Growth in the number of retail hydrogen fueling stations accelerated in California over the last year, with 56 stations now open, although the state is projecting that it will meet a 100-station target in 2024 rather than 2023.
The state’s 56 retail hydrogen stations open at the end of June marked an increase of eight in the last year, according to a report from the California Air Resources Board (CARB).
In mid-2020, the number of open hydrogen fueling stations was 42, an increase of only one station compared to 12 months earlier. CARB blamed the COVID-19 pandemic for the slow pace of station development in that period.
Meanwhile, about 11,134 fuel cell electric vehicles (FCEVs) were registered in the state as of April 1, up from 7,993 FCEVs in April 2021, the report said. The number of FCEVs on California roads is projected to reach 34,500 in 2025 and 65,600 in 2028.
Annual Evaluation
CARB prepares a report each year on deployment of FCEVs in California and development of hydrogen fueling stations. The report is required by Assembly Bill 8 of 2013.
AB 8 instructed the California Energy Commission (CEC) to fund the development of hydrogen fueling stations until there are at least 100 publicly available stations operating in the state. And a 2018 executive order from Gov. Jerry Brown set a statewide goal of 200 hydrogen stations by 2025.
The eight new hydrogen fueling stations identified in the 2022 report include two stations in the Los Angeles area, three in Orange County and three in the San Francisco Bay Area. Those are also regions where FCEV registrations are concentrated.
Station development isn’t going quite as fast as CARB predicted a year ago. At the time, the forecast was for 97 stations to be open by the end of 2022; now it appears that 79 stations will be open this year. The 100-station milestone has been pushed to 2024.
Station developers say they’re being slowed down by the permit review and approval process, the wait for electric utility connections, and delays in getting equipment.
Still, CARB said, 79 stations by year’s end would be “a significant increase.”
“If achieved, [it] will be the fastest pace of station openings in California history,” the agency said.
CARB noted that station development is becoming more difficult to track because not all projects are receiving state funding. CARB’s current analysis doesn’t include a plan that Iwatani and Chevron announced in March to build 30 hydrogen fueling sites in California by 2026. The stations would be in addition to those that Iwatani is developing under an agreement with CEC.
Renewable Content Calculated
The report also analyzes the renewable content of hydrogen transportation fuel. An estimated 59% of the fuel was renewable in 2021 and the figure was 65% in the first quarter of this year. Those numbers exceed state requirements, including a 40% renewable minimum in the hydrogen refueling infrastructure (HRI) program within CARB’s low-carbon fuel standard (LCFS).
HRI allows station operators to receive extra LCFS credits based on the difference between station capacity and fuel sales. Sixty-three stations are now approved to receive HRI credits.
While the recent figures exceed state requirements, they’re less than the 90% or more renewable percentage in the first half of 2021, CARB said.
The reduction may be due to station operators diversifying their hydrogen supply following past supply constraints, the agency said.
CARB’s 2022 report on hydrogen fueling stations, and reports dating back to 2014, are available here.
Washington lawmakers will likely prioritize legislation designed to sharply reduce carbon emissions from homes and commercial buildings during the upcoming 2023 session, which begins in January.
The federal Inflation Reduction Act contains tax credits and other measures related to decreasing emissions from residential and commercial structures. These measures include changing a lifetime cap on energy efficiency tax credits to an annual cap and setting up tax credits for installing heat pumps and making buildings more energy efficient.
State and local laws and regulations need to be implemented or tweaked to mesh neatly with the federal mandates, said Anna Loring, senior policy adviser to Gov. Jay Inslee.
Loring spoke Monday to the Washington House Environment and Energy Committee during a briefing on carbon emissions and buildings. She said the legislature needs to tackle the issue in the upcoming session.
Washington law calls for the state to reduce carbon emissions from homes and commercials buildings to 30% of 2006 levels by 2031.
By 2018, homes in Washington posted a carbon footprint that was 60.5% of 2006 levels, compared to a target of 65%, said Kjell Anderson, an architect serving on the State Building Code Council (SBCC). But commercial buildings’ carbon footprint is 69% of 2006 levels, falling short of the hitting the 2018 target of 60%.
All-electric homes with heat pumps are cheaper to build and maintain than ones with furnaces and air conditioners, Jonny Kocher of the Rocky Mountain Institute said.
However, “buildings are the fastest growing source of carbon emissions — driven by gas and heating,” said Patience Malaba, executive director of the Housing Development Consortium of Seattle-King County.
Malaba said there is a growing need for new homes for moderate- and low-income families in Seattle and King County, which will increase their carbon footprint. She also noted that low-income families have problems affording heat pumps — which combine air conditioning and heating — to trim their emissions. Financial incentives will be needed to obtain the participation of those families, she said.
The SBCC passed a requirement in April that all new commercial buildings must have heat pumps. Kocher expects that a similar decision for homes might be reached by the same council at its November meeting.
New Jersey’s Board of Public Utilities (BPU) is seeking stakeholder input to help craft the state’s third offshore wind solicitation, for 1.2 GW, in the first quarter of 2023, as it reaches for its goal of 11 GW of wind power by 2040.
The agency is asking stakeholders for insight into more than 40 questions for which the answers will help the state shape the Solicitation Guidance Document on issues such as project design requirements, the economic impact of the winning project and different aspects of the environmental and fisheries mitigation plans.
The questions include: whether the BPU should seek only projects of 1.2 GW or offer flexibility to diverge from that; whether the board should accept storage proposals as part of the solicitation; what strategy might ensure that the economic benefits pledged in a proposal are met; and how to ensure the full project pitched is constructed.
The board’s solicitation on Sept. 16 preceded a flurry of announcements by the Murphy administration to mark Climate Week, including plans to spend $10 million on green job creation and $3.125 million on researching the impact of the wind projects on marine wildlife.
The request for information is the first of two, according to the BPU. The second will be released after the board makes its decision on its transmission solicitation made under the State Agreement Approach (SAA) with PJM. The board received about 80 suggestions for how enhance the state grid in preparation for the increase in offshore wind power and expects to make a decision in October on which ones, if any, to adopt. (See NJ Seeks Efficiency, Savings in OSW Transmission Process.)
With that completed, the board expects to issue a draft of the third solicitation incorporating stakeholder comments in November.
Extreme Events
The solicitation, following the BPU’s award of 3.758 GW of power in solicitations in 2019 and 2021, will be the next step toward the 11-GW goal set out in an executive order signed by Gov. Phil Murphy on Sept. 21. The new goal is nearly 50% higher than the previous goal of 7.5 GW by 2035, which Murphy rescinded in the order, and the state has not yet set its final goal. The order added that “the BPU shall undertake to study the feasibility and benefits of further increasing the goal.”
“Extreme weather events and severe flooding across the country leave no room for doubt: The effects of climate change are becoming more impactful and more aggressive, and we must do the same,” Murphy said in a release announcing the signing of the executive order. In a speech at Climate Week in New York City the same day, Murphy called it an “aggressive target, but an achievable one,” adding that the task will be assisted by “technological advancements that are making turbines more and more efficient, almost literally by the day.”
The shift elevates New Jersey’s goal above that of New York’s OSW target of 9 GW by 2035. Both states will also see additional OSW power created from the federal auction in which six bidders pledged to create projects totaling 5.6 GW in the New York Bight, the coastal zone that straddles the two states. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)
Yet the state’s expanding offshore wind strategy comes amid concern among Republicans and business groups at the potential — and so far, unknown — cost of shifting the state away from fossil fuels and toward electricity.
Readiness Questioned
A spokesman for Affordable Energy for New Jersey, a coalition of business groups and building trade unions that has expressed concern about the cost of implementing New Jersey’s Energy Master Plan, questioned whether the state could handle an increased amount of the OSW production.
“The state has yet to plot exactly where in the ocean these turbines are going to go,” spokesman Michael Makarski told a regular quarterly meeting held by the BPU to seek public input Friday. He called the wind expansion plan “delusional.”
“We are not sitting on a stockpile of materials to construct these turbines, and the board doesn’t know exactly where these transmission lines are going to make landfall,” he said. “These are massive issues.”
“If we think that the siting process is going to be smooth sailing, then we should think again,” he said. “If we install one state-of-the-art 13-MW turbine every week, each week, for the next 18 years, we’ll hit that 11,000-MW goal. Now, that’s if we started today.”
The offshore wind projects — Ocean Wind 1 in the first phase; Ocean Wind 2 and Atlantic Shores in the second — have been warmly received by some environmentalists and public officials. But they have faced opposition from the fishing industry, which fears that the turbines will disrupt fishing areas and create a dangerous environment for boats pulling nets, and recreational fishermen. The tourism sector also has voiced concern that the sight of turbines could reduce the number of visitors coming to the state’s coast. Local residents and property owners are worried about the impact on properties resulting from construction to install cables and other equipment.
Some of those concerns are likely to emerge again Thursday when the BPU will hold a public hearing into a request by Danish developer Ørsted’s request for an easement across land owned by Cape May County on which to lay cables connecting the wind project with onshore load stations.
Tracking Marine Impact
Along with the wind goal announcement, Murphy released a report, Green Jobs for a Sustainable Future, last week that outlined recommendations and pathways for growing a demographically representative and inclusive green workforce. He also highlighted $10 million in new investments to guide and support the state in generating well paying jobs in the growing green economy.
“Today’s announcements underscore our determination to not only double our efforts in the fight against climate change, but to ensure that every New Jerseyan can reap the benefits of transitioning to a clean energy economy,” said Jane Cohen, executive director of the governor’s Office of Climate Action and the Green Economy.
The BPU and New Jersey Department of Environmental Protection (DEP) also announced Thursday that they would spend $3.125 million on four projects on research and monitoring of the impact of offshore wind projects on marine life. The funding, the second round of marine life research funding, will “study potential impacts to the recreational fishing industry, use acoustic telemetry to track fish movements, deploy passive acoustic technologies to monitor whale movements, and evaluate offshore wind infrastructure as potential platforms for long-term environmental and ecological monitoring,’” the agencies said.
The money will come from a fund of $26 million that is administered by the state with funds from the developers of the second-phase solicitation, Ørsted and a joint venture between EDF Renewables North America and Shell New Energies US.
“This round of projects will gather critical baseline scientific information that will help ensure the responsible development and operation of offshore wind facilities that protect our coastline and its natural resources that are precious to all of us,” DEP Commissioner Shawn LaTourette said.
The projects include:
$440,000 to assess the potential impacts of offshore wind energy on New Jersey’s recreational fishing industry, to be conducted by the Clean Energy and Sustainability Analytics Center at Montclair State University.
$1.9 million to track fish movements along New Jersey’s coastline and in offshore wind lease areas with acoustic telemetry. The work will be conducted by Monmouth University and the New England Aquarium.
$500,000 for deployment of passive acoustic monitoring systems on the seafloor to record the calls of baleen whale species, including the endangered North Atlantic right whale, to better understand the movements and behaviors of these animals. No contract yet awarded.
$285,000 for Rutgers University, Monmouth University, the National Renewable Energy Laboratory, and the Special Initiative on Offshore Wind to explore the potential use of offshore wind farms turbines, foundations and substations as potential environmental and ecological monitoring platforms.
FERC last week denied a complaint by two natural gas-fired plants that sought to have NYISO implement a “clean” minimum offer price rule (MOPR) for all new and existing resources receiving out-of-market subsidies in New York.
FERC voted 4-1 to reject the complaint by the 1,016-MW Cricket Valley Energy Center (CVEC) and the 635-MW Empire Generating facility, with Commissioner James Danly dissenting (EL21-7).
The October 2020 complaint by CVEC and Empire alleged that state subsidies were suppressing prices and distorting price signals in NYISO’s installed capacity market (ICAP).
The change, which exempted from the BSM rules new capacity resources required to satisfy the goals of the state Climate Leadership and Community Protection Act, “appropriately focused buyer-side market power mitigation on those resources that behave uncompetitively through the exercise of buyer-side market power,” FERC said.
Expanding the BSM rules, as suggested by the complaint, would reverse these changes, according to FERC, and upset the balance between “the need to mitigate the potential exercise of buyer-side market power against the harms of over-mitigation.”
Profitability Damaged
Empire and Cricket Valley complained that their profitability was damaged by the uneconomic retention of state-subsidized generation, including New York’s award of zero-emission credits to nuclear plants. Empire said its plant, which went into service in 2010, was forced into bankruptcy proceedings because it was unable to earn sufficient energy and capacity payments in the NYISO markets to cover its costs.
The 635-MW Empire Generating facility in Rensselaer, N.Y. | Empire
But the commission said it was not required “to shield NYISO’s market from the indirect effects of state policies to ensure that commission-jurisdictional rates remain just and reasonable.
“… We have already found the BSM rules to be just and reasonable … and neither the complaint nor the complainants’ financial performance provide a basis to undermine that finding,” it said.
In the May 10 ruling, the commission acknowledged that prior FERC orders — when the commission was under Republican control — “treated state policy choices as equivalent to anti-competitive conduct.”
But it said the current Democratic majority “no longer believes it appropriate to presume that states’ exercise of their reserved authority over generation facilities is the equivalent of anticompetitive conduct, simply because of the inevitable, albeit indirect, effect on ICAP market prices.”
Republican Commissioner Mark Christie issued a concurrence last week, saying he supported NYISO’s BSM proposal because the costs of New York’s policies would be limited to that single state ISO and not impact other regions. “The chief recourse for New York consumers and businesses who do not like the costs and consequences of that state’s public policies is to the ballot box,” he said.
Danly: Return to Cost-based Rates?
FERC Commissioner James Danly | FERC
Danly, also a Republican, reiterated his opposition to the narrowed BSM rules in his dissent last week, warning that, “When the inevitable price suppression caused by unmitigated state subsidies results in the premature retirement of generators with needed attributes, resource adequacy will be compromised.”
As states “continue to place their finger on the scale in order to favor certain resources,” FERC should consider returning to “cost-based ratemaking to protect ratepayers,” Danly said. “Doing otherwise perpetuates the notion that our markets are competitive and, therefore, capable of incentivizing investment in the necessary type and quantity of resources, when, in fact, they are not.”
Billions of dollars in add-ons to California’s electric bills are slowing the adoption of electric vehicles, heat pumps and other clean energy technologies, says a new study by CAISO Governor Severin Borenstein and two of his colleagues at the University of California, Berkeley.
Customers of the state’s three large investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — shoulder the “residual costs” of wildfire prevention and victim compensation along with rooftop solar subsidies and other big-ticket items, the study found.
The add-ons amount to an “electricity tax” that hits lower-income households hardest, it says.
“Customers across the three IOU service territories contribute $678 per year on average toward the residual cost burden,” the study says. “For PG&E and SDG&E customers, residual cost burdens are more than two-thirds of their total bills, whereas SCE customers pay slightly more than half of their bills towards residual costs. As a result, how California chooses to recover these costs is the primary driver of electricity costs.”
That, in turn, “discourages efficient substitution from natural gas and gasoline … towards electricity,” it said. “As such, high electricity prices act as a deterrent to electrification of transportation and buildings.”
Released Thursday, “Paying for Electricity in California: How Residential Rate Design Impacts Equity and Electrification,” was written by Borenstein and professors Meredith Fowlie and James Sallee at the Energy Institute at UC Berkeley’s Haas School of Business. Nonprofit think tank Next 10 commissioned the report.
The study is a follow-up to last year’s publication by the same authors, “Designing Electricity Rates for An Equitable Energy Transition,” which dealt with California’s strategy of recovering fixed utility and social program costs through “increased per-kilowatt hour (‘volumetric’) prices.”
“With nearly all fixed and sunk costs recovered through such volumetric prices, the price customers pay when they turn their lights on for an extra hour is now two to three times what it actually costs to provide that extra electricity — even when including the societal cost of pollution,” it said. (See Calif. Worries High Rates Could Hurt Climate Efforts.)
Last week’s report expanded on the prior study by analyzing, for the first time, detailed billing data from 11 million households and examining the consequences of the “electricity tax.”
It found that higher-income households pay a greater share of residual costs, “but lower-income households pay much more as a fraction of their annual income on average, so much so that the effective electricity tax is more regressive than the state sales tax.”
In PG&E and SDG&E territories, for example, the lowest-earning households pay more than 3% of their annual incomes in residual costs while those in the highest income group pay less than 1%.
Net Metering
The state’s controversial net metering system for rooftop solar owners “makes the effective electricity tax substantially more regressive,” it says. “This is because wealthier households are much more likely to have rooftop solar.
“The effect is strongest in SDG&E, where rooftop solar in 2019 already provided over 20% of residential electricity under net metering, thus offsetting a majority of the cross-subsidy created by the California Alternative Rates for Energy (CARE) program” for low-income households.
The California Public Utilities Commission issued a draft decision in December to reform net metering, which credits rooftop solar owners for surplus electricity exported to the grid but backed away from the plan amid protests from the solar industry and rooftop solar owners. (See CPUC to Delay Net Metering Decision for a Year.)
In its initial proposal, the CPUC said net metering “negatively impacts nonparticipating customers, is not cost-effective and disproportionately harms low-income ratepayers.” Utilities including PG&E estimated that net metering shifts up to $4 billion a year in costs from households that can pay for rooftop solar to those that cannot.
Solar subsidies and other components of the electricity tax are hampering electrification because “customers considering electrification face much higher operating costs if they electrify,” the study says.
“For California households considering purchasing an electric vehicle, the effective electricity tax raises the annual operating cost of an EV by around $600 per year on average,” and by $900 for average SDG&E customers, it says. “Recent research suggests that this could be reducing EV adoption by somewhere between 13% and 33%.”
For households considering electric space and water heating, “the effective electricity tax raises the annual cost of doing so by around $600 per year,” it said. “Recent research suggests that eliminating this tax could increase the fraction of new homes that are built with electric heating by around one-third.”
The authors said they do not dispute the need for utilities to recover costs but believe it could be done in different ways to promote equity for lower- and higher-income households.
One possible solution, the report says, would be to move “some costs that contribute to the residual cost burden onto the state budget, to be funded by increases in the sales or income tax.” That “would increase equity and improve efficiency because it would reduce the effective electricity tax.” Another solution could be to introduce a “system of income-based fixed charges.”
The authors said their primary aim was to provide useful facts and potential rate-design fixes, “guided by the twin objectives of fostering decarbonization and improving equity.
“All possible reforms create some manner of trade off, and as such should be debated in the broader policy context in the state,” they said.
The NERC Standards Committee on Wednesday appointed additional or supplemental members to three of the ERO’s 19 ongoing standards development projects’ drafting teams, as the organization works to catch up on some behind-schedule work.
The appointments were only a small part of a packed agenda for the committee, which met at the Texas Reliability Entity headquarters in Austin. It also authorized the initial postings of three draft standards; appointed two standard authorization request (SAR) drafting teams as the standard drafting teams for those projects; approved another SAR; and appointed the roster for another SAR drafting team.
In opening the meeting, Chair Amy Casuscelli, of Xcel Energy, noted that she had the day before attended a meeting of the Project Management and Oversight Subcommittee, which monitors the projects.
“I was just struck by the number of the projects that are open. There are more on the horizon that were discussed at the RSTC [Reliability and Security Technical Committee] meeting last week. There’s just a lot of work that’s coming up,” Casuscelli said. “All of those projects touch a really large number of our subject-matter experts … not to mention NERC staff, and there’s a really tremendous resource obligation that is wrapped up into all of those projects. … We are all definitely feeling the resource constraints that we have. … That means we all need to challenge ourselves to work smarter and work as efficiently as possible.”
Latrice Harkness, NERC manager of standards development, previewed the committee’s next three months, including the schedule for when draft standards would be voted on and posted for comment. The posting schedule listed projects for nearly every week through the end of October.
“That’s a lot of work coming down very quickly,” Kent Feliks, manager of NERC reliability assurance at American Electric Power, commented in response. “My people are already screaming that we already have a lot on our plate.”
“Our standards staff is meeting weekly … to look at this posting schedule a little more closely to make sure we’re not overwhelming industry with those project postings,” Harkness said.
“I know internally we’ve got some protests at the sheer number of things that we’re looking at too,” Casuscelli said with a chuckle. “So I think we’re all feeling it.”
8th Nominee Added over NERC Protest
The SC appointed eight additional members to the SAR drafting team for Project 2020-02 (Modifications to PRC-024 – Generator Ride-through), one more than NERC recommended, to join the team’s current five members.
The goal of the project is to replace PRC-024-003 “with a performance-based ride-through standard that ensures generators remain connected to the bulk power system during system disturbances,” according to a staff presentation. “From a risk-based perspective, the goal of the standard is to mitigate the ongoing and systemic performance issues identified across multiple interconnections and across many disturbances analyzed by NERC and the regions.”
The project stems from the general concern of retiring synchronous generators and their replacement with nonsynchronous resources. But the presentation also notes that “these issues have been identified in inverter-based resources as well as synchronous generators, with many causes of tripping entirely unrelated to voltage and frequency protection settings as dictated by the currently effective version of PRC-024.”
Several stakeholders expressed concern that most of the team was represented by generators, with a lack of reliability experience. When questioned about the one volunteer not recommended by NERC, Harkness said that staff had found the person would “not be a good fit.”
Feliks, however, noted that the committee “typically very much encourages people to be on drafting teams and encourages their participation. So looking at this particular drafting team — and quite honestly I don’t have a dog in this fight — but leaving one person off that’s volunteering; that, based on the resume, has some pretty deep experience in this, it doesn’t seem to make real logical sense.” He moved to include the candidate
Harkness clarified that in interviewing the nominee, staff discovered they were “totally against the project, and so there was no support for the SAR as it was. … When you think about team dynamics, you want to be able to build consensus. … If you jump out of the gate with someone against it, you may not get anywhere.”
Candidates for SAR drafting teams are nonpublic, so committee members could not speak about certain details that would identify the nominee in question, including specifically why they were against the project. Harkness would only say that the person did not think the standard was needed.
Feliks returned to his original point that “anyone who raises their hand [i.e., volunteers], given the fact that we’re running pretty thin, I’m pretty happy with.” But he also said that “part of this vetting process is to make sure industry thinks a standard revision is needed. … So a contrarian opinion on the SAR drafting team: isn’t that kind of the point of this? … The idea that NERC is picking a candidate based on what they want, I kind find a lot of concern with. It’s supposed to be up to the industry.”
This prompted Howard Gugel, NERC vice president of engineering and standards, to chime in. “Hopefully nobody [thinks] that NERC would ever try to stack a drafting team. That is not the intention [with this project] and not anything we would ever do.” The goal in assembling a team is “ensuring a successful project.”
“So while we quite often [recommend] people who have differing opinions, we find that it may be counterproductive to recommend somebody at the onset who is against the project itself,” Gugel said. Based on prior experience, “that tends to get the drafting team bogged down on issues in almost every call that they take.”
He also reminded the committee “of the speed at which we should be adapting to these newer technologies and getting standards out, and I would hate to put someone on a standard drafting team that would cause a year or two[-year] delay on these resources that are causing definite impacts to reliability.”
Other stakeholders voiced agreement with Feliks that there should be a difference of opinion on drafting teams and expressed doubt that the one person could derail an entire project. The committee ended up approving the eighth addition to the team, with five abstentions but no one opposed.
Discussion of the clean energy transition focuses too much on technology and not enough on the people who will make it work, speakers at the Global Clean Energy Action Forum said Thursday.
Leaders need to ensure the transition is just, the panelists said, and they also need to make it inclusive.
AFL-CIO President Liz Shuler said it is important to bring the voice and perspective of working people into the conversation and that it needs to be planned in advance rather than backfilled afterward.
“The term ‘just transition’ means different things to different people,” she said. “In the past we’ve seen transitions that have gone badly. I would argue the deindustrialization of the Midwest in the U.S., where manufacturing left, we didn’t have the right policy solutions in place, we didn’t have a proactive strategy to ensure that people transitioned into good jobs. People felt abandoned, left behind, angry and frustrated, and that has become destabilizing to our democracy. We can choose to do better this time.”
Angela Wilkinson, CEO of the World Energy Council, said the energy transition is not the destination but the process for reaching the destination; there needs to be a hopeful vision for what the destination is and what it means to people.
“Humanizing energy was an agenda we chose because we think the biggest gap in closing the implementation is the challenge of involving more people and very diverse communities in moving further, faster and fairly together,” she said.
The panelists broadly defined the goal as equal access for all to good-paying jobs carrying out the transition and equal benefits to all from completion of the transition.
Reuters reporter Valerie Volcovici, moderating the discussion, asked the panel about their thoughts on preparing a large skilled workforce for the epic task ahead. Electricians, she said, will be driving the transition in many ways; they are already in short supply on the cusp of a great expansion in their field.
“We have lots of technology, there is a lot of money available, but actually we have to create this mechanism for moving faster,” Wilkinson said. “And it’s communities that create … the pull for those technologies. So, the capabilities of the community are also what we need to think about. What’s the capability a community needs to be able to move its transition?”
Shuler said organized labor has been training skilled workers for more than a century and has been involved in multiple transitions during that time. It is important that the jobs created be good jobs, so that people will aspire to them, and also that there are multiple pathways to good careers.
“We are very centered around higher education and college being the solution for everyone, particularly in high schools,” she said. “And now we’re starting to see a resurgence in, ‘Yes, we do need electricians; we do need people with skills who can actually rebuild our nations across the world.’ Unions can be the pathway through apprenticeship and pre-apprenticeship — they’re almost like the other college degree. Four [to] five years it takes to grow a highly skilled electrician.”
Jonathan Wilkinson, Canada’s minister of natural resources (and no relation to Angela Wilkinson), said to bridge the labor gap, his country will need to rely on new immigrants and to include those it has historically excluded, particularly indigenous communities.
In Canada, 70% of the buildings standing today will still be standing in 2050 and will need a significant retrofit to meet decarbonization goals.
“That means you’re going to need tens of thousands of electricians and plumbers and construction workers, and those are occupations right now where we are struggling to find enough young people, given the demographics where lots of folks are retiring,” he said.
Volcovici asked how leaders can gain support and prevent fear in communities as the energy transition progresses, given the disruption caused by previous large-scale transitions.
Angela Wilkinson suggested involving communities so that they are helping direct the transition rather than sitting on the sideline hoping they won’t be left behind.
Shuler said specific details of the change are needed, so that people can see themselves in it.
Jonathan Wilkinson said the clean energy transition will be a hard sell for anyone who fears it will leave them behind, and said fear is stoked by widespread ignorance of what the transition is.
“[We need to] paint a much clearer picture for folks about what the energy transition actually means,” he said. “When people think about it, they think it means a solar panel on the roof or a wind turbine on the prairies. But obviously it’s a lot more than that, and I don’t think that policy makers have done a particularly good job of actually communicating that.”
The New England states aren’t challenging ISO-NE’s request to up its budget by 10%, but they are asking the grid operator to do a better job using metrics to measure its performance.
In a letter to ISO-NE earlier this month, the heads of agencies from each of the six states agreed that the $20 million budget boost, largely for new hiring and capital projects, is “necessary to improve ISO-NE’s function and performance.” (See ISO-NE Wants to Hike its Budget by 10% in 2023.)
They took issue, however, with what they say is a failure by the grid operator to comply with a year-old request to update its use of performance metrics to measure how that money is being spent. Specifically, the states wrote, ISO-NE is not using any of FERC’s common RTO/ISO performance metrics. The grid operator is also not using any performance metrics to determine the cost effectiveness of transmission fixes other than project costs, the states said.
“In both instances, ISO-NE appears to be limiting itself to narrowly defined and tailored metrics that foreclose comparisons across other entities or processes,” the officials wrote. “This limitation appears to have mitigated ISO-NE’s ability to learn from its one competitive transmission fix solicitation since its results cannot be compared with any other process.”
The grid operator defended itself in a reply last week, saying that it does in fact use metrics to measure its performance across a number of areas.
The common metrics that FERC uses, ISO-NE wrote, are less useful than those specifically tailored to the New England region. But the RTO said it will take another look at whether any of them could be useful.
As for transmission planning, ISO-NE noted that its tariff requires that new lines be built only as a last resort after other options have been considered. “The ISO will continue to monitor its performance in this area,” it said.
Decarbonizing the maritime industry entails much more than switching ships to zero-emission fuel, leaders in the sector said Thursday.
It will require creating the green corridors envisioned in the Clydebank Declaration — linked mini-ecosystems with participation of shippers, their support industries, ports, governments and others — they told an audience at the Global Clean Energy Action Forum in Pittsburgh.
Two dozen nations signed the Clydebank Declaration formalizing the green corridor concept at COP26, the United Nations Climate Change Conference in 2021.
U.S. Special Presidential Envoy for Climate John Kerry discusses green shipping at the GCEAF in Pittsburgh, Pa., on Thursday, Sept. 22. | Global Clean Energy Action Forum
Yet emissions in the shipping sector are still rising — not the trajectory needed to comply with the Paris Agreement on climate change, said John Kerry, the U.S. special presidential envoy for climate.
“If shipping were a country, it would be the eighth largest emitter of greenhouse gases in the world,” he said.
It’s not enough to have steel mills, automobiles and power plants decarbonize, he added. “We’ve got to have shipping at the table, in a serious way. The green shipping challenge will encourage everyone up and down the entire food chain.”
The food chain extends beyond the fuel that runs the ship, all the way to details such as how the cranes in the port are powered, Kerry said. It is “a continuity of effort, so that the entire corridor, from start to finish, becomes green.”
Rikke Wetter Olufsen, chief policy officer of the Danish Maritime Authority, said the first green corridors will “play an important role in their capacity to show how the green transition can work in practice.”
Bo Cerup-Simonsen, CEO of the Mærsk Mc-Kinney Møller Center for Zero Carbon Shipping, said the green corridor concept serves at least two purposes: “Getting the green value systems going to attract the initial customers and investors, and then aggregating demand to create a sustainable longer-term business model with greater demand.”
“I think that’s a working hypothesis of the green corridor which seems to hold,” Cerup-Simonsen said. “That’s a very strong proposition … that will [create] initial scale, and that should inform the global policy system.”
Eamonn Beirne, a deputy director in the United Kingdom’s Department for Transport, said he is encouraged. “In a sector with a reputation for rigidity or moving too slowly, we’ve been really thrilled with the momentum worldwide as the signatories and industry players alike have made green corridors a cornerstone of their respective journeys to zero-emission shipping.
“I think it’s crucial that the commitments at events like COP26 or this one today translate into action, and it’s been really great to see some of that happening.”
Because there are so many moving parts to the industry across the globe, there needs to be a playbook with common language and identified critical success factors, American Bureau of Shipping CEO Christopher Wiernicki said.
“One of the biggest things with green shipping corridors is you need data. Data is going to be so important in this process because without data you cannot make the right decisions,” he said.
Sandra Kilroy, senior director of engineering, environment and sustainability at the Port of Seattle, continued that theme, saying standardization is critical. She said the ports of Seattle and Los Angeles have begun collaborating for this reason.
“There’s a lot of differences, obviously, between what we’re doing,” she said. “But [the more] that we can be consistent in how we’re approaching the policy is going to be really helpful because we’re both picking up the phone and having meetings in D.C. trying to help institute the policies we need in place to move this forward.”
VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee on Wednesday rejected two proposals intended to allow market sellers to represent a greater degree of the risk they take on when entering the capacity market.
The strongest support went to the PJM package, which would have sought to ensure that sellers are able to fully reflect the cost of their Capacity Performance (CP) risk when entering into the Base Residual Auction and provide further clarity around the market seller offer cap (MSOC) review process itself. Nearly 60% of stakeholders supported the package over the status quo, falling short of the two-thirds threshold required.
A secondary proposal, from LS Power, contained many of the same provisions as the PJM language, while also allowing sellers the opportunity to seek a must-offer exception after they get their MSOC numbers from PJM. Those suggested revisions received 57% support.
When the issue was last discussed by the MRC during its July 27 meeting, load interests had voiced their concerns over the impact the language could have on capacity prices. (See “Discussions Continue on Market Seller Offer Cap,” PJM MRC Briefs: Aug. 24, 2022.)
Independent Market Monitor Joe Bowring said the current MSOC structure already allows sellers to fully reflect risk when entering the auction. “PJM’s proposal would significantly change the definition of the offer cap based on avoidable costs because the proposal would not permit net revenues to offset the” CP quantifiable risk, he said.
Bowring also pointed out that PJM’s proposal would significantly change the review process and permit it to take on a market monitoring role. “There is no reason to change the substance or process associated with the capacity market offer caps that are designed to prevent the exercise of market power and will operate effectively to prevent the exercise of market power.”
Generation owners spoke in favor of both proposals, saying that the MSOC as it stands doesn’t reflect the true cost of their risk. Jason Barker, of Constellation Energy, called the revisions a set of much needed reforms to the capacity market.
“The most important thing to take away is that this proposal aids in having market sellers provide an accurate assessment of their capacity risk,” he said.
Paul Sotkiewicz of E-Cubed Policy Associates said the packages came with the potential to make it more attractive for renewable energy resources, which face greater CP risk, to participate in the capacity market.
“I think we would see much more of those resources participate in [the market] … if they were able to reflect those risks in their [market] offer,” he said.
MRC Secretary Dave Anders said the MSOC deliberations have held much of the Resource Adequacy Senior Task Force’s attention over the past year, with two different attempts to address the topic — just one of 10 work activities the task force is charged with examining. He said it’s likely that the task force will pivot to focusing on those other issues relating to the capacity market for the time being.
MRC Approves Bankruptcy Revisions
The committee also approved revisions to PJM’s governing documents to strengthen protections for members in the event of a market participant declaring bankruptcy. The proposal will now go before the Members Committee next month.
The changes would clarify language regarding cash deposits and require a participant declaring bankruptcy to address PJM’s rights immediately upon making their filing. The provisions provide that if a party fails to obtain the assurances for PJM, it would provide cause for the bankruptcy court to grant the RTO relief from an automatic stay.
The package would also modify language regarding financial transmission rights, clarifying that they’re entitled to special protections. The FTR market is an area of focus following the default of GreenHat Energy, which cost PJM members nearly $180 million. (See FERC OKs GreenHat Settlements.)
First Read on New Black Start Fuel-assured Generation Classification
The MRC got its first look at a PJM-proposed package of revisions coming out of a yearslong effort to increase the reliability of non-fuel-assured black start resources during a restoration event. The revisions would create a new “fuel assured” category of black start generators that can demonstrate a higher level of reliability through enhanced fuel availability.
The proposal would require that each transmission zone have at least one fuel-assured black start generator and identify regions where additional restoration capability may be required.
The package, drafted with Brookfield Renewable and the D.C. Office of the People’s Counsel, received the endorsement of the Market Implementation Committee and Operating Committee in a joint vote earlier this month, receiving 76% support over a competing proposal from the Monitor, which received 9%. (See Stakeholders Endorse PJM’s Black Start Fuel Reqs Proposal.)
Michael Bryson, PJM senior vice president of operations, said the change would classify 10 to 20 fuel-assured resources out of the approximately 150 black start resources in the RTO’s fleet.
Senior Engineer Dan Bennett said each zone already has at least one existing black start generator that qualifies as fuel assured, but there are eight “extreme outliers” in which fuel loss could delay restoration by 10 or more hours. The proposal would increase PJM’s annual revenue requirement for black start resources by about $28.2 million per year.
Intermittent, hybrid and run-of-river hydro resources would be permitted to contribute to black start capability, using historical data to create a calculation with 90% confidence to estimate how much capacity can be expected from them. Their inclusion has been a point of contention with Bowring, who says that black start resources should be guaranteed to be ready to supply their capacity should they be called out during a restoration event.
“It should be 100% confidence level; there should be no doubt about it,” he said.
Bowring said that black start planning should be done regionally by PJM and not zonally; that the RTO’s proposal could cause customers to pay twice for fuel-assured black start; and that transmission owners should not substitute for PJM at any point in the procurement process.
Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said his members have shared many of the same concerns outlined by the Monitor, but PJM has struck a balance between fuel assurance and the cost to consumers in drafting its package.
“Overall, I would say this is one of the best processes where we’ve come together to find a balanced approach in the end,” he said.
Reserve Requirement Study Recommends Raising IRM and FPR
The MRC received a presentation on the preliminary 2022 Reserve Requirement Study results, which recommends increasing both the forecast pool requirement (FPR) and installed reserve margin (IRM) compared to last year’s study. The updated study resets the recommended figures for the next three years and sets a recommendation for 2026/27.
This year’s study results recommend an IRM of 14.9% for the 2023/24 delivery year, up from 14.8% for 2022/23, and a FPR of 1.093, compared to 1.0901. Both figures would continue to fall for the following three years on a similar slope to last year’s recommendations, just pushed out by a year. (See “Reserve Requirement Study Recommends Increasing FPR and IMR,” PJM Planning Committee Briefs: Sept. 6, 2022.)
Both the load and capacity model projections put downward pressure on the IRM and FPR, but those are outweighed by the upward pressure from the capacity benefit of ties. The new model used for this year’s study projects that PJM’s peak load will more closely coincide with the world peak, reducing the ability to import power.
The study also proposed winter reserve targets for the upcoming season, recommending 21% maximum monthly available reserves for December, 27% for January and 23% for February. The targets were set using RTO-aggregate outage data from the 2007/08 delivery year through last year.
The Planning Committee is set to vote on the FPR and IRM in October, after which the MRC and MC would review and vote on the proposal in the following month. The Board of Managers would consider granting final approval in December.
PJM Staff Seek Removal of CT Exception on Load Signaling
PJM staff gave a first read of a proposal to remove an exception that guarantees combustion turbines recover the costs of their actual generation, regardless of their load signal. Lisa Morelli, director of market settlements initiatives, said the rule is a vestigial holdover from when CTs provided a fairly invariable supply of power.
Advancements in turbine technology have given CTs a dispatchable range in their output, but PJM rules have not evolved alongside that, she said. While other generators are compensated for the lesser of either their actual generation or the amount they’re dispatched to provide, CTs currently can remain at their maximum generation and be fully compensated.
Removing the rule, which is codified by a single sentence in Manual 28, would subject CTs to the deviation charges other generators face for straying from their dispatch signal. Morelli said simulations show that uplift payments to CTs were about $1.3 million lower when recalculated without the exception over the eight highest CT uplift days in summer 2021, a 10% drop.
Streamlining Internal NITS Process Under Consideration
The MRC reviewed a set of suggested revisions to PJM’s internal network integration transmission service (NITS) process, which is aimed at streamlining the administrative process for transmission within the RTO’s network. Currently new agreements follow the same process as external, or cross-border, transmission agreements. (See “Issue Charge OK’d on Internal NITS Process,” PJM Operating Committee Briefs: July 14, 2022.)
The proposal would transition internal transmission to an “evergreen” model and remove the expiration dates and rollover notification requirement. The committee will be asked to endorse the package at its next meeting in October.
DR Proposal Brought Before MRC After MIC Rejection
A modified issue charge proposal from CPower, a curtailment service provider, to evaluate the use of statistical sampling for interval-metered residential customers came before the MRC after a similar initiative narrowly failed at the MIC on Sept. 7. Anders said CPower has the right to bring the package to the committee even after the MIC rejection, akin to an appeals process. (See “DR Data Proposal Rejected,” PJM Market Implementation Committee Briefs: Sept. 7, 2022.)
Stakeholders remained mixed discussing the first read, with some preferring that states take the lead on expanding demand response to residential customers and expressing concerns about utilizing statistical sampling instead of collecting data from households directly.
Bowring said that the proposal avoids the real issue of access to the meter data, which are essential to measure the actual impacts of DR.
E-Cubed’s Sotkiewicz said allowing DR to rely on sampling rather than interval meter data would treat one sector unfairly and discriminatorily, given the costs generators face in metering.
Sharon Midgley of Exelon said she was disappointed to see the initiative fail at the MIC and believes that the issue charge had been improved coming into the MRC.
The MRC is set to have its own vote on the proposal at its October meeting.
Issue Charge on Supplying PJM and IMM with Copies of FERC Filings
PJM Associate General Counsel Steven Pincus presented an issue charge to explore requiring members to provide copies of certain FERC filings to the RTO and Monitor.
The first read received a lukewarm response from stakeholders, who said all parties should do their own due diligence. Responding to Pincus’ assertion that he didn’t want the ask to become a “compliance trap,” they questioned the logic behind a requirement without consequences.
Members Committee
Board Member with Clean Energy Expertise
The Members Committee discussed amending PJM’s Operating Agreement to require that at least one of the nine members of the Board of Managers “have expertise and experience in the development, integration, operation or management of clean energy resources.”
Outlining the proposal, Albert Pollard, of the Illinois Citizens Utility Board, said that having leadership experienced in green energy could be helpful toward PJM’s clean energy commitments outlined in its strategic plan, goals shared by many utilities and stakeholders as well.
“It does say in a broader way that there’s a dedication to getting this right,” he said.
Pollard
noted that multiple serving board members already meet the qualification, meaning that no changes to the existing composition would be needed should the language be adopted.
PJM CEO Manu Asthana and General Counsel Chris O’Hara responded to stakeholder questions about how the requirement would be implemented, saying it would function as a qualification, rather than a dedicated board seat. So long as a seated member filled the qualification, it would not preclude an otherwise qualified candidate from being appointed, they said.
Sotkiewicz said he believes that requiring representation from one small subset of one sector of stakeholders would call into question the board’s independence.
