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November 5, 2024

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Key Energy Bills Win Crossover Votes in Md. General Assembly

Maryland’s House of Delegates on March 18 approved an ambitious plan for introducing time-of-use (TOU) rates for residential customers of the state’s investor-owned utilities, but only after provisions for a default, opt-out introduction of TOU was amended to a voluntary, opt-in program.  

The Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act (H.B. 1256) instead calls for the state’s Public Service Commission (PSC) to conduct a study of the impacts of the voluntary TOU program, determine whether a default rate would be justified and deliver a report to the General Assembly by Dec. 31, 2027. 

As originally drafted by Del. David Fraser-Hidalgo (D), H.B. 1256 was intended to combine the default TOU rates with incentives for distributed renewable energy technologies to promote electrification of homes and transportation, while also promoting load management and flexibility to minimize impacts on the grid as electricity demand grows.  

The bill was one of several pared-down energy bills that passed in the House or Senate on or before March 18, the General Assembly’s “crossover day,” when bills introduced in one house must be approved and sent on for a committee hearing and possible vote in the second house.

One example, Del. Lorig Charkoudian’s (D) H.B. 505, would have prohibited the state’s utilities from including the costs of any lobbying, political activities, membership fees or sponsorships in industry trade groups in their rates. Maryland is one of 11 states that have been considering such legislation to curb utilities’ political spending with their customers’ funds. (See Utilities Facing Increased Scrutiny Over Political Activities.) 

Those provisions were crossed out in the amended version of the bill, which the House passed 99-38 and was sent to the Senate Committee on Education, Energy and the Environment. But in an interview with NetZero Insider, Charkoudian said the bill’s remaining provisions still would provide consumer savings and utility accountability. 

Specifically, H.B. 505 would require Maryland utilities to become members of PJM, rather than join voluntarily. Under FERC rules, voluntary members get a 50-basis-point return on equity adder, which, Charkoudian said, translates to an extra $20 million in costs for the state’s consumers. Mandating membership in state law would save consumers “a significant amount of money,” she said. (See Citing California Law, FERC Rejects PG&E Request for RTO Adder.) 

The other remaining section of the bill would require utilities to submit yearly reports to the PSC, detailing all their votes at RTO meetings, regardless of whether the proceedings and voting records already had been reported publicly. 

Another Charkoudian bill, H.B. 1112, would allow the PSC to require the state’s utilities to acquire or contract for utility-scale energy storage projects if the commission finds storage to be a more cost-effective and efficient alternative to a reliability must-run (RMR) contract to keep a power plant running past its planned retirement date. 

Charkoudian sees the bill as a new way to respond to situations like the potential closure of the Brandon Shores coal-fired power plant in 2025 and PJM’s efforts to keep the plant open with an RMR until 2028. PJM recently rejected the idea of storage as an alternative solution, as proposed in a recent report from GridLab and Telos Energy. (See PJM Rejects Storage as Alternative to Brandon Shores RMR.) 

Passage of H.B. 1112 could provide a new option for Maryland, Charkoudian said. “We could spend all this money on reliability must-run, and [at] the other end, all we have is more greenhouse gas emissions and more pollution. Or we could take that very same money and spend it on battery storage, and we get the same reliability.” 

But, she acknowledged, even if the PSC were to decide that storage would be a better option, PJM still would have to sign off on it.  The bill passed 101-37 and was sent to the Senate Committee on Education, Energy and the Environment.  

Other Bills Crossing Over

S.B. 1, sponsored by Sen. Malcolm Augustine (D), would require the state’s retail electricity providers that offer “green power” to their customers to document whether they actually are selling electricity generated by a renewable power project or the renewable energy certificates (RECs) from a project that could be located outside the state. 

To offer green power, a retail supplier must show that the electricity being provided is at least 51% from renewables or RECs or at least 1% more than the amount of clean power required under the state’s renewable portfolio standard. For 2024, the state’s RPS calls for about 37% of Maryland’s power to come from renewables, but Gov. Wes Moore (D) has committed the state to 100% clean power by 2031.

Retailers also would have to have visible disclosure statements on their websites, explaining the purchase of a REC would not necessarily mean renewable energy also has been purchased.  

The green power provisions are part of a larger bill focused on regulation of retail power suppliers. S.B. 1 passed in the Senate 33-14 on March 8 and was referred to the House Committee on Economic Matters. 

Fraser-Hidalgo also is a lead sponsor on H.B. 689, which would replace Maryland’s $3,000 excise tax credit for electric or fuel cell vehicles with a rebate of the same amount, which auto dealers would provide at the point of sale. The original bill would have limited rebates based on consumers’ income, but those requirements were stripped out. The bill also includes $1,000 rebates for electric motorcycles and $2,000 rebates for three-wheeled motorcycles or “autocycles.” 

The bill passed 103-36 on March 18 and has been referred to the Senate Committee on Budget and Taxation.  

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Industry Sends Back NERC Cyber Monitoring Standards

In a 20-day ballot period that ended March 18, industry stakeholders voted down NERC’s proposed reliability standard that would require entities to implement internal network security monitoring (INSM) on certain cyber systems.  

As a result of the ballot, which saw the proposed CIP-015-1 receive a 48.52% segment-weighted vote for approval — a two-thirds majority is required for passage — the standard will be sent back to the standard drafting team for Project 2023-03 for revision. Future ballot periods for the standard may be shortened in accordance with a decision by NERC’s Standards Committee at its February meeting to authorize reducing additional comment and ballot periods to as little as 10 days. (See NERC Committee Greenlights Shortened INSM Comments.) 

The SDT created CIP-015-1 after a previous proposed standard, CIP-007-X (Cybersecurity — systems security management), failed to pass its initial comment and ballot period in January with only a 15.42% segment-weighted approval. Due to feedback received during that comment period, team members said they felt creating a new standard would “ensure that the purpose and requirements [of the standard] are clear and allow for future expansion if necessary.”  

Although this technically was the first ballot for CIP-015-1, NERC elected not to form a new ballot pool, keeping the same stakeholders that voted on CIP-007-X. The project’s page on NERC’s website said no changes will be made to CIP-007, which “will revert to the currently enforced version,” CIP-007-6. 

Respondents generally were supportive of breaking out the security monitoring requirements into a new standard, although some commenters asked why the SDT hadn’t gone further. James Keele and Gail Golden, both representing Entergy, pointed out that “other standards already require [cybersecurity] monitoring,” naming CIP-003-8 (Security management controls), CIP-005-7 (Cybersecurity — electronic security perimeter(s)), CIP-007-6 and CIP-010-4 (Cybersecurity — configuration change management and vulnerability assessments). 

Keele and Golden suggested the SDT consolidate the security monitoring requirements from those standards into the new standard as well. An unnamed commenter representing the Tennessee Valley Authority shared similar sentiments — though only mentioning CIP-007 and CIP-003 to be consolidated — as did Alain Mukama from Hydro One Networks. 

Keele and Golden also expressed reservations about requirement R1 of the proposed standard, which provides guidance to help registered entities “identify network data collection location(s) and method(s) by implementing a risk-based approach focused on network security risks.” Their comments said the wording of the requirement was not “clearly aligned with expectations in the measures [section of the standard] and the technical rationale,” putting entities at risk of being found noncompliant in audits. 

“The wording of CIP-015-1 R1.1 … appears to provide entities the latitude to identify [data collection locations and methods] based on risk, but without an expectation of an exceedingly robust methodology and without an expectation to consider all possible network data collection locations,” Keele and Golden said. “The requirement should be updated to … start with a list of all/many [network monitoring] locations and apply well-defined risk criteria … against that list to arrive at the final locations subject to the program.” 

Cain Braveheart, writing on behalf of the Bonneville Power Administration, also suggested the requirement’s language “leaves it open for auditor interpretation” and “some level of deference must be offered to an entity’s risk management approach,” or that NERC should “create auditor guidance on what a risk-based approach looks like.” He also asked the SDT “clarify the term ‘locations’ in the requirement, adding context currently only found in the technical rationale.”  

NERC’s Standards Committee will hear an update on Project 2023-03 at its upcoming meeting on March 20; the SDT will meet the following day to consider its next steps. The ERO considers the INSM effort a high-priority project because FERC has ordered it to submit standards requiring INSM by July 9 of this year. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.)

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Coast-to-coast, Grid Operators Prepare for April Solar Eclipse

The upcoming April 8 solar eclipse will run a course from central Mexico to Newfoundland, but grid operators far from its 124-mile-wide path of totality will be dealing with its impact as it cuts output from solar power generation coast-to-coast.  

According to NASA, major cities including Dallas and Indianapolis will feel the full brunt of the eclipse that afternoon, but RTO and ISOs are preparing for system challenges as far west as California. 

While it is too early to accurately predict the weather, the National Weather Service noted that six selected cities in its path typically see temperatures in the 60s on that date. 

ERCOT said the eclipse will affect its territory from 12:10 p.m. to 3:10 p.m., peaking about 1:40 p.m., when solar production likely will drop to about 7.6% of the maximum expected under clear conditions. ERCOT has 22,463 MW of installed capacity and has received about 7% of its power from solar this year, according to its latest data. 

The Texas grid operator is working with solar forecast vendors to ensure their models accurately forecast the eclipse’s impact. ERCOT plans to receive and review ad-hoc forecasts March 29 and then start to prepare for major generation ramps caused by the eclipse, which will occur on a Monday. 

ERCOT said it would review its day-ahead market results the day before the event to ensure its system is ready. 

MISO’s Carmel, Ind., headquarters and its southern operations center in Little Rock, Ark., both are in the path of totality and respectively should experience darkness for 3 minutes, 29 seconds and 2 minutes, 30 seconds. The impact on solar will depend on cloud cover. With clear skies, solar output in the RTO could plunge quickly by about 4,000 MW, but clouds could limit that to a drop of less than 1,000 MW.

At the event’s start, solar generation will roll off the system rapidly and increase rapidly near the conclusion, resulting in the need for ramping capacity and possibly causing congestion-management challenges, MISO said. The temperature drop associated with darkness could lower demand, the RTO noted. 

In a presentation to Entergy’s Regional State Committee last year, MISO noted it learned from eclipses in 2017 and 2023 that balancing and congestion management are the most challenging issues. 

SPP did not have recent analysis on its website and did not return a request for comment. In a report covering the August 2017 eclipse, it noted this year’s event would be another test of its ability to balance renewable energy because solar penetration has grown.

PJM

PJM said March 18 the path of totality will enter its footprint northwest of Cincinnati and exit over three counties in Northwest Pennsylvania. The total eclipse will cover the 124-mile path for up to several minutes, but the RTO said almost its entire 13-state footprint will see some impact over about 2.5 hours. 

Regardless of cloud cover’s effects, PJM is expecting to lose at least 80 to 85% of the output from its 8,200 MW of grid-connected solar and is preparing for the potential temporary loss of up to 4,800 MW of behind-the-meter solar. 

The dimming sunlight could lower temperatures by 4 to 10 degrees, but the impact will depend on how warm the weather is absent the eclipse. Under cool conditions, a temperature drop could lead to higher demand, but in warm conditions, the decrease likely would reduce loads. 

PJM said it would provide an update of the eclipse’s anticipated impacts under a clearer weather forecast at its April 4 Operating Committee meeting. 

Northeast

NYISO said in a presentation last September that the total eclipse will affect its territory from 3:16 to 3:29 p.m., but the event will leave some impact for about 2.5 hours. New York City and Long Island are expected to see between 60 to 90% obscuration of the sun, while Albany should see 96%.

Both Buffalo and Rochester will have several minutes of total eclipse. Those cities typically have about 60 to 65% cloud cover that time of year, NYISO said. With clear skies, solar output from both behind-the-meter and grid-connected solar could fall by more than 3,110 MW at the eclipse’s peak.

Impacts to wind power also are expected, as seen during the 2017 eclipse, when wind speeds and output dropped at the start of the event and increased as it ended, the ISO said.

ISO-NE said the eclipse could cut solar production in its territory by thousands of megawatts from 2:15 to 4:40 p.m. when all of New England will see at least 80% obscuration, with some northern areas seeing 100%. 

Most of New England’s solar power comes from small-scale, distributed systems that either are connected to retail customers or utilities’ distribution systems and not the ISO-operated grid. Those systems effectively cut demand for wholesale power when the sun is out.

The eclipse’s impact will make solar output drop off much more quickly than it normally would at sunset but, as in other areas, ISO-NE said impacts will depend on cloud cover. 

Out West

The eclipse’s effects will even be observed in the Western Interconnection.  

CAISO’s balancing authority area will experience a partial eclipse from about 10 a.m. to 12:30 p.m. PT. Relative to the eclipse of Oct. 14, 2023, the sun will be less obscured in CAISO territory: about 25 to 59% on April 8 compared to roughly 72 to 80% on Oct. 14.

And the profile of impacts will be different because the April 8 eclipse will start later in the morning, during greater solar generation. The Oct. 14 eclipse lasted from about 8 to 11 a.m. in California, with maximum impact about 9:30 a.m.  

The Oct. 14 eclipse knocked 4,500 MW of solar generation off the CAISO grid, followed by a rebound of 6,560 MW as the eclipse waned. (See Report Details CAISO Response to Partial Solar Eclipse.) 

CAISO’s April 8 forecast shows utility-scale solar dropping 6,349 MW between 10 a.m. PT, a peak at 11:20 a.m. and a 6,718-MW surge in solar generation by 12:40 p.m. 

The predicted upward ramp of 84 MW per minute is less than the Oct. 14 rate of 131 MW per minute.  

The projections for April 8, based on clear-sky conditions, are in a technical bulletin released this month. CAISO has been planning for the April 8 eclipse since February. Once again, coordination will be key to eclipse preparations. 

CAISO plans to use quick-ramping resources, including natural gas plants, battery storage and hydropower, to respond to rapid changes in solar generation. 

“To manage the solar ramps, the ISO has done extensive outreach to scheduling coordinators and market participants to emphasize the importance of following dispatch operating targets (DOTs) in real time,” especially for solar and battery resources, CAISO said in a frequently asked questions document. 

CAISO will coordinate with gas plants and gas suppliers to ensure sufficient supply during the eclipse. 

In response to the ramping needs, CAISO said it expects to commit an increased amount of regulation up and regulation down. But adjustments, especially to regulation up, likely will be smaller than in October due in part to lessons learned from that event. 

CAISO is holding meetings on the event with WEIM entities. “Coordination across the WEIM is crucial so that the market can optimally dispatch during the eclipse conditions,” the ISO said. 

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Tangled Challenges of Building Decarbonization Examined at IPPNY Conference

ALBANY, N.Y. — Building decarbonization is at once critical for the environment, expensive for building owners and potentially taxing for the power grid. 

Four people helping plan and direct decarbonization in New York acknowledged the complicated nature of the task and offered insight on how it is being approached March 19 at the Independent Power Producers of New York’s 2024 Clean Energy Spring Conference. 

Susanne DesRoches, NYSERDA | © RTO Insider LLC

The clean energy transition New York leaders are pursuing will not happen without a high percentage of the state’s 6 million buildings using less energy and cleaner energy. Buildings are the largest source of greenhouse gas emissions in New York City, and second-largest by a narrow margin in the rest of the state. 

And therein lies the difficulty: Millions of building owners need to take action to make it happen, in many cases at their own cost, to get New York to its 2050 goal of 85% GHG emissions reduction. 

“That’s a lot of people to get engaged in this transition, and that’s really challenging, but also a great opportunity to reach everyone in the state and bring them into what this transition is going to mean for them,” said Susanne DesRoches, vice president for clean and resilient buildings at the New York State Energy Research and Development Authority. 

A sticky problem is that many buildings in New York predate modern efficiency standards. Constructing highly efficient, all-electric buildings — which is gradually being mandated in the state — can cost a bit more but is relatively straightforward. Electrifying an existing building and making it more efficient can be much more complicated and expensive. 

Danielle Manley, Urban Green Council | © RTO Insider LLC

“Most of the buildings that we will have in 2050 and beyond are already built, so the real challenge is figuring out how to tackle emissions reductions in those buildings,” said Danielle Manley, policy manager at the Urban Green Council. 

But efficiency is an indispensable part of the process, she added. She showed a map of Consolidated Edison’s 70 network areas under three electrification scenarios. Electrification by itself would put numerous areas into grid constraint, based on their current capacity. Electrification with efficiency would reduce the number of areas in constraint. 

“The third scenario — that’s our smart electrification scenario: buildings electrify; they make energy efficiency upgrades; and they incorporate load shifting, thermal storage and electric battery storage — we see most of the areas back in the blue,” Manley said. 

Much of the discussion centered on New York City. Because of its lack of heavy industry and its extensive public transit system, the city’s buildings have an outsized influence on its carbon footprint compared with the rest of the state. 

Zachary Steinberg, Real Estate Board of New York | © RTO Insider LLC

The city also has some of the nation’s most expensive real estate and highest electric utility rates. And for all its glitz and wealth, it also has a poverty rate 50% higher than the U.S. as a whole. 

So, who is going to pay for all these upgrades? 

Zachary Steinberg, policy lead at the trade association Real Estate Board of New York, said the city’s Local Law 97, which will penalize building owners who do not electrify their property, is not an effective incentive; the return on investment is just too small. 
“Yes, the penalties are significant, but they’re only a fraction of the cost of what it’s actually going to take to improve buildings and decarbonize, particularly if we’re combining building electrification with efficiency work,” he said. 

There need to be more incentives to perform the work and more assistance paying for it, he added — fewer sticks and more carrots. 
Kathleen Schmid, deputy executive director of the New York City Mayor’s Office of Climate and Environmental Justice, said the city recognizes sticks are needed as it pursues decarbonization but wants to focus on carrots. 

Building Decarbonization

Kathleen Schmid, NYC Mayor’s Office of Climate and Environmental Justice | © RTO Insider LLC

“We need a program that gets to emissions reductions,” she said. “We will see this as a failure if we instead levy significant amounts of fines.” 

Local Law 97 sets an ambitious target: a 40% reduction in emissions from the largest buildings by 2030 and net zero by 2050. 
“We know there’s challenges, and we’re working through those challenges,” Schmid said. “We know the 2030 targets are going to be hard to achieve, particularly for those buildings with complex ownership structures in the residential space. 

“To Zach’s point, we know that it is a problem to shift the cost of heating from a building owner to a tenant. … There are significant equity and financial concerns. … The city is looking at all those ramifications.” 
Healthier, better-performing building stock is a high-value proposition for New York City, Schmid said, so Local Law 97 should be seen as a tool for modernizing buildings rather than a burden for their owners. 

“It’s not a thing that we’ve successfully figured out how to do across the board,” she acknowledged. 

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Opponents Sue to Halt Coastal Virginia Offshore Wind

Three conservative- and libertarian-leaning organizations have filed a federal lawsuit to block construction of the Coastal Virginia Offshore Wind (CVOW) project. 

The complaint, filed March 18 with the U.S. District Court for D.C., alleges federal regulators conducted a flawed review of the proposed project’s potential impact on the critically endangered North Atlantic right whale and that other federal agencies accepted this flawed analysis.  

The plaintiffs — the Committee for a Constructive Tomorrow (CFACT), the National Legal and Policy Center (NLPC) and The Heartland Institute — assert this was a violation of the Endangered Species Act and the Administrative Procedure Act and ask the court to halt work on CVOW until the flawed review is supplanted by a legally compliant review and a valid “biological opinion” about the impact on marine life is issued. 

The defendants are the Department of the Interior, the Bureau of Ocean Energy Management, Commerce Secretary Gina Raimondo, the National Marine Fisheries Service and project developer Dominion Energy. 

In a statement, Dominion said the complaint is baseless and that full measures are in place to protect whales and other marine wildlife. 

With 176 turbines rated at a combined 2.6 GW, CVOW is the nation’s largest offshore wind proposal and one of the most mature: BOEM greenlit it Oct. 31. (See BOEM Approves Coastal Virginia Offshore Wind.) Onshore assembly and staging of components has been underway for months, and offshore installation will begin in May. 

Dominion has held the lease for the 112,799-acre site east of Virginia Beach since September 2013. In 2020, it completed installation of a two-turbine research project there. In February 2024, it announced it would sell a 50% stake in CVOW. (See Dominion Sells 50% of Coastal Virginia Offshore Wind to Stonepeak.) 

Multiple lawsuits have been filed under multiple theories of law against projects along the Northeast coast that form the vanguard of what proponents hope and opponents fear will become a major new clean energy sector. A few thousand turbines rated at a few dozen gigawatts are envisioned from Canada to the Carolinas — along the migratory route of the North Atlantic right whale. 

The complaint against CVOW charges that federal regulators are looking at the impact of all these projects individually rather than as a whole. This ignores the cumulative potential impact on whales, it says. 

“Playing politics with such an iconic species as the right whale is a truly pathetic example of the Biden administration’s allegiance to climate alarmism,” Heartland President James Taylor said in a statement. 

“This project is not in the interests of Dominion Energy shareholders or customers,” NLPC CEO Peter Flaherty said. “It was only approved because Dominion Energy has undue influence on Virginia politics through outsized contributions to both Democrats and Republicans.” 

And CFACT President Craig Rucker said: “This piecemeal, incremental step analysis by BOEM is a textbook violation of the Endangered Species Act. Every court, including the District of Columbia, has held this individual approach to be illegal.” 

Dominion offered this rebuttal: “The issues raised in this lawsuit have no merit. The Bureau of Ocean Energy Management has done an extraordinarily thorough environmental review of the project and carefully considered potential impacts to marine wildlife and the environment. The overwhelming consensus of federal agencies and scientific organizations is that offshore wind does not adversely impact marine life. We’ve put in place strong environmental protections for this project and are confident the North Atlantic right whale will be protected.”

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Massachusetts Clean Heat Standard Reignites Debate over Biogas

The role of renewable natural gas (RNG) and hydrogen in decarbonizing Massachusetts’ heating sector has been a major topic of debate for several years, with major implications for the state’s gas network and electrical grid. 

Questions about alternative fuels were a major focus of the Department of Public Utilities’ three-plus-year investigation into the future of gas in Massachusetts, which ultimately concluded that the state’s gas utilities should not be able to recover costs associated with blending RNG or hydrogen into the gas supply from the general rate base (DPU 20-80). (See Massachusetts Moves to Limit New Gas Infrastructure.) 

Despite the DPU’s order, arguments over alternative fuels have remained a main point of contention in the Department of Environmental Protection’s (DEP) development of a “clean heat standard” (CHS), a program aimed at incentivizing emissions reductions from the state’s buildings sector. 

As proposed, the standard would apply to suppliers of heating energy at the retail level, including suppliers of oil, propane, natural gas and electricity. Residential suppliers would be required to obtain two types of credits — for full electrification projects and for emissions reductions — with the requirements increasing over time to keep up with state’s electrification and decarbonization goals. 

Suppliers could meet the requirements by embarking on projects themselves, purchasing credits associated with other projects or making alternative compliance payments (ACPs).  

In a reflection of the complexity of the program and the significant impacts it could have for the state’s clean energy transition, several questions have emerged in the stakeholder engagement process: 

How should credit requirements be allocated between different suppliers? How should the state measure emissions reductions? What is the role of ACPs? How should the program work for industrial and commercial heating? And, finally, what heating technologies should be eligible to generate credits, and therefore be incentivized by the program? 

In the draft framework released by the DEP in the fall, hydrogen and RNG are not eligible to generate credits, due to the state’s aim at focusing the CHS on incentivizing electrification. This direction was met with applause from climate advocacy organizations and outcry from industry and utility-aligned groups. 

“We are surprised and concerned that the Draft CHS Framework does not include any crediting for renewable gaseous fuels as part of Massachusetts’ building decarbonization solution,” commented the Coalition for Renewable Natural Gas, whose membership includes several of the state’s gas utilities, RNG producers and fossil fuel companies.  

“The portions of the gas system which currently serve the residential and commercial customers targeted for electrification will remain in place for a very long time, even with aggressive fuel-switching policies, and would be well-served by increasing renewable gases while that transition occurs,” the RNG coalition wrote.  

Other companies and industry groups, including the American Biogas Council, the American Public Gas Association, the Associated Industries of Massachusetts and the Mass Coalition for Sustainable Energy, opposed the exclusion of alternative gases from credit generation.  

Meanwhile, the omission of hydrogen and RNG from the program was praised by climate and environmental organizations, which have opposed policies that incentivize blending alternative fuels into the gas system.  

“The ineligibility of gaseous biofuels and hydrogen under the CHS is absolutely essential for keeping the commonwealth on the most cost-effective trajectory towards building decarbonization,” wrote the Acadia Center.  

Environmental organizations in the state have long expressed concerns that electrification is the most efficient pathway to decarbonizing the building sector and that blending alternative fuels into the gas network would deliver minimal climate and public health benefits at a high cost to gas ratepayers. 

The Acadia Center made the case that making hydrogen and RNG blending eligible to generate credits would be in “direct conflict” with the DPU’s 20-80 Order on gas system decarbonization.  

In the order, the DPU wrote that it “rejects the recommendation to change its current gas supply procurement policy to support the addition of renewable natural gas to LDC supply portfolios due to concerns regarding the costs and availability of RNG, as well as its uncertain status as zero-emissions fuel.” 

The DPU added that gas system upgrades to support the blending of alternatives fuels must be entirely funded by the customers that procure the alternatives, instead of the general rate base.  

The DEP said in a statement it’s committed to ensuring the standard is “consistent with the goals of DPU 20-80,” as well as the state’s existing Mass Save energy efficiency program. Energy efficiency measures are not eligible for clean heat credits “to avoid unnecessary complexity and redundancy with the Mass Save program.” 

Under the draft framework, certain liquid biofuels would be eligible for the emission reduction credits. Waste-based biofuels that are eligible for the state’s Alternative Portfolio Standard would receive full credits, while fuels that are eligible only for the federal Renewable Fuels Standard would receive a half credit. As proposed, this half credit would end in 2030. 

As with hydrogen and RNG, the biofuel industry has pushed to expand the range of fuels that are eligible for credits, while environmental groups have argued for tighter constraints around what fuels can be considered. Wood heating also would not be eligible for credits, drawing the ire of the wood pellet industry. 

The DEP has indicated that “no final decisions have been made” on the CHS and is considering public feedback on all aspects of the standard. The department has committed to revisiting the credit eligibility of different heating options at the 2028 program review. 

Beyond questions about credit eligibility, the proposed credit requirements for electricity suppliers have been met with pushback from both the utilities and environmental organizations, which have argued these obligations could undermine incentives for consumers to adopt heat pumps. 

“As constructed, the framework will likely increase electric rates, increasing operating costs of electric heat, which is counterproductive to the commonwealth’s electrification goals,” Eversource commented.  

The DEP is aiming to release a formal draft proposal of the CHS in the fall and has two stakeholder meetings scheduled in early April, along with a comment deadline April 5.  

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NJ Offers Path Forward for Stalled, Stranded Solar Projects

New Jersey is making it easier for customers to complete a solar project if their developer fails, after hundreds of customers were left stranded by contractors who disappeared, including two installers that filed for bankruptcy and a third that was sued for unfair trade practices. 

The New Jersey Board of Public Utilities (BPU) on Feb. 14 enacted an order that allows the board to relax some solar project rules, including waiving timelines and some project registration requirements, for customers whose project stalls after their developer suddenly ceases work.  

BPU staff said the action was needed in part because the developer often handles the paperwork for a solar project’s application for incentives under the state Successor Solar Incentive program, and the customer could miss out on incentives if the developer is not around to complete the job. 

The move reflects New Jersey’s effort to protect customer projects — and the state solar sector — from the kind of developer failure that has impacted projects across the country as installers wrestle with rising costs and interest rates and adverse market conditions, often resulting in bankruptcies. 

More than 100 solar developers have filed for bankruptcy nationwide since the start of 2023, including 22 in California and 11 in Texas, according to California-based Solar Insure, which provides monitoring and insurance warranties for solar projects. 

The company said such a high number of bankruptcies was “unseen” in the past 20 years, and California was particularly hard hit due to the introduction of the Net Energy Metering 3.0 compensation plan, which takes effect in April and awards much lower compensation rates for the power that rooftop solar owners put back on the grid. (See Can US Maintain Record Solar, Clean Power Growth?)  

Developer Disappearance

The BPU’s Feb. 14 order helps soften the impact of a developer’s disappearance. The failure of three New Jersey solar developers, for example, created difficulties for 900 customers in meeting the ADI program requirements and deadlines, BPU officials said. 

“The abrupt withdrawal of an installer from the market affects not only the business and its employees, but also its customers,” the order states. “When a solar installer suddenly stops working on a project and returning phone calls, these customers are often left stranded.” 

If the developer persistently fails to communicate with the BPU about the status of a project, the agency will take steps to debar the developer, which then leaves the customer without a representative and hinders their efforts to seek incentives, the order said. 

“Staff believes that providing a limited waiver of the relevant rule(s) for the Affected Projects would provide the customers of those installers relief without unduly undermining the structure that the rules provide,” the order states. 

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said the introduction of the rules reflects the BPU’s effort to help customers as the industries go through hard times and developers suffer bankruptcies and other “calamities that are beyond their control.” 

“There’s a lot of cost pressure on solar right now because they borrow a lot of money,” he said. “These are very capital-intensive installations. And the interest rates are through the roof … It’s really pushed a lot of companies very hard financially.” 

Customer Protections

The board’s order encourages customers who find their developer has departed to “find a new installer and re-register,” and the new rules make it easier to do so.  

The order allows the board to relax some rules for such customers and allows them to waive project timelines in certain circumstances. The order, for example, grants a waiver to customers on some time limits by which the project must redeem solar energy certificates, extending the period by which they can be redeemed to three years after the energy year in which the electricity was produced. 

The order allows the BPU to waive the requirement that a project receive a notice of conditional registration prior to starting construction for any affected project. And it directs the program manager to accept the registration and post-construction certification packages that carry the customer signature instead of requiring them to bear the installer’s signature. 

In addition, the BPU added two new categories of solar vendor to a database created to provide vendor names to customers so they can easily solicit several installer opinions and estimates. The two new categories are “Assistance for Distressed Customers” and “Operations and Maintenance Providers.” 

Legal Action

The BPU’s action was triggered in part by two cases in which the BPU heard from customers that developers Zenernet and Orbit Energy and Power had stopped responding to the customers and stopped communicating with the BPU’s third-party solar registration manager, TRC Environmental Corp., according to the BPU order. The BPU sent the two developers notices of “suspension and debarment” after they failed to respond to the company’s inquiry into whether they still were in business. 

The BPU last summer also began hearing from customers that Vison Solar, of Blackwood, N.J., had stopped responding to inquiries, eventually prompting the BPU to send a notice of suspension and debarment. 

Vision Solar by then faced a lawsuit, filed by the Connecticut attorney general on Feb. 27, 2023, that accused the company of engaging in “marketing and/or sales tactics that, separately or taken together, cause or influence consumers to execute lengthy and expensive solar contracts without the ability to make an informed, independent choice.” 

Customers suffered unreasonable delays in getting their solar systems activated and “incurred payment obligations to third-party lenders for solar systems they cannot use” because Vision failed to get the necessary permits, according to the suit. The BPU sent the company a letter of suspension and debarment Dec. 3. And a few days later, Vision Solar filed for Chapter 7 bankruptcy and went out of business, Connecticut Attorney General William Tong said in a January release. 

The BPU also sent solar developer Suntuity, of Holmdel, N.J., a notice of suspension and debarment this year after the company did not respond to an inquiry as to whether it still was in business. At the time, the company had “hundreds of incomplete registrations pending,” the BPU said. The Better Business Bureau website also lists multiple consumer complaints against the company.  

Customers in New Jersey, as in other states, have faced extravagant, and sometimes misleading, claims from developers eager to tap into the consumer enthusiasm for clean energy generation and the availability of government incentives to bring down the cost. 

The excessive claims last year prompted the BPU to issue a “scam warning,” which remains on the agency website. It states the agency “does not have a program that offers free solar panel installation for residents of the state. Any claims that such a program exists are false.” The announcement urged consumers to check the incentives listed on its website. 

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Next-gen Geothermal: Clean, Firm, Flexible and Ready for Liftoff

The U.S. may need 700 to 900 GW of clean, firm power to decarbonize the grid even as electricity demand increases, and next-generation geothermal power could pump out anywhere from 90 to 300 GW of that total, according to a new report from the Department of Energy. 

The report is the latest in DOE’s Pathways to Commercial Liftoff series, aimed at providing a road map for commercializing and scaling critical but still emerging clean power technologies. Previous reports have focused on advanced nuclear, clean hydrogen and virtual power plants. 

Traditional geothermal wells are located over existing underground sources of heated brine or other fluids, which produce steam to run turbines; they are, by their nature, limited to specific, often unique geographies. Next-generation geothermal seeks to tap previously inaccessible geothermal heat even deeper underground via injected fluids. 

While still “nascent,” the technology has “a unique value proposition,” the report says. 

“It is clean, firm, flexible; requires a small land footprint and no additional energy input; and is exposed to minimal supply chain risk. It is among the few options that can provide the clean firm power necessary to enable widespread deployment of variable renewables, such as solar and wind energy.” 

Referring to geothermal as “the heat beneath our feet,” Energy Secretary Jennifer Granholm sees next-gen geothermal as an opportunity for the U.S. to “lead the clean energy future with continued innovation on next-generation technologies … [by] cracking the code to deploy them at scale.” 

“With strong public-private partnerships, we can lower costs for this hot technology to expand access for cleaner, more reliable power to communities across the nation,” Granholm said in a press release announcing the report. 

DOE uses next-gen geothermal as an umbrella term for two kinds of emerging geothermal technologies: 

    • enhanced geothermal systems (EGS), which use “commercial directional drilling and hydraulic fracturing capabilities developed by the oil and gas industry to target and create fractures in hot, impermeable rock, allowing fluid to flow where it previously could not”; and 
    • closed-loop or advanced geothermal systems (AGS), which circulate fluids in boreholes in closed pipes. 

With both types, the heated fluids brought to the surface are used to create steam to drive turbines, similar to traditional geothermal. 

While DOE estimates about 40 GW of traditional geothermal resources now exist across the U.S., enhanced geothermal could provide up to 5,500 GW, according to the report. 

DOE believes next-gen geothermal could achieve commercial liftoff — that is, expand at scale and at a competitive price — by 2030 and provide 90 GW of power or more by 2050. Additional advances in technology and available land could drive that total as high as 300 GW, the report says. 

The Opportunity

DOE sees an enormous market opportunity for next-gen geothermal. It can be used for not only clean, flexible and dispatchable power, but as a form of long-duration storage, collecting heat when demand is low and then releasing it when demand is high. 

Next-gen plants could also be “a useful grid asset and a potential generation source for other power users like behind-the-meter industrial centers with high electricity demand, data centers or direct air capture facilities,” the report says. 

The value of geothermal is already being recognized in premium prices. Both traditional and next-gen geothermal projects are signing power purchase agreements for between $70 and $100/MWh, the report says. For example, when the California Public Utilities Commission mandated procurement of 1 GW of clean, firm power by 2026, part of that was 262 MW of geothermal, the report says. 

The U.S. currently has 3.7 GW of geothermal generation, 0.4% of the country’s total capacity. The entire geothermal fleet consists of 93 plants located in California, Nevada, Oregon, Idaho, Utah, New Mexico and Hawaii. At 900 MW, the Geysers in Northern California is the largest geothermal complex in both the U.S. and the world. 

Next-gen technologies are emerging at a time when older geothermal plants are retiring. The life cycle for geothermal plants is about 30 years, the report says. Between 2016 and 2021, seven new geothermal plants, totaling 186 MW, came online, while 11 older plants retired, taking 103 MW off the grid.  

To reach commercial liftoff, “industry must demonstrate that the engineering capabilities [for next-gen projects] can be deployed in greenfield conditions ― i.e., locations with no existing geothermal resources,” the report says. Successful demonstration projects in five to 10 geologically diverse locations would help to reduce technological and resource risk and unlock private investment, the report says. 

DOE estimates that deploying these demonstration projects, totaling 2 to 5 GW across four to six states, will require $20 billion to $25 billion in public and private investments. 

The department wants to be a catalyst. It recently announced $60 million in funding for three enhanced geothermal demonstration projects located in California, Utah and Oregon. The three projects include one being developed near the Geysers in California, one in Utah using hydraulic fracturing technology and the third in Oregon on the side of the dormant but still active Newberry Volcano. (See DOE to Fund Enhanced Geothermal Demo on Oregon Volcano.) 

DOE is also supporting efforts to cut the upfront costs of next-gen technologies through its Enhanced Geothermal Earthshot, which has targeted slashing the cost of EGS by 90% to $45/MWh by 2035 ― a critical benchmark also cited in the Commercial Liftoff report.  

According to the report, current demonstration projects have been able to cut project development costs by almost 50%. Fervo, the company behind the Utah demonstration project, recently announced it had cut its drilling costs from $9.4 million per well to $4.8 million. 

Challenges and Solutions

DOE sees five major challenges for next-gen’s commercial liftoff, as well as a range of possible solutions: 

    • high upfront costs and risks, which are constraining funding for development and limiting expansion into new locations. Solutions include “new financial products to reduce drilling costs, such as public-private cost-share agreements and drilling insurance programs,” along with market signals, like premium-priced PPAs, which could spur investment in early deployments. 
    • perceived and actual operational risks for deployments, which could be mitigated through the strategic siting and data sharing from 10 or more early deployments. 
    • long and unpredictable development cycles driven by permitting and interconnection bottlenecks, requiring streamlining of permitting processes, such as making technology changes that would allow certain permitting steps to occur simultaneously.
    • existing business models that undervalue next-gen geothermal technologies. Possible solutions include policies that support higher-cost, higher-value power and new offtake models that allow developers to use heat for multiple used and value streams. 
    • potential community opposition will require projects to follow environmental and seismic best practices, including “early, frequent and transparent” community engagement. 
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Public EV Charging Gets Boost in California

California’s EV charging network is getting a boost from two different directions: a state program aimed at providing high-density Level 2 chargers in underserved areas and the opening of Tesla’s charging network to non-Tesla vehicles. 

Both developments were discussed during the California Energy Commission’s monthly business meeting March 13. 

The commission voted for a $6 million grant to Los Angeles County to install 300 public chargers in an underserved area of East L.A. The proposal was submitted in response to the CEC’s CHILL-2 solicitation, which stands for Convenient, High-visibility, Low-Cost Level 2 Charging. 

The idea behind CHILL-2 is to increase public confidence in the availability of Level 2 chargers through high-density, high-visibility installations. 

During the same CEC meeting, Chair David Hochschild announced Tesla has begun opening its charging network to non-Tesla vehicles in California. He called the wider access a “really important milestone on our journey to a clean transportation future.” 

“The Tesla network is very well-maintained,” Hochschild said. “The chargers are very fast. The site selection is excellent.” 

Hochschild said the Tesla charging network opened first to Ford EVs, with other makes to be added throughout the year. 

Ford announced Feb. 29 it is providing an adapter needed for its EVs to use Tesla chargers. The adapter is available at no cost to members of the company’s BlueOval Charge Network through June 30. 

As of March 18, Tesla’s website listed Ford and Rivian as EVs supported on Tesla chargers, with General Motors, Volvo and Polestar coming this spring. The company noted many new non-Tesla EVs soon will have built-in North American Charging Standard (NACS) ports and won’t need the adapters.

California had 43,344 public EV chargers and 61,668 shared-private chargers as of March 1, for a total of 105,012, according to a CEC dashboard. Tesla chargers accounted for 62% of public DC fast chargers and 20% of total public chargers, CEC staff told NetZero Insider. 

A draft report from the CEC last year estimated the state will need more than 2 million chargers at public and shared-private locations by 2035 to support more than 15 million light-duty EVs. (See Report Shows Rapidly Growing Need for EV Chargers in California.)

Curbside Charging

In the L.A. County project, at least 300 Level 2 charging ports will be installed at five sites within a seven-square-mile area centered near the Ramona Gardens housing development in East L.A. 

The plan is to install 180 chargers in city-owned parking lots or parking structures and 120 chargers at “community curbside” locations on existing LED light posts. No site upgrades are needed, which will help keep costs down. 

“These chargers will result in a high-density and high-volume deployment that will be publicly accessible to all light-duty electric vehicle drivers,” the commission said in a resolution approving the funding. 

The networked chargers will be tied to other charging infrastructure and a central dashboard, allowing the county to “intelligently implement load management,” according to the scope-of-work for the project. 

The CEC has about $25 million through its Clean Transportation Program to fund CHILL-2 projects. L.A. County will provide a $2 million match.

Another two projects from the CHILL-2 solicitation were approved in February. 

The commission approved $4.6 million for Eneridge Inc. to install 400 Level 2 charging ports at 13 sites in Irvine. Another $5.8 million was approved for FlashParking to install 446 charging ports at 14 sites in Oakland, including two sites with battery storage.

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CAISO, Stakeholders Consider 2 GHG Mechanisms for EDAM

CAISO stakeholders and staff soon could be weighing two options for how the Extended Day-Ahead Market (EDAM) would track and account for greenhouse gases in a way that accommodates the patchwork of different carbon pricing programs across Western states.

Speaking at a March 14 meeting of the ISO’s Greenhouse Gas Coordination Working Group, Doug Howe, GHG policy consultant with the Western Climate Action MOU Group, delved into how the different carbon reduction programs among Western states complicate accounting for GHGs in EDAM. Some states — such as California and Washington — price emissions through cap-and-trade systems while many others seek to limit with “non-priced” GHG programs such as targets for declining emissions for utilities.

“For a standalone utility not in a day-ahead market, compliance would be a relatively straightforward procurement issue,” said Howe, a former member of the Western Energy Imbalance Market’s Governing Body. “In a day-ahead market, compliance would certainly still require the utility to procure the needed resources, but the added complexity is that of imports and exports through the market — specifically, how to account for imports and exports to report on compliance. 

“At a minimum, a thorough tracking and accounting system would be required that provides emissions attribution to all market transfers to avoid over- or undercounting.” 

In contrast to priced programs that place responsibility for compliance on the emitting resource, non-priced programs regulate the load-serving entity and require compliance across a longer time frame, often a year or more. When referring to non-priced programs, Howe excluded renewable portfolio standard programs, which exist in some form in every state in the Western Interconnection except for Wyoming and Idaho.  

Non-priced Challenges

The variety of GHG programs across the Western Interconnection means some states will require utilities to make aggressive emissions reductions as early as 2030 while others face no obligation to reduce.  

One of the main components needed to ensure GHG compliance within EDAM is “control” — or the ability of a market participant subject to a GHG program to have a say in what is imported into and exported out of its area, Howe said. That goes for utilities subject to non-priced programs as well as those operating underpriced programs. 

The variations in average emissions rates among Western states presents a key challenge for designing GHG market mechanisms that satisfy the needs of states with non-priced programs, Howe explained. While the relatively low emissions rates in the Pacific Northwest could help utilities there become compliant with their non-priced GHG mandates, the higher rates in Rocky Mountain and Desert Southwest regions indicate utilities in those regions might struggle to comply with 2030 mandates.

Pointing to patterns already seen in CAISO’s Western Energy Imbalance Market (WEIM), Howe said he expects “GHG competition will emerge” in EDAM, with the priced programs in California and Washington drawing in the lowest-emission resources first.

“This means higher-emitting resources will comprise the bulk of market imports and exports between utilities subject to non-priced GHG programs,” he said. 

“Given how we see the landscape emerging, we took on the exercise of thinking through other options that might allow the utility to garner economic benefits of being in the market without having to self-schedule significant parts of its portfolio, but at the same time have some control of the carbon content of its market imports and exports to ensure compliance,” Howe said.  

Howe presented two mechanisms to address the problem: the emissions constraint method and an import constraint method. 

In the emissions constraint method, a non-priced GHG zone establishes a maximum emissions rate for the dispatch interval and the market optimization chooses which resources’ energy and emissions will be attributed to priced zones.  

“It’s important for me to say that this method does not attribute only resources that can meet the specific emission rate. Rather, it selects resources that, as a pool of resources, can meet the maximum emission rate and energy requirements of the non-priced GHG zone,” Howe said. “A higher-emitting resource could be dispatched, be assigned to the non-priced GHG zone and be offset by a lower-emitting resource.” 

A non-priced GHG zone would operate under a must-offer obligation, meaning it’s obligated to offer a portfolio of generation that meets its load and the maximum emission rate set for the interval. Whenever the emission constraint is enabled, the must-offer obligation must be met.  

This method produces both an energy marginal cost and a GHG marginal cost, with resources attributed to the non-priced zone would be receiving payment from load for both costs, raising what Howe identified as a central policy question: whether the GHG marginal cost should be paid to generators.  

To address that question, Howe presented the second mechanism: the import constraint method.  

“Are there some ways that we can maybe avoid that kind of GHG marginal cost policy question of, ‘Should it be paid or should it not be paid?’ Because it’s a very thorny question,” he said.  

The import constraint method has many similarities to the other method, including allowing the utility to specify the maximum emissions target with a must-offer obligation and not requiring the constraint in every interval. The difference, though, is that external resources would not be attributed to non-priced GHG zones, which “effectively moots” the question of whether attribution should be voluntary. Instead, emissions attributed to non-priced zones would be computed as emissions from internal generation and market imports, minus emissions from exports.  

“In this case, the optimization will choose the internal generation and the amount imported and exported to minimize the total system costs while still meeting the maximum emission rate,” Howe said. “But to do this, we have to establish an imported emissions rate and an exported emissions rate, very much like the residual emissions rate” the Western Power Trading Forum (WPTF) discussed in another presentation.  

Residual Emissions Rate

“We really believe that we should have a long-term goal of developing a better tracking and accounting system for the market to accurately account for energy and to accurately account for emissions,” Clare Breidenich, assistant executive director at WPTF, said in presenting another approach for GHG accounting.  

Central to Breidenich’s proposal was use of residual market supply — energy not committed to market participants or attributed to GHG regulation areas. It determines the residual emission rate, a dispatch-weighted average emission rate of the market supply.  

If the market can ensure that entities are able to claim and procure their own resources to meet load, Breidenich said, then what is left is a relatively small increment of energy, which is the residual market supply.  

“If we can do a better job accounting for that increment of energy, as well as do a better job of accounting for the emission rate of that increment, it’s not clear to us that there really is a need for a dispatch mechanism,” Breidenich said.  

Power producers first need to agree on a set of accounting rules and an emission rate that determines what is in the residual supply, then determine how to match resource claims to dispatched energy and associated emissions and place them into entity accounts for correct attribution. Lastly, a reporting and publication system would be needed for producers and regulators.  

Under this framework, leftover energy in the market would go into the residual supply, and the emissions rate would be the average of the residual mix.  

The benefit of this approach, Breidenich said, is that it ensures all entities subject to GHG regulations can account for energy and emissions without imposing requirements or costs on LSEs and energy users in non-GHG areas.  

Regardless, she said, CAISO staff and stakeholders need to have a unifying assumption for how to treat attribution of energy and emissions throughout the states.  

“I appreciate the point about ensuring that we’re able to capture the generation associated with those non-price-based states that don’t have a clean energy policy in place,” said Anja Gilbert, lead policy developer at CAISO. “This is a recommendation put forth, but the states are going to have to opine in terms of, does this meet their requirements? And so, I’m really seeing this as [a situation in which] there could be multiple approaches just based on what different states choose to adopt.” 

But Mary Wiencke, executive director of Public Generating Pool, questioned whether the accounting framework could be applied consistently across states.  

“Within this framework, there may be areas of users’ choice that we can identify and then work within that framework with states to work toward consistency,” Wiencke said. “I also think there may be areas that just can’t be reconciled between different state policies.”  

Despite unresolved questions, stakeholders concluded on a positive note.  

“I know there’s a lot here, and this does imply a lot of work … but now is the time to start getting the accounting system right,” Breidenich said.  

“I think it’s a step beyond a lot of what we’ve been thinking about in terms of leveraging averages and data to really support some of the transfer attribution that we see through the market,” said Pamela Sporborg, director of transmission and market services at Portland General Electric. “I actually have hope for maybe the first time ever.”