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.”
NERC and the regional entities continued to see significant cost savings because of the COVID-19 pandemic last year, according to the ERO Enterprise’s yearly budget true-up report filed with FERC last week (RR22-3).
The commission requires NERC to report the ERO’s cost-to-budget comparison every year, along with audited financial statements for itself and each RE, giving the reasons for significant differences between the planned and actual figures. The filing must also include a justification for any use of cash reserves and explanation for why their use constitutes “unforeseen events” and not “a means to fund expected projects outside of the budget approval process.”
According to last week’s filing, NERC and every RE besides the Texas Reliability Entity spent less than they expected in 2021. NERC’s savings were the largest at more than $2.5 million, though its $80.3 million spending (actual) was also much bigger than any RE. Revenue was higher than planned for most entities, though Texas RE, SERC Reliability and the Northeast Power Coordinating Council reported their actual funding was lower than they had projected.
While NERC and the REs had factored some continued cost savings from the pandemic into their 2021 budgets, the ongoing shutdown of almost all business travel and cautious return-to-office policies across the ERO Enterprise meant entities spent even less than expected. (See NERC Aims for Cost Control in 2021 Budget.) NERC’s meetings and travel category, for instance, came in $1.9 million underbudget and personnel expenses were underbudget by $150,000, partly from “lower parking and transportation benefits due to the pandemic.”
Other entities told a similar story: The Midwest Reliability Organization spent just $5,904 of its $963,000 meeting and travel budget in 2021, and ReliabilityFirst similarly saved over 92% of its $980,000 budget for the same line item. Only WECC saw a savings of less than 90%, spending $58,097 of its $378,000 meetings and travel budget in 2021.
Some entities saved money last year by doing work inhouse that they had planned to outsource to consultants or contractors; NPCC, for example, replaced independent compliance auditors with full-time staff. NERC said that “increased experience and expertise gained by entity staffs, and implementation of process efficiencies, has enabled entity staffs to perform and complete work for which consultants or contractors were previously used.”
Despite the overall savings, however, several entities did report overspending in some categories, particularly personnel. For instance, although NERC’s personnel expenses were underbudget overall, the entity said the savings were largely from the capitalization of certain labor costs associated with various projects; without this capitalization, the category would have been $362,000 overbudget.
SERC and NPCC also reported greater-than-expected spending on salaries; in NPCC’s case, this was part because of the use of inhouse staff rather than consultants for compliance audits. SERC said its expenses were from raising compensation for critical staff because of market demand, along with incentives paid out by its Board of Directors for “exceeding corporate strategic initiatives and key performance indicator goals.”
NERC and the REs are currently accepting comments on their draft 2023 business plans and budgets, which they posted last month. (See NERC Plans Big Budget Hike for 2023.) The total ERO Enterprise budget is set to be $248.9 million, about $22.7 million more than the budget for this year. NERC’s budget hike of $12 million represents the lion’s share of the increase, but all REs are planning to raise their spending as well because of the current high inflation rate in the U.S. and the need for investments in cybersecurity. (See ERO Warns Inflation, Cyber Investments to Keep Boosting Budgets.)
The California Air Resources Board’s draft climate change scoping plan — and its proposal for the state to reach carbon neutrality by 2045 — is facing criticism from many directions.
In a letter submitted to CARB last week, a group of 73 environmental organizations said the plan would fail to meet the state’s greenhouse gas reduction requirements by 2030, as well as the 2045 carbon neutrality target.
Instead, the plan “relies on record-breaking levels of unspecified mitigation from the cap-and-trade program in 2030 and entirely unrealistic levels of direct air capture in 2045,” the groups wrote.
“This is not a serious climate plan for California,” they said.
The letter’s signatories include representatives of the Sierra Club, Earthjustice, California Democratic Party Environmental Caucus, and the Center on Race, Poverty and the Environment, among others.
Grid Impacts
On the other side of the debate are individuals who question the scoping plan’s push toward electrification — and the impacts that would have on the electric grid.
“The state of California does not have safe or reliable power,” wrote Dawn Durfee, who said she lost her home in the Paradise wildfire. Requiring all vehicles to be electric would only make matters worse, she said.
“People do need to run refrigerators, washers, dryers, air conditioners or heaters,” Durfee said in a letter to CARB. “People do not need to drive electric cars.”
In addition, Durfee said, worldwide air quality won’t improve until China and Russia cut their emissions.
“California is not the ruler of the universe!” she wrote.
Other letter writers said they couldn’t afford to buy an electric vehicle, or that an EV wouldn’t be able to tow their trailers. Some pointed to the environmental impact of used EV batteries.
“Forcing electric cars on the population is full of disastrous consequences,” Susan Dwyer said in a letter to CARB.
The CARB board will hold a public hearing on the plan on June 23. Written comments are due by June 24.
The scoping plan evaluates four scenarios. Alternatives 1 and 2 would bring the state to carbon neutrality by 2035. In Alternatives 3 and 4, the state would reach the target 10 years later, in 2045.
CARB staff have proposed going with Alternative 3, which would have the least impact on employment and economic growth among the four options, according to the draft.
In contrast, Alternative 1 would have the highest direct costs and slow economic growth the most, the plan said. That alternative would nearly eliminate fossil fuel combustion by 2035 and would have a limited reliance on carbon capture and sequestration.
Some letter writers called the proposed alternative “too little, too late.”
“Choosing the least expensive option, relying on unproven carbon capture technologies, [and] determining job loss without adding in job creation as the energy sector changes is disheartening,” wrote Meredith Rose. “My kids deserve better — and so [do] everyone else’s kids.”
The letter from the 73 environmental groups makes several policy recommendations, including phasing out fossil fuel extraction by 2035 and refining by 2045. Regarding electric power, the groups called for a ban on new gas-fired generation starting immediately and a target of zero GHG emissions by 2035.
“Fundamentally, the draft scoping plan fails to move California beyond oil and gas,” the groups wrote.
‘Puzzling’ Plan
An editorial in the Los Angeles Times on Friday called the scoping plan’s approach “puzzling” in light of California Gov. Gavin Newsom’s directive to CARB to accelerate climate action. The governor famously referred to the “climate damn emergency” when wildfires swept through the state in 2020.
And in July 2021, Newsom asked CARB to look into how carbon neutrality could be achieved by 2035.
The editorial said the plan would use “unproven technology” to remove “huge amounts” of CO2 from the air as well as capture it from cement plants and oil refineries.
Calling the carbon removal approach a “pie in the sky strategy,” the editorial advised using proven approaches.
“In reality, we already have most of the solutions to the climate crisis right in front of us — electrifying everything we can as quickly as possible and fueling it with clean renewable energy,” the editorial said.
Clean Grid Alliance on Monday asked MISO to consider penalty-fee withdraws for advanced-stage interconnection projects that are saddled with expensive network upgrade costs from SPP’s delayed affected system study (AFS) results.
A month after requesting relief for late-stage projects held in limbo until they receive AFS results from SPP, CGA’s Rhonda Peters returned to MISO’s Interconnection Process Working Group (IPWG) to propose a penalty-free withdrawal for projects rendered infeasible by SPP-identified upgrade costs. (See CGA Requests MISO Help for Late-stage Interconnection Projects.)
MISO and SPP have rolled out a new “first ready, first served” interconnection queue priority for generation projects that affect the seams through studies and cost assignments for network upgrades. The new order replaced the grid operators’ previous practice of studying projects that lined up for the queue first. (See FERC OKs New Queue Priority for MISO, SPP Seams Studies.)
In MISO, the new priority bypassed projects that entered the queue in 2018 and 2019. The RTO said those project cycles are destined for generator interconnection agreements (GIA) before the changes take effect.
Peters said some late-stage projects that entered the queue with the 2018 and 2019 cycles still don’t have “complete, accurate or available” network upgrade costs from SPP’s affected system studies.
She said the uncertainty has jeopardized the projects’ financing and power purchase agreements. “The risk factor is too high,” she said.
Peters said MISO should consider allowing penalty-free withdrawals from the queue when late AFS results unexpectedly increase affected system costs. That would allow developers to depart the queue without forfeiting their milestone fees, she said. Peters said MISO could allow projects to interconnect beyond the original seven-year deadlines to reach commercial operation or it could provide nonbinding estimates of likely upgrade costs to aid the developers’ decision making.
Peters said developers of late-stage generation projects have already committed significant capital but might be forced to withdraw when AFS costs “are so high that they could completely change the financial viability of the projects.”
“Advanced stage projects only withdraw if forced to due to circumstances beyond their control, such as unexpected or new network upgrades,” she said. “The financial commitment to reach GIA is significant, even without consideration of milestones. … The interconnection customer wants to reach its commercial operation date. Withdrawals occur only when there is no other course of action.”
MISO’s Ryan Westphal said allowing penalty-free withdrawals could “potentially harm other customers.” The RTO usually keeps milestone fees when interconnection customers leave the queue to minimize the costs of network upgrades on lower-queued projects.
Stakeholders pointed out that AFS results can often double an interconnection customer’s network upgrade costs.
Westphal asked whether other stakeholders would be comfortable with penalty-free exits from the queue.
Invenergy’s Sophia Dossin said while her company has projects in the 2018-19 cycles of the queue, it also has projects that entered in 2020 and later. She said Invenergy is poised to be affected on both sided of the issue and is comfortable with penalty-free exits.
“I would say a lot of customers that are being impacted by the 2018-19 delays will also be impacted by the penalty-free withdrawals. … If there were a Venn diagram, there would be substantial overlap.” Dossin said. “This already is creating a lot of financial issues today.”
Dossin added that no project’s financing partner wants the risk of a “multimillion dollar question mark” on projects waiting on AFS upgrades.
“We’re not in the business of playing games. We’d rather see our projects online,” National Grid Renewables’ Rafik Halim said. He added that he didn’t think developers would view the option as an unconditional “greenlight” to remove generation projects from the queue.
“We shouldn’t be signing a blank check as we sign our GIAs,” Halim argued.
Peters said MISO could institute “rigid” criteria, such as a minimum cost threshold increase for network upgrades.
Westphal said MISO wouldn’t likely move forward with a penalty waiver unless all stakeholders are on board.
“In our opinion … this seems like a mechanism to allow harm and financial impact to other customers,” he said.
Staff also pointed out that interconnection customers should already be estimating a spectrum of AFS costs. They said extending operation deadlines for the 2018-19 project cycles might simply perpetuate uncertainty and affect lower-queued generation projects.
Peters argued that it would “make a huge difference” to financiers if bookends for upgrade cost changes came from MISO instead of the interconnection customers themselves.
MISO is set to again discuss the fate of the 2018-19 interconnection projects during the IPWG’s August meeting.
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