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November 4, 2024

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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.”

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‘Sprint’ Over, Markets+ Regulators Eye Next Phase

Program management “sprints” within the high-tech sector have little on SPP Markets+ stakeholders’ work developing a market tariff, says Oregon Public Utility Commissioner Letha Tawney. 

High-tech sprints normally last four weeks, the Markets+ State Committee’s (MSC) vice chair said during a March 15 conference call with other Western regulators. 

“What we’ve had here is a 10- or 11-month sprint,” Tawney said. “It’s been really challenging for the SPP staff. Very challenging for them, but also it really asked a lot of the state agencies in a way that we’ve not tried to engage in the West before. We’ve not tried to tackle a whole tariff all at once in this way.”  

Tawney is hopeful the process will get smoother “more like our other engagements with regional organizations in the West, where we can go a little deeper, be a little more methodical.” 

No worries there. With the tariff approved by Markets+ stakeholders and going before SPP’s Board of Directors next week for final consideration before a FERC filing, stakeholders will focus on the more technical work of drafting protocols and rules. 

Reflecting on Tawney’s comments, Gia Anguiano, the Western Interstate Energy Board’s government relations specialist and the MSC’s staff secretary, said the next phase of Markets+ will be anything but a sprint. 

“We’ve been very deep in the tariff development process, but this protocols phase is the next level down. It’s going to be a bit more technical and in the weeds,” she said. 

SPP’s timeline would have that work completed by year’s end, along with expected FERC approval of the tariff early in the fourth quarter. 

The MSC staff will prepare potential comments from the regulators on the FERC filing. The committee plans to begin a conversation on the comments rather than wait for the tariff to be filed. 

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FERC Rejects Tri-State Rates for Failing to Unbundle Ancillary Services

FERC on March 15 rejected Tri-State Generation and Transmission Association’s proposed rates, ruling the cooperative failed to unbundle ancillary services, which has been required for jurisdictional utilities since Order 888 was issued in 1996 (ER23-2171-002). 

Tri-State’s 42 utility members have contracts through 2050 and are spread among Colorado, New Mexico, Wyoming and Nebraska — in both the Eastern and Western interconnections. The co-op uses 5,849 miles of high-voltage transmission lines, mostly in the Western Interconnection, and 4,400 MW of generation. It has been a FERC-jurisdictional utility only since September 2019, and its initial rate filings have been going through commission proceedings since then.

The co-op proposed unbundling generation and transmission but made no proposal to unbundle ancillary services under the formula rate it filed in June. It claimed it could not unbundle ancillary services because it does business in five different balancing authorities and does not control its own.

Except for Schedules 1 (Scheduling and Dispatch) and 2 (Reactive Supply and Voltage Control), Tri-State purchases ancillary services from the balancing areas it operates in and passes those charges through its rates without regard to geographic areas. The co-op said it would be impossible to accurately determine exactly which services purchased from the BAs are used by its specific members. 

“Tri-State asserts that separately stating the prices for just the ancillary services under Schedules 1 and 2 aligns with the spirit of Order No. 888, which Tri-State notes aimed to ensure that utilities provide non-discriminatory service,” FERC said. “Tri-State argues that, for the remaining ancillary services, it does not self-supply all of those services itself and does not sell those ancillary services to third parties.” 

But FERC found that in order to comply with Order 888, Tri-State must state prices separately for its wholesale service components. When it was considering unbundling in the leadup to 888, the commission heard similar complaints about the difficulty of figuring out the costs and beneficiaries of specific ancillary services, but none of those reasons proved compelling, it noted.

Unbundling makes a more equitable distribution of costs possible because customers that take similar amounts of transmission service may require different amounts of some ancillary services, FERC said. Bundling would result in some customers having to subsidize others. 

“We are unpersuaded that Tri-State cannot meet, and should therefore be relieved from, Order No. 888’s requirements,” the commission said. “Although it may be more difficult for Tri-State to track costs for other ancillary services, further efforts could be made to comply with the requirements of Order No. 888 to separately state prices for certain ancillary services.” 

FERC also rejected Tri-State’s proposal for rolled-in rate treatment, which would allow it to recover through the transmission rate all the costs of its non-networked transmission facilities and third-party transmission arrangements used to provide wholesale power service to utility members. But FERC said that the co-op could come back with more support for a rolled-in rate treatment.

“We find that, for the most part, Tri-State’s proposed rolled-in rate treatment appears to be consistent with the cost-causation principle, as the benefits accruing to Tri-State’s utility members appear to be at least roughly commensurate with the costs they bear,” the commission said. 

Some protesters argued that Tri-State’s arguments about its integrated planning process are repackaged versions of its “cooperative model” that it used to argue against unbundling all ancillary services. But FERC said that Tri-State has shown its integrated planning provides benefits to all utility members, which supports its proposed cost allocation. 

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New Jersey Lawmakers Back $250 Annual EV Fee

New Jersey legislators sent a bill to the governor’s desk March 18 that would place a $250-a-year fee on zero-emissions vehicles, brushing aside criticism from environmentalists and car dealers that the fee would hinder electric vehicle sales. 

The Senate voted 24-14 to approve the bill, A4011, which would revise the New Jersey Transportation Trust Fund Authority Act to increase revenue to help support state transportation infrastructure and mass transit expenses. The state Assembly voted 48-28 to support the bill, which includes an increase in the state gas tax and revises the way in which it is levied. 

Gov. Phil Murphy’s (D) office did not immediately respond to an inquiry as to whether the governor would sign the bill. 

Starting July 1, 2024, buyers of zero emissions vehicles would pay $250 a year to $290 a year when a vehicle is registered initially or is renewed. The fee in the first year would be $250, rising $10 a year until it reaches $290 a year in the fourth year, and stops increasing. Buyers would have to pay the fee for four years at once, for an upfront payment of more than $1,000. 

Supporters see the bill as a way to increase investment in state transportation and to secure revenue from EVs and other zero-emission vehicles that otherwise might not contribute because they don’t pay the gas tax. But opponents said the fee — coupled with Gov. Murphy’s plan to make EV buyers pay state sales tax, from which they currently are exempt — would hamper EV sales. (See NJ Bill Would Levy Annual Fee on EV Ownership.) 

“Clearly, the state’s aggressive EV mandates are on a collision course with our fiscal realities,” said James Brian Appleton, president of the New Jersey Coalition of Automotive Retailers. 

“No one disputes the notion that EV drivers must pay their fair share to maintain roads and bridges or that some form or some amount of user fee must be paid,” he said. “Consumers will not react well to this and shrinking EV incentives. And adding more than $1,000 to the upfront purchase price of a new electric car will render the governor’s goal of 100% EV sales in New Jersey unachievable.” 

Doug O’Malley, state director for Environment New Jersey, said the bill — if Murphy signs it — would give the state one of the highest EV fees in the nation. He said the bill, which was introduced March 4, has moved like “greased lightning” through the Legislature. He speculated the sponsors wanted to get it approved before the state budget season begins in earnest in the next few weeks. 

“This is a real setback for EV drivers. This is essentially a $1,000 tax that could well dissuade potential EV drivers from making the switch,” he said, adding it’s an upfront fee that gas vehicle buyers don’t have to pay. 

“It’s the opposite of a pay-as-you-go system,” he said. “No one pays the gas tax upfront for four years.” 

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Counterflow: Hair (and Pants) on Fire

Steve Huntoon | Steve Huntoon

Washington Post headline: “Amid explosive demand, America is running out of power.” 1 

The long article cobbles together charts without context, cites states with relatively high electric demand and quotes from all manner of folks. 

Missing are the entities that actually know whether there is “explosive demand” and whether “America is running out of power.” 

These entities are NERC and the RTOs like PJM that manage generation supply-demand and bulk transmission for most of the country.2 But why ask the experts? 

Explosive Demand?

Regarding “explosive demand,” please look at this NERC graph that shows forecast summer and winter peak demand annual growth rates for the next 10 years.3 The lines show the compound annual growth rate (CAGR) values on the right-hand axis. Do you see the most recent 10-year growth rates of 1.0% summer and 1.2% winter? And do you see how much higher these growth rates were from 1995 to 2014? So yes, demand growth is increasing — but at a relatively small rate in absolute and relative terms. 

10-year summer and winter peak demand growth and rate trends | NERC

Running out of Power?

As for America “running out of power,” here’s another NERC chart showing projected new Tier 1 and 2 generation resources over the next 10 years.4 Around 370 GW by 2033. This is a staggering amount of new generation relative to existing generation resources of 1,300 GW.5

Tier 1 and 2 planned resources projected through 2033 | NERC

Will all of it get built? No. Will the renewable (intermittent) resources have the same reliability value and load factor as dispatchable (firm) resources? No — I’ve written about their limits ad nauseum.6 Are there challenges that need to be worked through to ensure the energy transition does not degrade reliability? Yes. Crisis? No. 

Georgia

Georgia is the poster child for the Post article, where the major utility there, Georgia Power, projects increased demand from various sources.7 But is there a crisis? No. Georgia Power identifies eight measures to address the increased demand, including power purchase agreements with generators in Mississippi and Florida, expanding battery storage, building additional simple-cycle combustion turbines, and expanding distributed energy resource and demand response programs.8 Where’s the fire? 

Distracting from the Real Work at Hand

Articles like the Post’s distract from the real work at hand. Here are a few no-brainers I’ve flagged before:  

(1) Keeping existing nuclear plants open. Thank goodness Diablo Canyon was saved, as I pleaded for eight years ago;9  

(2) banning cryptocurrencies (especially “proof of work” crypto like Bitcoin), which have nothing but negative externalities like emissions, ransomware enabling, money laundering, drug smuggling and human trafficking; 10  

(3) rational onshore wind instead of irrational offshore wind, which costs at least twice as much per MWh;11

(4) rational grid solar instead of irrational rooftop solar, which costs five times as much per MWh;12  

(5) high-voltage interconnections between Texas/ERCOT and the rest of the country;13   

(6) unique emergency ratings for generation interconnection studies (and dispatch);14   

(7) new (but known) technologies for increasing capacity of existing transmission lines;15   

(8) not wasting money on green hydrogen electricity;16 and, dare we keep saying it,  

(9) carbon pricing.17 

The flip side of good public policies is bad public policies, such as premature closure of dispatchable resources (a threat that goes unaddressed in the Post article). Bad public policies can create a crisis that would be otherwise avoidable. But we shouldn’t assume we’ll foolishly create a self-inflicted crisis. 

A Last Word

In my humble opinion, the damage from an article like the Post’s goes beyond distracting us from the real work at hand. It adds to the collective trauma from all the big things we already worry about, like climate change, artificial intelligence, politics and international crises.  

We have plenty to worry about. Enough already.  

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

1 https://www.washingtonpost.com/business/2024/03/07/ai-data-centers-power/

2 As an example the most recent PJM load (demand) forecast is here, https://pjm.com/-/media/library/reports-notices/load-forecast/2024-load-report.ashx. Load growth attributable to electric vehicles and data centers is accounted for.

3 https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf, Figure 25.

4 NERC report, Figure 16.

5 https://www.publicpower.org/system/files/documents/Americas_Electricity_Generating_Capacity_2023_Update.pdf. This is U.S. generation capacity and does not include Canada.

6 https://energy-counsel.com/wp-content/uploads/2022/11/More-Happy-Talk.pdf; http://energy-counsel.com/docs/No-Carb-California.pdf; http://energy-counsel.com/docs/German-La-La-Land.pdf; http://energy-counsel.com/docs/Cue-the-PixieDust.pdf.

7 https://www.georgiapower.com/content/dam/georgia-power/pdfs/company-pdfs/2023-irp-update-main-document.pdf

8 IRP report, pages 2-3.

9 My column on the insanity of closing Diablo Canyon is here, http://energy-counsel.com/docs/Helter-Skelter-September-Fortnightly.pdf. No such luck with saving Indian Point which closure I showed would cost New Yorkers $830 million/year, http://energy-counsel.com/docs/New-Yorks-Surreal-New-Deal.pdf

10 https://energy-counsel.com/docs/The-New-Technoking-and-His-Bitcoin-Crown.pdf; https://energy-counsel.com/wp-content/uploads/2022/04/Stop-the-Insanity.pdf.

11 https://www.energy-counsel.com/docs/we-see-through-a-glass-darkly.pdf, item 3 and sources cited there.

12 Same column, item 4 and sources cited there.

13 https://www.energy-counsel.com/docs/a-modest-proposal.pdf; https://energyathaas.wordpress.com/2022/01/31/the-most-obvious-way-to-avoid-another-texas-blackout.

14 https://energy-counsel.com/docs/waste-not-what-not.pdf; tangible comments in the FERC rulemaking are here, https://elibrary.ferc.gov/eLibrary/filedownload?fileid=15740097.

15 https://www.epri.com/research/products/000000003002023004; https://energy-counsel.com/wp-content/uploads/2022/06/Transmission-and-Technology.pdf (penultimate paragraph).

16 https://energy-counsel.com/wp-content/uploads/2023/12/Hydrogen-Reality.pdf.

17 “‘If we don’t put that price of carbon on the system, I don’t see how anything could work,’ Harvard economist William Hogan said in the last session of the daylong conference.” https://www.rtoinsider.com/articles/29867-epsa-members-renew-call-carbon-price.

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Stakeholder Soapbox: PJM Moves to Wipe Out Energy Efficiency When It’s Needed Most

By Bo Clayton

After nearly two decades of flat load growth, U.S. electricity demand is rising. Fast. The boost in domestic industry related to the growth of data centers and increased economywide electrification is driving operators to revise load forecasts and scramble to flag concerns about future capacity insufficiency.  

They are right to be concerned: This new load is coming onto the aging grid far faster than solutions to handle that demand. New generation takes years to get through the backlogged interconnection queue; new and expanded transmission capacity even longer. We need to be using every tool in our toolbox to help meet these challenges — and energy efficiency is critical to ensuring we can do this effectively and affordably.   

Bo Clayton | Bo Clayton

For at least half a century — since the 1970s U.S. energy crisis — energy efficiency has been America’s cheapest, most reliable source of energy. Even as modern, clean technologies like solar PV, wind energy and battery energy storage have tumbled down their cost curves, megawatts of efficiency remain a winning bet for states and their utilities.  

A recent Lawrence Berkeley National Laboratory study confirms energy efficiency plays a significant role in many states. These energy efficiency programs range from major industrial-scale efforts to reduce consumption to hundreds of millions of residential customers around the country installing products and taking actions that, in aggregate, save a lot of energy and money.   

Rather than identifying ways to promote further efficiency in its footprint, the nation’s largest grid operator — PJM — inexplicably is taking the opposite approach. PJM is pursuing imminent changes that effectively will gut energy efficiency across its region, precisely at a time when those gigawatts of capacity are needed more than ever.   

PJM is seeking to bypass its standard stakeholder process to make a “quick fix” to its rules governing energy efficiency. PJM’s hasty proposal, which will be voted on at its Markets and Reliability Committee meeting March 20, essentially would invalidate a majority of states’ energy-efficiency programs by establishing an arbitrary timeline for when PJM thinks states should update their own energy-efficiency guidelines. (See PJM MIC Briefs: March 6, 2024; and PJM Seeking Expedited Approval of Energy Efficiency Changes.)   

PJM didn’t bother to explain which state programs would be impacted or provide support for its concern about how states are running these programs. This is irresponsible at best and outright disrespectful of state programs and efficiency progress at worst.  

In parallel, it effectively would eliminate the ability to aggregate energy efficiency through big box retailers, removing the primary means of energy efficiency participation in PJM to date. This could significantly hamper consumer adoption of energy efficiency solutions such as LED light bulbs and spray foam insulation.  

Make no mistake: PJM should revisit its rules governing efficiency’s participation in the capacity market. Much has changed in the 17 years since these rules first were adopted.  They are outdated and due for overhaul. But the process to do so must be transparent, inclusive and thoughtful.   

PJM isn’t even planning to allow its regulator — FERC — to have a say on the changes. That leaves it up to the PJM stakeholders to push back. If you are a stakeholder, I urge you to pursue the harder but better approach: Send the issue back to lower committees for thoughtful deliberation including PJM staff, states and others with a stake in the outcome. Anything less flies in the face of PJM’s own commitment to consensus-based issue resolution, to the detriment of consumers and grid reliability. Moreover, PJM will be abdicating its place at the forefront of energy innovation.    

This is not the time for PJM to erase decades of progress on energy efficiency by hastily implementing an ill-conceived rule change with far-reaching ramifications.  

Bo Clayton is the CEO of American Efficient, a developer of energy efficiency resources with 10 years of operating history in PJM.