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.
HENDERSON, Nev. — Gary Nolan, NERC compliance manager at Arizona Public Service, is more than a little uneasy about the future of the electric industry’s workforce.
Speaking Tuesday at WECC’s first in-person stakeholder meeting since the onset of the COVID-19 pandemic, Nolan raised what’s become a running concern for the utility industry: the inability to attract younger employees who want to stay in a position for the long haul.
“I know when I was hiring dispatchers 15 years ago, I was having to hire new ones every six to nine months,” Nolan said. “I kept thinking, ‘I don’t know how sustainable this could possibly be.’ In the 15 years since then, I would say I’m sure — as WECC has noticed — that has only gotten worse, right?”
Nolan could only think of a couple operators in APS’ control center who have more than two years on the job. He said it takes at least that long for an employee to become an effective operator of a high-voltage transmission network.
“And knowing this … next generation does not seem like they want to have one career for 30 years, unless something fundamentally changes here in the near future, I really think that we’re going to have to rethink how these jobs are performed or how we’re training for these jobs, because you cannot rely on an algorithm now to have those five to 10 years of [human] experience and know how to survive significant [grid] events,” he said.
“So that’s something that certainly scares the pants off me.”
Nolan’s comments came during an “interactive strategy forum,” part of the series of meetings at WECC’s annual member conference. WECC convened the forum to elicit members’ visions for the electric sector over the next decade to help the organization shape its long-term strategy.
“It’s important that WECC’s work be informed and shaped by our stakeholders. … What should we be prepared for in 2032? [Because] that 10 years will go by very fast,” said Kristine Raper, WECC vice president of external affairs.
New ‘Patterns of Living’
Maury Galbraith, executive director of the Western Interstate Energy Board, pondered the workforce issue from a different angle — but one that could still affect the electricity sector in a big way.
“Is work going to look the same in 10 years than it does today? I mean, are we going to really be having five-day workweeks? Eight-hour workdays? I cannot imagine that is going to be the future in 10 years. I think people will be setting their own schedules, working at their own pace on their own time,” Galbraith said.
He pondered how that could affect the “pattern of living” and the shape of electrical load over the course of a week.
“Are we really going to continue to have a problem with meeting load the length of 6:30 to 10 p.m. time frame? Or is all the load in that time frame going to go elsewhere? I just don’t think the problems of today are necessarily the problems of 10 years from now,” he said.
“I would imagine that there’s going to be big, big changes in how people work? I’m hoping we get four-day workweeks. That’d be great,” Galbraith said, eliciting applause from some in the room.
“I don’t know about you, Maury, but I’ve already been out of the 9-to-5, five-day-a-week world for quite a long time now,” said Fred Heutte, senior policy associate with the Northwest Energy Coalition. “Who could have imagined what a little organism called the coronavirus could do to our working patterns?
“I don’t think that we’re going to go back to the way things were. I agree that these patterns are significantly shifting, have already shifted [and] could shift more,” Heutte said.
Making Life Easier
For Utah Public Service Commission Chair Thad LeVar, a need for new infrastructure is the most pressing issue facing the Western Interconnection. He said the industry must figure out how to build more transmission in a way that prevents electricity from becoming a “luxury.”
“I don’t have the answers to that, but I think that’s what we have to deal with,” LeVar said.
Galbraith expressed optimism that the electric sector is poised to improve lives on a scale similar to the drive for rural electrification in the U.S. a century ago.
“I’m not a believer in technology for technology’s sake, but I am really excited about the electric industry,” Galbraith said, recounting that his own father grew up in Southern Illinois in a house with a dirt floor and no running water.
“He loved rural electrification,” he said. “There was nothing you could tell that man for my entire life that was bad about the electric system. You could point to a dam and say it killed all these fish, and it cut off a great kayaking river, and he didn’t care. It provided rural electrification; it made life easy for a whole generation of people. And there was no way you could diminish the electric industry in that man’s eyes.
“What are we going to do that’s similar to that in 10 years — and in 20 years?”
Galbraith thinks the answer lies in transportation electrification.
“I actually look forward to the day when I don’t have to go to a filling station. Maybe some of you are already doing that today,” he said, adding that he envisions a time when gas stations don’t dot every corner in his Colorado town. “I think we’ve got to focus on how we are going to make people’s lives a little bit easier.
“I see people getting excited about the electric industry in the next 10 years, and maybe a whole new generation of people saying, ‘Wow, look at what the electric industry achieved,’” Galbraith said.
LeVar said the industry faces the challenge of turning transportation electrification from a “strain on the grid to an opportunity.” He thinks policymakers lost an opportunity when they failed to make electric vehicle tax incentives contingent on manufacturers designing EVs to be available “two-way” to the grid.
“If something doesn’t move in that direction, electrification of transportation will be a strain where it really has the opportunity to be one of the solutions,” LeVar said.
Climate Insights
Heutte managed to find a bright spot in the most recent strain on the Western grid. As California was plunged into a series of energy emergencies stemming from an extreme and extended heat wave, Heutte noted, UCLA climate scientist Daniel Swain tweeted about a “striking” satellite image showing Hurricane Kay approaching California from the south along with an “enormous” pyrocumulonimbus cloud emanating from a wildfire in the northern part of the state.
“I’m struck by just how amazing it is that we can casually pull up this kind of real-time earth-orbiting satellite data on demand — it really is quite something,” Heutte said. “And the way I’m thinking about this is how we can incorporate this really vast meteorological and climate data into not just operations … but also longer-term planning.”
Riffing off Heutte’s comments, Dana Cabbell, director of integrated system strategy at Southern California Edison, said the industry will need to determine how to adapt the grid to myriad climate risks.
“As we’re seeing, there’s great climate hazard science going on,” Cabbell said. “We understand what we’re seeing in the year 2030, 2050, 2070, and how that can impact the grid overall. I think that really needs to start playing into our planning of the grid.”
Raper, a former Idaho utility regulator, asked Cabbell whether Western utilities should start incorporating those climate insights into the integrated resource plans they submit to utility commissions.
Cabbell said climate data should be included in transmission planning rather than in IRPs, but she acknowledged “it does make sense to look at it from a resource perspective too, because if we’re having more droughts, you’re not going to have the hydro[power],” leaving the question of what other resources will be available.
Raper rounded out the discussion with WECC’s objectives from the interactive exercise.
“I think if anything is clear, it’s [that] the future is pretty unclear,” she said. “We want to recognize that what the future might look like is constantly changing, which means that WECC needs to be able to adapt to that as well. We want to be able to react to the changes in order to protect the reliability and security of the interconnection. Your feedback is critical to our ability to perform insightful and impactful work.”
Calling the rapid growth of inverter-based resources on the bulk power system “one of the most significant drivers of grid transformation and … a high risk to BPS [bulk power system] reliability,” NERC on Wednesday published a strategy document outlining current and future work needed to help the organization address potential pitfalls of the new generation fleet.
NERC considers inverter-based resources (IBRs) to be generation types such as solar photovoltaic and wind facilities that “are asynchronously connected to the grid and are either completely or partially interfaced with the BPS through power electronics,” according to the organization’s draft reliability guideline for IBRs. Concerns about these resources have grown in part because of events like the Blue Cut fire in 2016, when erroneous tripping of solar generation caused the loss of 1,200 MW of output in Southern California.
Speaking at this week’s meeting of NERC’s Reliability and Security Technical Committee (RSTC), Ryan Quint, NERC’s director of engineering and security integration, explained that the organization has been working to address the risks of IBRs through initiatives such as the Inverter-based Resources Performance Subcommittee (IRPS). However, because there are “a lot of moving parts” to the issue, NERC felt it necessary to formalize an overall approach.
“We recognized [that] we needed to have a solidified, codified strategy to help bring things together, and we’ve heard that comment a couple of times here. So … this is that strategy,” Quint said. He added that a similar strategy for distributed energy resources — generation types that produce electricity but are not included in the bulk power system, such as rooftop solar panels and behind-the-meter batteries — “is in the works and will hopefully be coming at the December RSTC meeting.”
Report Outlines Risk Mitigation Approach
The Inverter-Based Resource Strategy document outlines a risk mitigation framework with four key tenets: risk analysis, interconnection process improvements, best practices and education, and regulatory enhancements.
NERC’s IBR risk mitigation strategy | NERC
Risk analysis includes NERC’s monitoring and awareness tools such as the event analysis process, disturbance reports, alerts and lessons learned reports. Interconnection process improvements include enhanced interconnection requirements, updated generator interconnection procedures and agreements, and the Institute of Electrical and Electronics Engineers’ 2800-2022 standard, which sets “uniform technical minimum requirements for the interconnection, capability and lifetime performance” of grid-connected IBRs.
The last two sections involve NERC’s reliability standard and reliability guideline development processes, along with industry outreach and engagement. NERC observed in the report that “reliability guidelines related to IBRs are the most commonly downloaded documents on [its] website” and that webinars on inverter-related topics “often have over 1,000 participants dialing in.”
NERC has planned several activities to support the strategy, such as issuing a Level 3 alert that “would enable industry action while reliability standards are being developed.” The organization is also considering updating its definition of the bulk electric system, which was last revised in 2014, to better account for IBRs.
Finally, the IBR document includes a series of IBR-related milestones to be presented to the RSTC at future meetings. These include standard authorization requests to begin projects aimed at revising NERC’s current standards — three of which are planned to go before the committee by the first quarter of 2023 — a set of reliability guidelines to be completed by the end of 2022, and white papers on IBR reliability issues and commissioning best practices to be submitted by the middle of next year.
MINNEAPOLIS — MISO’s mid-September Board Week centered on the tectonic industry shift underway as the RTO plans to string more transmission lines across the footprint to bring record amounts of new capacity online and avert reliability crises.
Since the MISO Board of Directors’ last public meeting in June, the grid operator has opened its wholesale markets to full energy storage participation, approved more than $10 billion in long-range transmission lines, obtained FERC permission to conduct a seasonal capacity auction, and is preparing to study enough proposed capacity entering its generator interconnection queue to cover its current summer peak.
Transition a ‘Double Whammy’ Risk
MISO’s vice president of operations, Renuka Chatterjee, told directors during a Tuesday session that the footprint’s fleet evolution is having a “double whammy impact” on the RTO’s risk profile. She said increased renewable energy makes the grid more dependent on forecasting while baseload generation retirements hinder its ability to absorb their intermittency.
Chatterjee said staff are working toward creating automated daily risk assessments that combine the interplay between solar and wind forecasts, load expectations, fossil fuel availability, net scheduled interchanges and transmission congestion. She said MISO will eventually introduce tailored daily reserve margin requirements.
The grid operator has committed to reviewing operating days that fall outside of historical norms to see if it needs to change its reliability preparations or new market products, Chatterjee said.
Jessica Lucas, executive director of system operations, said about 70% of MISO’s daily energy supply remains sourced from thermal generation, a concern before the national rail strike was apparently averted.
During the Thursday board meeting, CEO John Bear said the organization paid attention to CAISO operations during its early September heatwave. He said MISO trails California in the energy transition and noted that CAISO struggled with a lack of “controllable, long-duration resources” to weather the heat.
“We’ve got a good sense of where we need to go and how we need to get there,” Bear said.
More Tx to Yield Interconnections
Vice President of System Planning Aubrey Johnson said MISO expected more than 1,000 new generator interconnection requests, representing about 120 GW, for the 2022 cycle when the application window closed Thursday. He said it will be the third straight year staff have processed a record number of applications, each bigger than the previous.
Since 2014, MISO has received 329 GW of interconnection requests; 52 GW have progressed through to the generation interconnection agreement (GIA) stage that allows grid access. The grid operator currently has about 124 GW in the queue but has seen interconnection customers withdraw 153 GW over the past eight years. It hopes its recent transmission planning activity will drive up interconnection numbers and limit withdrawals.
“The last few years were relatively flat in terms generation additions and subtractions,” Johnson told board members during a Tuesday System Planning Committee meeting. “… What we’re seeing is an accelerated change in the resource mix, and it’s calling on us to do things differently.”
Transmission upgrade costs and dropouts for interconnections by region for the 2016-2020 queue cycles | MISO
MISO projects it will have 346 GW of nameplate capacity by 2042, but just under 200 GW in accredited capacity. The RTO currently has 201 GW in nameplate capacity and 173 GW in accredited capacity.
The grid operator is keenly aware that soaring network upgrade costs in parts of its footprint are hindering more generation additions. Interconnection projects tend to complete the queue when their associated transmission investments for interconnections are at or below $125/kW, Johnson said. However, upgrade costs have neared $1,000/kW or beyond in MISO’s West and South planning regions, eight times what investors are comfortable putting forward, he said.
“If you’re looking to interconnect in the Central region, come on in. The water’s warm,” Johnson said. “But if you’re looking to interconnect in the West or even the South, that’s a different matter.”
Johnson said transmission projects stemming from MISO’s Joint Targeted Interconnection Queue study with SPP should help yield more GIAs.
He said MISO is also immersed in identifying a second set of Midwestern transmission projects under its four-part long-range transmission plan (LRTP). The RTO obtained board approval in late July on the first, $10.4 billion set of LRTP projects in MISO Midwest.
“July 25 was a great day, but we’re going to continue to press on and define and develop what the next stage of projects is going to be … Much like football, we thought about the win for 24 hours, and then we moved on,” Johnson said.
The grid operator released the first competitive request for proposals stemming from the LRTP, a 345-kV line from an Indiana substation to the Michigan border. Proposals are due Jan. 11. The grid operator plans to release a new RFP for a different LRTP project about every three months and administer simultaneous bid evaluations.
The grid operator characterized wholesale storage activity as nominal so far. But its interconnection queue currently has more than 13 GW of standalone battery storage as part of more than 150 projects in varying stages of development. That doesn’t include the queue’s hybrid generation projects, which usually pair renewable energy with a storage resource.
Unease over MISO Support for Gas Plant
Clean Grid Alliance’s Beth Soholt told board members that MISO has recently and unacceptably favored natural gas generation’s development over other resource types in bring new generation online. She said staff presentations following capacity shortages during the 2022-23 planning year advocated new gas-fired capacity, despite its fuel-neutral posture.
Soholt pointed to the RTO’s July letter to the Rural Utilities Service (RUS) in support of a loan for the proposed, $700 million gas-fired Nemadji Trail Energy Center in Superior, Wis., which would be jointly owned by Dairyland Power Cooperative and two Minnesota utilities.
In the letter, MISO said it was concerned about looming generation shortfalls and asked RUS to “consider grid reliability” and Nemadji Trail Energy Center’s role in the footprint’s resource adequacy.
“While MISO is both fuel- and technology-neutral, MISO needs to help ensure the best options to provide needed resource capabilities and attributes are available to bridge the gap between electrical baseload retirements and replacement capabilities and attributes,” Deputy General Counsel Kristina Tridico wrote.
Tridico said “the retirement of generation plants is occurring far faster than new energy sources with equivalent attributes, whatever the fuel source, can be developed, constructed and brought online.”
“While the letter was very careful to color within the lines of grid reliability, I’ve never seen MISO send a letter in a specific docket advocating for a specific new resource. This is not appropriate,” Soholt said during a public comment period Tuesday. “MISO has always said it is fuel and technology neutral, but a different message is coming through in the last several months of MISO messaging and presentations.”
Soholt said, “at the end of the day, there are many solutions to MISO’s resource adequacy challenges, and the work is not done yet.”
She urged MISO to not encourage members to rush headlong into natural gas solutions before it assesses battery storage’s flexible attributes in its market portfolio.
MISO executives didn’t respond to Soholt’s criticisms in real time during Board Week. In a later statement to RTO Insider, the grid operator said it believes the letter speaks for itself.
