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November 19, 2024

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Targeted Electrification ‘Promising but No Silver Bullet’ for Gas Cost Dilemma

Targeted electrification could allow decommissioning of up to 10% of gas distribution mains, representing “a promising strategy but not a silver bullet to solve the long-term gas cost challenge,” researchers told the California Energy Commission.  

At a Feb. 28 workshop, Energy and Environmental Economics (E3), nonprofit Ava Community Energy and Gridworks presented the results of CEC-funded research on whether pairing gas decommissioning with targeted building electrification — transitioning whole neighborhoods to electric rather than having a mix of services — could provide gas system savings while promoting equity and meeting community needs.  

As building electrification advances, gas system costs will spread across fewer customers, leaving renters and low-income homeowners who cannot afford to electrify the most vulnerable, a “major equity concern,” E3 Associate Director Ari Gold-Parker said.  

“We think this approach could be part of what we’re calling a ‘managed transition’ to reduce gas system spending and help to manage gas rates in the long term,” he said.  

E3 and its partners said their research found 5-10% of gas distribution main miles could be decommissioned to save money over the next 20 years. To be eligible, lines must be “hydraulically feasible” — able to be removed without impacting gas system safety and reliability — such as mains at the end of radial systems. The team also targeted lines with the highest scores for operational risks — those most likely to need replacement within a decade. 

“Even though this is a fairly small share of total main miles, these projects still reflect a very important opportunity to avoid a large share of the capital cost that would otherwise be incurred on the gas system during this time period,” Gold-Parker said.  

The researchers concluded that combining targeted electrification with gas decommissioning can provide net benefits to the state, electric ratepayers and gas ratepayers. But they said there is a significant funding gap for the upfront costs of electrifying buildings, calling it the “missing money.”   

In addition to high upfront costs, other challenges include customer preferences and current policies and regulatory rules, they said. 

Identifying Sites

The first step of the research project was to develop a framework for finding potential sites for targeted electrification. From 11 candidate sites, the team proposed three pilot sites in Ava Community Energy’s service territory: East Oakland (an urban single-family, disadvantaged community with 70 gas meters); Oakland-Allendale (a mix of single-family, multifamily, and nonresidential buildings with 110 gas meters) and San Leandro (a suburban single-family disadvantaged community with 190 gas meters). The CEC grant did not include funding for implementation; the project team said in their June interim report that they plan to apply for funding to implement one or more pilot projects. 

The team used Pacific Gas and Electric’s gas asset analysis tool to help them find areas that will likely need pipeline replacement. But the team said it needs a longer-term planning process to identify sites with enough lead time to implement electrification. Gas utilities identify these projects on the timeline of the general four-year rate case, but the researchers said a 10-year planning process was more appropriate.  

Next, the team performed site-based benefit-cost analyses.  

To address the “missing money” for the upfront costs of electrifying buildings, the team suggested repurposing savings to fund electrification, though that option could reduce long-term savings to gas ratepayers. “Even though this approach works on paper and might be valuable in the near-term, in the long term this approach would really undermine the potential for gas decommissioning projects to support the key equity objective of providing long-term cost reductions for gas ratepayers,” Gold-Parker said.  

The greatest financial benefit will come from avoiding pipeline replacements. The study found that gas decommissioning will be the most cost-effective in less dense neighborhoods due to the cost of electrification. “While two gas decommissioning projects with the same length of gas mains will have the same gas pipeline savings, the costs of implementing a gas decommissioning project would be higher in a site with more dense development (i.e., with more customers to electrify),” the researchers said in their benefit-cost analysis.  

Moving `at the Speed of Trust’

Ava Community Energy, which sells renewable energy in the East Bay, led efforts to engage its communities, including partnering with a community-based organization and the city of Oakland to host home energy resource fairs.  

While the resource fairs provided educational opportunities for residents unfamiliar with electrification, Allison Lopez, senior analyst at Ava Community Energy, said attendance was very low.  

“This could be for various reasons. Perhaps even the topic of electrification or home energy savings is a bit too foreign or novel to boost interest,” Lopez said. “While we think events like this have great potential, we found it very difficult to scale awareness about this project or gain feedback through this channel.”  

Ava also partnered with Environmental Justice Solutions to assemble paid focus groups for residents in the proposed pilot sites. While attendance again was low, Lopez said they received good feedback. 

Focus group participants expressed concern over the cost of electrification, increased electric bills and a lack of familiarity with electric equipment. Lopez said Ava is prioritizing affordability, working on improving communication and education, and building trust.  

“We heard repeatedly that communities move at the speed of trust,” Lopez said. “It really takes a lot of time to build and maintain trust.” 

For the plan to work, all pilot project site residents will need to consent to electrification, making implementation “extremely challenging,” Lopez said.  

Recommendations

In addition to a longer-term capital project planning process and funding to address the upfront costs of electrification, the researchers called for better data and planning tools for site selection, and changes to utilities’ “obligation to serve.” 

“In the current regulatory paradigm, utilities contend that 100% customer opt-in is required to decommission gas infrastructure. This requirement means large sites with many customers may prove difficult or impossible to implement gas decommissioning and even small sites may require substantial financial incentives to achieve 100% opt-in,” the researchers said. “Any gas system decommissioning projects pursued in the next few years will need to consider ways to work within the obligation to serve. In the longer term, California will need to evolve the obligation to serve to ensure it does not become a barrier to the state’s decarbonization goals.” 

The researchers said the state and its utilities need a long-term plan for gas infrastructure aligned with the state’s climate goals. They noted the California Public Utilities Commission’s Long-Term Gas Planning proceeding “is entering a new phase focused on long-term planning for gas system decarbonization.” 

“Clear plans and targets could provide key regulatory support for alternatives to gas pipeline replacement,” they said. “Long-term planning should consider the role of targeted electrification and gas decommissioning as part of a portfolio of measures to reduce gas system investments and mitigate long-term cost pressures.” 

Next Steps

Ava is developing a deployment plan proposing a phased approach over a 10-year span beginning with community engagement.  

“We recognize that this approach will take a lot of time and there will definitely be less certainty about whether customers will ultimately decide to remove gas service,” Lopez said. “But we believe this approach is in line with community feedback that we’ve received.”  

The researchers noted their project considered two “important but distinct” equity goals: promoting electrification in disadvantaged communities and maximizing gas system cost savings.  

“We believe the state may achieve better outcomes by developing and promoting different programs for these two goals,” they said. 

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ISO-NE CLG Highlights Importance of Demand Response

Speakers at the ISO-NE Consumer Liaison Group (CLG) meeting March 6 stressed the importance of proactive efforts to unlock the potential of demand response and peak shifting, as electrification is projected to double New England’s peak loads in coming decades.  

The CLG met in Portland for its first quarterly meeting of 2024 and featured discussions on the benefits of widescale load shifting, along with the barriers that prevent the realization of those benefits. 

Andrew Landry, deputy public advocate for Maine, called demand response “an important tool that we need to take advantage of to the maximum extent.” 

Landry cited ISO-NE’s projection of a 57-GW peak load in 2050, as well as the RTO’s finding that limiting this peak to 51 GW would save about $9 billion in avoided transmission upgrades. 

“If we can find ways to reduce the demand, even with the amount of electrification that’s going on, it would reduce the need for transmission,” Landry said. 

He highlighted FERC data showing demand response makes up a significantly lower percent of total installed capacity for ISO-NE compared to CAISO, MISO, NYISO and PJM. 

Eric Johnson of ISO-NE echoed the importance of reducing demand but added that “there’s a lot of infrastructure challenges that need to be resolved.” He noted that the FERC data does not include the region’s significant energy efficiency gains. (Report: Many US Utilities not Delivering on Energy Efficiency.) 

Jill Powers of CAISO presented to the CLG about load-shifting efforts in California, where demand response surpasses all other RTOs by percent of installed capacity. Powers said demand response programs have helped the state avoid rolling blackouts during grid stress events and emphasized the role of both in-market and out-of-market mechanisms to engage a wide range of customers. 

“It’s not just at the wholesale level that we need to be collaborating” to unlock demand flexibility, Power said.  

She outlined two out-of-market programs in California that incentivize demand reductions during peak hours: the Demand Side Grid Support Program and the Emergency Load Reduction Program. The programs are not administered by CAISO, but they do respond to real-time and day-ahead signals from CAISO. 

“We believe that demand can provide responses similar to a flexible resource, helping to balance the grid,” she said.  

The CLG also featured a panel of New England stakeholders, who focused on the role of ISO-NE in increasing demand response efforts within the region. 

Doug Hurley, vice president of policy at Icetec Energy Services, stressed that peak demand reductions from one electricity customer on the grid provides benefits to all customers by reducing the clearing price, limiting emissions associated with peaker plants, and ultimately reducing the need for new transmission investments.   

Hurley said the region needs to align state demand programs and retail rate design with optimal times to charge and discharge batteries — such as at night or midday when cheap solar power is available — to better balance load and reduce emissions. 

He also called out ISO-NE’s compliance proposal for Order 2222 as a “missed opportunity” to increase the participation of flexible demand resources in its markets, saying the “compliance to date will not achieve any participation.” (See FERC Accepts ISO-NE Order 2222 Compliance Filing.) 

Ian Burnes of Efficiency Maine Trust agreed with Hurley’s criticism of ISO-NE’s Order 2222 compliance and called on ISO-NE to help ease the barriers for small resources to participate as demand response resources. 

“We have a lot of work to do here,” Burnes said. “It’s very, very difficult to aggregate lots of small assets and have them participate.” 

Burnes added that significant investments in physical infrastructure to enable residential customers to receive and respond to incentives to shift their demand will be necessary.  

“I do not want to trivialize that investment — it is going to be hard,” Burnes said. “I think that needs to be our focus.”

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SEC Scales Back GHG Reporting, Climate-risk Disclosure Rules

The Securities and Exchange Commission voted 3-2 on March 6 to approve new rules that will require only very large companies to disclose some of the greenhouse gas emissions they generate. The catch is that disclosure will be required only if the emissions are “material,” that is, information investors need to make informed decisions about buying or selling the company’s stock.

This and other provisions in the final rules represent a major rollback from the more rigorous proposed rule the commission released almost two years ago, which would have required all publicly traded U.S. companies to report the full range of emissions generated by their operations and supply chains.

According to the SEC, the rule proposed in March of 2022 would have required an estimated 7,000 publicly traded U.S. companies and 900 foreign companies to report on Scope 1 and 2 emissions from their direct operations and energy use, respectively, and on indirect Scope 3 emissions from their supply chains.

Emission reporting requirements in the final rule have been whittled down, depending on company size, determined by the amount of their “public float” or the amount of stock held by public investors. Small and medium-sized companies, with less than $75 million in publicly held stock, are exempt from any emission reporting.

Very large companies, with more than $700 million in publicly held stock ― called large-accelerated filers (LAFs) ― will have to report their material Scope 1 and 2 emissions, as will companies classified as accelerated filers (AFs) with $560 million in publicly held stock.

In another major change, the new rules set up a phased-in reporting schedule, with LAFs not required to start reporting emissions until their fiscal years beginning in 2026. Reporting for AFs is pushed back to fiscal years beginning in 2028.

A limited level of independent verification of emission reporting, called “assurance,” will not be required for LAFs until 2029 and for AFs until 2031.

The 2022 proposed rules would have begun reporting in the year following approval.

Speaking on background, an SEC spokesperson explained the rollback as the result of the large number of comments the SEC received raising concerns about the cost of Scope 3 reporting and arguing that at present, methods of determining supply chain emissions would not provide reliable disclosure.

Corporate reporting requirements on climate-related risks — such as the financial impacts of extreme weather events or a company’s own climate-related targets or goals — also have been eased, according to the SEC.

Instead of requiring companies to disclose the impact of extreme weather events on specific line items in their financial statements filed with the SEC, the new rules call for financial statements to include only “notes” on capital costs, other expenditures and losses due to extreme weather.

Instead of requiring detailed information on a company’s climate-related targets and goals — scope, timelines, yearly progress — reporting on climate targets and goals will depend on whether they have “material” impacts on a company’s business strategies, operational results and financial condition.

Couched in financial jargon, the rule’s ongoing references to material impacts can appear like so many loopholes. For example, climate-related risks must be reported only if they “have had or are reasonably likely to have a material impact” on a company’s business strategy, operational results or financial condition. Whether such impacts are material could depend on a company’s own analysis of relevant “facts and circumstances.”

But SEC Chair Gary Gensler said materiality is a standard widely used in financial markets and reporting, backed by long-standing Supreme Court decisions. Information is deemed material if it would be likely to alter the investment or voting decisions of a “reasonable investor.”

He sees the rule’s grounding in materiality as a key point for its validity and legality, and an argument in its defense.

A 50-year History of Disclosures

The SEC has been requiring various levels of environmental disclosures for 50 years, most recently in 2010 when the commission issued guidelines for compliance on the issue, according to a commission fact sheet. The proposed and final rules are described as a continuation of SEC’s efforts “to respond to investor need for more consistent, comparable and reliable information about the financial effects of climate-related risks on [companies’] business” and how companies are managing that risk.

The release of the proposed rules on March 21, 2022, triggered an outpouring of comments, which required the SEC to extend the comment period once and then reopen it after a technical glitch resulted in comments submitted online not being received. More than 24,000 comments were received, including a last-minute flurry of 8,100 comments in the 72 hours preceding the commission’s meeting, Gensler reported during a post-meeting press call.

In his opening remarks at the meeting, Gensler noted that 90% of companies in the Russell 1000 “are publicly providing climate-related information,” and close to 60% also are providing public information on their GHG emissions. The Russell 1000 is a Seattle-based stock index covering 1,000 of the largest companies in the United State.

However, these disclosures often are made in corporate sustainability reports, not standard SEC filings, Gensler said. Integrating climate-risk information into SEC filings “will help make them more reliable. There are standard controls and procedures for filings, unlike for sustainability reports.”

Gensler also stressed that the SEC and all its rules are “merit-neutral,” and in this case, “that means we’re neutral about climate,” he said during the press call. “You can use this disclosure … to sell something that’s a green asset or buy it.

“We’re agnostic with regard to climate risk. We’re also agnostic on how companies manage climate risk,” he said. “We’re not agnostic about disclosure of material risk.”

Reflecting that neutrality, the 886-page final rule carefully avoids even mentioning climate change, referring throughout to “climate-related risk.”

The Split Vote

But the 3-2 vote signaled a clear ideological split on the commission, with Commissioners Caroline Crenshaw and Jaime Lizárraga joining Gensler with votes to approve, and Commissioners Hester Peirce and Mark Uyeda in opposition.

Peirce slammed the final rule as fundamentally flawed due to “its insistence that climate issues deserve special treatment and disproportionate space in commission disclosures and managers’ and directors’ brain space, because the commission fails to justify that disparate treatment.

“The rules’ anticipated benefits do not outweigh the costs,” she said. “Proponents of a commission climate rule hope that it will yield more accurate, comparable and complete climate disclosures. If we do not look at it too closely, the final rule may appear to fulfill these hopes, but a closer inspection brings us crashing back to the reality that many climate disclosures are high-price guesses about the present and future.”

Peirce also said the changes in the final rule were so substantive the commission should have reproposed it and once again gathered public comment.

Uyeda was equally critical, arguing that the rule represents regulatory overreach and “is the culmination of efforts by various interests to hijack and use the federal securities laws for climate related goals. In doing so, they have created a roadmap for others to abuse the commission’s disclosure regime to achieve their own political and social goals. …

“The result is using disclosure not as a tool to aid investors but to bypass Congress to achieve political and social change without the corresponding accountability to the electorate,” he said. “The commission is a securities regulator without statutory authority or expertise to address political and social issues.”

Arguing that the rule’s requirements for climate-risk disclosure are without precedent in the SEC’s previous disclosure requirements, Uyeda invoked the recent Supreme Court decision in West Virginia v. EPA and its “major question” provision that “an agency must cite something more than merely plausible textual basis for its action.

“The agency must instead point to clear congressional authorization for the power it claims, and the commission has not done so for this rulemaking.”

Crenshaw countered, “The commission has clear authority under the Securities Act and the Exchange Act to require disclosures that are in the public interest and for the protection of investors, as today’s rule is. This well-established authority has been consistently relied upon and affirmed and reaffirmed across dozens of disclosure rule makings over multiple decades. …

“Our public company disclosure regime is meant to be updated as markets innovate and investor demand changes,’ she said. “SEC rules have consistently required disclosure of risks even when the metrics related to those risks are labeled by some as not strictly financial, such as the greenhouse gas emissions.”

While voting for the rule, Crenshaw called its rollbacks on emission and other climate-related risk reporting “a missed opportunity. It remains my great hope that a future commission will rise to the occasion and enact more fulsome disclosure requirements in furtherance of our mandate and investor demand.”

Reactions

Immediate reactions to the SEC’s approval of the rule included environmental and business groups both raising the possibility of legal challenges.

The Sierra Club said it was “considering challenging the SEC’s arbitrary removal of key provisions from the final rule, while also taking action to defend the SEC’s authority to implement such a rule.”

Tom Quaadman, executive vice president for capital markets competitiveness at the U.S. Chamber of Commerce, noted the organization previously “raised significant concerns about the scope, breadth and legality of the SEC’s climate disclosure efforts. … While it appears that some of the most onerous provisions of the initial proposed rule have been removed, this remains a novel and complicated rule that will likely have significant impact on businesses and their investors.

“The Chamber will continue to use all the tools at our disposal, including litigation if necessary, to prevent government overreach and preserve a competitive capital market system,” he said.

But most early reactions echoed Crenshaw, praising the rule as a good first step but calling out the rollback on Scope 3 emissions and other disclosure requirements as major red flags.

“Climate risk is financial risk. This is a sensible rule to protect investors.” said Elizabeth Derbes, director of financial regulation and climate risk for the Natural Resources Defense Council. “What’s wrong with this rule is that it needs to do much more. Investors have been pressing for mandatory disclosure of greenhouse gas emissions, and the agency needs to give them a fuller picture of companies’ risk exposure.”

“For most companies and financial institutions, indirect emissions throughout a company’s value chain represent the largest source of a company’s transition risk,” said Mindy Lubber, president and CEO of Ceres, a nonprofit focused on sustainable finance. “While we are disappointed the rule does not include key provisions from [the SEC’s] 2022 proposal, including the mandate of the disclosure of Scope 3 emissions, investor demand for the disclosure of Scope 3 emissions continues to grow and many companies will be required to disclose this data in other jurisdictions,”

Sen. Sheldon Whitehouse (D-R.I.), chair of the Senate Finance Committee, was typically blunt. “While better than no rule at all, it is unfortunate that the SEC and other regulators continue to shy away from finalizing robust rules that would better protect investors, the economy, and the planet,” he said.

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Md. Cross-over Bills Aim to Remove Barriers to Clean Tech Deployment

The Maryland General Assembly is less than two weeks away from cross-over day — March 18 — when bills introduced in one house must have received a favorable vote and moved to the other chamber. Energy bills are very much in the mix as the legislative pace accelerates, and some bills already have crossed. 

With lawmakers and Gov. Wes Moore (D) facing projections of rising budget deficits over the next few years, bills passed so far focus on removing financial and administrative barriers to deploying zero-emission technologies, such as limiting the restrictions homeowner associations can place on residents wanting to install solar panels or electric vehicle chargers on their property.  

Thus far, only one bill calls for new funding — a modest $5 million per year in 2026 and 2027 — for a no-interest loan fund to help nonprofits install solar or other clean energy technologies to help them reduce their energy bills. 

The following bills have already passed in the House of Delegates: 

H.B. 366:This bill tightens existing law on the kind of restrictions homeowner associations can place on individual homeowners’ ability to install solar on their property. Current law says HOAs cannot set restrictions that “significantly” increase the cost of installation of a solar system or “significantly” decrease its efficiency. The update caps installation cost increases at 5% and system output decreases at 10%. It passed by a vote of 100 to 38 on Feb. 29 and has moved to the Senate Judicial Proceedings Committee.  

H.B. 159: Similar to 366, this bill would prohibit HOAs from restricting home or condominium owners who want to install EV chargers in their assigned parking spaces. If an HOA requires an application to install an EV charger, it would have 60 days to process the application. If no action were taken during that time, the application would be considered approved. The home or condominium owner would be responsible for installation, operation and maintenance costs. It passed 114-23 on Feb. 15 and was referred to the Senate Judicial Proceedings Committee. 

Bills passed in the Senate include: 

S.B. 169: This bill would establish a Green and Renewable Energy for Nonprofit Organizations Loan Program at the Maryland Energy Administration, to be used to provide no-interest loans to nonprofits to install clean energy equipment to help them reduce their energy bills. Under the law, the governor would be authorized to budget $5 million per year for the loan program in 2026 and 2027. It passed 44-0 on Feb. 14 and was referred to the House Economic Matters and Appropriations committees.  

S.B. 258: This bill would raise the energy conservation targets for state-owned buildings, from a 10% cut in energy consumption below 2018 levels by 2029 to a 20% cut by 2031, and would require the Department of General Services to audit at least 2 million square feet of the buildings it oversees annually. Also, the Maryland Green Building Council would be required to update its High Performance Green Building Program for new buildings and major renovations to ensure it is aligned with the state’s goal of reaching net-zero emissions by 2045. It was approved 37-9 on Feb. 29 and referred to the House Environment and Transportation Committee.  

S.B. 337: This bill would expand membership on Maryland’s Commission on Climate Change to include the secretary of emergency management and the chair of the Public Service Commission or their representatives. Created in 2015, the commission advises the governor and General Assembly “on ways to mitigate the causes of,  ​prepare for and adapt to the consequences of climate change.” It cleared 46-0 on Feb. 15 and was referred to the House Environment and Transportation and Economic Matters committees. 

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National Grid Backs out of Twin States Clean Energy Link Project

Despite support from the U.S. Department of Energy, National Grid has backed out of a major project to significantly increase the two-way transmission capacity between New England and Quebec.  

The news is a setback for efforts to increase bidirectional transmission connections between the regions, which could become increasingly important in coming decades as electricity demand increases and intermittent renewables proliferate. 

A partnership between National Grid and the nonprofit Citizens Energy Corp., the Twin States Clean Energy Link was proposed as a 1,200-MW transmission line through Vermont and New Hampshire expected to cost about $2 billion.  

The project was aimed at unlocking the potential of Canadian hydropower to fill in electricity gaps as intermittent renewable resources expand in New England. In this dynamic, New England would send power to Quebec during periods of renewable surpluses, while Quebec would send hydropower south during wind and solar lulls. (See Québec, New England See Shifting Role for Canadian Hydropower.) 

While two under-construction transmission projects between Quebec and the Northeast U.S. (New England Clean Energy Connect and Champlain Hudson Power Express) are set to provide consistent baseload power to New England for decades, Twin States was focused on hydropower’s balancing potential. 

“The cancellation of Twin States is a blow to New England’s decarbonization efforts,” said Emil Dimanchev, the co-author of a 2021 study that found increased bidirectional transmission capacity between regions would help reduce the timeline and cost of grid decarbonization. 

Dimanchev said the news indicates existing power market structures do not provide enough incentives for forward-looking transmission investments that would provide long-term benefits. 

He added that the project’s cancellation “is a symptom of the slow pace of wind build-out in New England. It shows us that there is a greater need for planning transmission and generation investments in a more coordinated fashion.” 

National Grid declined to elaborate beyond a brief statement on the reasons for the cancellation. 

“National Grid has determined that the project is not viable at this time,” the company wrote. “We will continue to pursue paths to building much-needed transmission capacity for the region and for our customers and communities.” 

“While we respect National Grid’s decision to suspend development of the Twin States Clean Energy Link,” Citizens Energy President Joseph Kennedy III wrote in a statement, “we are disappointed to lose this vital opportunity to help New England meet its green energy goals.” 

In October, DOE announced its intention to serve as an anchor off-taker for the project by purchasing up to 50% of the line’s capacity to reduce development risk. (See DOE to Sign up as Off-taker for 3 Transmission Projects.)  

“It’s discouraging that a project that had such significant Department of Energy support could not make it across the finish line,” said Joe LaRusso of the Acadia Center. “Broader U.S.-Canadian cooperation and coordination is still needed, because in the future we are going to have to have a grid that spans the entire Northeast Power Coordinating Council reliability zone.” 

New Hampshire officials expressed disappointment in response to the news. Donald Kreis, New Hampshire’s consumer advocate, called using Canadian hydropower to balance renewables an “intriguing idea,” but said the project’s cancellation shows the lack of a business case for new transmission lines between New England and Quebec.  

“There is a need for more transmission capacity in New England, [but] the merchant model — at least as premised on moving more power out of Canada — seems to be unraveling as a viable proposition,” Kreis said.  

In an op-ed written prior to the project’s cancellation, Kreis expressed concern about a legislative proposal for New Hampshire to contract up to 240 MW of the line’s capacity. Kreis said other states should step up to help fund the project. 

“New Hampshire represents, at most, around 10 percent of New England’s electric consumption,” Kreis wrote. “If we are going to promise to fund a 1,200-megawatt transmission project intended to benefit the whole region, our fair share is, at most, 120 megawatts.” 

Hydro-Quebec, which had not signed a commercial agreement related to the project, expressed its disappointment with the cancellation while reiterating the company sees significant potential in increased bidirectional electricity exchange. 

Serge Abergel, COO of Hydro-Quebec’s U.S. operations, told RTO Insider the company will continue studying the potential of new two-way transmission projects. 

As the deployment of intermittent renewables accelerates, “there’s no doubt that the future has some sort of bidirectional agreement in store for Quebec and its neighbors,” Abergel said, while emphasizing that the Twin States project was an early-stage attempt to build on hydropower’s balancing potential. 

“We just don’t have enough information to convince people yet, nor do we have enough information to say this is not interesting,” Abergel added. “Our work goes on.” 

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RTO, Day-ahead Choice Closely Linked, Nev. Effort Shows

NV Energy is aiming to bring a proposal to Nevada regulators by the end of the year for joining a day-ahead market, but what process regulators will use to evaluate that request is still very much up in the air. 

“It would be good for our internal purposes and potentially for others in the West, because a lot of the utilities in the West feel that their market decisions are based in not insignificant part on what their neighbors are doing,” David Rubin, NV Energy’s federal energy policy director, said during a March 4 workshop. “There are clearly relationships, for example, between Nevada and Idaho.” 

Rubin said that by filing a proposal with the Public Utilities Commission of Nevada (PUCN) by the end of the year, NV Energy could let others know the company’s intentions before they have to decide on making a “fairly significant” financial commitment for the next phase of SPP’s Markets+. CAISO’s Extended Day-Ahead Market (EDAM) and Markets+ are competing to attract day-ahead market participants. 

Rubin said the interrelationship among utilities in the West when it comes to day-ahead markets is underscored by recent studies, including a just-released report from Brattle Group, which found greater economic benefits for NV Energy if the utility went with EDAM rather than Markets+. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

PUCN Investigation

Rubin’s comments came during a PUCN workshop conducted by Commissioner Tammy Cordova, the presiding officer in an investigation of regional market activities in the West. In addition, state law requires NV Energy to join an RTO by 2030, and the investigation will look into how the PUCN will oversee that process. 

NV Energy and other interested parties filed written comments on the matter ahead of the workshop. (See Nev. Regulators to Weigh Approaches to RTO Membership.) 

Some commenters said the commission could consider an NV Energy proposal to join a day-ahead market through its energy supply plan (ESP) — a process that was used in 2014 when the utility decided to join CAISO’s Western Energy Imbalance Market (WEIM). But joining an RTO would be more complex, and new rules from the PUCN might be needed, some said. 

During the workshop, Shelly Cassity of the PUCN’s regulatory operations staff said joining a day-ahead market is “a much bigger step” than becoming a WEIM member. And the 135-day timeline for evaluating an ESP is relatively short, she said. 

“We think that the ESP process may not be the ideal route,” Cassity said. “We think regulations may be necessary.” 

Similar Issues in Colorado

In considering day-ahead market and RTO issues, the PUCN may look to Colorado, where the legislature in 2021 passed a bill requiring utilities to join an RTO by 2030, similar to Nevada’s Senate Bill 448. The Colorado Public Utilities Commission has been working on rules to guide the process of joining a day-ahead market or RTO and recently released draft regulations. 

During the PUCN workshop, Brian Turner, a director at Advanced Energy United, said the Colorado PUC is looking at splitting the decision about utilities joining an RTO into two parts: whether the RTO meets criteria laid out in statute and then whether joining an RTO is in the public interest. 

The definition of an RTO in Nevada’s SB 448 includes requirements that the organization be FERC approved, improve reliability in the state and have a governance structure that’s independent of transmission users. 

Cordova indicated she was open to considering Colorado’s approach. 

“As we keep telling people, this is Nevada, it’s not Colorado,” she said. “But I am also a big fan of not creating a wheel that I didn’t have to invent.” 

PUCN’s March 4 workshop is expected to be followed by additional workshops, including at least one focused on the Brattle Group findings and other studies of potential market benefits. 

Cordova said she’d issue a procedural order laying out a timeline for the proceedings in the next week or so.

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Global CO2 Emissions Hit New High, Could Have Been Higher

The International Energy Agency reports that worldwide CO2 emissions hit a record in 2023 but would have climbed even higher without the rapid adoption of clean technology.  

The year-over-year emissions growth in 2023 was not as great as in 2022, IEA said, even as the growth in energy demand accelerated. Over the past five years, IEA added, clean energy generation capacity increased at twice the rate of fossil generation. 

The analyses come in the 2023 edition of IEA’s annual CO2 emissions update and in the inaugural edition of its new “Clean Energy Market Monitor.” 

Combined, the two reports attach new statistics and details to trends that have been observed in recent years. Takeaways include: 

    • Global CO2 emissions increased by 410 million tons in 2023, reaching 37.4 billion tons; this compares with a 490-million-ton increase in 2022. 
    • Advanced economies saw a record decline of emissions in 2023 as low-emitting resources accounted for half of their electric generation; their emissions dropped to a 50-year low, and their use of coal dropped to a 120-year low. 
    • This is because clean energy continues to be largely concentrated in advanced economies and China; in 2023, they accounted for 90% of new solar and wind generation and 95% of electric vehicle sales. 
    • Clean energy has become a major industrial sector and an important part of the world economy; investment has been growing 10% annually and totaled $1.8 trillion in 2023 alone. 
    • China continued its rapid buildout of clean-energy technology in 2023, adding 64% more solar capacity than the rest of the world combined and leading every other metric except nuclear. But China also ratcheted up fossil fuel consumption in 2023 as it continued its post-pandemic recovery and saw hydropower generation decrease by 125 TWh. The overall emissions increase was estimated at 565 million tons. 
    • The United States decreased CO2 emissions from energy combustion by 4.1%, even as its economy grew 2.5% and hydropower and wind power output declined; the coal-to-gas transition was the largest factor. 
    • By contrast, coal demand in emerging and developing economies was the largest driver in the worldwide increase in CO2 emissions. 
    • Extreme drought curtailed hydropower output in multiple regions in 2023; the use of fossil fuel as a replacement accounted for more than 40% of the worldwide increase in emissions. 
    • In countries with large energy demand for indoor temperature control, the 2023 heating season was much milder than 2022, but the 2023 cooling season was not much hotter, yielding a 120-million-ton net year-over-year reduction in emissions. 
    • Heat pump sales dropped marginally in 2023, which is attributed to consumer hesitance on large purchases. 
    • Hydrogen electrolyzer capacity increased 360% in 2023, but that was from a low starting point. 

In a news release accounting the reports, IEA Executive Director Fatih Birol said: “The clean energy transition has undergone a series of stress tests in the last five years — and it has demonstrated its resilience. A pandemic, an energy crisis and geopolitical instability all had the potential to derail efforts to build cleaner and more secure energy systems. The clean energy transition is continuing apace and reining in emissions — even with global energy demand growing more strongly in 2023 than in 2022.” 

The International Energy Agency reports the largest increase in renewable energy and the largest amount of avoided emissions was in the solar sector. | IEA

But the transition needs to extend beyond the handful of leading economies, Birol added: “We need far greater efforts to enable emerging and developing economies to ramp up clean energy investment.” 

Statistics in the “CO2 Emissions in 2023” report are based on IEA analysis of energy, economic and weather data about carbon dioxide emissions from energy combustion and industrial processes. The “Clean Energy Market Monitor” relies on data from national sources and industry associations. 

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NV Energy to Reap More from EDAM than Markets+, Report Shows

NV Energy would gain significantly more economic benefits from participating in CAISO’s Extended Day-Ahead Market (EDAM) than SPP’s Markets+, new analysis from the Brattle Group shows. 

The analysis was included in slides referenced — but not presented — by the utility during an RTO markets workshop hosted by the Public Utilities Commission of Nevada on March 4. An NV Energy official said the utility will review the findings with the commission at a future workshop, the date for which has not been determined. (See Nev. Commission to Tackle Rules for RTO Membership.) 

The Brattle study looks at financial outcomes for NV Energy based on five market footprints, with benefits measured against a business-as-usual scenario that assumes membership in CAISO’s Western Energy Imbalance Market remains unchanged. 

Brattle said it conducted the simulations underpinning the study using a nodal production cost model of the Western Interconnection “with added market functionality, such as contract-path transmission.”  

The study looks at performance in 2032, “which aims to reflect the first decade of markets operations, representing both an intermediate year in the near future and a year with reasonably high renewable penetration in the” Western Interconnection, Brattle said. 

In the “Bookend EDAM” scenario, which assumes nearly all utilities in the Western Interconnection participate in the EDAM, NV Energy would gain about $62 million in annual benefits from higher transfer revenue and lower annual production costs (APC). In that scenario, the utility would facilitate a sharply increased amount of trade between with Southwest and California, while also helping to transfer more low-cost generation from California and the Southwest to the PacifiCorp-East and Idaho Power balancing authority areas. 

NV Energy would reap the most benefits — $149 million — from the “Middle View 1” scenario, in which EDAM contains all entities that already have announced for that market, plus Seattle City Light, Portland General Electric, Idaho Power and NV Energy. In that scenario, the Bonneville Power Administration and most of the Northwest’s publicly owned utilities, Puget Sound Energy, and all Arizona BAAs join Markets+. NV Energy sees fewer transfers here than in Bookend EDAM, but it also has less competition for low-cost renewable generation, reducing its purchase costs by about $50 million. 

The “Bookend Markets+” scenario assumes NV Energy is participating in Markets+ along with all Northwest and Southwest (including New Mexico) entities, putting a seam between PacifiCorp-East and CAISO and PacifiCorp-West. In that scenario, NV Energy earns $16 million in benefits based on transfer revenues and lower APC but loses access to low-cost generation in the EDAM. 

The “Middle View 3” scenario keeps NV Energy in Markets+ but removes the Avista, NorthWestern Energy, El Paso Electric and PNM BAAs, reducing the Nevada utility’s annual benefits to $9 million based on lost revenue and increased purchase costs in the smaller footprint. 

But NV Energy would incur net losses from participating in Markets+ in “Middle View 2,” which assumes Idaho Power joins EDAM, “cutting off a major pathway” between the Southwest and Pacific Northwest, with flows between areas restricted to just 200 MW. In that scenario, energy flows with Idaho decline by about 3,000 GWh a year.  

Brattle’s analysis examined outcomes from five different market scenarios in the West. | Brattle Group

Takeaways

Among Brattle’s suggested “key takeaways” from the study: NV Energy’s estimated benefits would be highest in the EDAM, “largely due to the opportunity to sell additional generation at higher prices and buy at excess solar at lower prices.”  

The study also found that the scale of NV Energy’s benefits is heavily influenced by the market footprint’s shape “due to its large amount of transfer capability and centrality” in the Western Interconnection.  

“NVE benefits tend to be higher when it is central to the market and facilitates transfers within the market (e.g., in Bookend M+ case, in which NVE facilitates transfers between the PNW and SW; or Bookend EDAM case, in which NVE facilitates transfers between CAISO and the SW),” Brattle said. 

Conversely, benefits decline for the utility when it sits on the margin of Markets+, the analysis found. 

Brattle noted also that NV Energy would suffer negative impacts from shifting out of the WEIM and into Markets+ “as it loses access to excess renewable supply from CAISO in real time and sees lower prices for [real-time] sales.”   

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ACORE Panel: IRA is Safe, but Trump Could Decimate DOE

WASHINGTON, D.C. ― The best way to defend the clean energy incentives in the Inflation Reduction Act could be to stop mentioning the law and focus on its benefits, a trio of speakers told the American Council on Renewable Energy (ACORE) Policy Forum on Feb. 29. 

Melissa Burnison, vice president of federal legislative affairs at Berkshire Hathaway Energy, called for a refocus on areas of bipartisan agreement: “Our transition to a smart grid and … technologies that make the grid more efficient, that also increase their ability to carry more power [and] the responsiveness of the grid.” 

“Everybody likes jobs and … everybody likes clean air and clean water for their kids, too, and for their communities,” said Sarah Hunt, president of the Joseph Rainey Center for Public Policy, a conservative-leaning D.C. think tank. “So, if you can talk about the benefits that your business has received from this policy, from this legislation, and how that translates and passes on to your customers and communities with which you engage … that’s the best way to go about it.” 

In a rare all-female panel, Burnison, Hunt and Kelly Speakes-Backman, executive vice president for public affairs at power and transmission developer Invenergy, debated the way forward for the IRA and the future of U.S. clean energy policy should Republicans win both Congress and the White House in November.  

Introducing the panel, moderator Jayni Hein, co-chair of the carbon management and climate mitigation group at Covington & Burling, spoke first of the benefits of the law, with money and projects flowing to both red and blue states. “But despite these widely shared benefits, we’re at a really uncertain point,” Hein said.  

“The Department of Treasury is in the midst of finalizing some very important rules and guidance,” such as direct pay and transferability of tax credits, along with updated guidance on bonus credits for energy communities and domestic content. 

With the election hanging over such decisions, “the best defense is offense,” Hein said. 

But the panelists mostly stuck with an emerging consensus ― also heard from other speakers at the forum ― that the economic benefits the IRA is creating will make it hard to repeal. (See Whitehouse: Best Defense for IRA Is Funding, Building More Projects.) 

Burnison described her view as “optimistic and grounded.”  

“Bipartisan benefits from the IRA, from tax policy [are] something that ― even from the most conservative congressional members, we’ve heard ― we’re not going to see a wholesale repeal of the IRA,” she said.  

“First of all, it’s probably not possible, and second of all, it doesn’t make sense for their constituents.”  

Hunt argued that even if Donald Trump returns to the White House and Republicans win control of both houses of Congress, “much of [the] IRA, much of the federal investment in clean energy [research and development], especially all-of-the-above, technology-neutral [incentives], are going to be fine.” 

“I don’t think that President Trump and a Republican Congress are going to care a whole lot about the federal budget being too big,” she said, pointing to Republican spending between 2017 and 2020. 

Going further, Hunt attempted to reframe the IRA as a “good Republican energy bill,” which included many provisions worked out in “bipartisan activity or even Republican offices.” The law has become politicized because the Democrats chose to pass it through the budget reconciliation process, rather than taking longer and pushing for a bipartisan bill, she said. 

In calling for a return of manufacturing to the U.S., she said, Trump “socialized industrial policy … and it allowed for the IRA … for that conversation to take root and happen.” 

Hunt said she sees support for the IRA coming from officials who worked at the Energy and Interior departments during the former administration and are now in leading positions at energy companies and advocacy groups.  

Burnison was at DOE when former Texas Gov. Rick Perry was secretary of energy. Both she and Hunt identified themselves as Republicans who embrace clean energy and favor a technology-neutral approach. 

Republicans Now Recruiting

Although the IRA’s clean energy incentives are likely safe, a second Trump administration will likely prioritize a fundamental shift in energy policy, from decarbonization and climate to energy and national security, the panelists said.  

Speakes-Backman sees such a shift resulting in budget cuts at DOE, which could affect staffing and policy.  

Recalling her time at DOE as principal deputy assistant secretary in the Office of Energy Efficiency and Renewable Energy from 2021 to 2022, she said implementing the IRA has been an enormous job for the department after its staffing was cut by Trump. 

Her own office had “the lowest rate of staff to dollars ever in the history since 1977 … with dozens of studies that were [postponed] ― on transmission, on hydropower, certainly on solar and renewables,” Speakes-Backman said. “There were quite a few things that were stalled out across the entirety of DOE.” 

Even if Republicans in Congress are “not going to be as focused on spending, they certainly will be focused on spending on administrative agencies that are pushing toward clean energy,” she said. “There is going to administrative slowdown,” which could also slow efforts to pass legislation to streamline permitting.  

The agencies working on clean energy ― DOE, Interior and EPA ― “are going to be decimated,” Speakes-Backman said. 

Neither Hunt nor Burnison saw any major threat in a Republican refocusing of energy policy.  

That approach will change priorities around “how we look at things like solar and what we’re importing,” Burnison said, referring to Chinese dominance in the refining and processing of critical minerals for solar panels and electric vehicles. “What does that timeline look like in order to begin to phase out some of those imports and to begin to rebuild our domestic manufacturing capability and reliability?” 

Responding to Speakes-Backman’s concerns over cuts to DOE, Hunt talked up current efforts, being led by the Heritage Foundation, to recruit and train new staff for federal agencies, who will be “ready to go on Day 1” of a new administration. At the same time, she discounted Project 2025, the foundation’s 920-page blueprint for the next Republican administration.  

The section on DOE, authored by former FERC Commissioner Bernard McNamee, calls for the department to be renamed the Department of Energy Security and Advanced Science, with a narrowed focus on energy and national security, “cutting-edge fundamental advanced science” and developing new nuclear weapons. 

While Hunt said the report should be read “with a grain of salt,” the personnel recruitment and training program is part of Project 2025 and led by three former Trump officials.  

Good Business

Hunt said the electric industry’s support for the IRA will protect it from being repealed by Trump.  

Burnison said Berkshire Hathaway and other energy companies are looking for the finalization of guidelines on the law’s tax credits and other rules, which will provide the regulatory certainty the industry has been waiting for.  

“Are we expanding regulatory authorities? Are we contracting some of those? Where are the regulatory authorities moving to or even over to DOE? … Are we changing what those look like?” Burnison asked. With large energy or transmission projects taking five to 10 years or longer to permit and build, she sees a mismatch between IRA incentives and long-term business planning.  

Speakes-Backman is waiting for the final guidance on tax credits for green hydrogen “as it relates to the ramp to hourly accounting” — matching the zero-emission energy used to produce clean hydrogen on a 24-7 basis versus the annual accounting widely used now.  

“I think we all want to get to an hourly, fully clean hydrogen, but as we’re standing up the industry, there is a pace,” requiring a phased-in approach, she said. 

Whoever wins the White House, Senate or House must understand “that clean energy is good business,” she said. “Whether that be in renewables, whether that be in natural gas to help peaking, whether it be transmission, whether it be energy storage, it is good business for this country.” 

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NJ Panel Backs Bill to Increase Distribution Capacity for Renewables

New Jersey’s Senate Environment and Energy Committee unanimously approved a bill March 4 requiring electric utilities to develop plans for upgrading their distribution infrastructure to increase renewable generation capacity. 

The bill would give the state’s four utilities 90 days to draft and submit a plan to the Board of Public Utilities, with a goal of reopening “many of the state’s electric distribution circuits that have been closed to any additional renewable energy installations, or restricted to 100 kilowatts or less of remaining circuit capacity” (S2816). The bill gives the BPU 30 days to approve or modify each plan; utilities would be required to schedule the work “at the earliest date possible.” 

The committee also approved bills to restrict new fossil fuel generation and divest oil and gas investments on party-line votes at its March 4 meeting. 

Committee Chair Bob Smith (D), co-sponsor of the distribution upgrade bill, said it would “allow us to get more solar into New Jersey residential homes” at a relatively modest cost. 

Still, he added, “this bill doesn’t say you must do” the upgrades, but instead requires the utility to submit a plan to the BPU, which then decides how to proceed.  

“What we’re saying by the bill is ‘Let’s get it done,’” Smith told the committee. 

Many Rejections

The bill, which the committee backed 5-0, comes as New Jersey, like other states, is struggling to connect a surge of renewable energy projects to the grid in a timely fashion.  

Solar developers say the problem is particularly egregious in Atlantic City Electric’s territory in South Jersey, where connections can take months or years. (See Solar Developers: New Jersey’s Aging Grid Can’t Accept New Projects.) 

“There’s a lot of rejections coming down,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, which proposed the bill to Smith. Developers are going into the utility with a planned solar rooftop or ground mount project “and the utility says, ‘You can’t connect there; we can’t do it,’” he said. 

“It’s a first step, taking the worst problem first,” he said of the bill, adding he expects the industry to be addressing interconnection problems for a decade or more. In this case, the bill focuses on improving customers’ ability to connect to the distribution system, rather than addressing the transmission system.  

The bill would require each utility plan to address issues such as how to permit the flow of electricity from the distribution system through an electrical substation to the transmission system, and to “include, activate and utilize all available inverter technology.” The bill also requires the plans to include any inverters needed to implement energy storage systems. 

Brian O. Lipman, director of the state Division of Rate Counsel, urged the BPU in a March 1 letter not to back the legislation. He said the plans required by the bill would be too complicated to be properly evaluated in the period allowed and would “very likely cause ratepayers to grossly overpay for imprudent and unreasonable costs.” 

Addressing the committee March 4, Lipman said the legislation should give the utilities more time to craft a plan and the BPU more time to review it. The BPU also should be allowed to reject a utility’s plan, not just approve or modify it, he said. 

“Part of the process at the BPU is vetting out the ones that are good, making sure that those are done, and making sure the ones that are not so good are actually taken off the table,” he said. 

Smith said he will amend the legislation to add a denial option and provide longer timelines. 

Constitutional Amendment

The Democrat-controlled committee also backed a bill that would seek to amend the state constitution to prohibit construction of new fossil fuel power plants, except for peaker units, on a 3-2 vote (SCR11). If the legislation is enacted, the issue would go to voters to decide whether to back the prohibition. 

The bill would prohibit the state from granting any approvals for the construction of a plant “that produces electric power, in whole or in part, from the combustion of coal, natural gas, oil or petroleum products.” The legislation also prevents anyone from building such a plant. 

“This bill is an attempt to be reasonable about our fossil fuel electric power generation,” said Smith, a bill co-sponsor. Instead of saying, “Shut the switch off now,” he said, the bill allows fossil fuel plant to continue generating until “the end of the useful life.”  

The committee first discussed the bill at a Feb. 5 hearing to solicit public opinion without a vote. After receiving comments that relying on renewable energy without peaker plants would threaten reliability, Smith revised the legislation to allow for the construction of new peaker plants. 

Even so, Dennis Hart, executive director of the Chemistry Council of New Jersey, which represents more than 60 manufacturers, said the bill could threaten the energy sources on which his members rely. He said they already pay 50% more for energy than manufacturers in other parts of the company. 

The state’s nuclear plants, which produce about 30% of the state’s energy, are already 60 years old, and their future performance can’t be assumed, he said, adding later that the state needs a “diversity” of energy sources. 

“We need a reliable, cost-effective source of electricity,” he said. “And I think it’s shortsighted to cut out fossil fuel generation.”  

Misinformation

Environmental groups also had concerns about the bill. David Pringle, speaking against the bill on behalf of Empower New Jersey, an environmental group, said the focus of the amended bill was too narrow, and would only prevent the construction of “new gas plants of a very large nature.” Those plants, he added, are not likely to be built anyway because they are no longer economically feasible. 

Anjuli Ramos-Busot, the director of the New Jersey chapter of the Sierra Club, also opposed the bill, saying the state already has enough peaker plants to support renewable energy, and any attempt to update them would be limited by the state’s Environmental Justice law, which took effect in 2023. 

She said the organization is also worried that taking the issue to a voter campaign would unleash a flood of misinformation about clean energy. 

“We’ve seen a decrease — a slight decrease — in support for offshore wind, because of misinformation, because of the fossil fuel industry pouring in millions and millions of dollars to misinform the public,” she said. “Our fear is that we won’t be able to compete. Sierra Club is an environmental nonprofit; we don’t have millions of dollars to spend in a campaign to educate properly the public and deny the misinformation.” 

Before moving the bill for a vote, Smith said “all the experts that I’ve talked to feel that you got to have some peakers,” suggesting they should be permitted under the bill. He added that he is not afraid of triggering a heated campaign.  

“I have a lot of faith in the voters of New Jersey,” he said. “I think they can figure it out.” 

Investment Pressure

The committee also backed, by a 3-2 partisan-line vote, a second bill that had been discussed on Feb. 5 but not voted upon so that public input could be evaluated. The bill, S198, sponsored by Smith, would prohibit the state from investing “in any stock, debt, or other security of any company, or any subsidiary, affiliate, or parent of any company, that is among the 200 largest publicly traded fossil fuel companies, as established by carbon content in the companies’ proven oil, gas, and coal reserves.” 

Ray Cantor, senior lobbyist for the New Jersey Business and Industry Association, said that given that the state’s pension fund is underfunded by $80 billion, “it’s bad policy to use the pension to try and drive public policy.”  

But Smith said that the impact of climate change is too great to continue supporting fossil fuel companies. 

“My hope is that if they get called out by enough state governments, the federal government, that maybe they’ll change what they do,” he said.