 are sited in what the IRA defines as “energy communities” eligible for 10% additions to the ITC or PTC. Energy communities, broadly defined, are areas that have been dependent on fossil fuel production and have lost jobs and tax revenue as a result of plant closures.
Projects built with single-axis tracking made up 94% of all new utility-scale solar in 2022, the highest percentage ever. | Lawrence Berkeley National Laboratory
Other trends detailed in the report include:
Almost all new utility-scale projects — 94% — added to the grid in 2022 were installed with single-axis trackers, which adjust panel position to follow the sun to increase solar output. Fixed-tilt projects are increasingly limited to sites with rugged or uneven terrain, such as landfills or brownfields, or with high winds.
Texas and California continued to lead the nation on new utility-scale solar in 2022, adding 2.4 GWAC and 2.1 GWAC respectively.
But the two states also led the nation in overproduction resulting in project curtailments. In Texas, ERCOT reported 2,797 GWh of solar curtailed in 2022, while CAISO curtailed 2,057 GWh.
Hybrid projects with solar and storage are steadily increasing. A record 26 new hybrid plants, totaling 2.2 GWAC were added to the grid last year, but the average duration of storage on these projects fell, from 3.2 hours in 2021 to 2.7 hours in 2022.
Power purchase agreements (PPAs) for utility-scale solar now average $25/MWh, up slightly from a 2019 low of $22/MWh but still competitive with wind and natural gas.
Interconnection And Value
President Joe Biden has set an aggressive target for the U.S. to decarbonize its electric power grid — and run completely on zero-emission energy — by 2035, while cutting emissions economywide 50% to 52% by 2030.
A growing number of reports and analyses are estimating that reaching these goals will require a dramatic ramp-up in solar generation. Released Wednesday, a report from industry consultants ICF sees solar going from 3% of the U.S. energy mix in 2022 to 16% in 2030 and 65% by 2050. The International Energy Agency’s recently updated road map to net zero by 2050 calls for a fourfold increase in solar and wind deployments worldwide.
Based on Wood McKenzie’s numbers, the LBNL sees new utility solar capacity increasing more than fourfold from 12 GW in 2022 to over 50 GW per year.
But here again, getting there will depend on a combination of economic and technical factors, first and foremost how quickly utilities and grid operators can upgrade their systems and processes to speed up interconnection.
The interconnection queues across the U.S. remain jammed with a total of 947 GW of solar, including 351 GW that were added to queues in 2022, according to LBNL. Hybrid solar and storage projects make up 457 GW of the total, the report says.
Western non-RTO queues are largest, with about 250 GW, followed by MISO (more than 200 GW) and PJM (more than 150 GW), according to the report.
interconnection queues at the end of 2022. The non-RTO West, MISO and PJM having the most solar waiting for interconnection. | Lawrence Berkeley National Laboratory
Another factor will be the impact of tariffs on solar panels imported from Cambodia, Malaysia, Thailand and Vietnam, which are scheduled to go back into effect when Biden’s moratorium ends in June 2024. While the IRA has triggered a growing number of announcements of new solar cell and panel plants in the U.S., Abigail Ross Hopper, CEO of the Solar Energy Industries Association, has said it could take three to five years to stand up a complete U.S. supply chain. (See Commerce Dept. to Reimpose Tariffs on SE Asian Solar Manufacturers.)
A possible counterbalance to any future tariffs, solar’s value to the grid is rising, compared to PPA prices, the report says. The market value of solar varies across different RTO and ISO service regions, ranging from $51/MWh in CAISO to $85/MWh in PJM and up to $108/MWh in some non-RTO areas of the Southeast.
“Since 2020, rising wholesale energy prices more than compensated for moderate PPA price increases, making solar more competitive than it has ever been across the nation,” the report says.
BOSTON — Massachusetts, Rhode Island and Connecticut have reached an agreement on coordinating the procurement of offshore wind, Massachusetts Gov. Maura Healey (D) announced Wednesday.
Healey touted the benefits of the multi-state agreement at the American Clean Power (ACP) Association’s Offshore WINDPOWER 2023 conference, stressing the importance of regional collaboration and the potential of the agreement to benefit ratepayers.
“Through this agreement, here’s what we’re going to do: Align our procurements to leverage our collective buying power, lower project costs and maximize benefits for ratepayers across the region and increase the efficiencies and reduce project risk for offshore wind developers,” Healey said at the conference.
The Massachusetts governor added the states collectively have the authority to procure up to 6,000 MW of offshore wind capacity. According to the memorandum of understanding (MOU), the state agencies will “work in good faith to ensure that multi-state bids are considered.”
Under the agreement, multi-state bids could be extended to just two of the states, or all three. Each of the states are in various stages of the RFP processes for new procurements. Massachusetts has issued the largest solicitation of the three states at up to 3,600 MW, with proposals due in January. (See Mass. DOER Issues Draft RFP for Region’s Largest OSW Solicitation).
“Regional collaboration through this three-states MOU will not only help in advancing offshore wind projects of large scale by securing cost-effective energy prices for ratepayers — but it also provides a significant opportunity for long-term economic development,” Rhode Island Gov. Dan McKee (D) said in a press release.
The announcement — and the conference that hosted it — come at a crucial time for the region’s offshore wind industry, as supply chain constraints and high interest rates have strained existing power purchase agreements (PPA).
On Monday, Avangrid and two Connecticut electric utilities announced the termination of the PPA for the 804-MW Park City Wind project (Conn. PURA 19-12-18, see Park City Wind to Cancel PPAs, Exit OSW Pipeline). Meanwhile, the Massachusetts Department of Public Utilities approved the termination of the SouthCoast Wind PPA on Friday (Mass. DPU 20-16, 20-17, 20-18) following the termination of the Commonwealth Wind PPA earlier this summer (Mass. DPU 22-70, 22-71, 22-72, see Commonwealth Wind PPA Cancellations OK’d).
Healey doubled down on the importance of offshore wind, calling it “an anchor for our state’s short-term and long-term success,” despite the recent industry challenges.
Several speakers at the conference praised the agreement. Pedro Azagra Blázquez, CEO of Avangrid, said the agreement is necessary and “very important,” in his remarks following Healey’s.
ACP called the agreement “a bold way to drive cost efficiencies for projects across a broad swath of New England while promoting economic growth, enhancing security and driving down energy costs.”
“Procurement at this scale is exactly what industry needs to solve some of its most pressing issues,” said Liz Burdock, CEO of the Business Network for Offshore Wind, in a statement. “Big scale drives real cost reductions, fosters a pipeline large enough for new manufacturing investments and should create enough certainty to entice developers and vessel owners to enter into framework agreements that would unlock capital sitting on the sidelines.”
Throughout the conference, speakers expressed both optimism about the long-term outlook for the industry and the concern that if the current round of procurements fails to produce meaningful results, supply chain issues could push back the in-service dates of the next round of projects into the 2030s. Such a delay could significantly hinder the ability of states to meet their emissions reduction targets.
Bob Grace, president of Sustainable Energy Advantage, called the multi-state agreement “somewhere between a very big deal and not a big deal,” noting that Massachusetts, Connecticut and Rhode Island previously participated in the joint procurement of renewable energy in 2015-16. The joint procurement resulted in a mix of land-based wind and solar projects, selecting proposals totaling 460 MW.
Grace said the experience was extremely unwieldy as each state’s laws and procedures became constraints on their neighbors and was a process that many involved vowed never to repeat. He said the announced offshore wind agreement appears to learn from that experience by coordinating procurements rather than jointly procuring. He added the benefits of the agreement will hinge upon how effectively the states can work together.
“There is no way for the New England states to hit their climate goals without offshore wind,” Grace said.
While many policymakers in the region have pushed to get as much offshore wind in the project pipeline as soon as possible to reduce emissions, Massachusetts Attorney General Andrea Joy Campbell (D) has expressed concern about the size of Massachusetts’ recent solicitation.
In her initial comments on the solicitation, Campbell said timing these procurements during a period of cost increases could leave ratepayers with inflated bills (Mass. D.P.U. 23-42). The state Attorney General recommended capping the maximum procurement at 1,600 MW instead of 3,600 MW, with smaller, more frequent procurements to follow the solicitation.
This strategy “likely would help moderate the pace of offshore wind procurement and protect ratepayers from the volatility in the current market,” Campbell said.
While announcing the states’ agreement, Healey stressed the importance of federal support for offshore wind to keep costs manageable.
“A critical piece of this is how we’re able to maximize federal funding,” Healey said, highlighting the administration’s application for an up-to-$250 million matching grant from the U.S. Department of Energy for transmission upgrades that would help connect offshore wind to the grid.
Healey called on conference attendees to help push the federal government for more support for the offshore wind industry.
“This is a federal administration that has purported to be about a clean energy transition,” Healey said. “Hold them accountable.
The Western Power Pool (WPP) on Monday floated a proposal to revamp transmission planning in the West with the aim of spurring development of the kind of large-scale transmission projects FERC’s Order 1000 process has failed to produce.
The proposal, which WPP laid out in a concept paper, envisions creation of a new group, the Western Transmission Expansion Coalition (WTEC), which would “explore a new approach for West-wide transmission planning that will result in an actionable transmission plan to address regional and interregional needs.”
The paper says that while the region’s current planning processes overseen by NorthernGrid in the Northwest, WestConnect in the Southwest and CAISO comply with FERC requirements, “the legal and regulatory structure upon which they were built is limited and has not resulted in the identification of new transmission solutions that result in transmission builds.
“The limited nature of regional planning also handicaps the broader West in developing inter-regional transmission solutions. To effectively address the collective needs of the grid for the future, transmission planning must be performed in a more holistic and coordinated manner, such that a plan for transmission expansion solutions can be optimized to meet a broader set of needs,” the paper says.
WPP spokesperson Kevin Langbaum told RTO Insider that participants in “informal” conversations that produced the plan included WPP, BPA, the Pacific Northwest Utilities Conference Committee (PNUCC), the Northwest & Intermountain Power Producers Coalition (NIPPC), the Public Power Council (PPC), PacifiCorp, Idaho Power, Portland General Electric, Snohomish PUD, Puget Sound Energy and clean energy advocacy group Renewable Northwest.
“At the request of leadership from the Bonneville Power Administration (BPA) in response to stakeholders’ urging and supported by leadership of several energy industry entities and utilities, an informal group formed to discuss approaches to address a widely recognized concern that current transmission planning frameworks in the West do not result in sufficient transmission solutions to support the needs of the future energy grid,” the WPP said in describing the proposal.
The concept paper defines an “actionable” transmission plan as one that would “enhance” regional and interregional reliability, “address economic efficiency and help states achieve their respective goals.” In the paper, “regional” refers to the NorthernGrid transmission planning area covering the Pacific Northwest and Intermountain West, where the proposal originated, while “interregional” denotes all three Western U.S. planning areas — CAISO, WestConnect in the Southwest and NorthernGrid — as well as BC Hydro and AESO in Canada.
Beyond the goal of creating an actionable plan that increases grid reliability and efficiency, the effort also would seek to improve “visibility and coordination” of planning across the West and “support” future cost allocation decisions, although the paper makes clear the WTEC “does not intend to formulate or prescribe a cost allocation standard” for projects.
The concept paper does not provide a technical scope for the effort but instead proposes to establish the structure that would define the scope of the effort.
“While this effort is focused on the production of an initial transmission plan, the WTEC envisions that the process could evolve into a durable, long-term function, including periodic updates and refreshed analysis,” WPP said in the paper.
Two Committees And A Task Force
The paper proposes the WTEC be organized into two committees and a task force to address technical matters around transmission planning.
At the top would be a Steering Committee “comprised of senior and executive leadership from diverse entities committed to the study effort” and “responsible for resolving and making major decisions to structure the transmission plan.”
“While the Steering Committee will make decisions informing the transmission plan, it also carries the responsibility to collaborate with other committees organized to support the effort,” the paper states.
The paper proposes the Steering Committee include representatives from NorthernGrid (including BPA and others to be named), CAISO, WestConnect (including WAPA and others), WECC, Canadian province transmission planning, NIPPC, Renewable Northwest, Interwest Energy Alliance, PNUCC, PPC and WPP. The committee also would include a “state” representative to be determined after consultation with the region’s states.
A Regional Engagement Committee (REC) would consist of representatives from various stakeholder sectors and would “be responsible for providing input and feedback on the approach for the transmission plan, as well as providing input on major decisions informing the transmission plan,” according to the paper.
The REC would consist of two members each from: the Steering Committee, federal power marketing agencies, non-federal power marketing organizations, independent power producers, independent transmission developers, public interest groups, ratepayer advocacy organizations, industrial electricity customers, state agencies and tribes. It also would include four members each from investor-owned utilities and consumer-owned utilities.
The paper also proposes a Technical Task Force that would identify transmission study scope and approach, “including but not limited to renewable energy zones, resource expansion, electrification and load data, and scenario development, including extreme event scenarios, phasing of study outcomes and recommendations, data protocols, etc.”
The task force would consist of technical staff from Steering Committee members, Pacific Northwest National Laboratory, the Northwest Power and Conservation Council, WPP, and merchant and independent transmission developers. It also would include an independent consultant with expertise in transmission selected by the Steering Committee.
The concept paper also outlines the intent for “periodic communications and public webinars to provide stakeholders from the public with input and feedback opportunities.”
WPP is seeking feedback on the proposal and has posed a series of questions for stakeholders regarding the proposed participation structure of the WTEC, the composition of its committees and its plans for broader engagement with the region. Comments are due by Oct. 31 and should be sent directly to WPP CEO Sarah Edmonds at sarah.edmonds@westernpowerpool.org.
