SARATOGA SPRINGS, N.Y. — Europe appears to be retreating from electric competition and single-price clearing auctions, trends that could spread to the U.S., MIT professor Michael Mehling told the Independent Power Producers of New York’s (IPPNY) Fall Conference on Wednesday.
Mehling, deputy director of the MIT Center for Energy and Environmental Policy Research, spoke after the annual European State of the Union, where European Commission President Ursula von der Leyen proposed capping prices for renewable and nuclear generators at $180/MWh and imposing windfall profit taxes on oil, gas and coal companies. Von der Leyen also called for “a deep and comprehensive reform” of the merit-order electricity market, saying the EU needs to “decouple the dominant influence of gas” on prices.
Von der Leyen’s proposals came in response to rapidly rising prices resulting from drought, reduced offshore wind production, the phaseout of nuclear units and, most recently, Russian gas supply cuts.
Energy Security
The EU’s energy security has also been impacted by its aggressive climate targets, which prompted a shift from dispatchable coal and gas resources to renewables, Mehling said.
The European Parliament recently backed a target to get 45% of its energy from renewable sources by 2030, compared with 22% in 2020. Additionally, the EU adopted laws requiring at least 55% GHG emission reductions by 2030 compared to 1990 levels and net-zero emissions by 2050. It also created energy efficiency directives that require the continent to achieve a 20% reduction in energy consumption by 2020.
“Energy security is definitely — there’s no argument about it — compromised in the EU now,” Mehling said.
European leaders have increasingly considered market interventions. As of October 2021, 25 member states had adopted price regulations or transfer mechanisms such as income supports and tax reductions to address rising prices. The French government recently bought the remaining shares of the nation’s main utility, Electricite de France. Germany’s government has started talking about reopening many of its retired nuclear plants, Mehling said, while Poland “has gone back to coal.”
Lessons for the US
Mehling said one lesson from Europe’s experience is “how quickly you can go from believing firmly in … deregulated markets to seeing a tremendous appetite to intervene at every level, both in the name of climate policy, but also in the name of reducing energy costs.”
“Is that something that could also happen here?” he asked. “Some would say it’s already beginning with, you know, all kinds of different policy complements to the traditional … liberalized parts of U.S. electricity markets.”
In 2021, before its invasion of Ukraine, Russia supplied almost half of Europe’s gas and coal imports and a quarter of its oil. Russia is now responsible for less than 10% of Europe’s gas imports. As the EU weans itself from Russian gas and builds more LNG terminals, demand for U.S. gas will increase significantly, creating a “convergence of prices around the globe,” Mehling said.
Mehling said EU leaders risk making mistakes in attempting to respond to the crisis with quick, decisive actions, such as the proposal to decouple natural gas from setting market prices.
But he said economists and policymakers must determine whether single-price clearing markets still make sense as the fuel mix shifts to one dominated by low variable cost renewables that often produce negative prices.
“For 20 or 30 years, we thought we knew what the optimal [market] design would be,” he said. “But with changing circumstances … I think we also have to be sober enough to realize that at some point, this dearly held principle of what the optimal approach would be may have to be revisited.”
SPP staff are taking yet another crack at adding counterflow optimization (CFO) to the congestion-hedging process following a late-August workshop with the Board of Directors, Members Committee and other stakeholders.
Staff offered more than a dozen alternative congestion-hedging solutions, culled from surveys and meetings with stakeholders. Stakeholder groups will get another opportunity to discuss the final recommendations before they are brought to the governance committees and the board during their October meetings.
“My hope is the things that staff has developed, and the feedback we’ve heard today, provides us with a pathway to do some work with stakeholder groups to help shape whatever comes back to the board in October,” board Chair Larry Altenbaumer said. “I don’t want to presuppose staff’s recommendation or what it should be, but I want to make sure we’re being as thorough as possible in providing constructive guidance on whatever that solution might be.”
It hasn’t been easy for CFO to get this far. The Holistic Integrated Tariff Team recommended in 2019 that CFO, limited to excess auction revenue, be added to SPP’s market mechanism that hedges load against congestion charges. The process, which keeps system transmission flows between two points in balance, was meant to address concerns about how congestion rights instruments are awarded and the current process’s efficiency.
The Market Working Group spent months trying to reach agreement on how best to add CFO, only to eventually turn it over to the Strategic Planning Committee. (See SPP SPC Takes on Congestion Hedging Issues.)
That was when Altenbaumer stepped forward and suggested staff and stakeholders work together and reach consensus on how best to add CFO to the market. (See “Counterflow Optimization not Dead Yet,” SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)
“There’s been no shortage of analysis. It’s simply a lack of consensus,” Altenbaumer said. “Lack of consensus doesn’t mean we have a lack of an issue. It’s reached a point where it doesn’t mean we should delay our concerns.”
Altenbaumer, who facilitated the Aug. 30 workshop’s panel discussions, alluded to the difficulties that still lie ahead for SPP’s staff and stakeholders.
“Facilitating this reminds me of a game show host,” he said. “I’m not sure whether it’s ‘Jeopardy,’ ‘Let’s Make a Deal,’ ‘The Price is Right’ or, God forbid, ‘Family Feud.’ We’ll see what happens when we get into this.”
That the positions in the opposing camps have only solidified quickly became evident. Some stakeholders say SPP’s congestion-hedging process is unfair and continue to ask for changes. Others says the status quo works for them.
John Stephens, who manages City Utilities of Springfield’s (Mo.) generation fleet and transmission system, said most market participants who nominate financial positions before transmission congestion rights (TCRs) are awarded are “absolutely happy” because they’re getting all of their nominated congestion hedges.
“This is not a complicated problem. There are a lot of details and we could spend hours and hours digging into those details, but essentially, we have 25 people in line, but we have 20 widgets to give away,” he said. “How we allocate those limited numbers of widgets is the problem in my mind. The first 20 guys in line are getting widgets, and the last five are not. We would like to see a more equitable process, where people get a similar percentage of the widget.”
Overview of SPP’s allocation process for auction revenue rights | SPP
“The main factors that have prevented stakeholders from moving forward is comfort with the status quo on a complex issue,” Southern Power’s Chase Smith said. “There’s the risk and uncertainty that is probably viewed by implementing something new and not completely understanding how it will impact each of the market participants. Some market participants are impacted by ARR [auction revenue rights] allocations more than others. There’s concern some moderate counterflows may impact the current congestion-hedging mechanism.”
“Unfortunately, the problem is that some people and their actions are not harmed directly by the actions of others, but the actions that they are taking or not taking is affecting someone else. And that’s hard to sort of grasp,” said Keith Collins, SPP vice president of market monitoring.
A consultant’s review last year determined market participants have too much latitude over the congestion-hedging process, staff said. It determined ARRs are set equal to transmission service rights requests, with 75 GW of candidate ARRs and a 50-GW nomination cap. The consulting firm found nomination patterns generally pursue highly valued paths, resulting in increased curtailments and asset owners leaving too much unclaimed monetary value.
Staff’s proposed solutions include aligning commercial and transmission models and using a planning feedback loop to provide a list of congested elements for considering in the planning processes. They said this will provide incentives for transmission expansion projects.
Under this proposal, SPP would also model load to ensure settlement locations, match network integrated transmission service agreements and model generators to better match candidate ARRs with generation in the day-ahead market.
Other proposals included:
adding an additional round to the long-term congestion rights process and allowing participants to keep their positions for a year;
baseload a percentage of the nomination cap for each participant based upon a ratio of every transmission service request’s path;
use CFO after the first round of the ARR allocation process, uplifting its cost to the market participants that opt in;
changing the nomination caps in the annual ARR process; and
limiting system capacity to 50% for each of the annual ARR and TCR process.
Stakeholders expressed their interest in further developing the alternative proposals, although there was pushback from those who have been heavily involved in the CFO effort.
“I certainly want to make sure what we’re doing is consistent with where we think we need to be in five, six or seven years downstream, and that we don’t put a Band-Aid on something that will certainly change,” Altenbaumer said. “We need to have a good understanding of the interdependencies. We don’t want to solve this problem in the marketplace if there are some options to develop strategic transmission that provides overall benefits to the system.”
“To the extent we need to run some of these ideas to ground, I think we can do that,” American Electric Power’s Richard Ross — chair of the Market Working Group that has been responsible for much of the development — told Altenbaumer. “I may perhaps be a little pessimistic, but I’m not sure that I’ve heard one [idea] that I feel like is going to minimize the impact on others quite as much as the option that we’ve been talking about for so long.”
SPP’s Micha Bailey, who conducted the workshop, said his concern remains future uncertainty.
“Look at the [generator interconnection] queue and look at all the solar and the batteries that are right behind [wind requests],” he said. “Once again, I wish I had a crystal ball. I wish I could say, ‘Look all y’all, we’re great. All y’all are protected.’ If we don’t work towards a solution together, it’s very bleak for me to say, ‘Hey, we’re in a good spot.’”
Refunds on Overlapping Congestion Charges
Staff also told stakeholders Wednesday during a Seams Advisory Group meeting that SPP and MISO will issue refunds in October to AEP and the city of Prescott, Ark., for overlapping congestion charges on pseudo-tied loads and resources between the two markets.
FERC approved a settlement agreement on Sept. 7. Under its terms, the RTOs will refund $142,768 to AEP and $53,017 to Prescott, split evenly between the grid operators (ER22-2221).
The commission opened an investigation in 2019 into the overlapping charges following complaints from AEP subsidiary Southwestern Electric Power Co. and Prescott that both the host and attaining markets were charging for congestion across the same transmission path. It accepted the RTOs’ proposed” predictive flow factor process” solution in December and directed them to refund the complainants. (See FERC Accepts MISO-SPP Congestion Charge Solution.)
SPP will recover its portion of the settlement payments through a revenue neutrality uplift from market participants that either provide generation, consume generation, have scheduled interchange transactions, or have virtual bids or offers.
The predictive flow factor process improves the exchange of market flow data and better predicts impacting market flows when determining relief obligations during market-to-market. The two RTOs have more than 2.7 GW in combined pseudo-tied generation or load.
ERCOT’s Technical Advisory Committee last week followed direction from the Board of Directors as it discussed proposed revisions to its membership qualifications and ways to accelerate the revision request process during its annual procedural and organizational review.
Acting at the behest of the board’s new Reliability and Markets (R&M) Committee, TAC’s members expanded a requirement that they have a combined five years of industry experience in regulatory, markets, operations and/or finance to include plant operations and energy procurement.
They agreed with a requirement that employers or sponsors certify that TAC members are authorized to make segmental decisions. A certification form has yet to be developed.
“The R&M wants people sitting on TAC to be qualified,” TAC Chair Clif Lange, with South Texas Electric Cooperative, said during the Sept. 12 virtual meeting.
Representatives from the Office of Public Utility Counsel and the residential consumer segment are exempt from the requirements.
Lange and Vice Chair Bob Helton, with ENGIE North America, also discussed a proposed “shot clock” for revision requests “languishing in the process” that would speed up their movement. The shot clock would be used for existing requests the Public Utility Commission has “explicitly stated” they would like moved forward. However, it can’t be used when an RR is first introduced at TAC’s Protocol Revision Subcommittee; urgent status is used in that instance.
The committee’s leadership is suggesting its procedures be amended so that a decisive vote must be taken at TAC or one of its subcommittees if requested by the RR’s sponsor or ERCOT. Failed votes would still be appealable through the normal appeals process.
Lange said the proposal was brought in August to the R&M, which approved of the direction.
“There are some details to work out,” he said. “This creates potentially a very clean way to move things forward without developing an alternative process.”
The Sierra Club’s Cyrus Reed, who does not sit on TAC, raised a concern over whether the revised process would violate administrative procedures rule. Staff pointed out that any proposals would have to go through the stakeholder approval process, allowing for further discussion then.
Lange and Helton told members that TAC will continue to report to the board its activities and decisions. The committee’s leadership will meet with the full R&M Committee to provide background on its decisions and counter positions. The board’s committees meet the day before full board meetings.
TAC’s membership will return with feedback on the proposals during its regular monthly meeting Sept. 28.
TAC Passes on Bylaw Changes
The committee also delayed discussion of proposed amendments to ERCOT’s bylaws until its Sept. 28 meeting.
The proposed changes, drafted at the board’s direction, would no longer require members’ approval of bylaw amendments. It would require that members be provided notice and the chance to comment on any proposed amendments or other “fundamental actions.”
Other changes would expand the directors’ ability to participate and vote by teleconference or similar means when an in-person quorum is achieved for their meetings.
Members have until Sept. 30 to comment on the revisions. The board plans to discuss the amendments when it next meets on Oct. 17-18.
The changes are a result of legislation passed last year after the February 2021 winter storm that shifted authority from market participants to the independent board.
ERCOT distributed a market notice with the proposed changes just before the close of business on Sept. 9, a Friday.
The New York Climate Action Council (CAC) on Sept. 13 heard progress reports from three subgroups that will provide recommendations on a final scoping plan to implement the Climate Leadership and Community Protection Act (CLCPA).
In its draft scoping plan, the CAC tasked the three subgroups, Gas System Transition, Alternative Fuels, and Economywide Polices, with studying their critical issues in depth and bringing consensus positions to the council. (See NY Officials Approve Draft Climate Action Plan.)
The Sept. 13 meeting was likely the last opportunity for each subgroup to share their progress before they present their final scoping recommendations to the council for consideration.
Gas System Transition Seeks Clear & Equitable Timelines
The Gas System Transition subgroup, tasked with developing an orderly downsizing of the state’s gas systems, updated the CAC on some of the key considerations that will influence its final recommendations. These included prioritizing continued safety and reliability to disadvantaged communities, ensuring a just and transparent transition of the industry’s workforce, and mitigating both the costs and health burdens to customers as they transition away from gas distribution systems.
The subgroup also plans to develop a detailed timeline to provide clearer guidance on what the gas transition means to consumers and producers.
Alternative Fuels Facilitate Multi-Industrial Transition
The Alternative Fuels subgroup considered how resources such as hydrogen, biofuels and renewable natural gas could decarbonize industrial sectors resistant to electrification.
The subgroup informed the CAC that it focused on identifying how fossil fuels’ capabilities can be replaced without compromising the CLCPA’s goals. The final recommendations are likely to urge New York to be open to new undeveloped fuel technologies and think strategically about how alternative fuels could scale and support industrial reliability and economic development.
The group said strategies should ensure the highest potential for reductions of emissions of GHG and co-pollutants, prioritizing emissions reductions in disadvantaged communities. The plan should prioritize electrification rather than alternative fuel use in such communities, it said.
Maureen Leddy, director of the Department of Environmental Conservation’s Office of Climate Change, discussed how the subgroup identified “rust belt” rural regions that may need significant infrastructure upgrades for electrification. Such communities could benefit from onsite biogas, such as methane, that “can be used locally, if adequate demand and supply is feasible” since this would reduce costs and address peak load constraints by taking pressure off the electric grid.
The Alternative Fuels subgroup also emphasized that “research into undiscovered technologies should be using federal [funds]” and that these projects should “have clear guidelines” on how they will impact economic, societal and environmental sectors.
The subgroup pointed out that it has been working closely with the Gas System Transition subgroup.
The draft scoping plan outlined three policies that would help push New York’s economy toward zero emissions: a tax or fee on emissions (carbon pricing); a cap on emissions across the economy, or within particular sectors with an auction mechanism that provides revenue for investment (cap-and-invest); and a clean energy supply standard, which would require fuel providers to reduce their carbon intensity.
The Economywide Strategies subgroup, asked to evaluate those policies, appeared poised to identify key decision-making criteria: ensuring compliance with CLCPA emissions limits; maintaining price stability and affordability; avoiding regressive economic impacts, and prioritizing equitable distribution of benefits to disadvantaged communities.
This subgroup, as with the other two subgroups, will not be making any decisions around which economic policy will be adopted, but will influence the degree, amount, or level to which these policies will be set.
Next Steps
The three subgroups are likely to present their final reports at either the Oct. 13 or 25 CAC meeting.
The CAC also announced that it will be moving to two meetings per month and that future meetings would be held in-person.
SARATOGA SPRINGS, N.Y. — Three years after New York passed some of the strongest climate protection legislation in the nation, the technology to reach its goals and the plan to roll it out are still works in progress. And that has the head of the Independent Power Producers of New York (IPPNY) more than a little concerned.
The draft scoping plan of New York’s Climate Leadership and Community Protection Act (CLCPA) contains many unanswered questions on affordability, reliability and zero-emission technologies, IPPNY CEO Gavin Donohue said at the group’s Fall Conference on Wednesday.
“If we’re not going to use natural gas to keep the lights on, what is it going to be? There is no consensus on what qualifies as zero-emissions resources,” Donohue said in his opening remarks to the conference. “I am concerned about reliability. I don’t think the plan takes in reliability enough.”
The future of natural gas-fired generation — and what new technologies could replace its role in balancing intermittent renewable sources — dominated the discussions at the conference, which attracted more than 125 industry stakeholders to the Saratoga Springs City Center.
Seeking State’s Guidance
“It’s scary,” Donohue said, citing California’s pleading with residents to curtail power usage during its August heat wave; the deadly 2021 winter storm in Texas; Europe’s energy squeeze as a result of its reduced nuclear capacity; and the Russian invasion of Ukraine. “We really have to learn from those examples.”
Donohue called on state officials to provide guidance on how to reach the CLCPA’s requirements: reducing the state’s greenhouse gas emissions by 40% below 1990 levels by 2030; increasing renewables’ share of the state’s generation mix to 70% by 2030; and reaching net-zero emissions from electric supply by 2040. Those goals must be reconciled with the reality that gas and oil made up 70% of NYISO’s capacity as recently as July, he said. “How do we just ignore the fact that we needed oil and gas to keep the lights on at that rate?” he asked.
Last month, the New York State Building & Construction Trades Council and state AFL-CIO, which represent energy infrastructure workers, joined IPPNY in issuing Seven Principles for reaching the state’s climate goals, saying current plans lack a full cost analysis and a plan for grid reliability.
It followed the groups’ August 2021 petition asking the Public Service Commission to create a competitive program to encourage private sector investment in at least 1 GW of zero-emissions energy systems that would be in commercial operation by 2030.
“Under the law, the Public Service Commission has to determine what” qualifies as zero-emission resources, Donohue said to the audience, which included Commissioners Diane Burman and David Valesky.
Although the commission has outlined policies to achieve the 70-by-30 target, it has not said how the state should achieve the 2040 zero-emission target or when it would consider establishing such policies. “The commission’s silence on these matters creates uncertainty in the electricity market and investment community.”
The petition cites as possible technologies hydrogen; nuclear; combined cycle and combustion turbines fueled by zero-emission biogas; and natural gas with carbon capture and sequestration.
The petition asked the commission to decide by July 1 the zero-emission energy systems likely to be technically capable by 2030. “Having these new technologies enter into service by 2030 will allow operational experience to accumulate and provide an opportunity for any needed technology refinements to assure that all necessary resource additions are operating in time to achieve the 2040 zero-emission target,” it said.
The commission has taken no action on the petition.
Reasons for Optimism
Department of Environmental Conservation Commissioner Basil Seggos, who spoke after Donohue, said the DEC is meeting monthly with the Department of Public Service and NYISO to address reliability concerns as the state prepares to finalize the CLCPA scoping plan. The plan, which Seggos said generated 35,000 public comments, is due to be finalized and submitted to the governor and legislative leaders in January. (See NY Officials Approve Draft Climate Action Plan.)
“We have to keep the lights on as we make this incredible transition, this really difficult transition, to the future,” Seggos said.
Seggos did not downplay the difficulty of the task at hand: “This will be the hardest thing that New York state ever does, and frankly, that the U.S. ever does: addressing the climate crisis and doing it in a way that benefits everybody.”
But he said he was optimistic, citing the nation’s response to World War II and the COVID-19 pandemic and the climate spending authorized by Congress under the Inflation Reduction Act. “What is $369 billion [multiplied to by] leveraging private dollars? It’s trillions, probably.
“We’ve got the technologies,” he said, qualifying that “we may not have all of them; they may not be at scale yet; but we have the makings of these technologies.”
Implementation Questions
IPPNY’s outside counsel, David Johnson of Read and Laniado, asked Seggos about the DEC Division of Air Resources’ DAR-21 policy implementing Section 7(2) of the CLCPA. The provision requires the state to determine if applications for Title V air pollution control permits are “inconsistent with or will interfere with” statewide GHG emission limits under the CLCPA’s targets. DAR must finalize its regulations by Jan. 1, 2024.
Johnson said the DEC has denied Title V permits for the Danskammer and Astoria repowering projects and renewal of the existing Greenidge generating station.
Seggos responded that the division expects to release information later in September on the status of the DAR-21 process but needs to solicit more input before finalizing it. He said the department is making determinations on a case-by-case basis until “until the entire realm of the CLCPA is constructed.”
Developers seeking a new or renewal permit should provide an analysis determining if their project will cause an increase in emissions, he said. “Please engage with us and bring us that analysis early if you can, even if it’s in draft form.”
Ken Pokalsky, vice president of the Business Council of New York State, asked about the parallel goals of the CLCPA: its focus on environmental justice, and on ensuring that the disadvantaged communities that have suffered the greatest impacts from climate change reap investments from the transition. There is no guidance yet on what constitutes disproportionate and inequitable impacts, Pokalsky pointed out.
The process is still underway, Seggos replied, adding that he hopes the mapping of disadvantaged communities is completed soon, because they will guide the decision-making and the investment and benefits analyses mandated by the CLCPA.
Marji Philips of LS Power asked what the state’s “Plan B” is for replacing natural gas. Battery storage and hydrogen aren’t yet viable backup options for intermittent zero-emission power sources, she said.
“I don’t think we have a Plan B,” Seggos replied. “I think that we are on the edge right now when it comes to global climate change. We have one shot to get this right. That’s what makes this so challenging.”
Rate of Change
NYISO Executive Vice President Emilie Nelson also acknowledged the challenge of retiring fossil fuel generation while rapidly increasing generation through new technology and expanding the grid to accommodate it.
“One thing that is certainly on the ISO’s mind is the rate of change that is needed,” she said. The grid must be even more reliable after the transition than it is now, because so much of the economy will rely on electricity, she said.
She referenced the scenario in the ISO’s System & Resource Outlook calling for New York to have 45 GW DEFR online by 2040; that is more than all resources currently available to the state. The fact that the state is relying on technologies that have not been commercialized is a big part of the challenge, she said.
“The unknowns certainly can be daunting; they can be scary,” she said. “What we need to do is have honest dialogue about what those challenges are, so that we make sure we’re clear-eyed about what we need to manage.
“This isn’t going to be a linear change,” Nelson added. “It’s going to require adjustment. It’s probably going to be messy at times.”
ARLINGTON, Va. ― Infocast’s two-day Hydrogen Hubs Summit last week was intended to focus on the $8 billion in federal funding for clean hydrogen hubs ― officially dubbed “H2hubs” ― authorized in the Infrastructure Investment and Jobs Act (IIJA) and the multiple value streams they can create.
However, that was largely overshadowed by the production tax credit (PTC) for green hydrogen — up to $3/kg — in the Inflation Reduction Act (IRA), as speaker after speaker hailed the incentive as a “game changer.”
The result of hard lobbying by the industry, the PTC is “the single most important thing that we could have done and will do moving forward,” said Erin Lane, vice president for public affairs at Plug Power, a green hydrogen production and storage company. “It’s not just driving costs down here in the United States, but the rest of the world is watching, and they’re going to follow suit.”
The PTC “makes the U.S. the No. 1 place to build [hydrogen] production projects in the world, both from a country risk and economic perspective,” said Alejandro Perellón, investment director for the Americas at Hy24, an investment firm focused solely on hydrogen. “It’s going to be tough for other geographies to compete with that. … Capital is going to flow to the U.S.”
The conference drew about 240 business leaders, federal, state and local government officials, and researchers and nonprofit representatives, most of them with hydrogen projects at some stage of planning or development.
As defined in the IIJA, an H2hub is “a network of clean hydrogen producers, potential clean hydrogen consumers and connective infrastructure located in close proximity.”
The U.S. Department of Energy provided an overview of the program in a Notice of Intent released in June, and according to its website, the official funding announcement is scheduled for the coming weeks. (See DOE Hydrogen HUB Funding Program Announced.)
The demonstration hubs that may soon be receiving IIJA funds are not at commercial scale, noted Todd Shrader, deputy director for project management at DOE’s Office of Clean Energy Demonstrations, which will oversee the program.
Now less than a year old, the office is “trying to identify the risks and mitigate them where we can and then leverage, of course, private partnerships across all these efforts to move this into commercialization,” Shrader said. “The Notice of Intent indicated six to 10 hubs, but we see our mission as, yeah, we’ll help build the first six to 10, but how does our mission translate into plant 10 to 100? What can we do to de-risk that and move forward with the mission or move forward with transformation of the economy itself?”
Building Supply, Creating Demand
A July analysis from the Center for Strategic and International Studies (CSIS) found 22 hub proposals in the works, most of them coming from public-private partnerships.
Laura Luce, CEO of Hy Stor Energy, said her company has 80,000 acres for a Gulf Coast hub that could eventually produce green hydrogen from electrolyzers powered with solar or other renewables. The hydrogen will then be stored in multiple underground salt caverns ― Mississippi has more than 50 of them ― and sent out to a range of potential end users located in the area.
The goal is “to bring manufacturing and some of those products and services that need expansion ― [such as] steel, ammonia and fertilizer ― into our location, so that we can have this kind of circular economy and be very dependent on each other,” Luce told the audience at.
Hy Stor’s first small project, including a 1-MW electrolyzer, will be completely off-grid so the company can ensure customers are getting 100% carbon-free hydrogen, Luce said. Hy Stor has already permitted four salt caverns, the first of which will be able to store 70,000 metric tons of hydrogen, she said.
“By having multiple caverns and by having adequate compression, we can start cycling them,” Luce said. “We’ve designed our caverns so they can recycle 12 times a year as demand increases, so you really get a tremendous amount of leverage on that initial investment.”
The company hopes to have the first electrolyzer up and running by 2023 or 2024, she said.
Another example, although not on the CSIS list, is the Center for Houston’s Future’s vision for a network of clean hydrogen hubs across Texas, which already has well developed infrastructure, both pipelines and storage, for hydrogen produced from natural gas. Speaking at the summit, Brett Perlman, the center’s president and CEO, detailed the state’s other selling points, including “lots of expertise in hydrogen and using hydrogen, a concentration of academic and industry-driven innovation … [and] a welcoming environment for infrastructure development.”
Texas also has a wealth of renewable wind and solar projects in the western part of the state. “We want to build this as a broad-based ecosystem,” Perlman said.
According to a report from the center, a Houston hub would produce hydrogen for applications in the fossil fuel industry — refining, natural gas blending and port operations ― while a Corpus Christi hub would focus on hydrogen for use in iron and steel manufacturing. A Dallas hub would specialize in waste-to-hydrogen production, while Beaumont would be a center for hydrogen used for power generation.
The goal is for Texas to produce about 21 MMT of clean hydrogen per year, half for domestic consumption and half for export, Perlman said. Beyond applying for IIJA funding, the next step is focusing on “demand aggregation and demand creation,” he said.
“The idea [is to] engage with demand creation, getting early adopters who are interested in driving demand either domestically or internationally to come to the table,” Perlman said. “We believe that will have a knock-on effect in the next set of supply projects.”
A Clean Hydrogen Standard
By contrast, Dominion Energy, Virginia’s largest investor-owned utility, sees hydrogen as playing a more modest role in its plans to decarbonize its power generation in the state by 2045, as required by state law. While the utility is working on the permitting and construction of a 2.6-GW offshore wind project, it has not signed on to any proposal for an IIJA-funded H2hub.
Dominion is investing in renewable natural gas and looking at blending hydrogen with natural gas as a means to reduce emissions, said Rizwan James, manager for combustion fleet turbine engineering. So far, it has completed one pilot project in Utah, which tested blending 5% hydrogen with natural gas, and is waiting for approval of a second, similar pilot in North Carolina, James said.
Opposition to hydrogen from some clean energy and environmental groups is rooted in such applications, which are seen as a “greenwashing” strategy to prolong the use of fossil fuels. They are skeptical of the IIJA’s requirement that its funding must go to clean hydrogen hubs that are technologically diverse in both their feedstocks and end uses. While at least one hub will produce hydrogen from renewable energy, one will use fossil fuels and one nuclear, according to DOE’s notice.
Similarly, one hub must demonstrate the use of clean hydrogen for power generation, one for industrial applications, one for residential and commercial heating, and one for transportation. The initial round of funding will include grants of up to $10 million for producing a detailed hub plan over the next 12 to 18 months and will require the federal dollars to be matched 50/50 with private or other public funding.
The law also requires DOE to establish a clean hydrogen standard, Shrader said, which is already looming as a major challenge for applicants and their hubs ― and a point of intense industry debate — as the IIJA and IRA set different benchmarks.
The IIJA defines clean hydrogen as producing no more than 2 kg of carbon dioxide per kilogram of hydrogen at the point of production, with a possible re-evaluation of that standard after five years. But to qualify for the IRA’s $3/kg tax credit, the maximum is 0.45 kg of CO2 per kilogram of hydrogen.
Lesser credits are available for higher concentrations, beginning at $1/kg for a CO2 intensity of up to 1.5 kg and bottoming out at 60 cents for 2.5 to 4 kg.
While all H2hubs will have to meet the IIJA’s 2-kg carbon-intensity standard, the NOI states, “DOE intends to also evaluate full lifecycle emissions for each application and will give preference to applications that reduce GHG emissions across the full project lifecycle, inclusive of hydrogen production, compared to current industry standards.”
While potential applicants are already asking if and how the standards might be reconciled, Janet Anderson, senior technology and policy adviser for the Clean Hydrogen Future Coalition, said that finding common ground may not be possible.
“They’re not related,” Anderson said during a panel on the second day of the summit. “I don’t really know how they can be reconciled.”
Compared to DOE’s “full lifecycle analysis,” the IRA “states that the lifecycle analysis will end at the point of production or, if you will, go well-to-gate,” she said. “Significant indirect emissions” must also be included, she said, but “everybody working on hubs would like to see a lot more certainty about what’s going to happen with this,” as the Treasury Department and Internal Revenue Service hash out rules and guidance.
Nima Simon, grid fuel and power supervisor at industry analyst ICF, said her clients are raising questions about whether indirect emissions will include Scope 3 emissions: those generated in a company’s supply chain that it cannot control, such as from waste generated by suppliers or their employees’ business travel.
Both Anderson and Simon also stressed that hydrogen technology, carbon intensity definitions and carbon accounting methods will change over time. “This isn’t going to happen in 60 days. It’s going to take some time,” Anderson said.
“There might be a public comments period,” Simon said. “It’s still very early stages; there is maybe some room for conversation.”
MINNEAPOLIS — MISO, its market monitor and members debated the best course to implement ambient-adjusted line ratings during a Sept. 15 Advisory Committee meeting.
The Independent Market Monitor and some members endorsed widespread adoption before FERC’s Order 881 takes effect in 2025, while transmission owners advocated a more restrained introduction.
Renuka Chatterjee, vice president of operations, said the key terms in formulating ratings are “push” and “safe.”
“We want to push our system to its limits, but we want to keep it safe,” she said.
Chatterjee reminded the membership that the Northeast’s massive blackout of 2003 initially began with power lines in northern Ohio drooping into trees and tripping circuit breakers.
MISO says that universal use of ambient-adjusted ratings (AARs) in conjunction with strategic transmission reconfigurations “will only locally and marginally decrease congestion.” It said the billions worth of transmission projects identified under MISO’s long-range transmission plan (LRTP) and its Joint Targeted Interconnection Queue study with SPP are better positioned to “substantially” reduce congestion.
Only 12% of MISO’s transmission facilities use the AAR mechanism.
“Now, you can conclude that 88% of lines need work, but not all of these are congested lines,” Chatterjee said.
But the IMM’s David Patton said MISO should have “full utilization of the system first” before it builds out transmission facilities.
Patton said that since the fall of 2021, MISO has achieved $34 million in savings by using AARs on 65 constraints. But he said the RTO and its transmission owners have left $282 million in possible savings on the table by not deploying AARs on all constraints. He said had MISO used two- to-four-hour emergency line ratings in the footprint, it could have saved $179 million since last fall.
Patton said binding transmission constraints with overly conservative ratings can strand generation and keep MISO from accessing the full range of its reserves.
Some members asked TOs to install AAR programs before Order 881’s compliance deadline.
Clean Grid Alliance’s Natalie McIntire pointed out that the first batch of LRTP lines aren’t expected to be in service until 2028 and 2030. She said in the meantime, MISO can use AARs and dynamic line ratings (DLRs) to get the most out of its transmission system. She said more precisely calibrated ratings will ease the system congestion caused by wind production in the footprint’s northern region and might allow for more wind generation interconnections.
Michigan Public Service Commission Chairman Dan Scripps said DLRs and AARs can help avert load shed during extreme weather events and when generation is scarce.
“We’re not going to eliminate congestion. We can reduce it through AARs … but it’s not the end-all and be-all,” ITC’s Cynthia Crane said.
Crane said the MISO footprint will likely benefit from AARs in the spring and fall shoulder seasons and in the mornings and at night, when temperatures are cooler.
“Unfortunately, we’re not going to see much benefit from AARs during the summer or during heat waves,” she said.
Otter Tail Power’s Stacie Hebert, a MISO transmission owners representative, likened standing up AAR programs to complex undertakings such as the grid operator’s market platform replacement or its long-term transmission planning.
“Some things just take as long as they do to get them done,” Hebert said.
Crane said AAR programs mean that TOs will have to overhaul software to maintain databases with millions of entries that change hourly.
“From our standpoint, three years feels like tomorrow,” she said of Order 881’s compliance deadline.
Hebert said the most congested transmission elements are usually transformers, which FERC has ordered TOs to review. She said TOs are carefully maintaining transformers because hobbled supply chains are making them increasingly difficult to replace.
“We’re not looking to put additional risk to our transformers at this time in this current environment,” she said, noting TOs don’t have their normal stockpiles of spare transformers.
Hebert said that although TOs agree there are savings to be had, she disagrees with Patton’s figures.
“In order to make that estimate for the footprint, he had to make some assumptions, and he doesn’t have access to that information,” she said.
Hebert said she didn’t see how Patton could factor in the next limiting transmission element in his ratings saving calculation. She said line ratings have been underscored lately because of big-ticket and possibly overblown savings being estimated.
Multiple MISO TO representatives said estimating AAR savings is moot because they will have to implement AARs anyway.
Some Advisory Committee members said MISO and TOs conducting closed-door meetings of its Reconfiguration for Congestion Cost Task Team (RCCTT) doesn’t inspire trust that TOs are making decisions with everyone’s best interest in mind. MISO and TOs say the confidential sessions are necessary because the group discusses critical infrastructure.
The nonpublic RCCTT has met since last year and focuses on rerouting transmission flows during times of heavy congestion costs. It maintains a monthly list of the top congested constraints within the footprint.
ERCOT has scheduled a pair of live virtual presentations this week to discuss the terms of its proposed settlement with Brazos Electric Power Cooperative that is part of the utility’s bankruptcy case.
The identical presentations will be held Tuesday at 2:30 p.m. (CT) and Wednesday at 10 a.m. ERCOT said because it expects a large number of attendees, it will not answer questions or facilitate a chat feature during the presentations. However, questions can be submitted in advance to MPElectionNotice@ercot.com.
The U.S. Bankruptcy Court for Southern Texas’ chief judge last week conditionally approved Brazos’ disclosure statement on the settlement with ERCOT and its proposed exit plan from Chapter 11 bankruptcy. The decision allows Brazos to begin soliciting votes from creditors and settle its dispute with ERCOT (21-30725). (See related story, Judge Approves Brazos Chapter 11 Exit Plan.)
The decision also allows ERCOT to move forward with an election-notice process for eligible market participants that will conclude on Oct. 21. A hearing has been scheduled before the court in November to consider final approval of the settlement and the exit plan.
Brazos was originally charged $1.89 billion for wholesale power market costs during the February 2021 winter storm that it owed the market. The settlement with ERCOT has reduced that to $1.4 billion.
The Texas grid operator said in a market notice Friday that it has not reached a final agreement on some provisions in the plan and that it expects further modifications as it continues to negotiate with Brazos and other key stakeholders. It said it has been coordinating with the Texas Public Utility Commission and Attorney General’s Office on the proposed settlement and continued negotiations.
ERCOT attached a letter to the notice from PUC Chair Peter Lake, who said Brazos’ reorganization addresses the economic recovery of the grid operator’s bankruptcy claim and “material, noneconomic concerns important to the commission and ERCOT.” That includes the cooperative’s continued existence and management, Lake wrote.
The grid operator said it is developing a webpage where it will post a recording of one of the virtual presentations and other important settlement materials, including answers to submitted questions.
A Washington-based electric-powered airplane company intends to sell 50 commuter aircraft to an airline serving Florida, the Bahamas and the Caribbean.
The nine-passenger, two-pilot aircraft — dubbed “Alice” after one of the co-designers listened to “White Rabbit” by Jefferson Airplane while he worked — is scheduled to go through its first test flight by the end of September, said Eviation spokesperson Lauren Lewis.
Eviation is based about 40 miles north of Seattle in Arlington. The first flight of its Alice model will take place at an airfield in the Central Washington town of Moses Lake, which is used for test flights by various aircraft companies.
The companyhas signed a letter of intent to sell 50 Alice aircraft to Miami-based Global Crossing Airlines, which serves the United States, the Caribbean and Latin America, the two companies announced Thursday.
“We are delighted to enter this agreement with GlobalX, whose investment in zero-emissions flight demonstrates the airline’s commitment to cleaner skies, lower operational costs, and the provision of the most innovative options for air travel, Eviation CEO Gregory Davis said in a press release. “Quieter, smoother and with a cabin design that defines the future, the in-flight experience aboard the Alice will offer GlobalX passengers a new way to fly.”
“We plan to offer the aircraft to our cruise line, tour operators, leisure travel providers, and business clients with a need for short-haul charter flights across Florida,” said Ed Wegel, CEO of GlobalX, in the same press release. “The Alice aircraft will allow us to offer sustainable, regional flights to and from major markets, and is the first step in our initiative to be a zero-carbon emissions airline by 2050.”
In an email to NetZero Insider, Lewis said the sale is the third in the works for Eviation. The other deals include the sale of 12 Alice cargo planes to Germany-based logistics and freight corporation DHL, and 75 Alice commuter planes to Massachusetts-based Cape Air. Cape Air provides commuter service for the northeastern United States, the Caribbean, Midwest and eastern Montana.
The Alices will be built in Arlington. Delivery times to the prospective customers are still be worked out, Lewis wrote. Eviation declined to provide sales price figures.
The installation of charging stations for the all-electric aircraft is still being worked out, with the process encompassing airports, fixed-base operators, airlines and manufacturers, Lewis wrote.
First unveiled at the Paris Air Show in 2019, the twin-engine prototype had been developed in Arlington. It has a range of 440 nautical miles with a cruise speed of 250 knots. Its maximum takeoff weight is 16,500 pounds.
In a unique joint vote, the PJM Operating and Market Implementation committees overwhelmingly endorsed an RTO package of revisions of its fuel requirements for black start resources.
The changes center around the creation of a new “fuel assured” classification of black start service providers that can demonstrate a higher level of reliability by reducing fuel availability concerns.
The PJM package, which was drafted with Brookfield Renewable and the D.C. Office of the People’s Counsel, received 76% of the 206 votes cast, while a proposal from the Independent Market Monitor received 9% support over the status quo, the RTO revealed during a special joint meeting of the committees Friday. The revisions will now go before the Markets and Reliability Committee during its meeting this Wednesday.
In addition to meeting existing black start requirements, the PJM proposal would require that a fuel-assured unit must either have adequate fuel storage for 16 hours of full run time, the ability to operate independently on two or more interstate pipelines, be directly connected to a natural gas gathering system, or be capable of providing 16 hours of full load operation with 90% confidence, as determined by the RTO.
The new fuel assured category would also come with a higher black start incentive, but it would come with a penalty of lost monthly revenue for generators that fail to meet the requirements. The increased incentives would cost an estimated $436,000 across all sites, PJM said during the Friday meeting.
The penalty remained a source of concern for some stakeholders who believe the risk isn’t matched with the payoff for becoming a fuel-assured unit.
The mitigation of eight high-impact black start sites in five transmission zones is also estimated to increase PJM’s annual revenue requirement for the service by $28 million per year, according to the RTO.
PJM staff said they will continue to tweak the revisions in the days leading up to the MRC vote to provide further clarifications and to add that gas generators submitting a fuel-assured application can demonstrate their ability to use two pipelines with actual usage in the past year, rather than needing to test each pipeline independently.
Voting on the IMM and PJM proposals opened after the OC meeting closed on Sept. 8 and closed Sept. 13. Stakeholders of both the OC and MIC could vote on the packages, though individual entities were limited to one vote overall and any duplicates were removed.
The Monitor’s package largely differed around the treatment of intermittent resources; while the PJM proposal would allow for their inclusion as fuel-assured units if they were determined to be able to meet the requirements with 90% confidence, the IMM language excluded them outright because the technology is not currently ready for them to provide power at the reliability needed for black start. (See PJM, Monitor Debate Black Start Fuel Requirements Proposals.)
The IMM also expressed concerns that the PJM package could result in overpayment for units that meet the fuel-assured requirements but don’t enter into the black start procurement process as such, allowing them to receive the benefits of being fuel assured without the risk associated with the penalties.
