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November 1, 2024

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Checking in on Clean Energy at the Massachusetts Legislature

As Massachusetts’ 2023 legislative session heats up, the state is looking to use its new Democratic trifecta to build on two omnibus climate bills signed in 2021 and 2022.

Top legislators and policy makers have highlighted expediting clean energy permitting and siting processes, boosting clean energy infrastructure, reducing electric rates, decarbonizing the gas distribution network and addressing issues related to the role of competitive residential electric suppliers as some of the top priorities for 2023.

Rep. Jeff Roy, co-chair of the joint House and Senate Telecommunications, Utilities, and Energy (TUE) Committee, told RTO Insider that reducing the time it takes to bring clean energy projects online is a major goal of this legislative session.

“Right now, for somebody to get a permit to build some infrastructure, they have to go to a state agency, then they have to go to a local agency, a conservation commission, a planning board, design review, any number of bodies that are out there, to jump-start the process,” Roy said.

The TUE Committee played a major role in passing wide-ranging climate bills in the past two years but has faced a recent divide between the House and Senate representation in the Committee over the balance of power between the two branches. The House and Senate members of the Committee have been holding separate legislative hearings.

Lawmakers say they remain focused on crafting policy. Asked whether the divide will hinder the Committee’s ability to legislate this session, Roy responded “absolutely not.”

Sen. Mike Barrett, the Senate TUE co-chair, echoed Roy’s interest in expediting the grid infrastructure permitting processes in the state but expressed his desire for more information on the specific obstacles holding up clean energy projects.

“I’m wary of bills that try blunt-force approaches, and there are many of them,” Barrett said. “These bills purport to reform the process simply by imposing time deadlines. They don’t otherwise display any particular understanding of the underlying nuances and they’re not deregulatory in the sense that they pinpoint a cause of delay and remove it.”

In April of this year, Gov. Maura Healey’s administration created a state Commission on Clean Energy Infrastructure Siting and Permitting, tasking it with drafting recommendations by the end of this year on administrative, regulatory and legislative changes needed to speed up permitting and siting processes.

Roy also has filed a bill to create an electric infrastructure permitting office, which would work to expedite the permitting process for electric utility projects necessary to enabling decarbonization. The office would issue consolidated permits to cover all state and local authorizations required to build and operate electric infrastructure and would be required to make a final decision on applications within seven months of application.

“What we’re trying to do,” Roy said, “is move the community input back to the beginning of the process, give folks an idea of what they’re trying to do and how it’s going to help them, and then streamline the permitting process, so it runs parallel. So, you’re doing your local permitting in parallel with your state permitting, and you can shorten the length of time the process takes.”

He noted the massive increase in infrastructure that will be necessary simply to enable electric vehicle owners to reliably charge their vehicles in the state, citing a 2022 study conducted by National Grid which found that a significant number of highway charging locations will require as much or more electricity than a typical sports stadium.

While state lawmakers look to streamline project approvals, representatives from several municipalities and environmental organizations — including the City of Boston, Gas Transition Allies and 350 Mass — are pushing to increase access to Department of Public Utilities (DPU) adjudicatory proceedings, supporting a bill that would require the DPU to allow municipalities, state legislators, relevant non-profits and groups of more than 10 ratepayers to participate as full parties in DPU proceedings.

Cathy Kristofferson of the Pipeline Awareness Network of the Northeast testified to the TUE committee that her organization has repeatedly been denied full-party status by the DPU, despite receiving such status in New Hampshire.

“We have stopped trying,” Kristofferson said, adding that the DPU has consistently denied full-party status to other non-industry organizations like the Conservation Law Foundation and the Sierra Club.

National Grid opposed this bill in written testimony submitted to the TUE Committee, saying that the result of the legislation would be that “the siting of energy facilities would become more difficult, more contentious, more political and possibly more frequently appealed.”

The Future of Competitive Electric Supply

Another major focus of the legislative session has been the role of competitive electricity suppliers in the state. A report released earlier this year by the Massachusetts Office of the Attorney General found that competitive suppliers cost residents of the state over $500 million between 2015 and 2021, compared to the cost of the default supply service.

House Bill 3196 and Senate Bill 2106 would move to ultimately ban competitive residential electricity suppliers in the state, and are supported by the Healey Administration, the attorney general’s office and the City of Boston.

“It is egregious that we allow this industry to continue to harm and prey upon people that are really struggling,” said Attorney General Andrea Campbell. The attorney general’s office’s recent report on competitive suppliers found low-income customers and residents of color to be disproportionately affected by these added costs.

Campbell said enforcing existing regulations and targeting individual predatory suppliers is extremely time- and resource-intensive and is a distraction for the office’s other priorities.

“We don’t take it lightly to ban an entire industry,” Campbell said. “They have chosen not to follow regulations, and when we try to go after them it is very difficult … some go out of business, enter bankruptcy, so we can’t even get those resources back to offer the restitution to these consumers that they deserve and are entitled to.”

Barrett indicated he’s open to eliminating competitive electric suppliers in the state, while highlighting the need to reform the default utility service.

In contrast, Roy said he would prefer to pursue reforms instead of an outright ban.

“Truthfully, I’m not a fan of putting the competitive suppliers out of business because of a few bad apples that are out there,” Roy said, calling for more oversight and policing from the attorney general’s office and DPU.

“I think the good players in this space have a lot to offer,” Roy said.

Gas System Emissions and the Role of Public Power

“In general, I’d like to move some costs off of consumers’ monthly electric bills that more properly belong on their monthly gas bills,” Sen. Mike Barrett told RTO Insider.

Barrett said the state needs to move away from its reliance on natural gas to meet its emissions goals, adding that by shifting some costs from electric rates to gas rates, the state could provide an economic incentive for the adoption of electrified heating systems.

“I’ve felt for a long time that natural gas prices are unduly low, because of course we don’t have a price on carbon,” Barrett said. “Getting the price of natural gas right would mean accounting for all the pollution impacts for which it’s responsible.”

Roy agreed with the need to transition away from natural gas but said reducing the state’s dependence on the fuel will be an extended process, and that the safety of the gas system needs to be a priority.

“We’re going to have to transition, obviously, away from fossil fuels, but that’s going to take some time,” Roy said. “How we do that? I want to look at the possibility of using some blended fuels that will lower the emissions in the meantime. And I do believe we need to replace any piping that is dangerous and is hazardous to human life and property.”

Concerning who is allowed to build and operate gas system alternatives like networked geothermal, Barrett said he wants to ensure that utilities are not given another monopoly in the state.

“There’s no reason why networked geothermal should not be public power, much as a municipal light department represents public power,” Barrett said. “Public power always needs to be part of the conversation.”

Featuring an even more expansive view on the role of public power, House Bill 3679, introduced by Rep. Mike Connolly, would create a task force to study the potential for a public takeover of the state’s investor-owned utilities, echoing the ongoing push for consumer-owned electric utilities in Maine (See Maine Voters to Decide on Upending Utility Landscape in 2023.)

“With the man-made climate disaster looming over the future of our planet, we must reorient each and every sector of our economy toward sustainability and equity,” Connolly wrote in his testimony supporting the bill. “We can’t do that effectively or quickly enough with corporate entities such as National Grid and Eversource extracting profits from our electric and gas utility customers and exerting their influence over policy decisions. With this legislation, we wish to start a process for considering how we can pursue new models of public ownership, where consumers, utility workers, and our environment are all given the ultimate priority.”

Concerning such an expansive public takeover of the state’s gas and electric utilities, Barrett expressed concern about the amount of money that likely would be spent by the utility industry in opposition to any serious effort to bring utilities under public ownership.

In Maine, a 2023 ballot measure to initiate a consumer takeover of the state’s electric utilities has been meet with millions of dollars in opposition funding. Avangrid — the parent company of Central Maine Power — has spent over $13 million as the main funder of a group called Maine Affordable Energy, founded in opposition to the ballot measure.

The Massachusetts legislative session extends until Nov. 4, and the TUE Committee has hearings scheduled through late September. As recent climate bills in the state have come together late in the session, discussions over new climate, utility and energy legislation could extend well through the fall.

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ACORE Report Highlights Billions of Dollars in PJM’s Generator Queue

Billions of dollars and thousands of jobs are tied up in PJM’s generator interconnection queue, which could be unlocked if the RTO efficiently reformed it, the American Council on Renewable Energy said in a report released Wednesday.

The report, “Power Up PJM,” found that moving forward with just the changes already approved by FERC could lead to $33 billion in investment and 199,000 job-years, defined by ACORE as the full-time equivalent of one job for one year. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

If PJM had proactively developed sufficient transmission capacity as well as enacting the revisions, it could have enabled another 100,000 job-years and $17 billion in additional capital investments in the next four years, according to the report.

PJM is just starting to implement the changes, which will move its queue from a first-come, first-served serial process to a first-ready, first-served cluster study approach, said Noah Strand, ACORE policy associate and a co-author of the report.

“Under this first-come, first-served approach, each project withdrawal would prompt a restudy of the preceding applications without the departing project in the model,” Strand said on a web conference with reporters.

That worked when the queue was mainly hooking up new natural gas plants located relatively close to load, but now it needs to connect many more renewable projects that are often farther away from load — meaning they face higher interconnection costs, as transmission planning does not account for future generation.

“Data has shown that renewables pay disproportionately high upgrade costs relative to conventional fuels such as natural gas,” Strand said. “And those costs have multiplied in recent years, sometimes enough to exceed the costs of building the projects themselves.”

Often developers do not find out how much they will have to pay for upgrades until late in the process, which can kill off otherwise commercially viable projects, he added.

As of March, the queue had grown to more than 2,600 projects totaling 260 GW; about 85% of those were renewables — enough to replace all the generation in the RTO, Strand said.

The queue data in ACORE’s report does not reflect offshore wind because of the use of FERC Order 1000’s State Agreement Approach, which has been used by New Jersey and is likely to be picked up by Maryland, Strand said. (See NJ BPU Backs Plan for 2nd Grid Upgrade Process with PJM.)

Based on how much is in the queue and the historic completion rates of planned projects, a reasonable estimate is that PJM will add about 34 GW of new renewables as it implements the approved changes in the next few years, Strand said.

“We don’t expect that 100% of the renewable projects in PJM’s queue will be completed, but our report holds that the development of new transmission is key to increasing the number that do get built, namely if PJM opts for the large-scale, high-voltage lines that are most needed,” Strand said.

Getting that long-range transmission built would require additional changes to PJM’s process, which are the subject of a pending Notice of Proposed Rulemaking at FERC. (See FERC Issues First Proposal out of Transmission Proceeding.)

But getting the needed transmission buildout will require more than FERC action, with the American Clean Power Association’s Brendan Casey saying congressional action is required.

“I think permitting reform is essential, especially when we talk about long-range transmission,” Casey said. “Some of these projects are taking 10 to 20 years from inception to start construction, and it’s just not sustainable.”

Getting transmission built out to meet some state policies in an RTO as diverse as PJM will be tricky, with 13 states that have varying levels of commitment to combating climate change. But several speakers on the webinar argued that the economic benefits highlighted in ACORE’s queue report are enough to entice any state to build out transmission.

“The projects waiting in PJM’s queue have economic benefits to offer all states and all communities where they’re being developed, red or blue. That’s one piece,” the Rocky Mountain Institute’s Katie Siegner said. “And the electricity cost benefits of these increasingly affordable new generation sources is another piece that should incentivize a bunch of different stakeholders across party lines and across different states to come together to figure out transmission planning.”

A PJM spokesman responded that the RTO “reformed its interconnection queue process with stakeholder approval in record time” and will implement the new rules on July 10.

While the RTO has a large queue, it also noted 44,000 MW of resources, which are mostly renewables, have already cleared the study process, but have yet to be built. Those projects are running into delays elsewhere such as the supply chain, financing, siting or other regulatory issues. “The queue is really not the current issue,” PJM said.

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Under the Dome: ERCOT Sets Peak Demand Marks

ERCOT set demand records three times Tuesday as demand soared above 80 GW during a sweltering heat wave, breaking a record set last July.

The first mark came during the hour ending at 4 p.m. CT, when ERCOT met an average demand of 80.25 GW. Demand averaged 80.79 and 80.83 GW during the next two hours. All three marks, which are not official, would break the record of 80.15 GW.

The record would likely be short-lived. ERCOT is expecting demand to peak above 81 GW from Wednesday through Friday.

The Texas grid operator came within 5 MW of the 2022 record Monday. Preliminary data indicate demand averaged 80.144 GW and 80.137 GW during the hours ending at 5 p.m. and 6 p.m., respectively.

“It’s a hellacious week, even by Texas standards,” Stoic Energy’s Doug Lewin wrote in his most recent Texas Energy and Power Newsletter.

The culprit is a heat dome, or high-pressure system, that has been sitting over much of Texas for more than a week now. Meteorologists expect the system to punish Texas for at least another week.

Temperatures are expected to peak Wednesday, with a high of 107 degrees Fahrenheit in Dallas. The heat index could reach as much as 112 F in the city.

Space City Weather’s Matt Lanza expects heat index values of 110 to 115 F and said wet-bulb globe temperatures, a measure of heat stress in direct sunlight, will be in the human body’s “extreme” level.

“Whatever index you use, it will feel terribly hot all week,” he said.

Texas has been under excessive heat warnings since last week, as have parts of New Mexico and the Gulf Coast. Heat advisories are in place from northern Florida to southern New Mexico, affecting more than 46 million people, according to the National Integrated Heat Health Information System.

With the heat dome creating clear skies over much of the state, solar resources again nearly met their summer capacity expectation of 12.6 GW. Wind overperformed Tuesday afternoon, producing more than 17 GW of energy and combining with solar to account for more than a third of ERCOT’s fuel mix. Wind resources have a 10.4-GW summer capacity.

The grid operator set a record for solar production on June 24 at 13.08 GW. It also set a high for weekend peak demand Sunday at 78.97 GW; ERCOT recorded nearly three dozen demand marks last year.

ERCOT issued its second weather watch of the year for Sunday through Friday, urging Texans to monitor grid conditions and be prepared to reduce energy use during high-demand periods. It also asked for voluntary conservation measures for four hours on June 20 because of the extreme heat and its forecasted demand. (See “New Grid Notifications Added,” ERCOT Monitor Recommends New Market Design in Report.)

Prices were settling no higher than $44/MWh on Tuesday afternoon.

ERCOT did not respond to a request for comment.

SPP Extends Resource Advisory

The extreme heat also forced SPP to extend a previously issued resource advisory for its entire 14-state balancing authority footprint in the Eastern Interconnection because of expected higher-than-normal generation outages, high demand and uncertain wind forecasts.

The advisory went into effect at midnight CT on Monday, lasting through midnight Saturday. The advisory does not require public conservation but was issued to raise awareness among generators and transmission providers of potential threats to reliability.

The National Weather Service has forecasted triple-digit temperatures in Oklahoma on Wednesday. It said the heat will expand north in Kansas and Missouri and does not expect relief before the Independence Day holiday.

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Calif. Governor, Lawmakers Agree on Infrastructure Bills

California Gov. Gavin Newsom and legislative leaders reached an agreement Monday on most parts of Newsom’s package of infrastructure bills intended to hasten clean energy development and improve grid reliability.

“We are accelerating our global leadership on climate by fast-tracking the clean energy projects that will create cleaner air for generations to come,” Newsom said in a joint statement with Senate President pro tempore Toni Atkins and Assembly Speaker Anthony Rendon announcing the deal.

The bills they agreed on include Senate Bill 149, which would streamline judicial review of certain clean energy and transportation projects by requiring that challenges to the projects under the California Environmental Quality Act (CEQA) be resolved by the courts within 270 days, including lawsuits and appeals. (See Newsom Stresses Role of Permitting in Calif. Energy Transition.)

Some environmental groups strongly opposed weakening CEQA protections.

The compromise between Newsom and lawmakers exempted from the streamlining provisions a highly controversial proposal to convey water from Northern to Southern California via a tunnel under the Sacramento-San Joaquin Delta.

Another measure, Assembly Bill 122, would allow but mitigate the removal of western Joshua trees, iconic California desert plants the state Fish and Game Commission is considering listing under the California Endangered Species Act but that occupy large swath of land slated for utility-scale solar arrays and battery storage.

Other measures include:

    • AB 124, which would authorize the California Infrastructure and Economic Development Bank and the state Department of Water Resources to use funding from the federal Inflation Reduction Act to finance projects that reduce greenhouse gas emissions.
    • AB 126, which would extend funding for the state’s Clean Transportation Program and the Air Quality Management Program through Department of Motor Vehicle fees and require an annual funding allocation of 10% for hydrogen refueling stations from the Clean Transportation Program through 2030 or until a sufficient network of refueling stations exist.
    • SB 147, which would allow the incidental taking of species that are fully protected under the state Endangered Species Act during the construction of infrastructure projects and declassify the peregrine falcon, brown pelican and thicktail chub, a small fish, from the law’s list of fully protected species.

The agreement on the infrastructure bills was part of a larger negotiation between Newsom and lawmakers on the fiscal year 2023/24 budget.

In his budget plan released in January, Newsom proposed slashing $6 billion from the state’s $54.3 billion climate commitment because of this year’s tax revenue shortfall. (See Calif. Governor Proposes $6B in Climate Budget Cuts.)

Lawmakers wanted much of the climate funding restored. The two sides agreed to keep $51.4 billion of the commitment in the budget, reducing it by $2.9 billion.

Newsom had until 11:59 p.m. Tuesday to sign, veto or make line-item revisions to the bills containing the Legislature’s budget plan.

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NYISO to Comment on State’s Cap-and-invest Plan

RENSSELAER, N.Y. — NYISO on Tuesday said it will file comments for New York state to consider as it plans its cap-and-invest program, addressing issues such as allowances and leakage.

Mike DeSocio, director of market design at NYISO, told stakeholders at a meeting of the Installed Capacity Working Group and Market Issues Working Group that the ISO “supports placing a price on carbon emissions and thinks that it is very compatible with the competitive wholesale markets New York has benefited from over the last two decades.”

But, he added, “we are very concerned about reliability and want to reinforce that any program should envision times where there may be a need to run generation to support keeping the lights on that have run out of allowances.”

The cap-and-invest program would auction emission allowances to obligated sources, such as large-scale greenhouse gas producers, and nonobligated entities, such as agricultural or forestry industries. Nonobligated sources would see their allowances retired by the state, while obligated sources would need to purchase allowances to continue emitting. Money obtained from these auctions would go into a climate action fund, with much of it set aside for disadvantaged communities (DACs). (See NY Climate Justice Panel Sets Disadvantaged Community Criteria.)

“The program should be designed in a way where a generator does not need to make a decision or choice between running to keep the lights on or complying with an allowance,” DeSocio said.

The ISO will also comment on how to best address leakage, as well as inform agencies that however they plan to tackle the issue, NYISO will need plenty of time to develop software compliant with the new regulations.

NYISO will also share its support for the creation of an independent monitor, who is able to oversee the state’s policy.

“We’re treating this as an opening for us to offer our experience and help New York shape the cap-and-invest program,” DeSocio said. The ISO will happily provide guidance on any topic, but it would be helpful for agencies to give more insight into the program’s time frame, he said.

Chris Wentlent, chair of the New York State Reliability Council’s Executive Committee, asked whether NYISO plans to comment on having separate trade requirements for different DACs, and on the intent to initially have no offsets for generators.

DeSocio responded that NYISO did not plan to comment on either topic, but “both are important pieces for the state to consider, especially considering other requirements established by the [Climate Leadership and Community Protection Act], but this is not something the ISO will weigh itself into.”

The state’s Department of Environmental Conservation and the New York State Energy Research and Development Authority recently ended a series of webinars dedicated to explaining the cap-and-invest policy and identifying where public input could be most helpful to regulatory decision-making. (See NY Starts Public Review of Cap-and-invest Plans.)

The DEC and NYSERDA plan to have two rounds of pre-proposal outreach and ask that initial comments be submitted no later than July 1. Comments can be sent either online or mailed to the DEC’s Division of Air Resources.

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NJ Building Decarb Plan Garners Support, Criticism

New Jersey’s three-year, $150 million program to promote energy efficiency and building decarbonization incentive programs should be bigger and bolder to achieve the state’s ambitious clean energy goals, several speakers said at two public hearings last week.

Yet the proposal also ran into criticism from fossil fuel supporters and others who said the plan focused too much on transforming the state to make electricity the dominant — perhaps only — fuel used for building heat and hot water systems, and they questioned whether the plans would secure enough public support to achieve the goal.

The two online hearings, in the afternoon and evening of June 20, drew more than a dozen speakers and provided the first display of public, environmentalist and industry response to the straw proposal, known as Triennium 2, which aims to provide a strategy for reducing emissions through energy efficiency and shifting the state to increased electricity use. The Board of Public Utilities plans to have the completed program in place in July.

The three-part plan, which follows a similar three-year strategy enacted in 2020, sets out general goals and incentive mechanisms and details demand response proposals. A third part of the proposal outlines a series of possible building decarbonization (BD) startup programs that target single and multifamily residential buildings, as well as commercial buildings, an already contentious issue in the state and one that provoked some of the most vigorous discussion at the hearings. (See NJ BPU Outlines $150M Building Decarbonization Plan.)

Eric Miller, New Jersey energy policy director at the Natural Resources Defense Council (NRDC), said at the hearing that the demand response and building decarbonization plans “are critical in meeting our climate targets while lowering customer bills, and providing more options for how customers interact with the grid to cool and heat their homes.”

Still, he added, “we are concerned with the straw proposal placing a $50 million-a-year program budget.” The NRDC “has concerns that it’s insufficient to meet the scale required to hit the targets” set out by Gov. Phil Murphy in a recent executive order, he said. The order set a goal of electrifying 400,000 additional dwelling units and 20,000 commercial or public buildings by December 2030.

Susanna Chiu, senior director of operational services for PSE&G, said that although the utility “generally agrees” with the building decarbonization guidelines, which place much of the responsibility for implementing the strategy on utility run programs, the company has reservations about the size.

“We feel that the $50 million-per-year proposal for the second Triennium is not enough to make an impact,” especially if the BPU expects to meet Murphy’s building decarbonization goals, she said.

“Huge Burden”

The Triennium 2 proposal is the state’s latest initiative seeking to cut building emissions, which account for 17% of the state’s greenhouse gases, following the governor’s executive order and the creation of a Clean Buildings Working Group to study the issue. Business and fossil fuel interests have pushed back on the effort, and in January, the New Jersey Department of Environmental Protection held off enacting a rule that would have banned the installation of new commercial-size fossil fuel boilers after Jan. 1, 2025, after protests from business and fuel groups. (See NJ Backs off Ban on Commercial-size Fossil Fuel Boilers.)

Opponents say switching to electricity will be extremely expensive, and they decry the use of a “mandate” to require the switch. But state officials say they instead will implement the switch from fossil fuel to electricity by offering consumers and property owners incentives and public education on the benefits of electric appliances.

Steven S. Goldenberg, representing the New Jersey Large Energy Users Coalition, said at the first hearing that the proposed budget, when coupled with the state’s other clean energy initiatives in the state Energy Masterplan, is a “huge burden on ratepayers.”

He questioned the effectiveness of offering subsidies to encourage property owners to switch from fossil fuels, and cited insights gathered when he worked on a clean energy study for then-Gov. Chris Christie.

“I still recall very clearly their consistent testimony that it’s very difficult to incent people to upgrade their equipment if their current equipment was operable,” he said. “So that if someone had an operating furnace, even though it may be low efficiency and a nice offer is made to upgrade it to a more efficient unit, those offers were being rejected.”

Anne-Marie Peracchio, managing director marketing and energy efficiency at New Jersey Natural Gas, said the utility was the only one in the state “that had an electrification pilot approved.” She noted that “at the halfway point of this triennial, there was only one reported participant.”

Peracchio urged the BPU to consider including “low- and zero-carbon fuels like clean hydrogen and renewable natural gas” in the straw proposal.

“It is critical that the state policy does not limit broader opportunities for cost-effective decarbonization by placing an over-reliance on electrification when that is just one of the available strategies to building decarbonization,” she said.

Heat Pump Incentives

Andrew McNally, a lobbyist for South Jersey Industries, which represents two gas companies among other businesses, said electrification is no easy task. He said he expected electricity rates to increase as demand grew, and urged the BPU to “maintain its focus on affordability,” because the cost increases will affect low- and moderate-income households the most.

In addition, he said, “electrification stands to increase overall emissions” because the increase in demand will force the state to use power that is not generated by clean energy sources.

“Our current electric generation mix continues to rely on fossil in substantial part,” he said. “Until the state realizes its emissions-free generation goals, or at least makes substantial progress towards it, increased reliance on electricity will produce more carbon emissions.”

But Allison McLeod, policy director for the New Jersey League of Conservation Voters, urged the BPU focus on encouraging people to switch from delivered fuels, such as oil, and natural gas, to electrification, and not to provide support for people interested in switching from delivered fuels to natural gas even if it reduces emissions.

“We would not support incentivizing or installing fossil fuel equipment as part of the straw proposal,” she said. “The building decarbonization efforts should focus exactly on that — decarbonization — not committing our state to additional fossil fuel infrastructure.”

Representatives of two geothermal heat pump companies, Dandelion Energy of Mount Kisco, N.Y., and Princeton Air Conditioning of central New Jersey, urged the BPU to emphasize the use of the appliances more, saying they are efficient and can be cost effective.

Heather Deese, director of policy and regulatory affairs at Dandelion Energy, said the widespread installation of pumps in other states has shown how to shape an effective building decarbonization program.

“The overall framing around a three-year program of ‘try and then scale’ is too cautious,” she said. “The focus of the building decarbonization plan in New Jersey should be on quickly establishing and scaling programs. We really don’t have time for a wait-and-see approach.”

The program should prioritize switching customers from natural gas to electric heat pumps, she said, noting that the 15- to 20-year life of a gas furnace means 5 to 7% of natural gas-heated homes would replace their existing furnaces every year.

“We also recommend that the BD program should direct the utilities and state-run programs to include ground-source heat-pump rebates alongside air-source heat-pump rebates as a core part” of the state’s building decarbonization and energy efficiency programs, she said.

Deese and Scott Needham, president of Princeton Air Conditioning, each noted that New York has a program that provides incentives for the installation of heat pumps, and a tax credit benefit as well.

“It’s amazing how little mention in the state of New Jersey geothermal heat-pump systems get,” Needham said.

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Maine Gov. Vetoes OSW Bill Over Labor Requirements

Maine Gov. Janet Mills on Monday vetoed legislation to streamline the permitting of ports to serve the offshore wind industry she and many others hope to develop in the Gulf of Maine.

Mills herself had originally proposed the bill to standardize evaluation of offshore wind port proposals and dubbed it “An Act to Modify the Visual Impact Standards for Offshore Wind Port Development.” (LD 1847.)

The Legislature amended it to include several progressive priorities, including requirements for project labor agreements for building the port and then for work done there; labor peace agreements; workforce diversity and equity plans; just transition and workforce development plans; and the use wherever possible of zero-emissions port equipment and technology.

They aptly renamed the amended measure “An Act to Modify the Visual Impact Standards for Offshore Wind Port Development and Establish Labor Standards for Wind Power Projects.”

Mills objected to the labor provisions of the Legislature’s amended bill. Last week she asked legislators to remove the language or to add additional language that would ensure employee-owned business and small businesses would benefit as well as union workers. They did not.

In her veto message Monday, she told legislators:

“Harnessing the benefits of offshore wind will require an ‘all-hands-on-deck’ approach that includes unions, small businesses and existing employee-owned and other Maine companies. Without that approach, Maine will be at a disadvantage compared to other New England states. It is imperative that investment in offshore wind facilities and projects foster opportunities for Maine’s workforce and construction companies to compete on a level playing field for this work.”

Mills said in the veto message that she wanted to work with the Legislature on LD 1847 and on LD 1895, another offshore wind measure that contains provisions unacceptable to her. She said she sees some willingness to do this among the measures’ sponsors.

In the June 21 letter to the sponsors, Mills said she recognizes “the value of PLAs, or collective bargaining agreements, as a tool to lift up working men and women by ensuring that they are paid strong wages with good benefits.”

But she had three specific objections to requiring them in this instance:

    • More than 90% of Maine’s construction workers are non-union.
    • Construction costs are soaring, and a PLA would further increase prices that ultimately would be borne by Maine ratepayers.
    • No other New England state imposes a statutory requirement for PLAs on offshore wind projects. Rather, state and federal regulations and solicitations typically “encourage” PLAs, which she would not object to.

Organized labor was not happy with Mills’ position.

“You can’t create the jobs of tomorrow with yesterday’s wages & labor standards,” tweeted the Maine AFL-CIO, which endorsed Mills for re-election in 2022.

Executive Director Matt Schlobohm said in a Facebook post: “Maine’s climate motto has been ‘Maine Won’t Wait.’ With this veto, Gov. Mills is saying, ‘Maine Will Wait’ — for thousands of good jobs, for clean energy & for the build out of a new industry. We will wait because the Governor is opposed to fair labor standards which are the industry norm.”

Mills is a Democrat, as are the majorities of both houses of the Legislature, and organized labor is a core constituency of the Democratic Party.

As President Biden signed the landmark Inflation Reduction Act of 2022 — enacting a welter of transformational clean-energy tax credits and subsidies — the White House emphasized that it would create good-paying union jobs nationwide by incentivizing prevailing wage agreements and apprenticeship programs.

Maine’s Situation

The U.S. Bureau of Labor Statistics reports that 9.2% of workers in Maine were union members in 2022, compared with 10.1% nationwide.

The percentage is much higher in other Northeast states that are trying to build an offshore wind industry: 12.7% in Massachusetts, 14.2% in Connecticut, 14.9% in New Jersey, 16.1% in Rhode Island and 20.7% in New York, the second highest in the nation.

Maine has some obstacles to its offshore wind ambitions that the other states do not.

For starters, the other states are developing wind power with turbines whose foundations are fixed to the ocean floor, a model used for decades worldwide. The Gulf of Maine is too deep for this — any turbine array there will need to float, and floating technology is still in its early stages, with limited commercial build-out as research and development continue.

But Maine is seeking a lease from the U.S. Bureau of Ocean Energy Management to site a floating research array generating up to 144 MW, and the University of Maine has a long-running effort to position itself as a center of U.S. floating wind research.

There also is the question of where to put the ports that would (or would not) need to employ union labor. As in other states, there is strong local opposition to industrializing the coast and ocean, which along with forests are central to Maine’s identity.

But most of Maine’s long, rocky coast is unsuitable to be a homeport for hulking installation vessels.

Sears Island on the central coast has emerged as a candidate. It is one of the largest accessible undeveloped islands on the Eastern Seaboard, and over the past few decades, one proposal after another — nuclear reactor, LNG terminal, coal power plant, oil refinery, container port — has died in the face of local opposition.

There is an Irving oil terminal a few hundred yards away on the mainland, but aside from that it remains a wooded nature preserve in a region dotted with quaint villages and small harbors. Advocates want to keep it that way.

At a meeting of the Maine Offshore Wind Port Advisory Group on Monday, multiple speakers voiced opposition to the concept of building a port there, some vowing a fight if one was proposed.

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MISO Operators Helm Uneventful May

May in MISO proved no trouble for control room operators.

MISO averaged 70 GW of average systemwide load, lower than 2022’s 73 GW average. The footprint registered a 102-GW monthly peak on May 31. Operators also noted a 2.8 GW all-time solar peak on May 25, when panels supplied 4.3% of system load at midday.

Real-time locational marginal prices dropped by nearly two-thirds from last May, at $26/MWh, with natural gas prices sliding from about $8/MMBtu to around $2/MMBtu year-over-year. Natural gas generation supplied 42% of the energy mix; coal accounted for 24%, while wind generation and nuclear took a 16% and 14% share, respectively.

MISO recorded an average 55 GW of daily generation outages in May, on par with the same time last year and in 2021.

Meanwhile, MISO has declared its first capacity advisories and conservative operations instructions of the summer. It preemptively issued a capacity advisory for June 29 until further notice due to extreme heat indexes in the region. Parts of Louisiana are expected to reach triple-digit heat indexes through the weekend.

The grid operator called conservative operations, a capacity advisory and a hot weather alert for MISO South June 26 as the region weathered the continued heatwave. The short-lived warnings were issued and terminated a few hours later in the afternoon.

Earlier, MISO declared conservative operations for northern portions of its footprint on June 22 and 23 due to higher-than-anticipated load and heavy transfers.

MISO is forecasting summer heat to be front-loaded in June. (See MISO: Little Firm Capacity to Spare This Summer.)

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Clean Hydrogen and Renewable Energy Feud over Tax Credit Rules

Low-carbon hydrogen production and cleaner electric generation are the goals of a global effort led by governments and corporations trying to slow climate change by drastically reducing carbon dioxide emissions within the decade.

But the two goals appear to be at odds, in a collision involving environmentalists and technology trade groups battling over how much clean electricity can be diverted from the grid to produce hundreds of millions of tons of hydrogen annually.

At least half a dozen groups filed comments months ago with the U.S. departments of Energy and the Treasury to influence the creation of the rules that the IRS will use to determine the size of the production tax credits authorized by the Inflation Reduction Act for hydrogen production as well new renewable energy projects. Renewable energy producers are expecting at least a preliminary announcement on the rules later this summer.

The IRA authorizes a tax credit of 2.75 cents/kWh generated and up to $3/kg of hydrogen produced for the first 10 years of operation. The legislation also extends the 30% investment tax credit for at least two years.

The collision of interests between the renewable energy industry and fledgling hydrogen producers is in the details, including:

    • Whether existing wind and solar installations can divert their output from the grid to new power-hungry electrolyzers — possibly forcing more dirty power on the grid to make up for the diversion — or whether only newly built wind and solar generation can be used if the hydrogen producers want a tax credit;
    • Whether electrolyzer companies relying on grid power must purchase additional renewable power by buying renewable energy credits (RECs) and in the same region, or will be allowed to perform the “true-up” annually by purchasing additional power for anywhere on the grid; and
    • Whether electrolyzer companies should operate off the grid, producing hydrogen only when dedicated wind and solar power is available, or extend operations by also building on-site energy storage — options that potential hydrogen producers say will stunt the growth of the new industry.

The American Clean Power Association (ACP) issued a “Green Hydrogen Framework” last week distilling the conflicting issues and proposing a consensus resolution it said its 750 members would be able to endorse if DOE and the IRS adopt them.

The proposed compromise focuses on future hydrogen producers relying on grid power and would enable electrolyzer companies to buy power from existing wind and solar installations if they “are operational no earlier than 36 months” prior to the electrolyzer beginning production.

In other words, an electrolyzer company buying clean power from an older renewable energy facility would not qualify for IRA tax credits under this plan.

One exception under the ACP proposal: An electrolyzer company could buy from any existing wind and solar plant facing “persistent congestion.”

The ACP plan would also limit renewable energy purchases and credits to the same region in which an electrolyzer is operating.

Arguing that new production of green hydrogen should be continuous, the ACP plan would also phase in the requirement that hydrogen producers should replace renewable energy used by electrolyzer plants being built in 2029 and later years.

Those electrolyzer plants that begin construction before the end of 2028 could true-up the energy accounting requirement annually, according to the plan, an annual accounting rule that would be grandfathered in future years.

“This compromise framework offers a roadmap for effectively balancing the dual priorities of supporting early-market development of green hydrogen with maintaining a rigorous and robust standard for ensuring clean production,” the report argues.

“At present, green hydrogen is objectively not cost competitive with other forms of existing hydrogen production,” the reports notes in a reference to hydrogen split from methane. “Accelerating green hydrogen production through the Inflation Reduction Act’s clean hydrogen tax credits can help propel decarbonization across the economy — an estimated 90-million-ton reduction in carbon emissions each year by 2030.”

“These large emissions reductions are due to the fact that green hydrogen is essential for decarbonizing key sectors of the U.S. economy that are difficult to abate through direct electricity usage — including heavy-duty manufacturing, chemical production and heavy-duty transportation.”

The Fuel Cell & Hydrogen Energy Association criticized the ACP plan as a compromise that will “chill development.”

“The IRA offers a significant opportunity to reduce GHG emissions, decarbonize heavy-energy users and help achieve the Biden administration’s climate, energy security and clean manufacturing goals,” CEO Frank Wolak said. “We are concerned that the positions described by the American Clean Power Association, particularly on additionality, will chill development of the essential first generation of clean-hydrogen facilities. Restricting generators capable of selling environmental credits and leaving nuclear and hydropower out altogether are inconsistent with the broad intent of the IRA.”

The proposed resolution follows the publication of a least seven previous analyses and proposals from other groups, including one from the American Council on Renewable Energy and energy consulting firm Energy and Environmental Economics. (See How Green is that Green Hydrogen.)

For future producers of hydrogen, the debate about how future tax credits are determined is more than academic. (See Plug Power: Would-be ‘Category King’ of $10T Global Hydrogen Market and Air Products Plans $500M Hydrogen Plant in NY.)

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Vistra’s Deal for Energy Harbor Runs into Opposition at FERC

Vistra’s more than $3 billion purchase of Energy Harbor and its nuclear plants ran into opposition at FERC on Friday as consumer advocates in Ohio argued the deal would harm the state’s retail power market (EC23-74).

PJM’s Independent Market Monitor, Monitoring Analytics, did not oppose the merger, but it argued that FERC should condition its approval on behavioral commitments from Vistra so it cannot abuse market power in the RTO’s capacity market and local energy markets.

Vistra proposed buying Energy Harbor, which owns the generation and competitive retail business spun off from FirstEnergy, in March. Vistra plans to combine the three nuclear plants from the deal with its existing clean energy assets and retail businesses in a new subsidiary called “Vistra Vision.” (See Vistra Pays More than $3 Billion for Energy Harbor.)

Ohio restructured its industry in 2001, allowing customers to buy power from competitive retailers, but even those who do not shop benefit from the default standard service offer (SSO) auctions into which Vistra and Energy Harbor have bid their generation in recent years, said the Northeast Ohio Public Energy Council (NOPEC).

“The Ohio SSO market is served by a small — and shrinking — set of suppliers. Over the past five years, the average number of suppliers has dropped from 11 to six,” NOPEC said. “In addition, in recent SSO auctions all (or almost all) registered bidders were selected to provide one or more tranches. This is a sign that these auctions currently have limited alternative suppliers.”

Both have participated in 39 auctions since 2019, with Energy Harbor winning 22% of total supply and Vistra 33%.

“When both Energy Harbor and Dynegy have submitted winning bids in the same auction, their combined shares of the procured tranches range from 35% to as high as 82%,” said NOPEC.

NOPEC is a regional council of local governments that provides electricity aggregation services to their citizens, which represents 68% of the total retail power market of 2.5 million customers — with the rest making individual decisions to shop with specific retailers. Energy Harbor and Vistra each serve about 20% of the state’s government aggregation market, said NOPEC, which is the largest provider of such services with slightly more than their combined share.

“The proposed transaction, and Vistra’s resulting increased share of the governmental aggregation market, follows directly on the heels of efforts by its subsidiary, Dynegy, to attempt to eliminate NOPEC as a competitor,” the group said.

Vistra’s subsidiary Dynegy asked the Public Utilities Commission of Ohio (PUCO) to terminate NOPEC’s certificate to serve as a government aggregator after it returned some customers to utility SSO rather than force them to pay spiking prices. NOPEC noted that Dynegy did the same thing because both were responding rationally to market conditions, while the nonprofit was working to ensure its member communities and their retail customers got the lowest prices possible.

The PUCO threw out Dynegy’s request, saying that NOPEC did nothing wrong in returning some customers to SSO.

The Ohio Consumers’ Counsel also urged FERC to review the measure and its impact on the retail market in Ohio, noting that the commission has agreed to do so when state agencies have limited authority over mergers.

“The potential adverse effects of this merger on retail consumers in Ohio will be significant,” the OCC said. “FERC’s review of both the retail and wholesale impacts of the merger on Ohio consumers is needed so that Ohio consumers can be protected from the adverse effects of this merger.”

Fewer bidders in the SSO auctions will likely raise prices in them, which will have an impact on the offers made by retailers.

“The standard service offer is used by Ohio consumers as the price to compare against the prices offered by marketers, including prices offered by governmental aggregators,” the OCC said. “Thus, higher standard service offer prices would act as a price ‘umbrella,’ allowing for increases in both marketer headroom and likely the prices offered by them. This also could result in higher profits for marketers, to the detriment of consumers.”

Both NOPEC and the OCC argued that the deal would have detrimental effects on PJM’s wholesale markets, as did the Monitor, though the latter argued behavioral constraints were the best way to deal with any such issues.

“The IMM recommends behavioral remedies to address flaws in PJM’s energy market power mitigation rules to ensure that Vistra cannot exercise market power as a result of the Energy Harbor acquisition,” the Monitor said. “Absent a reorganization of the entire market, structural remedies for individual transactions are not likely to be as effective as behavioral remedies because the structural remedies are generally based on an unrealistic, static view of market structure.”

Nuclear units have traditionally participated as zero- or low-cost baseload resources in the PJM markets, meaning they bid low and clear often — while benefiting when power prices spike. But now, owners of nuclear plants are increasingly looking to serve some kind of load directly located nearby that is outside of the wholesale markets, which creates the ability and incentive for nuclear plants to exercise market power.

“Under this offer strategy for the nuclear units, the combination of Vistra with Energy Harbor would result in more structural market power for Vistra as measured by the [three-pivotal-supplier] test both in local markets and in the aggregate energy market,” the Monitor said. “The impact on energy prices and congestion could be very large if the FERC permits this behavior and enough plants engage in the behavior.”

Energy Harbor has a deal with Standard Power to use its Beaver Valley nuclear plant to provide between 200 and 300 MW of power to a data center.

Any competitive concerns from that deal can be dealt with by requiring Vistra to reduce the capacity interconnection rights equal any “behind the generator” load added to the acquired nuclear plants, the Monitor said.

It also suggested three other behavioral requirements: a prohibition on submitting price-based offers that intersect, or cross, the cost-based offer for the resource; that Vistra include operating parameters that are identical to their parameter-limited schedules in its energy-market offers; and that the company use a market seller offer cap in the capacity market that is equal to its units’ net avoidable-cost rate, which the IMM said is the competitive offer for capacity resources.