ISO-NE this week launched its effort to revamp its resource capacity accreditation process, a key fix to the capacity market that has been tied in with discussions around the contentious minimum offer price rule.
In a presentation to NEPOOL Markets Committee on Tuesday, ISO-NE’s Steven Otto laid out the beginnings of the RTO’s thinking and offered some early hints as to where it’s leaning as it prepares a more detailed proposal in the coming months.
The goals of the project are to boost reliability and maintain cost effectiveness as New England moves toward a decarbonized grid. The RTO’s current accreditation process is a mishmash of approaches that the grid operator has acknowledged doesn’t do a good enough job reflecting different energy sources’ contributions toward resource adequacy and reliability.
One of the key decisions that ISO-NE is thinking through, Otto said, is whether to employ an average or marginal approach to capacity accreditation.
The pros and cons of marginal and average approaches to capacity accreditation | ISO-NE
Marginal approaches “set a resource’s accredited capacity based on the marginal reliability impact of an incremental change in size,” he said. Average approaches, on the other hand, set the accredited capacity based on the average reliability impact of a resource’s class.
The RTO is currently leaning toward a marginal approach, Otto said, sometimes also called a Marginal Reliability Impact value.
The advantages of a marginal approach, according to ISO-NE, are that it sends accurate entry and exit signals to market participants, can incorporate interactions between resource types, and provides the same compensation to resources that provide the same service.
It’s far from a settled conversation though: The grid operator is planning a roughly yearlong stakeholder process to hash out the details and decide on a proposal to send to FERC.
The first phase, involving conceptual design and education, is planned to go through October of this year. The RTO will start presenting a detailed design in November and move to finalize that design and produce tariff language by next spring. Stakeholder committee votes are planned for May and June of 2023.
Feedback on capacity accreditation will come both through the stakeholder process and outside of it: The Massachusetts Attorney General’s Office, for example, is planning to produce a report with recommendations in the coming weeks.
The Biden administration announced Thursday it will require that electric vehicle chargers installed with federal funding meet minimum reliability standards and charging speed, work for all cars and take common payment methods.
“The new standards will ensure everyone can use the network — no matter what car you drive or which state you charge in,” the White House said in a fact sheet on the proposed regulations governing $7.5 billion in federal funding authorized by the Infrastructure Investment and Jobs Act (IIJA).
The Department of Transportation wrote the regulations in consultation with the Department of Energy in the administration’s bid to build a national network of 500,000 EV chargers.
The funding, which will be spent over five years, includes $5 billion allocated to states, D.C. and Puerto Rico based on a formula under the National Electric Vehicle Infrastructure (NEVI) program and $2.5 billion in competitive grants for smaller towns or tribes that may not qualify for the NEVI funds.
Transportation Secretary Pete Buttigieg said the chargers will be “available to everyone everywhere, whether driving in urban, rural or tribal communities. It means a standard to build EV charging stations every 50 miles, no more than 1 mile off the highway, with a focus on the interstate system and alternative fuel corridors.”
“Everyone should be able to find a working charging station when and where they need it without worrying about paying more or getting worse service because of where they live. You shouldn’t have to sort through half a dozen apps on your phone just to be able to pay at a charging station,” he added. “No matter where you live or where you’re headed, everyone should be able to count on fast charging, fair pricing and easy-to-use payment for their EVs.”
Deputy National Climate Adviser Ali Zaidi said the regulations will “democratize access to a cost-saving technology.”
Energy Secretary Jennifer Granholm said U.S. EV sales doubled in 2021 and could double again this year as rising gas prices make EVs more affordable.
“At today’s gas prices, EV owners can save about $60 bucks every time they charge up compared to an equivalent fossil fuel-powered vehicle,” she said. “This administration wants to make sure every American can reap those cost savings, and key to that mission is giving people confidence that they can drive an EV wherever they want to go and charge up wherever they live.”
Granholm reiterated her call for Congress to pass tax credits to incentivize EV purchases, “because if we’re going to build out infrastructure like we haven’t done since the Eisenhower era, we have to build it right.”
The standards will require at least four 150-kW DC fast charging ports per station so “if you get there and there’s a few people ahead of you, you can [charge] at the same time,”said Stephanie Pollack, deputy administrator of the Federal Highway Administration.
“It has to be working 97% of the time; that’s a consumer complaint that we’ve heard,” added Pollack. “There’s a requirement for real-time data that will ensure that third-party apps can provide you information when you’re on the road so you can find not just a charger but the nearest charger. Is someone else using it? Is it currently operating?”
In February, DOT and DOE announced the first installment of funding, $615 million for 2022, ranging from a low of $2 million for Puerto Rico to $60 million for Texas. (See States to Get $615 Million for EV Charging from IIJA Funds.)
“These federal charging programs were designed to catalyze additional private sector investments that complement the buildout of a user-friendly, cost-saving and financially sustainable national EV charging network,” the fact sheet explained.
State plans are due in August, and FHWA will be approving them on a rolling basis. “As soon as the state has an approved plan, they can start putting that money to work,” Pollack said.
“People need to have confidence that they can find a charger so that they’re willing to buy electric vehicles,” Pollack said. “A national network means the experience [when] you pull up to that charger is the same no matter where you are.”
Economic Development
Officials also touted the economic development impacts of the spending.
Zaidi said EV companies announced 22,000 manufacturing jobs in the first quarter of the year, with companies locating in the U.S. to be part of the country’s supply chain. “It means we’re going to capture more of the economic upside here in the United States,” he said.
White House Infrastructure Implementation Coordinator Mitch Landrieu said the standards will “trigger competition” in the EV space, noting “the historic private investment from automakers like Ford, Stellantis and [General Motors], and EV charging manufacturers like Tritium and Siemens.”
Officials said the Joint Office of Energy and Transportation will select 25 members to serve on a federal advisory committee, the EV Working Group, to “make recommendations regarding the development, adoption, and integration of light-, medium- and heavy-duty electric vehicles into the transportation and energy systems” of the U.S.
The joint office also will engage the American Public Power Association, Edison Electric Institute and National Rural Electric Cooperative Association “to inform electric system investments and support state planning.”
Granholm said the administration plans to offer up to $30 million in funding for clean energy mobility pilots and demonstration projects in underserved and rural areas “to create solutions for overnight at-home charging in multifamily buildings. We want all these solutions, and we want experts across the country helping us to make sure we’re doing it right.”
Related Initiatives
Officials said the new regulations would supplement DOE’s May announcement of $45 million through its “EVs4ALL” program to develop very fast charging batteries.
The administration also touted the Department of Agriculture’s EV charging resource guide for rural property owners, states, territories, tribes and others, and a climate smart schools guide explaining funding for charging for rural school districts.
In addition, the General Services Administration has created blanket purchase agreements to help federal agencies and others to procure EV chargers and services at federal facilities.
New York investor-owned utilities last week said they support cost-of-service-based electric rates with time-bound incentives to provide cost relief for EV charging station owners, which they deem preferable to solutions based on rate design. (18-E-0138; 22-E-0236).
The rate-design-based solutions proposed by several stakeholders “are too broad-brushed and inflexible, do not reflect cost causation, and are inferior to targeted, transparent, flexible, and timebound non-rate design based incentive solutions,” the utilities said in comments filed with the New York Public Service Commission.
The proceedings concern EV supply equipment and infrastructure, and establishment of a commercial tariff or other solutions to facilitate faster charging for light-, medium-, heavy-duty and fleet electric vehicles (EVs). (See New York Utilities Report Slow Start to EV Fast Charging.)
The IOUs responding included Con Edison (NYSE: ED) and its subsidiary Orange and Rockland; Central Hudson Gas and Electric; National Grid (NYSE: NGG) for its Niagara Mohawk Power subsidiary; Avangrid (NYSE: AGR) subsidiaries New York State Electric and Gas (NYSEG) and Rochester Gas and Electric (RG&E); and PSEG Long Island operating for the Long Island Power Authority.
Cost Concerns
Advanced Energy Economy and the Alliance for Clean Energy New York asked the commission to “consider how to fairly spread the costs across all customers rather than commercial customers alone,” which the utilities said reflects the EV program being one of several public policies supporting clean energy initiatives.
Other stakeholders said that demand charges send important price signals but reducing or eliminating those charges in tariffs may be the only cost-relief option, an approach the utilities deemed “suboptimal compared to solutions that would provide cost relief and maintain appropriate price signals.”
For example, the Alliance for Transportation Electrification noted that “demand charges are a fair and efficient means of recovering the costs utilities incur … but can raise issues when included in rates paid by charging station operations.”
PowerFlex said that rates should align with grid needs so EV adoption does not become a cost burden to electric customers. It said that while demand charges encourage grid-beneficial behavior, they should not be so high so as to discourage EV charging station installation.
ChargePoint recommended reducing demand charges and increasing volumetric charges for at least 10 years, while Tesla supported shifting DCFC charging customers to rates with reduced or no demand charges. The Metropolitan Transportation Authority wanted utility rates to be set such that commercial EV fleet owners do not incur higher costs than when operating diesel and compressed natural gas vehicles on a cost per mile basis.
Vehicle weight classes and EPA regulatory categories. | EPA
The utilities counter that targeted incentive-based operating cost relief can support EV fast charger installation while retaining the beneficial price signals in demand charges.
“Rate-design-based solutions also result in shifting more costs from EV charging station operators to other customers compared to incentive-based solutions. The bill impact of incentive-based cost relief programs can be smaller than that of rate-design-based solutions and more spread out both over time and across all customer groups, rather than concentrated in that year in a single service class,” the IOUs said.
Fast charger network Electrify America suggested that residential customers who charge their vehicles at home end up paying more than residents of multi-unit dwellings in urban areas who rely on public chargers, and that demand charges are “the largest differentiating factor between effective electricity rates billed by the utility to residential and to commercial EV customer accounts.”
While the disparity between at-home and public charging may be a barrier to more equitable EV adoption, moving away from cost-reflective utility rate design likely would create further inequities among utility customers and create disincentives for efficient investment and innovation, the IOUs said.
“Proposals for rate-design-based solutions are not aligned with appropriate and established rate design principles … and do not reasonably manage cost shifts while promoting access to benefits, i.e., availability of fast charging to all customer groups. Optimal solutions should instead seek to target incentives to reach only the charging stations that need them and thus avoid inadvertent or unexpected cost shifts to other utility customers,” the utilities said.
The New York Power Authority advocated partnerships between ride-sharing companies and public fast charging providers to spread demand costs among more users, increase utilization and help reduce the impact of these costs.
The IOUs said they “support solutions that leverage price signals to encourage the adoption of innovative business models and technologies that enable grid-beneficial behavior.”
California-based demand response provider OhmConnect is seeking NYISO’s approval to this summer begin enrolling small customer aggregations (SCAs) as special case resources (SCRs) in the ISO’s wholesale capacity market.
“All residences will be Con Ed customers located in NYISO Zones H, I, or J,” John Anderson, director of energy markets at OhmConnect, said Tuesday in presenting the SCA proposal to the ISO’s Installed Capacity/Market Issues/Price Responsive Load Working Group.
OhmConnect has enrolled over 250,000 residential customers into its various programs in CAISO, ERCOT and Australia.
Most SCA proposals that come before the working group are trying to address the problem of a lack of available metering data and to win approval for alternative metering methodologies, but OhmConnect’s New York customers all have advanced metering infrastructure or smart meters, and the aggregator obtains the customer data directly from Con Edison through their Share My Data platform, Anderson said.
“The challenge we face is instead a technical one in the NYISO demand response information system (DRIS), and simply stated, the system as currently configured cannot accommodate customers whose average coincident loads are smaller than 1 kW,” Anderson said.
OhmConnect has in fact already signed up several thousand residential customers, approximately half of whom are already participating in the ICAP program, he said.
“These customers are sufficiently large that we were able to enroll them directly in the program, and our focus here today with the SCA proposal is on the remaining half of our customer base that was too small to enroll directly due to the current DRIS design,” Anderson said.
An SCA proposal must be approved by at least four of the chairs and vice chairs of the NYISO Management Committee and Business Issues Committee, and the chairs of the ICAP and Price Responsive Load Working Groups. The approvals were to be requested from the applicable approvers by email after the meeting, said Ethan Avallone, NYISO distributed resources operations manager.
“This metering meets the NYISO’s expectations for the SCR program participation, and the ISO supports enrolling these resources as a small customer aggregation in the SCR program,” Avallone said.
OhmConnect will initiate the following sequence of actions upon notification from NYISO of a mandatory or test ICAP-SCR event to commence at hour T and with duration of N hours. | OhmConnect
The SCAs will consist of the curtailment from residential customers who will participate in the ICAP-SCR program, and OhmConnect intends for these customers to participate in the 2022 Summer Capability Period as early as July and is requesting multiple SCAs for each zone to accommodate future anticipated customer growth, Anderson said. NYISO rules prohibit any change to an SCA within a given capability period.
“When a customer enrolls and authorizes us access to their data, we can use the data to directly calculate performance of the resources in an SCA. We do not need to infer that performance, but can measure it directly,” Anderson said.
Asked about the effect of customers opting out of a DR event, Curtis Tongue, OhmConnect co-founder and chief strategy officer, said, “We typically see opt-out rates from our customers at about 1% or less per event, so in practice it ends up being a relatively negligible impact.”
Several market participants asked how NYISO will ensure that any additional SCA proposals, whether to serve different load zones or not, would employ the same methodology being approved in this process.
If the aggregator has the first proposal approved in one methodology and comes the next month with another proposal, “we would validate that they are doing the same exact methodology,” said Steven Gill, technical specialist on the ISO’s distributed resources operations team. “We have correspondence back and forth with [OhmConnect] that it’s the same exact methodology and load reduction plan, and the same exact intentions and way they’re going to deliver megawatts to the grid.”
As it stares down its footprint’s supply crunch, MISO is proposing to revise its generator retirement studies to include more notice, relaxed confidentiality rules, and stiffer adherence to local reliability requirements.
However, staff was firm during Tuesday’s Planning Subcommittee that the changes will not add resource adequacy considerations to MISO’s existing study process.
The grid operator announced last month that it was considering bulking up the studies under its Attachment Y process that determine whether retiring generation needs to stay online longer under a system support resource agreement. (See Capacity Shortage Prompts MISO to Consider Broadened Retirement Studies.) Presently, the retirement studies focus solely on the transmission system’s reliability, not resource adequacy; MISO does not have the jurisdictional authority to extend generators’ operational lives because of resource adequacy concerns.
The RTO’s Sydney Yeadon said staff seek to “mitigate some challenges” with escalating retirement notices coming from its membership.
She said MISO will impose a one-year notice requirement on retiring generation before MISO begins Attachment Y studies, a six-month extension of current practices.
“More time is needed to conduct more in-depth studies,” Yeadon said. She said the yearlong warning will give staff “greater visibility of the near-term resource mix.”
Anticipating more generation retirements, MISO also proposed to conduct retirement studies in batches on a quarterly basis instead of when the requests are received.
MISO’s Andy Witmeier said a quarterly kickoff of retirement studies will help staff better manage their workload. He said the RTO is never certain of how many retirement or suspension requests it will receive at any given time.
“We need more time in order to do the analysis,” he said.
The doubled notice time and quarterly cadence will allow MISO to conduct stability studies on a more frequent basis. Yeadon said the extra studies are necessary as the amount of retiring baseload generation picks up.
The grid operator will also begin sharing the systemwide number and megawatt value of retirement requests, Yeadon said. She said MISO “obviously” won’t share the details of individual retirement requests.
Attachment Y notices are currently confidential unless an owner waives recission rights and places a unit directly into retirement, the generator doesn’t return to service when the recission period ends, or MISO evaluates the resource as a possible system support resource.
The RTO also plans to alter the customary mitigation practices used in the retirement study process’ steady state analyses. Staff allows load shed as a mitigation option when voltage and thermal violations are uncovered but going forward, staff wants to lessen wean reliance on load shed.
Stakeholders debated whether MISO’s proposed limits on load-shed mitigation amount a change rooted in resource adequacy concerns.
“We’re just trying to ensure reliability with the practices we have,” Yeadon said.
“That’s going to get litigated, I’m sure,” replied Customized Energy Solutions’ David Sapper, representing MISO load-serving entities.
Witmeier said it’s not MISO’s purview to dictate when generation retires and that the grid operator is merely focusing on local reliability requirements.
“The enhancements that we’re proposing here are [an] improvement to the process,” he said.
Stakeholders asked whether MISO is considering further changes to its retirement studies to hang onto the capacity it has.
“I feel like there’s been a lot of stakeholder discussion around this, and I wonder if MISO internally has been discussing some kind of joint forum on it,” Clean Grid Alliance’s Natalie McIntire said.
Witmeier said no such workshop is on the horizon for now. He said the stakeholder-led Resource Adequacy Subcommittee could pursue future discussions on Attachment Y process, but it hasn’t yet.
MISO considers the issue a planning matter, though stakeholders have called for improving the Attachment Y process, given the topic’s implications to the footprint’s resource adequacy.
“We don’t want to slow down the improvements that we see could be done now,” Witmeier said.
“This is a step in the right direction, but it doesn’t go far enough,” Prairie Power’s Karl Kohlrus said of the study process changes.
Kohlrus said he’s concerned that staff isn’t reflecting all future baseload retirements in their transmission-planning models. He said MISO hasn’t yet accounted for all announced baseload retirements or impacts stemming from Illinois’ Climate and Equitable Jobs Act.
“I’m concerned that there’s no place for MISO to do accurate modeling … It’s kind of scary as a planner that you’re studying a future that won’t exist,” he said.
Staff said they will update planning models with the latest retirements later this year.
MISO Independent Market Monitor’s Michael Chiasson also said the RTO’s retirement and suspension practices have a loophole where a unit can remain on an extended outage for years without being pressured to designate its unit as either suspended or retired. Chiasson said resource owners who don’t want to replace their capacity are essentially allowed to “tie up interconnection” points with nonoperational units.
“I see a couple of examples here and there, not huge amounts … It’s not really widespread at this point,” Chiasson added. But he said as MISO reassesses its current retirement study practices, “it’s a good time” to also address the gap.
Coal Retirements Mounting
Coal advocate America’s Power said it has tallied announced coal retirements in MISO at 19.3 GW in the 2022-2027 timeframe and 27.3 GW by 2030. The group said if utility announcements pan out, 35% of MISO’s current coal fleet will retire within the next five years, with half of the fleet idled by 2030.
America’s Power said its estimates don’t factor in coal retirements that might be spurred by reinvigorated federal regulations. The group said those regulations could lead to more than 30 GW of MISO’s existing coal capacity installing selective catalytic reduction and/or flue gas desulfurization.
“We are concerned that these facts about future coal retirements might not have received the attention they deserve,” the group said in a late April memo circulated within MISO.
America’s Power also said the coal generation that will retire over the next five years supplied an annual average of 16 percent of MISO’s energy during 2019-2021 with an average capacity factor of slightly more than 50%.
New Jersey’s Department of Environmental Protection (DEP) on Monday officially adopted new rules requiring more rigorous monitoring and reporting of greenhouse gas emissions in certain situations, while also releasing a proposal designed to limit new pollution in environmental justice areas.
The DEP posted in the New Jersey Register the final version of rules setting out a three-pronged approach for air pollution control that requires property and facilities owners to monitor and report emissions of methane and halogenated gases. The rules require facilities that emit 100 tons or more of methane a year — such as landfills, natural gas utilities and biogas generators — to report those emissions. Facilities that use 50 pounds or more of high global warming potential (GWP) refrigerants, which are used in refrigeration and air conditioning systems, must register and report their use of that equipment and refrigerants.
They also require public utilities that operate natural gas distribution lines in the state to report details of the lines, their advanced leak detection systems and blowdown events.
Through these measures, the DEP is addressing gaps in the department’s “comprehensive strategy to address greenhouse gas emissions” statewide, it said.
The rules levy penalties for companies that don’t comply of between $200 and $1,000 for a first offense and between $1,000 to $5,000 for the third offense, depending on the rule violated.
Preventing New Pollution
The initiative is part of Gov. Phil Murphy’s effort to cut emissions and set the state on a course of using 100% clean energy by 2050. His 2019 Energy Master Plan calls for the state by the same year to reduce greenhouse gas emissions to 80% below 2006 levels.
The master plan also sets out a multipronged approach to prevent new polluting plants and facilities from entering low- and moderate-income (LMI) communities and pave the way for those communities to enjoy the benefits of clean energy.
To that end, the DEP on Monday also published in the Register proposed rules that would allow the agency to block new facilities or mitigate the effects of expanding existing facilities in LMI or minority areas. While the rules are focused on the impact of pollution on disadvantaged communities, they may also contribute to cutting GHGs. The rules, for example, seek to limit ground level ozone, which the U.S. Energy Information Administration considers a GHG.
“If you limit emissions of other air pollutants, you could also limit emissions of GHGs,” said Nicky Sheats, director of the Center for the Urban Environment and board chairman for the New Jersey Environmental Justice Alliance, which helped draft the rules. Still, he added, it’s possible that the law might not reduce emissions because it could just prevent the location of a new polluting plant in one area so that it could arise in a different area.
The rules would set out a multistep process through which the department can approve or deny an application for a new pollution-generating plant or facility, or the expansion of an existing facility based on an assessment of both existing environmental conditions and how much the proposed facility would worsen those conditions.
DEP officials say the rules, which would provide the operating framework for the state’s Environmental Justice Law passed in 2020, would enable them to end the pattern that has long resulted in LMI and minority communities receiving a disproportionately number of polluting industrial, commercial, and government plants and facilities.
The department plans to hold four public hearings in July on the proposal, and to have the rules in place by year-end.
“This law is transformative, literally the most transformative law in at least 30 years,” DEP Commissioner Shawn LaTourette told reporters at a press briefing on the rules June 2.
The rules would require the department to analyze and evaluate permit applications for eight categories of proposed pollution generating plants and facilities: major sources of pollution, such as power plants and cogeneration facilities; incinerators or resource recovery facilities; large sewage treatment plants; transfer stations or solid waste facilities; recycling facilities that receive at least 100 tons of recyclables; scrap metal facilities; landfills; and medical waste incinerators.
They would also give the DEP the authority to take steps to prevent or limit the placement of additional polluting facilities in disadvantaged communities, which state officials account for about half the state’s population.
“We have never had that level of authority before, to look at an entire facility’s emissions; that [did] not exist,” he said. “Now it does,” he added, and said: “There are many things that happen at a facility that cause negative environmental outcomes, that we don’t have an existing hook into that these rules now finally gives us.”
Conflicting Visions
Environmentalists welcomed the proposal.
Sheats said he believes few, if any, other states have a law as tough as New Jersey’s. The key element is the DEP’s ability under the rules to do a cumulative impact analysis of a proposed facility, studying not just the environmental impact of the proposal but the ongoing impact of all the polluting facilities placed in the area in the past, he said.
“It covers multiple sources of pollution, so multiple pollutants,” he said, adding that the rules would also give the DEP the right, when making a permitting decision, to look at “social vulnerabilities” such as disease rates and the lack of health care in the community.
Maria Lopez-Nuñez, director of environmental justice and community development at Ironbound Community Corp. in Newark, expressed the hope that they will help halt the stream of polluting facilities into her neighborhood.
“We’ve been waiting a long time for the type of protections that these rules lay out,” said Lopez-Nuñez, adding that there although the rules could still be improved, they are a good start.
“Prevention is the best tactic,” and the EJ Law helps do that, she said. “We want to make sure that the industry that comes into the neighborhood is the greenest and has the best technology, or that it doesn’t come here at all if it’s going to contribute to the problem.”
But the New Jersey Business & Industry Association, one of the state’s largest trade groups, said the proposal did not address some of the organization’s concerns with the law, especially the broad sweep of its reach.
“While we understand that more needs to be done to address environmental conditions in many of our state’s disadvantaged communities, this rule covers too much of the state and sets up impossible standards to meet,” he said. “The result will be that no new major manufacturer can locate in these areas, and those that are already there will not be able to expand,” he said.
Evaluating Stress Factors
The rules would kick in when a permit application for such a facility is submitted to the DEP and require the department to analyze the community around it to determine whether it is “overburdened.” The proposal defines that as a census tract with one of three characteristics:
at least 35% of households qualify as low-income;
at least 40% of the residents are minorities; or
at least 40% of households have limited English proficiency.
If the DEP concludes that the community is overburdened, the rules would then require the DEP to look at how the existing environment is shaped by 26 “stressors” or stress factors that can create adverse environmental conditions and if the proposed facility would increase the stress, and by how much. Among them are: the amount of ground level ozone; fine particulate matter; the cancer risk from diesel participate matter; traffic density and presence of railways in the area; the presence of known contaminated sites; and the amount of sewage overflows in the area. The factors also include more general contributors to health stress, such as the unemployment level, the portion of the older population that has less than a high school diploma and the lack of recreation space.
Disproportionate Impact
The results of that analysis would be compiled into an Environmental Justice Impact Statement and made public and scrutinized at public hearings, said Sean Moriarty, the DEP’s deputy commissioner for legal, regulatory and legislative affairs.
“The applicant will be required to respond to all public comments substantively,” he said. “They’ll be required to provide information or to provide measures to address the concerns of the community. And that will be part of the decision the department ultimately makes upon completion of that process.”
The DEP will then assess whether the facility will have a “disproportionate impact” in worsening the environmental burden, he said.
“For new facilities, we have the authority and are required to deny an application where disproportionate impact exists unless the facility can demonstrate that it serves a compelling public interest in the overburden community,” he said, adding that the benefits must be local, rather than presenting a compelling public interest statewide or in a broader area.
The DEP can’t deny the application if it calls for an expansion or renewal of an existing facility, he said. But in that scenario, it is “authorized to impose appropriate conditions” that would avoid or minimize the impact on the community, he said.
Ameresco announced last week that it will partner with Bright Canyon Energy to build the Kūpono Solar Project, a solar-plus-battery storage facility in Pearl Harbor.
The companies, operating under the joint Kūpono Solar Development Company, say the Hawaii project is designed to produce 42 MW and will include a 168-MWh battery energy storage system (BESS) that should provide enough energy to power approximately 10,000 homes on Oahu at night. The joint company also claims the project will reduce more than 50,000 tons of CO2 annually.
Kūpono Solar signed a 37-year land lease with the U.S. Navy to build the project on 131 acres within the Navy’s West Loch Annex of Joint Base Pearl Harbor-Hickam. The company will operate the facility under a 20-year power purchase agreement with Hawaiian Electric (HECO).
“The Navy is excited to see this joint Kūpono Solar/Hawaiian Electric project move forward for our community’s benefit,” Capt. Randall E. Harmeyer, public works officer for the base, said in a press release.
In light of a recent water contamination fiasco at the Navy’s Red Hill fuel facility that saw approximately 19,000 gallons of fuel spill out of an old storage tank and into Oahu’s water supply, Nicole Bulgarino, Ameresco executive vice president and general manager for federal solutions, said she wanted to assure the company’s commitment to the community.
“We’re trying to be a good developer from a community perspective,” Bulgarino said in an email to NetZero Insider.
“We don’t necessarily want to be looked at as a developer, but truly as a partner, a clean tech partner,” she said. “In this case, the Navy is only the land host. They are not buying any of the power that’s generated. In fact, the power generated by the system is connected directly to a HECO-owned substation. … That power should be serving Oahu. Wherever the load is, is where the power will fall to.”
Kūpono Solar is in the final stages of seeking approval from the Hawaii Public Utilities Commission. The state’s Consumer Advocate came out in support of the project last week, and Bulgarino expects the project will be approved.
“I’m sure there will be some final declarations or requirements that we’ll view and agree to, but it’s a great project. It’s on land that can’t be used for anything else. … We’re hopeful,” she said.
Rebecca Dayhuff Matsushima, HECO vice president of resource procurement, expressed the utility’s support for the project.
“We’re hoping for PUC approval and continuing our work with the Kūpono Solar team,” she said in an email.
If approved, the project’s construction is expected to be completed in early 2024.
The U.S. Department of Energy announced Monday that it will detail in September or October what regional consortia of industry and government must do to apply for up to $8 billion in federal matching funds to generate and use clean hydrogen on a local level.
Energy Secretary Jennifer Granholm made the announcement at the start of the department’s annual three-day symposium on hydrogen development and use.
The first day of this year’s symposium showed the breadth and depth of the government’s efforts to leverage the expertise of its federal labs in partnership with industry to develop technologies to produce and use low-cost hydrogen in industry, power generation and transportation.
The department’s Notice of Intent to fund hydrogen hub projects also came simultaneously as its $2.6 million Hydrogen Shot Incubator Prize, a contest “to identify, develop and test disruptive technologies that reduce the cost of clean hydrogen production” to help the government meet its goal of hydrogen produced by electrolysis of water at a price of $1/kg.
And it came just 14 months after President Biden announced his administration’s goal to reduce greenhouse gas emissions by 50% by 2030 compared to 2005 levels and create economy-wide net zero emissions by 2050.
“Hydrogen energy has the power to slash emissions from multiple carbon-intensive sectors and open a world of economic opportunity to clean energy businesses and workers across the country,” Granholm said in brief remarks at the start of the symposium. “These hydrogen hubs will make significant progress towards President Biden’s vision for a resilient grid that is powered by clean energy and built by American workers.”
One of the first areas that is expected to replace fossil fuels with hydrogen is heavy transportation, including 18-wheelers as well as locomotive engines and possibly shipping, which would refuel at major ports. There are also plans to replace coke (produced from coal) in steelmaking with hydrogen.
Currently, the nation’s industries produce about 10 million metric tons of hydrogen per year, almost all of it from methane, which leaves behind carbon dioxide.
The hydrogen hub grants will include funding for at least two hubs producing hydrogen from locally produced natural gas but collecting the carbon dioxide for insertion deep underground. Other hydrogen hubs will produce the gas from electrolysis of water, using either renewable energy or power generated by nuclear reactors when grid demand for their output falls.
Today, the U.S. produces about 10 million metric tons of hydrogen annually, most of it from natural gas through high-temperature steam reforming of methane.
Multiple stakeholder groups, including state regulators, protested MISO’s FERC Order 2222 compliance filing on Monday, with many expressing indignation with the RTO’s request to delay implementation until nearly 2030 (ER22-1640).
MISO filed its proposal April 14, with the commission granting its request to extend the standard 21-day comment period until June 6. In a letter accompanying the proposed tariff changes, MISO said its proposed Oct. 1, 2029, effective date is necessary because it will take “several years of technology development to enable DERA [distributed energy resource aggregation] participation in wholesale markets.”
Approved in September 2020, Order 2222 directed all FERC-jurisdictional RTOs and ISOs to revise their tariffs to allow DERAs to provide any services they are technically capable of in their wholesale markets. (See FERC Opens RTO Markets to DER Aggregation.)
The commission had set a compliance filing deadline of nine months after the order’s publication in the Federal Register (about June 2021), but several RTOs quickly requested more time, with PJM and ISO-NE, for example, filing on Feb. 2 (2/2/22). Over that time, officials repeatedly told stakeholders how complex and time consuming the work was. (See “Order 2222 Compliance Work ‘Highly Complex,’” SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022.)
FERC gave RTOs and ISOs flexibility in proposing a deadline for implementation. MISO’s is the longest among the grid operators. It proposes making registration available beginning Oct. 1, 2029, with participation in energy and ancillary service markets offered by March 1, 2030. The RTO told FERC that it first needs to complete its market systems enhancements (MSE) project — a long-in-the-works replacement of its market platform expected by the end of 2024 — before it has the technological capability to comply with the order.
“The completion of the MSE project, including the replacement of MISO’s legacy systems and software with the integration of new market engines into MISO’s systems, is a necessary prerequisite to development of the software and systems needed to incorporate DERA in the [RTO]’s markets,” it said.
MISO also said it wants to prioritize work on its much-delayed Multiple Configuration Resources (MCR) initiative, which is intended to improve modeling of different combinations combined cycle unit types. When completed alongside the MSE project, MCR “is expected to provide reliability benefits by providing operational flexibility needed to manage the MISO region’s increased reliance on intermittent resources, such as wind and solar, to meet the region’s baseload demand needs,” the RTO told FERC.
“While MISO recognizes the benefits of promoting distributed energy resource participation in its wholesale markets through the addition of distributed energy resource aggregations, the benefits of these aggregations are unknown and relatively limited by the existing retail regulatory construct in many of the states in the MISO region.”
Environmentalists, consumer advocates and state regulators said the 2029 date was unacceptable.
The Organization of MISO States said it “recognizes the importance and benefits of MSE and MCR but questions MISO’s purported inability to pursue a parallel path for the implementation of MCR and Order 2222. MISO does not provide sufficient evidence why parallel implementation is not possible outside of a generic description that pursuing these changes simultaneously would increase the risks to reliably implement these products.”
OMS noted that PJM proposed a 2026 effective date, after implementing its new market clearing engine and Enhanced Combined Cycle model in 2025. “From the testimony MISO provided, it is unclear why MISO cannot do the same.”
Filing jointly, groups including the Natural Resources Defense Council, Sierra Club and the Union of Concerned Scientists noted that MISO’s proposed date would push back DERA participation to “nearly 10 years after the commission issued Order No. 2222 and nearly 14 years from the commission’s publication of the Notice of Proposed Rulemaking that led to Order No. 2222.”
“In essence, MISO is arguing that its markets must remain unjust and unreasonable and unduly discriminatory with regard to DERAs for nearly a decade while it sorts out technology issues that it ought to have been aware of and planning for since well before the commission issued Order No. 2222,” the groups said.
Advanced Energy Management Alliance argued that “MISO has not provided a reasonable explanation for such an extended implementation timeline given the rapidly evolving needs of consumers and the overall electric grid.” Similarly, Advanced Energy Economy and the Solar Energy Industries Association jointly argued that “by choosing to implement other initiatives over compliance with Order No. 2222, MISO is choosing to keep barriers to participation of DER aggregations in place nearly a decade after the commission first sought to remove them.”
Utility and TO Support
In contrast, MISO member utilities were largely supportive of the timeline, agreeing with the RTO on the complexity of the work.
“In permitting thousands of new generation resources to access wholesale markets, Order No. 2222 requires enormous technical planning to ensure that local distribution and transmission systems are upgraded to accommodate the new resources; that market rules, IT systems and data requirements are sufficient to allow coordination of these new resources without jeopardizing safety, reliability or cybersecurity; and preservation of appropriate roles and authorities for both state regulators and local distribution system owners,” Consumers Energy said.
“This is no small task, as MISO’s filing makes clear — particularly when implementation must take place alongside efforts to address other critical priorities of RTOs and ISOs, including reliability, resiliency, customer affordability and a seismic shift in the electric grid’s underlying resource mix.”
Alliant Energy said it “generally supports the changes as filed, recognizing that there is still much to learn and understand regarding the operation and impact of DER aggregations in MISO’s markets.” Ameren said it “appreciates MISO’s independent assessment of its current capabilities and supports MISO’s determination that the identified software improvements need to be completed before other initiatives can be launched.”
While noting “potential revisions … are needed,” MISO transmission owners also supported the effective date.
“MISO has undertaken multiple initiatives … to address the unique and complex challenges to electric system reliability in the MISO region,” they said. “Completion of these initiatives is expected to bring immediate and quantifiable reliability and economic benefits to the MISO region. At the same time … only three states in the MISO footprint currently permit retail demand resource aggregation, which could significantly limit participation of such aggregations in MISO’s markets.”
Maryland Gov. Larry Hogan (R) tells a great story about his part in hammering out the compromises needed to get the bipartisan Infrastructure Investment and Jobs Act (IIJA) passed in 2021.
Hogan was then chair of the National Governors Association and had a particular focus on infrastructure, he recalled at a Thursday seminar on the IIJA hosted by the Bipartisan Policy Center in D.C. When negotiations over the bill got bogged down, Hogan said, “I hosted kind of an unprecedented summit in Annapolis, where I brought together Republican and Democratic governors, senators and congressmen. … We locked them in a room, plied them with alcohol and crabcakes for two days and walked out of the front door of the governor’s mansion with a basic deal” and set of recommendations for the $1.2 trillion package.
But, six months on, the challenge for the Biden administration and state governments like Maryland’s is getting the money out the door and ensuring it gets to the projects and communities where it will have optimal impacts, Hogan and other speakers at the event said.
“Getting access to that money is not easy,” said Karen Wayland, CEO of the GridWise Alliance, a nonprofit focused on grid modernization. “Getting access to federal dollars requires you to have grant writers, requires you to do all sorts of reporting,” which smaller utilities that need the funds may not have the resources for, she said.
“How do we help all utilities everywhere access federal money?” Wayland said. “Because if we don’t, then we’ll be moving toward what I call an expanded view of the digital divide” on grid modernization.
The states have a critical role in implementation of the law, Hogan said. IIJA funds flow through state agencies to individual projects, he said, and state and local officials need both clear guidance and flexibility to ensure the money is spent efficiently and effectively.
According to a recent IIJA progress report from the White House, allocations to Maryland now total about $1.7 billion, with more than 80% earmarked for transportation infrastructure and the remainder going primarily to climate and energy projects.
Still, Hogan cautioned that while the IIJA is “an important step forward, it’s not quite the transformational, immediate thing. Everybody thinks we all of a sudden have trillions of dollars in this big pile in the back of our State House that we are ready to dole out. … It’s basically a 20% increase in infrastructure spending spread over five years, so it’s about a 4% [per year] increase in infrastructure.”
Similarly, in a moderated discussion at the BPC event, Hogan and Calvin Butler, chief operating officer of Exelon (NASDAQ:EXC), spoke of the law, and its billions for transportation, energy, water and broadband infrastructure as a foundation or force multiplier that will stimulate private investment and public-private partnerships.
Following the recent separation of its regulated utilities and nonregulated energy generation and services business, now Constellation Energy, Exelon has committed $29 billion in capital spending to transmission and distribution infrastructure through 2025, Butler said. With its own infrastructure task force, the utility plans to “partner with our local jurisdictions across the country to say, ‘If you’re going to target and go after any of those [IIJA] grants, we’re going to partner with you to leverage our dollars,’” he said.
In Maryland, for example, the utility is working with two counties seeking federal dollars to electrify their bus fleets to ensure a system of chargers is in place, Butler said.
The state has backed up such efforts, Hogan said, with public and private infrastructure spending, reforms aimed at cutting red tape and an infrastructure subcabinet established “to develop, evaluate and coordinate a cohesive infrastructure strategy that leverages” the IIJA funds.
“It’s not like we flipped the switch, and all our problems are over,” Hogan said. “It’s a small investment from the federal government, and we’re going to try to utilize that to spur a whole lot more private sector investment.”
Waiting for Guidelines
Since President Biden signed the IIJA into law in November, the White House and federal agencies have been focused on getting the money out, with some agencies, such as the Energy Department, announcing new funding opportunities almost weekly.
In January, the White House issued the 459-page Bipartisan Infrastructure Law Guidebook, which provides a high-level overview of all the funding in the $1.2 trillion law, plus online links to specific funding opportunities and information on eligibility and how to apply. Additional guidebooks breaking down the law’s funding include one each for rural and tribal communities, as well as a technical assistance guidebook aimed at providing “targeted support” to help communities and organizations access specific funding in the law.
More detailed information has been issued for individual funding streams in the IIJA, such as the law’s $7.5 billion for electric vehicle charging infrastructure. A memorandum on the program, which aims to put 500,000 EV chargers on American highways, was issued in February. (See States to Get $615 Million for EV Charging from IIJA Funds.)
But guidelines for other key infrastructure programs have been slower in coming, Hogan said. State and local officials are still waiting for guidelines for a cybersecurity grant program, and state allocations for the law’s $65 billion in broadband funding have been delayed while the Federal Communications Commission updates its service maps.
At a hearing before the House Energy and Commerce Committee in March, FCC Chairwoman Jessica Rosenworcel pledged to have the new maps completed by this fall. But a “challenge period” mandated by the IIJA, in which the maps may be contested by local communities, could further delay final determination of the allocations.
Consistency of Funding
Even when the process encounters fewer snags, challenges remain for state officials accessing IIJA funds. The EV charging funds provided a prime example for speakers on a panel following Hogan and Butler on Thursday.
Phil Jones, executive director of the nonprofit Alliance for Transportation Electrification, said that money will flow through state departments of transportation, which don’t understand the electric power system. “Building out these charging stations, especially for medium- and heavy-duty vehicles, it’s going to put stress on the grid. These are large loads coming in.”
Wayland sees a different but equally significant disconnect “between the speed with which the [automakers] have decided to make investments to transform the fleet and the desire of consumers to transform the way they drive, and the ability of the utility industry to move quickly enough to be there when people want to plug all those vehicles in.”
“We’re not going to break the grid in the long term,” Wayland said. “But in the short term, I think we’re going to see some bumps because the utility industry, even when the capital is available, has to move through a very chunky, cumbersome regulatory process.”
She hopes that grid improvement funds in the IIJA “will help de-risk some of the decisions that the policymakers and the regulators have to make when it comes to the investments that are going to be critical for supporting transportation electrification.”
A second, more detailed set of guidelines for the EV charging money could be released at a two-day stakeholder event on Thursday and Friday, to be hosted by the Joint Office of Energy and Transportation, set up by DOE and the U.S. Department of Transportation to oversee distribution of the funds, Jones said.
David Strickland, vice president of global regulatory affairs at General Motors, said his company is committed to ensuring EVs and charging infrastructure are available, and affordable, for all communities as it moves toward an all-electric fleet by 2035.
His main concern on implementation of the IIJA is “consistency of funding. We have a five-year tranche of money, and I think a lot of people are betting to make sure that it is a consistent level. I have seen more than a few times in my life where there have been interruptions of that money at the federal level, especially … for these communities in need,” he said.
For Jones, the IIJA’s $7.5 billion for charging infrastructure is only a down payment. He predicts the U.S. could need up to $250 billion for EV charging to remain competitive with China and Europe.
“We’re going to have to renew this federal infrastructure bill in five years,” he said. “So, we just have a lot more to do.”
The pros and cons of marginal and average approaches to capacity accreditation | ISO-NE
