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November 17, 2024

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9 States Agree to Accelerate Home Heat Pump Installations

Leaders of nine states have agreed to pursue greater adoption of heat pumps by their combined 93 million residents. 

A memorandum of understanding announced Feb. 7 sets a goal of heat pump technology comprising 65% of residential heating, cooling and water heating equipment sales by 2030 and 90% by 2040. That compares with a present-day market share of roughly 25% in the nine states. 

The Northeast States for Coordinated Air Use Management (NESCAUM) brokered the MOU, which reaches well beyond the borders of the air-quality advocacy organization. 

California, Colorado, Maine, Maryland, Massachusetts, New Jersey, New York, Oregon and Rhode Island signed onto the MOU. It builds on a September announcement by the U.S. Climate Alliance in which 25 governors set a 2030 goal of 20 million heat pumps operating in their states. (See Climate Alliance Seeks to Boost Heat Pump Sales.) 

The nine states agreed to lead by example and promote zero-emission technologies in state-owned buildings. They also will seek to direct at least 40% of efficiency and electrification investments toward low-income households that pay a large percentage of their income for energy costs, and to communities that historically have experienced high air pollution levels. 

NESCAUM noted that buildings are a leading source of greenhouse gas emissions. In the nine participating states, buildings emit 173 million metric tons of carbon dioxide per year, plus much smaller quantities of nitrogen oxides, fine particulate matter and other substances blamed for health problems. 

Multiple variables will bear on how these outputs change amid greater use of heat pumps, and there is not a ready estimate of what a 65% or 90% market share would accomplish by way of reduction, said Emily Levin, a NESCAUM senior policy adviser. 

She told NetZero Insider that small-scale residential installations are the subject of the MOU because controlling temperatures in larger residential and commercial structures with heat pumps is a more complicated proposition, and the technology is evolving. 

The MOU is not legally binding, and it is designed to sidestep the controversies that often attach to proposed fossil fuel bans or electrification mandates. 

Levin said there is not one single path to 65% market share; each state will develop its own strategy, and each strategy likely will have multiple tracks. 

“I think we see it being all of the above and looking a little different in every state,” she said. “There will likely be new policy measures in the mix.” 

Some of the first wave of electrification rules, such as the one New York passed in 2023, exempt retrofits of existing buildings. (See NY to Begin Banning Gas in New Construction in 2026.) 

But almost all of the residences that will exist in 2030 and 2040 already have been built. So any meaningful drive to building decarbonization will need to specifically target existing structures. A mix of incentives, tax credits and practical assistance is offered to make this happen. 

“We’re seeing a range of policies emerging to tackle existing buildings,” Levin said. 

There are potential sticking points on the path to 65% market share. 

A larger workforce skilled in heat pump technology needs to be trained, for example. Levin said these efforts are underway. The skillsets in the traditional HVAC industry are not entirely different, but there is a learning curve in the move to electrification. 

Grid capacity is also a consideration, she said, but there are strategies that could mitigate heat pumps’ demand for electric power in regions that previously relied on fossil fuels for heat. 

There also could be pushback from industries that rely on existing technology and see electrification as an existential threat. Some proposals have turned into battles. 

NESCAUM hopes this effort will be perceived more positively and has enlisted HVAC industry stakeholders in the push for the MOU. 

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NJ Opens 2nd State Agreement Approach to Connect OSW with PJM

The New Jersey Board of Public Utilities (BPU) has initiated a second state agreement approach (SAA) process with PJM to build the transmission needed to connect 3,500 MW of offshore wind with the RTO’s grid.

In a Feb. 5 announcement of the SAA, BPU President Christine Guhl-Sadovy said the first agreement in 2022 — also the first for PJM — made the state a national leader in developing offshore wind, putting it on track to construct 4,890 MW.

In addition to resources being developed through PJM’s traditional generation interconnection queue, the second SAA will allow the state to meet Gov. Phil Murphy’s goal of installing 11 GW of offshore wind by 2040. PJM and the BPU jointly filed the SAA with FERC on Feb. 2 (ER24-1187).

“We believe that a coordinated and planned approach could result in more efficient and cost-effective transmission solutions, significantly reducing the risks of permitting and construction delays and protecting ratepayers with cost containment options,” Guhl-Sadovy said in a statement. “This approach helps minimize environmental impacts associated with onshore and potentially offshore upgrades. We look forward to further evaluation and planning, as a result of SAA 2.0.”

PJM CEO Manu Asthana said New Jersey’s use of the SAA process shows the promise it holds for states with policy goals that required developing new generation.

“The continued collaboration between PJM and New Jersey through the State Agreement Approach underscores PJM’s commitment to reliably and cost-effectively facilitating states’ renewable energy policy goals,” Asthana said in the announcement. “PJM’s competitive planning process allows for creative solutions to complex infrastructure challenges. New Jersey has been a leader in this approach and can be a template for other states pursuing their individual energy policies.”

New Jersey has pushed ahead with solicitations for offshore wind infrastructure since approving the $1.1 billion in transmission projects PJM recommended through the first SAA round, but hit a snag when developer Ørsted canceled its two Ocean Wind projects in November. (See New Jersey Launches OSW Infrastructure Solicitation.)

Speaking at a Feb. 6 PJM Transmission Expansion Advisory Committee meeting, PJM’s Susan McGill said the RTO plans to run the SAA planning process parallel to the 2024 Regional Transmission Expansion Plan (RTEP), with the goal of opening competitive solicitation windows for both in July. Doing so would allow PJM to select project components that meet both future reliability needs and New Jersey’s interconnection request in the most cost-effective manner and on a timeline that allows the BPU to consider project approval in the second quarter of next year.

McGill encouraged developers to draft proposals that address needs identified in both windows and submit them to each window, which would allow PJM to ensure it is selecting the best match of components.

“We will look at it from every angle to make sure we are only building what’s needed,” she said.

McGill said PJM will also give further thought to a stakeholder question about whether this approach could result in transmission owners who submit projects having to pay twice the fees to have a proposal considered for both windows.

Several stakeholders raised concerns that having two competitive windows open at once could strain the resources of PJM and transmission owners. They suggested that better ideas might be submitted if the RTO conducted the processes on a staggered timeline.

PJM’s Sami Abdulsalam said the RTO considered delaying one of the windows but said there are time constraints on when each needs to be finished. Completing one without knowing what proposals will be made for the other could result in overlap and projects having to be canceled, he said.

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Hawaii PUC Approves HECO Grid Resilience Plan

The Hawaii Public Utilities Commission on Feb. 1 approved Hawaiian Electric Co.’s five-year resilience plan to harden the grid against future natural disasters like the wildfires that ravaged the state last year, particularly the island of Maui. 

The PUC’s approval of the Climate Adaptation Transmission and Distribution Resilience Program will allow HECO to receive $95 million offered by the Biden administration in August for investments in resilience. HECO’s ratepayers will fund the remainder of the plan’s $190 million overall cost. In a press release, the utility said the federal funds should reduce the program’s cost for consumers by half, with an estimated impact on the monthly bills of residential customers using 500 kWh to be 17 cents on Oahu, 47 cents on Hawaii Island and 39 cents in Maui County. 

The first phase of the plan will involve replacing or strengthening more than 2,000 transmission poles on critical circuits, HECO said. Additional steps include: 

    • increased situational awareness and control through cameras, sensors and reclosers in areas with higher wildfire risk; 
    • removal of trees that are weak, dead, diseased or otherwise in danger of falling on power lines; 
    • strengthening circuits serving hospitals, defense facilities and other critical customers; 
    • undergrounding selected distribution circuits; and 
    • hardening existing control centers, moving the Maui control center to avoid flooding and building a backup control center on Oahu. 

HECO faced widespread criticism in the immediate aftermath of the fires, which killed 100 people on Maui in August and burned more than 3,000 acres, including the historic town of Lahaina. As of October, more than 35 lawsuits had been filed against the utility, including by Maui County, which accused HECO of failing to power down electric equipment amid fire danger warnings from the National Weather Service. (See Hawaiian Electric Faces Multiple Lawsuits over Wildfires.) 

The county also said the utility and its sister company, Maui Electric, failed to properly maintain and repair utility poles and to keep vegetation trimmed and away from power lines. 

Testifying before the House Energy and Commerce Committee’s Oversight and Investigations Subcommittee in September, HECO CEO Shelee Kimura pushed back against the allegation that her company was responsible for the fires, noting that the lines in the area where the Lahaina fire began in the afternoon of Aug. 8 were not energized at the time. (See House E&C Members Grill HECO CEO About Maui Fires.)  

In later supplemental testimony, Kimura added that HECO had put its high-wind protocol in place Aug. 7, including a protocol to disable automatic reclosing on certain circuit breakers and reclosers to prevent lines that trip offline because of faults from re-energizing. She also acknowledged that HECO, “like most utilities,” did not have a pre-emptive public safety power shutoff program in place Aug. 8, but that it was working with stakeholders to design such a program. 

Last month HECO said it was continuing wildfire restoration efforts in West Maui, including by replacing destroyed transmission poles with more resilient steel infrastructure. While nearly all of the 12,000 customers in the area had restored power at the time, the utility warned that it will not have the ability to reroute power from other circuits until the work is completed later this year, meaning that outage restoration times may be longer than normal. 

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Cupparo Replaces Certoma as SPP Board Chair

SPP’s Board of Directors has elected independent director John Cupparo to be its chair, the RTO said Feb. 6.

Cupparo, who will assume the role Feb. 7, will fill out the remainder of Susan Certoma’s term, which expires at year’s end. Certoma told stakeholders Feb. 6 she is stepping down as chair but will remain a board member.

Susan Certoma | © RTO Insider LLC

“It’s an honor and a privilege to have the opportunity to follow in the footsteps of the SPP board chairs that have come before me,” Cupparo said during a Feb. 6 board meeting, which featured several discussions on resource adequacy and the grid’s transformation.

“As we saw in the conversation today, SPP is faced with a series of opportunities and challenges,” he said. “I believe SPP is well positioned to capture those opportunities and to meet those challenges, given the strength of this board, [SPP CEO] Barbara [Sugg] and her team, [and] the members in the broader SPP community.”

Cupparo was elected to the board in 2022. He will continue to chair the Strategic Planning Committee and serve on the Interim Markets+ Independent Panel and the Finance and Human Resources committees. He previously was an officer with PacifiCorp, a senior executive at Berkshire Hathaway Energy leading a transmission investment program in the West and a board member for WECC.

Certoma opened the board’s quarterly meeting Feb. 6 by announcing she was giving up her position as board chair, a position she has held since 2023. She will continue to serve on SPP’s Finance and HR committees.

“At this time, there are other matters that require my attention,” Certoma said.

Sugg lamented that the meeting’s virtual format prevented a standing ovation for Certoma. Still, members were able to use the webinar application to send virtual hand claps to Certoma.

“I don’t think that the membership realizes the load of work that the chair takes on, and it is significant,” Sugg said. “Susan has been with me at every step of the way over the last year.”

The three-year board terms for both Certoma and Cupparo expire at the end of the year, along with that of Ben Trowbridge. All three have expressed a desire to remain on the board. The Corporate Governance Committee will consider their interest when it meets next week.

Liz Moore will remain as the board’s vice chair.

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Mass. Gas Working Group Finalizes Recommendations to Legislature

The Massachusetts Gas System Enhancement Plan (GSEP) Working Group submitted its final report to the state Legislature at the end of January, providing a series of recommendations on aligning the state’s efforts to replace leak-prone pipes with its climate mandates. 

Intended to inform lawmakers as they attempt to craft an omnibus climate bill this spring, the recommendations also highlight key areas of contention between the gas utilities, climate advocates and state officials. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.)  

The working group consisted of representatives from a wide range of stakeholders, including state agencies (The Attorney General’s Office, Department of Environmental Protection, Department of Public Utilities and Department of Energy Resources), nonprofits (Conservation Law Foundation, HEET, Low-Income Energy Affordability Network, National Consumer Law Center and PowerOptions), and the state’s gas utilities (The Berkshire Gas Co., Eversource Energy, Liberty Utilities, National Grid and Unitil Corp). 

The existing GSEP program dates to a 2014 law directing utilities to replace or repair old gas pipes to reduce methane leaks, allowing the utilities to recover the costs on an accelerated timeframe. The program has faced criticism for encouraging investment in the gas system as the state simultaneously moves to phase out its reliance on gas. 

GSEP costs are expected to increase substantially in the coming years. An analysis by Dorie Seavey of Groundwork Data estimated capital expenditures from the program would cost ratepayers more than $34 billion between 2022 and 2039. The state Attorney General’s Office (AGO) estimated “if GSEP continues at its current pace, the total cost of this initiative will be approximately $40 billion over the next decade, an expense borne by ratepayers.” 

The working group was initiated by the state’s 2022 climate law and worked throughout the past year to produce a series of recommendations. 

Members of the working group voted on proposals to redefine the types of projects that are included and prioritized in the GSEP program, authorize the utilities to terminate gas service to existing customers within the scope of GSEP projects, and change the GSEP cost recovery timeline. 

Repair and Retirement

The majority of the working group, including the state agencies and advocacy groups, voted to add language shifting the program from a focus on pipe replacement toward the inclusion of pipe repair and retirement to help minimize costs and avoid stranded assets as the state moves away from gas. The gas utilities and the United Steelworkers Union (USW) opposed adding language promoting repair. 

Representatives for the state’s gas utilities argued that “it is more cost-effective and in the best interest of customers to replace pipe segments rather than undertaking extensive repairs that only serve to defer inevitable replacements.” The utilities voted in favor of adding language around pipe retirement.  

The working group also favored requiring the utilities to evaluate non-gas pipe alternatives (NPAs) prior to GSEP repairs or replacements. The AGO wrote that this would force the gas companies “to be proactive about the transition to renewable energy.” 

The gas utilities and USW opposed this requirement, arguing it undermines the purpose of the law. The gas utilities added they “do not believe it is practical or efficient to evaluate a NPA for all GSEP projects, and in fact, may result in delays to replacement of high-risk leak prone pipe, having a negative impact on safety.” 

Emissions Limits

The group also voted to add language to specify that GSEP projects must be consistent with the state’s decarbonization mandates, including the sector-based emissions sublimits. This proposal was supported by most stakeholders, with partial opposition coming from gas utilities. 

The utilities said the state should constrain the consideration of subsector emissions limits to the “Natural Gas Distribution and Service” sector, arguing that emissions limits that apply to natural gas consumption are beyond the scope of the GSEP program. 

Redefining the Obligation to Serve

Most of the stakeholders also voted to add language allowing gas utilities to “terminate natural gas service to a customer” to implement non-gas GSEP upgrades that would provide similar heating service to customers. This was supported by the state agencies and advocacy groups, with several of the nonprofits stressing the need to add language protecting low-income ratepayers. 

Redefining the obligation of local distribution companies to serve “can provide an opportunity for LDCs to identify opportunities for their participation in efforts to achieve net-zero greenhouse gas emissions,” commented the Conservation Law Foundation. “This is a potentially vital tool in Massachusetts’ transition to a clean energy future and should be considered as a viable change sooner rather than later.” 

The gas utilities and USW opposed this proposal, arguing that changing the statutory obligation to serve existing gas customers is beyond the scope of the working group. 

Cost Recovery Timelines

A plurality of members also supported a proposal by the AGO to phase out accelerated cost recovery for gas infrastructure investments, backed by the advocacy groups.  

“GSEP is, at its core, a funding mechanism that allows utility companies to recover the costs of natural gas infrastructure replacement on an accelerated timeline,” the AGO wrote, adding that accelerated cost recovery encourages the “further institutionalization of natural gas infrastructure that should be largely phased out by 2050.” 

The utilities and USW opposed this proposal. The utilities argued that repealing the accelerated cost recovery is beyond the working group’s scope, adding that the proposal “is tantamount to the repeal of the GSEP statute.” 

The fate of the proposals now sits with the Legislature. The working group included two members of the Legislature, Sen. Mike Barrett (D) and Rep. Jeff Roy (D), co-chairs of the Legislature’s Joint Committee on Telecommunications, Utilities and Energy. Barrett typically voted in alignment with the advocacy groups and state agencies, while Roy abstained in the votes. 

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DOE Opens 2nd Solicitation in Transmission Offtake Program

The U.S. Department of Energy opened the second solicitation in its program to prime the pump for new transmission needed to meet the Biden administration’s climate goals.

Initial proposals for the $1.2 billion to be offered in Round 2 of the Transmission Facilitation Program will be due March 11, DOE’s Grid Deployment Office said in its Feb. 6 announcement.

Authorized by the Infrastructure Investment and Jobs Act, the program allows DOE to borrow up to $2.5 billion to assist in the construction of high-capacity transmission lines that otherwise would not be built or to increase the capacity of already planned lines.

On Oct. 30, DOE announced it would spend $1.3 billion to purchase up to 50% of the capacity on three projects totaling 3.5 GW: the 500-kV Cross-Tie Transmission Line (Nevada and Utah), the Southline Transmission Project (Arizona and New Mexico) and the Twin States Clean Energy Link (New Hampshire and Vermont). (See DOE to Sign up as Off-taker for 3 Transmission Projects.)

The program offers capacity contracts to late-stage projects to increase investors’ and potential customers’ confidence and reduce the risk of developers undersizing projects. DOE will seek to recover its costs by selling its capacity rights, allowing it to make offers to additional projects.

DOE’s National Transmission Needs Study, also released in October, estimated the U.S. must more than double its regional transmission and expand interregional capacity more than fivefold by 2035 to ensure reliability, resilience to extreme weather and access to renewables.

Responding to industry feedback, DOE broke its second solicitation into two parts, with an initial submission of a  “project paper and virtual presentation” to be followed by a detailed application and in-person interview.

DOE will hold a public webinar to provide additional information on the solicitation Feb. 21 at 3 p.m. ET.

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Bill to Create Wash. Oil Market Oversight Agency Dies in Committee

OLYMPIA, Wash. — A Washington bill that would have created a new agency to monitor the state’s oil industry has died in committee.

Senate Bill 6052 was stopped in the state Senate’s Ways and Means Committee on Feb. 5 because of the costs stemming from the cybersecurity need to protect the data to be collected from oil companies, the bill’s sponsor, Sen. Joe Nguyen (D), told NetZero Insider. The bill will be revived in the legislature’s 2025 session, he said. (See Wash. Bill Seeks Increased Monitoring of Petroleum Sector.)

Washington’s Legislature is in the middle of a short 60-day session that will mainly tweak the 2023-2025 biennial budget adopted last year.

In a recent hearing on the bill, oil industry representatives voiced concerns about the cybersecurity of several dozen different types of information the proposed Division of Petroleum Market Oversight would collect and analyze to make sure the industry is not engaging in price gouging. The cybersecurity measures bumped up the initial costs of establishing the agency to $30 million, which is not available in the budget the Legislature is working on, Nguyen said.

But the money should be available in the 2025 session, which will deal with the main biennial budget, Nguyen said.

Creation of the agency has been a major plank in Gov. Jay Inslee’s push to fight climate change. Inslee and Democratic leaders are concerned the oil industry has been unjustifiably raising gas prices due to the cap-and-invest program the state launched last year.

“We knew a proposal like this would be a heavy lift for a short session, especially with the expense of setting up new state infrastructure for this,” Inslee spokesperson Mike Faulk said in an email. “Even as gas prices in Washington have dropped to almost their lowest in two years, consumers will continue experiencing dramatic price swings. … As we make the transition to clean fuels, transparency into oil pricing will only become more important for protecting consumers.”

“Until the close of this session, no proposal is truly dead,” said Jessica Spiegel, senior director for the Northwest region at the Western States Petroleum Association. “However, there are legitimate concerns about the structure, scope and costs of the new state agency SB 6052 would have created. Once we move beyond this issue, the focus can be on the important work of reforming Washington’s cap-and-trade program.”

The WSPA represents four of Washington’s five oil refineries.

Modeled after a new California office, the proposed agency would collect a massive amount of financial and industrial data from various branches of the oil industry in Washington, including five refineries and a complex supply chain.

The agency would have subpoena power and would confidentially refer suspected legal violations to the Washington Attorney General’s office. It also would report its observations and conclusions to the governor’s office, other state agencies and the Legislature.

Inslee called for the bill following the political and economic fallout from the state’s introduction of a cap-and-invest program that went into effect in January 2023. Critics have blamed the program for a gas price increase of 21 to 50 cents per gallon, depending on how calculations are done.

Inslee has pointed to the fact that the oil industry reported $200 billion profits in 2022, sparking suspicions that it is price gouging behind closed doors. Meanwhile, a public referendum is headed to the November ballot to repeal the cap-and-invest program against the wishes of the Democratic-controlled Washington Legislature.

Washington’s gas prices have been among the highest in the nation since last summer, including spending a week as the highest. However, citing AAA figures, Nguyen said Washington’s gas prices have been among the five highest in the nation since the 1970s for economic and geographic reasons.

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President Biden’s LNG Pause Fuels Partisan Debate at House Hearing

Republicans teed off on President Biden’s pause on processing new applications for LNG exports at a congressional hearing Feb. 6. (See Report: Biden Admin to Evaluate LNG Terminals’ Impact on Climate.)

“In addition to undercutting our domestic energy industry, President Biden’s decision is a gift to Vladimir Putin,” said Rep. Jeff Duncan (R-S.C.), chair of the House Energy, Climate & Grid Security Subcommittee. “Global demand for natural gas is expected to increase 46% by 2050. And our European and Asian allies who want to do business with the United States will now look to Qatar, Russia and Iran to meet their growing energy needs.”

Duncan said committee leaders had invited a speaker from the Department of Energy, but nobody from the administration came. Undersecretary of Energy David Turk is scheduled to testify on the subject at a Senate Energy & Natural Resources Committee hearing Feb. 8.

The pause comes after the industry already has built enough capacity to export 14 billion cubic feet per day, with enough under construction to double that capacity, said Subcommittee Ranking Member Diana DeGette (D-Colo.). Additional projects with full approvals from FERC and DOE, but yet to start construction, would triple that capacity, DeGette said.

None of those facilities under development will be affected by the pause in reviews, she added. The last time the review process for new export facilities was updated was 2018, when export capacity was just one-third of today’s level.

“The fact that our nation’s production has ramped up so quickly must be considered, especially since the U.S. currently has enough approved capacity to fulfill the world’s energy needs in the short and medium terms,” DeGette said. “Continuously increasing LNG exports, without updating guidelines to account for new information, is a fundamentally unserious proposal.”

EQT calls itself the largest producer of natural gas in the country, with its drilling focused around the Marcellus and Utica shales in Pennsylvania, Ohio and West Virginia. EQT CEO Toby Rice blasted the decision to pause approvals for new export facilities.

“The Biden administration’s decision was pure politics,” Rice said. “The moratorium was made under the guise of updated research and a claim that we needed updated studies on the environmental and economic impact of U.S. LNG. But we all know what it really is, and that’s an election-year stall designed to garner votes.”

Europe has had to rely on importing LNG from the U.S. since its countries were cut off from Russia following its invasion of Ukraine, said Brigham McCown, senior fellow at the Hudson Institute. Last month, spot prices there averaged $9.56/MMBtu (million British thermal units), while Henry Hub gas was at just $2.26/MMBtu this week, McCown said.

“Europe should not be allowed to recede into the background,” McCown said. “Energy security highlights the need for a comprehensive approach and a stable policy environment coupled with innovation, technology and international cooperation. Our allies would like to be able to have energy security as well.”

Gillian Giannetti is a former high school teacher along the part of Louisiana’s coast called “cancer alley” because of the concentration of industrial facilities and their pollution’s impact on locals. Now senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project, Giannetti said she’s witnessed the effects on her former students, who had high rates of asthma and other respiratory conditions.

The pause impacts only LNG facilities being built to serve countries that do not have a free-trade agreement with the U.S., she noted. DOE must find that a facility shipping gas to non-free trade countries is in the “public interest” to approve it, and so far, it has yet to deny an application for any facility, Giannetti said.

“Put simply, DOE’s tools for assessing whether future gas exports are consistent with the public interest are both obsolete and inapplicable,” she added. “First, DOE has never published guidelines for evaluating the public interest for LNG exports. Never.”

The closest it came was a 1984 effort that sought to come up with rules for LNG imports, which do not work well for licensing export facilities four decades later, Giannetti said. DOE did do some studies on the economic impact of LNG exports in 2018, but they need to be updated too, she added.

The Industrial Energy Consumers of America (IECA) was not invited to testify, but it released comments saying LNG exports affect domestic prices, especially when storage is low. That coincides with demand peaks, which the IECA claims contributed to $84 billion and $53 billion in higher natural gas and electricity prices in 2022 compared to a year earlier.

“Accelerating volumes of LNG exports do have increasing impacts to reliability and prices of natural gas and electricity that are accentuated when inventories are low and during peak winter and summer demand,” said IECA President Paul Cicio. “The relationship is fundamental to the law of supply and demand. Low inventories result in high prices and high inventories result in low prices.”

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New Jersey Senators Back Grid Connection Fee Revision

New Jersey’s Senate Environment and Energy Committee endorsed a sweeping revision of how clean energy connections to the grid are funded and advanced legislation that would give tax credits to help install electric vehicle charging stations and retrofit warehouses for rooftop solar projects. 

The five-member committee on Feb. 5 unanimously supported S209, which would make warehouse retrofit projects eligible for corporate business tax credits of the lesser of $250,000 or half the cost of the project for buildings of at least 100,000 square feet. The bill sets a cumulative total of $25 million awarded in credits under the bill. 

The panel voted 4-1 in favor of a second bill, S210, that would provide a tax credit of the lesser of half the cost or $1,000 to pay for an EV charger at a taxpayer’s business, trade or occupation, or at a location where it could be used by tenants or guests of a multifamily or mixed-use property. 

The bill also would offer a tax credit for the purchase of a commercial zero emission vehicle that would equal half the additional cost of buying a clean energy vehicle rather than one powered by fossil fuel. The bill would allow for a tax credit of up to $25,000 for a vehicle weighing less than 14,000 pounds, $50,000 for a vehicle weighing between 14,000 and 26,500 pounds, and $100,000 for a vehicle weighing more than 26,500 pounds. 

Preparing the Grid

Other bills met more resistance in the committee, which handles much of the state’s clean energy legislation. 

The Democrat-controlled committee voted 3-2 along party lines for a bill, S212, that would revise the regulations that set interconnection standards for Class 1 renewable energy sources, crafting them in line with standards written by the Interstate Renewable Energy Council (IREC). 

The changes would include the introduction of fixed, one-time “grid modernization fees” to be paid by the project owner to defray the cost of connecting to the grid, “including, but not limited to, costs related to administrative tasks, studies, infrastructure upgrades and grid upgrades carried out by the electric utility.” The fees would be based on the number of kilowatts of energy to be produced by the project, with a limit of $50 per kilowatt for projects less than or equal to 10 kilowatts. 

Connection costs not covered by the developer fees would be recovered by the utility from the ratepayers. 

Sen. Bob Smith (D), the committee chairman and a bill co-sponsor, said the legislation is aimed at strengthening the state’s ailing grid, which is considered inadequate to handle a surge of new clean energy projects. 

“We have a grid that is the equivalent of toothpicks and chewing gum,” Smith said, adding there are lengthy delays before a project can get connected, during which the project often “dies as a result.”  

Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, said the urgency of the initiative can be seen in his agency’s estimate that on a clear day, solar projects provide 35% of the state’s load between 10 a.m. and 3 p.m. The state has reached an “inflection point,” and the improvements funded by the bill are essential, he said. 

“We’re almost in a crisis where the grid is shutting down to new solar,” he said. 

But Brian O. Lipman, director of the New Jersey Division of Rate Counsel, in a Feb. 1 letter to the committee, urged senators to hold the bill because it would create “avoidable and expensive electric system upgrades that will be foisted onto captive ratepayers.” 

Lipman said the current “beneficiary pays principle” means that developers and the utilities make “efficient siting decisions” because projects for which the connection costs are too high won’t go ahead. “The risk is better handled by the interconnection customer than captive end-use customers,” he said. 

Subsidizing Storage

Lipman also opposed S225, which would create an incentive program to support new energy storage systems. New Jersey, like other states, sees an extensive storage capacity as key to creating a renewable energy system that is reliable. But the state has little storage capacity. It failed to reach a legislative goal of installing 600 MW of storage by 2021 and now aims to install 2 GW of storage by 2030. (See New Jersey Offers Plan to Boost Lagging Storage Capacity.) 

S225, which the committee approved in a 3-2 vote, would require the New Jersey Board of Public Utilities (NJ BPU) to develop a pilot — and later permanent — program that would award up-front incentives paid in dollars per kilowatt-hour based on the installed capacity of the storage system. The incentive would cover up to 40% of the project cost. 

The program would pay a “performance incentive to compensate the owner of a customer-sited energy storage system or front-of-the-meter energy storage system” for the cost of providing “capacity, demand response, load shifting, generation shifting, locational value and voltage support,” according to the bill. It says the cost of the incentives would be “apportioned” to ratepayers. 

Lipman, in a Feb. 1 letter to the committee, expressed concern the bill would “impose significant costs on New Jersey’s electric ratepayers, while impairing the state’s ability to leverage other sources of funding for energy storage.” He estimated the incentives would cost the state’s societal benefits charge program $60 million. 

But Evan Vaughan, executive director of the Mid-Atlantic Renewable Energy Coalition, said he believed it would “help the market take off in the state.” 

“We have numerous front-of-the-meter storage companies in our membership that are eager to develop projects in New Jersey,” he said. “But they need this legislation in order to make those projects pencil.” 

Discussion Dispute

Two bills discussed by the committee in order to solicit input, but not voted on, drew vigorous opposition from the business community, while drawing support from environmental groups. 

SCR11 would amend the state constitution to prohibit the construction or reconstruction of any new power station that would burn coal, natural gas, oil or petroleum. If approved by the legislature, the proposed prohibition would need voter support in a ballot initiative to be enacted. 

Smith, the bill sponsor, said about 35% of the state’s electricity is generated by nuclear plants and 7% comes from solar projects. The remaining 55% comes from carbon-emitting plants, mostly natural gas. 

Michael Egenton, executive vice president at the New Jersey Chamber of Commerce, said changing the constitution over the issue is excessive, and added that prohibiting the plants would stifle the state’s ability to grow and keep businesses. 

“We have to make sure that we have reliable, affordable, sustainable energy — and I’m talking about energy all across the board,” he said. 

Tina Weishaus, co-chair of the DivestNJ Coalition, and a member of Empower New Jersey, which opposes fossil fuel projects, said that given the health damage to nearby communities, operating such plants is “morally wrong.” 

“We cannot live in a world that continues to burn fossil fuels, and create greenhouse gases and toxic pollutants, that are killing us,” she said.    

Business groups also opposed S198, which would prohibit the state pension funds and annuity funds from investing in the “200 largest publicly traded fossil fuel companies,” and require the funds divest from any such companies in the existing portfolio. 

The divestment should be done “in accordance with sound investment criteria and consistent with their fiduciary obligations,” the bill states. It also gives the director of the State Division of Investment the power to reinvest in fossil fuel companies and funds or continue investing in them if “within a reasonable period of time” the value of the state retirement funds drops to 99.5% or lower of the “hypothetical value had no divestment occurred.” 

Smith rejected the suggestion that the state’s divestment would be of no consequence to big fossil fuel companies that do “trillions of dollars of business.” He said they do listen to “governments and institutions in society that stand up and say, ‘You’re going in the wrong direction.’” 

But Ray Cantor, a lobbyist for the New Jersey Business and Industry Association, said pension fund managers have a fiduciary responsibility to make decisions that generate as high a return as possible. The state should “not be looking to use our pension funds as a lever to enact public policy,” he said. 

Scot Mackey, a lobbyist for the American Petroleum Institute, said the industry is trying to address climate change. Penalizing investment in the industry would penalize the investments “that they’re making in the future, as they try to change and they try to grow into what the future is going to look like,” he said. 

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PJM Stakeholders Open Poll on Proposal to Align Electric and Gas Markets

PJM’s Electric Gas Coordination Senior Task Force has opened a poll on a proposal aimed at aligning components of the RTO’s energy market with gas pipeline operations. 

The joint package sponsored by PJM, Dominion Energy and Gabel Associates would add intraday real-time commitment runs to the day-ahead market ahead of the three gas nomination cycle deadlines and notify gas-fired generators that they are being committed with adequate time for them to nominate for fuel in the subsequent cycle. In turn, generators would be asked to notify PJM if they have procured fuel or expect to do so in time to be scheduled. 

Speaking during a Jan. 30 task force meeting, PJM’s Brian Fitzpatrick said the proposal is focused on improving situational awareness over the status of gas generators and reducing the need for operators to check in with the approximately 300 such resources during emergency conditions. 

“Really it’s about reducing the unknowns and identifying where there are risks,” he said. 

Having multiple commitment periods throughout the day corresponding to the gas nomination cycles would give PJM insights into when resources are likely to be available, such as whether they have obtained fuel for evening peaks. 

Voting on the proposal will be open for around two weeks, and results are expected to be discussed at the task force’s Feb. 29 meeting. This is the second poll the task force has held, following a round in which six packages failed to receive majority support in October. 

The highest vote-getter was a joint proposal sponsored by PJM and Dominion, which would have required gas generators to confirm to PJM that they had procured adequate fuel to meet their day-ahead commitment. It would have also required that resources that had not procured fuel during a PJM cold weather alert verify gas availability with pipeline operators twice a day and reflect any shortages as a forced outage. 

Michael Borgatti, Gabel senior vice president of RTO services and regulatory affairs, said he’s hopeful that the joint proposal can be a compromise between all those previously brought to the task force. 

The revised package now under consideration states that generators should confirm the availability of their fuel supply and reflect that in their parameters, but Fitzpatrick said it would not carry any enforcement or penalties. 

Brock Ondayko, director of RTO operations for AEP Energy, said that even without any specified penalties at PJM, generators that report incorrect information — such as stating that a unit has purchased fuel and then experiencing an interruption in supply — could run into compliance issues with FERC. 

Independent Market Monitor Joe Bowring said the fuel reporting component is vague and would be ineffective at providing true situational awareness without stronger requirements. In particular, he said allowing generators to state that they expect to have fuel available would add too much ambiguity to the process. 

“It is creating false confidence, so I really don’t see the point of this,” he said. “In my view this is potentially worse than not having it. … The straightforward approach is to have a mandatory requirement to report whether a unit has procured gas. Combining the voluntary reporting in the proposal with reporting about what generators expect makes that part meaningless or worse than meaningless. A rule based on a generator’s expectation is an unenforceable rule.” 

Vistra Director of PJM Market Policy Erik Heinle said the deadlines for reporting information to the RTO could distort the gas market if a large number of generators are trying to get contracts in place at the same time. 

Bowring also said that the proposal would be a significant change to PJM’s day-ahead markets that has not included a careful review of how the interaction with markets would work and the likely consequences. 

“Issues including whether the commitment process prior to the day-ahead market would use the same software and have the same objective function have not been addressed. Issues about how market payments and uplift payments would be defined and the treatment of commitments prior to the day-ahead market that carry forward into the next day have not been carefully thought through. The Market Monitor supports increased situational awareness and supports inclusion of offer parameters that are consistent with pipeline rules, but this proposal is being rushed to a vote before important questions have been asked, let alone answered,” Bowring said.