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November 19, 2024

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NM Sets Course to Adopt New Clean Vehicle Rules

New Mexico is about to launch a rulemaking on regulations that would largely mirror California’s ZEV sales requirements, but with one key difference.

Instead of following California’s Advanced Clean Cars II mandate that all new cars sold in the state be zero-emission in model year 2035 and beyond, New Mexico would cap the zero-emission requirement at 82%, starting with model year 2032.

New Mexico is also moving toward zero-emission requirements for trucks, similar to California’s Advanced Clean Trucks rule.

New Mexico Gov. Michelle Lujan Grisham announced Monday that the state plans to enact advanced clean car and clean truck rules. The announcement came during a visit to the Chalmers Ford dealership in Rio Rancho.

“These rules will speed up much-needed investment in New Mexico’s electric vehicle and clean hydrogen fueling infrastructure, create new job opportunities and, most importantly, result in cleaner and healthier air for all New Mexicans to breathe,” Lujan Grisham said.

Advanced Clean Cars and Advanced Clean Trucks would require vehicle manufacturers to deliver an increasing percentage of zero-emission vehicles for sale each year. As proposed, New Mexico’s clean cars rule would start with a 35% ZEV requirement for model year 2026, increasing each year up to an 82% requirement for model year 2032 and beyond.

In contrast, California’s ZEV requirements in Advanced Clean Cars II continue to increase until reaching 100% in model year 2035. California will also allow sales of some plug-in hybrids. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

Requirements under New Mexico’s proposed Advanced Clean Trucks would start with model year 2027 and vary depending on vehicle class. For model year 2035, the zero-emission requirement would be 55% for Class 2b-3 trucks, 75% for Class 4-8, and 40% for Class 7-8 tractors. Those percentages are the same as in California’s Advanced Clean Trucks program.

The proposed rules would apply to automakers, rather than auto dealers or consumers, and would not prohibit the sale or ownership of new or used gas-powered vehicles.

Colorado’s Plan Similar

Environmental advocates who have been urging New Mexico to update its car and truck standards were pleased with Lujan Grisham’s announcement.

“It’s a big step forward,” said Noah Long, a senior attorney with the Natural Resources Defense Council. “Those are really important rules.”

Long said New Mexico’s proposal is similar to an Advanced Clean Cars regulation being considered in Colorado, where increasing ZEV requirements for automakers would stop at 82% in 2032.

NRDC’s analysis has shown “significant benefits” of the rule through 2032, and even more benefits if required ZEV percentages continued to increase. Long noted that the states could amend their regulations to increase stringency in later years.

In addition to Colorado and New Mexico, Maryland, Delaware, New Jersey and Rhode Island are considering adoption of Advanced Clean Cars II this year, according to NRDC. Washington, Oregon, New York, Massachusetts, Virginia and Vermont have already adopted the California program.

Although draft rules have not yet been released, the New Mexico Environment Department posted a fact sheet on the proposed rules that lists the percentage requirements.

The clean cars and trucks rules will be part of the same rulemaking process, which could start as soon as this month, NMED spokesman Matthew Maez told NetZero Insider. The draft rules will generally follow California’s regulations, Maez said, with a few differences.

“The largest difference will be that the proposed rules in New Mexico will culminate in California’s 82% requirement for manufacturers by 2032,” he said.

Availability Issues

In May 2022, New Mexico adopted the Advanced Clean Cars (ACC) regulation, which is based on California’s earlier program. (See NM Adopts Calif. Advanced Clean Cars Rules.)

ACC supporters said at the time that the rule would boost EV availability in New Mexico, where people often struggle to find an electric car to buy. Automakers will prioritize delivery of EVs to the jurisdictions that require them, proponents said.

“These new rules will ensure that all New Mexicans have access to a greater number of new zero- and low-emission vehicle models, while hastening the transition away from polluting diesel and gasoline-powered cars and trucks,” NMED Cabinet Secretary James Kenney said in a statement.

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FERC Approves $1.8M Penalty Against Exelon Utilities

FERC on Friday approved a $1.8 million penalty against Exelon’s utilities, part of a settlement between the subsidiaries and ReliabilityFirst for violations of NERC reliability standards (NP23-17).

NERC submitted the settlement to the commission in a Notice of Penalty on May 31, along with a separate spreadsheet NOP concerning violations of the Critical Infrastructure Protection (CIP) standards (NP23-16). The spreadsheet NOP was not made public because FERC considers CIP violations to be critical energy infrastructure information. FERC said in its Friday filing that it would not further review any of the settlements, leaving the penalty intact.

Exelon utilities Atlantic City Electric (ACE), Delmarva Power and Light (DPL), Pepco, Baltimore Gas and Electric (BGE), Commonwealth Edison and PECO Energy collectively provide electric service to nearly 9 million people in New Jersey, Maryland, Delaware, Virginia, Illinois, Pennsylvania and D.C.

RF’s settlement with the companies stems from violations of FAC-009-1 (establish and communicate facility ratings), which required that transmission owners and generator owners establish facility ratings that are consistent with an established facility ratings methodology. (The standard was replaced in 2013 by FAC-008-3.) The compliance issues were initially identified by ACE, DPL and Pepco; their discovery prompted BGE, ComEd and PECO to conduct investigations, which unearthed their own ratings issues.

ACE kicked off the investigation process in April 2019 after it discovered that it had placed a transmission line back into service without communicating the updated facility rating to PJM. The discovery led ACE to compare more facility ratings against PJM’s records to ensure that all of the RTO’s records were accurate. However, the utility found more inaccuracies in this review, prompting Exelon to expand the scope of the reviews to include DPL and Pepco. Exelon first informed RF of the issues — through the regional entity’s legal team — following this expansion in July 2019.

In December 2019, while the reviews were underway, RF issued an audit notification letter to the utilities. As part of the audit, the RE notified the utilities that they were in violation of FAC-008-3. The review continued through March 2021, when the three utilities identified 235 out of their 349 facilities that required facility rating changes.

BGE, ComEd and PECO reported to RF in July 2020 that they were also in violation of FAC-008-3, having begun their own reviews the year before as a result of the widespread issues discovered by ACE, DPL and Pepco. Their reviews, completed in December 2022, found 278 total misratings across their collective 1,504 facilities.

RF determined that the violations by all six utilities began in June 2007, when FAC-009-1 took effect. They ended in March 2021 in the case of ACE, DPL and Pepco, and in December 2022 for the remaining companies; these dates indicate when the extent of condition reviews were completed and all discrepancies officially corrected.

The RE found that the violations posed a serious risk to grid reliability in the cases of ACE, DPL, Pepco and PECO, and a moderate risk for the other two utilities. Explaining this assessment, RF said that the number of errors and their duration both indicate “a longstanding, systemic issue” with the utilities’ facility ratings practices. It further noted the large adjustments needed in some cases (one facility required a reduction of up to 66%) and that more than a dozen facilities were found to have operated near or above their corrected ratings.

RF attributed the violations to “insufficient internal controls throughout each company’s facility ratings program and processes.” It noted that “multiple teams at various steps” contributed to each utility’s overall facility ratings process, without enough care taken to ensure accurate recording of information at each stage, increasing the potential for human errors.

In the case of the initial three utilities, the RE suggested that a “lack of clear overall ownership and accountability for the … facility ratings program” also exacerbated the risk, along with a lack of formal training for relevant teams. For the remaining utilities, RF found that they had failed to maintain or confirm facility baselines, in some cases relying on baselines developed by third parties that were not adequately reviewed prior to adoption.

ACE, DPL and Pepco committed to more than 25 mitigating activities including implementing additional controls for data accuracy; establishing a new standard repository for relay load limits; committing to regular updates for stakeholders involved in the facility ratings process; and creating a new common facility ratings database. Actions by BGE and the other utilities include completing a full review of the extent of the conditions and implementing a common tool for documenting equipment and facility ratings across all Exelon companies.

RF noted the utilities’ cooperation throughout the process, including their self-disclosure of the suspected noncompliance and their willingness to conduct full physical walkdowns of their facilities “within a relatively short time frame” as reason for mitigating the penalty. On the other hand, the RE said that a previous compliance issue related to FAC-008 served as an aggravating factor in the penalty determination because the utility “failed to identify the full breadth of their systemic issue with facility ratings.”

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DOE to Invest $1 Billion to Build Demand for Clean Hydrogen

The Department of Energy on Wednesday announced plans to use $1 billion from the Infrastructure Investment and Jobs Act to underwrite demand for the clean hydrogen to be produced by the regional hydrogen hubs (H2Hubs) funded with $7 billion from the law.

The goal of the proposed “demand-side support mechanism” will be to “ensure both producers and end users in the H2Hubs have the market certainty they need in the early years to unlock private investment and realize the full potential of clean hydrogen,” according to DOE’s press release.

A combined notice of intent (NOI) and request for information (RFI) also released Wednesday outlined several options for how the money might be used. For example, DOE might act as a “market maker,” buying clean hydrogen from the hubs and then selling it to offtakers. Other options might include:

    • “Pay-for-difference” contracts that provide support to projects based on current market prices;
    • A fixed level of support for projects ― for example, a fixed amount per kilogram ― added on top of other sources of revenue; and
    • Funding to support feasibility studies undertaken by potential offtakers near the H2Hubs.

“Ensuring America is the global leader in the next generation of clean energy technologies requires all of us — government and industry — coming together to confront shared challenges, particularly lack of market certainty for clean hydrogen,” Energy Secretary Jennifer Granholm said in the press release. “That’s why DOE is setting up a new initiative to help our private sector partners address bottlenecks and other project impediments — helping industry unlock the full potential of this incredibly versatile energy resource and supporting the long-term success of the H2hubs.”

The RFI also asked for industry input on how hubs or companies might apply for the demand-support funds. The options here range from a reverse auction, with projects bidding in the lowest amount needed to make a project viable, to an “eligibility-based process,” in which all projects meeting certain threshold criteria would receive some form of support.

Another key question is whether an independent entity should administer the program.

Final applications for the regional H2Hubs were due April 7, and according to DOE’s Office of Clean Energy Demonstrations, which is overseeing the initiative, six to 10 hubs will be selected for funding by the end of the year. DOE will accept comments on the NOI-RFI through July 24 and expects to issue a “broad agency announcement” for the initiative by early fall.

A broad agency announcement is similar to a request for proposals but does not define a specific project. Rather, it poses a problem and invites proposals for different solutions.

Demand Lags Supply

President Joe Biden and DOE have framed clean hydrogen and the H2Hubs as essential for addressing hard-to-decarbonize industrial sectors, such as cement, steel and heavy-duty trucking.

The hydrogen hubs, to be located in diverse geographic regions across the country, are intended to kick-start the U.S. market, and the initiative drew a range of applications, some with two or more states partnering on a project. The Inflation Reduction Act backs up the hubs with a production tax credit of up to $3/kg for clean hydrogen, creating a strong draw for foreign investment as well.

So, with that level of support, why is further investment needed?

DOE’s Pathways to Commercial Liftoff Report for clean hydrogen, released this year, puts securing long-term offtake contracts at the top of its list of challenges to commercialization.

“At present, producers struggle to find credit-worthy offtakers with sufficient hydrogen demand sited within an affordable distance to hydrogen production who are willing to sign long-term contracts,” the report says. “Many offtakers with near-term break-even points are refineries and ammonia production facilities that can retrofit their existing facilities with carbon capture and sequestration rather than seek out a new clean hydrogen producer.”

Speaking at a recent event at the Bipartisan Policy Center in Washington, D.C., David Crane, DOE’s undersecretary for infrastructure, teased Wednesday’s announcement, saying that while the IRA did a good job of incentivizing supply, “the history of energy … is that demand formation always lags supply.” (See DOE Under Secretary: Industrial Decarb Should Happen This Decade.)

Building demand is a priority for the White House and DOE, he said.

The Liftoff report details other challenges for demand-building, such as the inability of offtakers to hedge any price volatility. Another concern for offtakers is that without a broad national supply chain, amounts of clean hydrogen may be insufficient or variable.

Crane sees the hubs as a first step to the buildout of both production and distribution facilities across the country that will support new applications for clean hydrogen and bolster offtaker and investor confidence.

As outlined in the RFI, the ultimate goal for the demand-support initiative is “the formation of a mature commodity market for clean hydrogen,” based on price transparency and standard, long-term contracts.

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Massachusetts DPU Greenlights Major Battery Projects After Delays

The Massachusetts Department of Public Utilities has cleared the way for construction of two major battery facilities that would get the state most of the way to its 2025 energy storage goals.

After an extended planning and review process, the Medway (Mass DPU 22-59) and Cranberry Point (Mass DPU 22-18) projects suffered setbacks when the state Energy Facilities Siting Board (EFSB) decided May 11 that it lacked jurisdiction over battery energy system storage (BESS) proposals because they were not energy generation facilities.

That move sent the proposals to the DPU for review. This, combined with earlier delays, made developers fear they would miss their contractual obligation with ISO-NE to come online by June 1, 2024, potentially opening them to millions of dollars in penalties.

On Friday, the DPU issued rulings exempting the two projects from local zoning rules, effectively greenlighting both, though with a lengthy list of conditions on design and construction.

In an email to NetZero Insider this week, Plus Power, which owns the LLC developing Cranberry Point, declined to predict whether it could pull permits and start and finish construction in 11 months.

But CEO Brandon Keefe said: “We thank Massachusetts’ leadership for making this decision based on the facts of regional need, project design, minimal environmental footprint and safety best practices. Battery energy storage is already widely deployed across the country to help decarbonize and modernize electric grids. The Cranberry Point Energy Storage project will be a critically important asset to improve power reliability and clean electricity for Southeast Massachusetts.”

Cranberry Point Energy Storage is a 150-MW/300-MWh BESS proposed by Plus Power in Carver, northeast of Fall River; a short overhead power line to an existing substation is part of the project.

Medway Grid Energy Storage System is a 250-MW/500-MWh BESS proposed by Eolian Energy in Medway, northwest of Fall River. The project also includes an underground line running to an existing substation.

Together, they would provide 80% of the 1,000-MWh goal Massachusetts has set for Dec. 31, 2025, under its Energy Storage Initiative.

Large-scale storage is expected to play a critical role in the clean energy transition as the grid increasingly relies on intermittent generation resources and traditional patterns of electric consumption change.

‘Different World’

The long-running deliberation by the EFSB was a source of frustration for the developers of the two projects but was not fruitless: The extensive record it established enabled DPU to move quickly on the proposals.

However, the matter also highlighted the need to revise decades-old regulatory language codified long before utility-scale energy storage was contemplated.

When the EFSB punted to the DPU, a spokesperson for Gov. Maura Healey’s Office of Energy and Environmental Affairs addressed this shortcoming, telling NetZero Insider the EFSB is guided by statute.

“As the case before the board today demonstrates, that statute was designed for a different time when the power system was based on large fossil fuel power plants owned by utilities. Today, we live in a different world,” the spokesperson said. “This is why EEA Secretary [Rebecca] Tepper established a commission on permitting and siting to assess and address the jurisdiction around building large amounts of renewables in an equitable manner. It is critical that we as a state review our regulatory scheme to ensure we can site the renewables that we need to meet our energy and climate goals.”

BESS facilities have a lower profile than some other components of a carbon-free power grid, with none of the imposing height of wind turbines and horizontal sprawl of solar arrays. But a spate of intense fires in consumer-scale lithium batteries has prompted pushback from residents who live near proposed BESS sites and are worried that utility-scale lithium battery systems pose an exponentially larger threat than e-bike batteries.

The similarities between the two types of batteries start and end at the word “lithium,” but that distinction can be lost on people who do not work in the battery or firefighting industries.

The DPU addresses safety concerns in conditions it sets for construction of Cranberry Point and Medway, which require developers to:

      • update the DPU regularly on completion of their hazard mitigation analyses and emergency response plans;
      • detail in those plans the personnel, equipment and apparatus required to respond to a significant thermal event;
      • work with the local fire departments on providing real-time notification to nearby residents;
      • develop an evacuation and/or shelter-in-place protocol during emergencies;
      • report to the DPU within seven days any incident that requires fire department notification; and
      • comply with state regulations on PFAS.

Also, the companies must submit plans to ensure that any firefighting water is fully contained in stormwater basins and does not discharge from the basin or otherwise seep into the ground. The DPU directed them to submit a plan to collect and test samples of the water and report the results back to the DPU.

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FERC Affirms Affiliate Status of Evergy, Bluescape

FERC affirmed Evergy’s status Monday as an affiliate of Bluescape Energy Partners, rebuffing rehearing requests from the Kansas City utility and the Edison Electric Institute (ER20-67).

The commission cited the 2020 Allegheny Defense Project v. FERC decision in denying the rehearing requests “by operation of law.” The D.C. Circuit Court of Appeals’ ruling in Allegheny found FERC no longer could grant rehearing requests “for the limited purpose of further consideration.”

Evergy’s operating companies filed a change in status with the commission in 2020, reflecting a change in their upstream ownership when Evergy’s leadership said it would remain a standalone company after pursuing purchase offers. In February 2021, Dallas-based Bluescape said it was investing $155 million in Evergy and, in return, gaining two seats on its Board of Directors.

Last October, FERC issued an order finding Evergy and its subsidiaries are Bluescape affiliates by virtue of the board’s new membership. The commission found that Evergy’s appointment of Bluescape executive chairman C. John Wilder as an independent director to its board to be a “concern” it previously had expressed in a proceeding involving CenterPoint Energy.

C. John Wilder | C. John Wilder via LinkedIn

FERC also clarified that placing non-independent officers or directors on a utility’s board of directors or its holding company — regardless of whether the ownership stake is 10% or more of the utility or its holding company — qualifies the entity placing those directors as an affiliate of the public utility. (See FERC Clarifies When Board Appointees Make Companies Affiliates.)

Evergy filed its rehearing request in November, alleging FERC’s order contradicted its affiliate definition by not representing an independent basis from which to find affiliation and because its interpretation “confused the function of a rebuttable presumption.” (The commission’s definition of affiliate provides those “owning, controlling or holding with power to vote, less than 10 percent of the outstanding voting securities of a specified company creates a rebuttable presumption of lack of control.”)

“If an entity owns less than 10%, it need make no further showing; unless an opponent adduces some evidence going to control, the issue is settled in favor of no control,” the company argued. “If, however, [the commission] or a protestor adduces sufficient evidence that an entity controls a public utility despite owning less than 10%, the result is to rebut the presumption, i.e., to eliminate the presumption. But that’s not what FERC’s order does. FERC treats rebuttal as resolving the issue in favor of control.”

FERC said it continued to find Wilder’s appointment “overcomes the rebuttable presumption of a lack of control” under its affiliate regulations. It also said the appointment is a per se finding of control “further supported by other aspects of Bluescape’s ownership of Evergy.”

“This indicates … ‘there is liable to be an absence of arm’s-length bargaining in transactions between’ Bluescape and Evergy ‘as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that [Bluescape] be treated as an affiliate’” the commissioners said in the order.

FERC’s acting chair, Willie Phillips, concurred with the order but also said that the commission should have opened a Section 206 proceeding under the Federal Power Act or asked for further briefing.

“Perhaps after briefing we would reach the same result; perhaps not,” he wrote. “Either way, that process would have allowed us to fairly examine what is an issue of first impression before the [c]ommission, helping ensure we reach legally durable results when exercising such an important aspect of our authority.”

Commissioner James Danly dissented, saying the order failed to “fully and adequately” respond to Evergy’s arguments raised in its rehearing request.

“It violates the Administrative Procedure Act,” he said, referring to the process by which federal agencies develop and issue regulations.

EEI’s rehearing request was dismissed after FERC rejected its late intervention motion, saying it failed to demonstrate good cause to intervene out-of-time. The commission ruled EEI was not a party to the proceeding.

Hearing Set for Evergy Asset Recovery

FERC last week accepted SPP‘s filing on behalf of Evergy Kansas Central (Evergy KC) and Evergy Kansas South to establish regulatory assets and recover their unamortized balance through its tariff. The June 30 order was effective July 1, subject to refund, and established hearing and settlement judge procedures (ER23-1762).

The commission said its preliminary analysis found that Evergy’s and SPP’s filings have not been shown to be just and reasonable and may be otherwise unlawful. It said the filings raise issues of material fact more appropriately addressed in the hearing and settlement judge procedures. The hearing will be held in abeyance to provide time for settlement judge procedures.

Evergy KC requested FERC approval to establish three regulatory assets: catalyst costs, generation baghouse costs and critical infrastructure and cybersecurity costs. It also asked for approval to recover the unamortized balances for the assets’ costs incurred in 2019.

Kansas Electric Power Cooperative (KEPCo) filed a formal challenge and complaint in November 2020 against Evergy KC’s annual update to its rate schedule. It argued that the utility had included several regulatory assets’ amortization expenses in the update without commission approval.

FERC in April 2021 granted the complaint and directed Evergy KC to remove from the formula rate inputs any amounts that represented the recovery of the costs. Evergy KC and Evergy Kansas South made a subsequent filing in a separate docket (ER22-1657) that again requested approval to establish the regulatory assets and recover the unamortized balance. FERC accepted the request, suspending it for a nominal period and establishing hearing and settlement judge proceedings.

Evergy KC made another filing to reverse the regulatory asset and immediately record and recover those costs as current operating expenses. FERC rejected that request in October 2022, but Evergy requested a rehearing.

The commission affirmed its finding in February but held that to “the extent … Evergy KC chooses to make an FPA section 205 filing seeking approval to recover the 2019 regulatory-asset related expenses in rates, the [c]ommission will evaluate its filing consistent with [c]ommission precedent.”

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NYSERDA Asks PSC to Revise REC Capacity Price Calculations

The New York State Research and Development Authority last week petitioned the state’s Public Service Commission to adjust how it calculates the reference capacity price (RCP) for renewable energy certificates to account for NYISO’s new capacity accreditation construct (18-E-0071/15-E-0302).

The RCP is an input used to calculate how much generators who own index REC contracts are paid each month. The price, along with a reference energy price, is subtracted from the index strike price to determine the total amount paid. Thus, the lower the RCP, the higher the revenue.

NYSERDA told the PSC that some intermittent generators were having difficulty predicting the amount of capacity revenue they expected to receive because of the changes. The agency proposed eliminating the need for generators to predict their unforced capacity (UCAP) production factor, itself an input in the calculation for the RCP, and change the variable to a fixed value, unless a generator requests a specific value and the commission approves it.

“Eliminating the need for [REC bidders] to predict future UCAP amounts would reduce the risk associated with future variance between a resource’s capacity revenue and reference capacity price,” NYSERDA wrote.

But while “the proposed revised reference capacity price formula provides a more flexible and resilient hedge and is therefore expected to lower bid prices in future” requests for proposals, NYSERDA cautioned that it “is not able to reasonably predict the associated reduction in ratepayer costs.”

NYISO received FERC approval in 2022 to adopt a new marginal capacity accreditation market design that placed more value on intermittent suppliers and generators providing marginal contribution to reliability, instead of their average contribution. (See FERC OKs NYISO Capacity Market Changes Stemming from NY Climate Law.) The new rules are scheduled to become effective May 1, 2024.

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Duke Energy Sells Distributed Renewable Business to ArcLight

Duke Energy on Wednesday announced a $364 million deal to sell its commercial distributed generation business to an affiliate of ArcLight Capital Partners.

The deal follows a $2.8 billion transaction Duke announced June 12 to sell its utility-scale renewable business to Brookfield Renewables. Both are expected to close by the end of the year and will support Duke’s focus on the growth of its regulated businesses, including plans to incorporate more than 30 GW of regulated renewable energy onto its system by 2035.

“The sale of our commercial renewables businesses streamlines our portfolio and provides the resources to support the long-term needs of our customers in our growing regulated territories,” Duke Energy CEO Lynn Good said in a statement. “Over the next decade, we plan to invest significant amounts of capital to fund the critical energy infrastructure necessary to serve our customers and support our clean energy transition.”

Once the two deals close, Duke will be out of the competitive side of the business, having sold off its generation in PJM to Dynegy (now part of Vistra Energy) in 2015.

Duke’s utilities serve 8.2 million electric customers in North and South Carolina and four other states, along with 1.6 million natural gas customers. It has goals of getting to net-zero methane emissions in its gas utilities by 2030 and net-zero carbon emissions from its 50 GW of utility-owned generation by 2050.

The distributed generation business going to ArcLight includes REC Solar operating assets, a development pipeline and operations and management portfolio, as well as distributed fuel cell projects managed by Bloom Energy. Its employees will transition to ArcLight to maintain business continuity for operations and customers.

Duke has been working on the sale of its businesses for months, taking a $1.3 billion impairment on their sale in the fourth quarter last year and an additional $175 million impairment due to the sale in the first quarter this year. (See Duke Energy Sees Earnings Fall on Warm Winter Weather.)

“Our investment in Duke Energy’s commercial distributed generation business supports ArcLight’s long-standing strategy of acquiring operating assets from leading strategics and creating strong stand-alone renewable platforms,” ArcLight Managing Director Marco Gatti said in a statement. “We believe this is an attractive opportunity to acquire a first-rate commercial distributed generation portfolio, partner with a talented team and build upon longstanding, high-quality customer relationships.”

The deal is subject to customary closing conditions and will need to be approved by FERC due to the sale of the Bloom Energy distributed fuel cell assets.

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Report: DER Interconnection in ‘Real Disarray’ Across US

New Mexico is the best place in the U.S. for getting distributed energy resources (DERs) hooked up to the local distribution system, according to a new interconnection scorecard from the Interstate Renewable Energy Council (IREC) and Vote Solar.

The state is the only one that earned an “A” on the recently released Freeing the Grid scorecard, which is based on states’ adoption of key policies and best practices that can streamline approvals, increase efficiency and reduce costs for the interconnection of DERs.

“One of the great things about New Mexico is they had a very robust stakeholder engagement process … and they really overhauled the rules,” incorporating many of IREC’s recommended best practices, said Mari Hernandez, assistant director of regulatory programs at the nonprofit. New Mexico is also the only state to include provisions aimed at incentivizing and streamlining interconnection for projects that will benefit disadvantaged or underserved households, she said.

“That is something we wanted to signal is really important,” Hernandez said. “Our hope is to figure out more ways to think about equitable access and interconnection, and how to make sure we’re considering that within interconnection rules.”

Whether on transmission or distribution systems, interconnection ― the process for allowing new energy projects to connect to the grid ― has become a major bottleneck for solar, wind and storage projects. Freeing the Grid (FTG) grades all 50 states, D.C. and Puerto Rico on whether they have adopted jurisdictionwide interconnection policies and procedures that apply to all regulated utilities.

“Interconnection is fundamental to the clean energy transition,” Hernandez said. “So, we really believe that what’s included in interconnection procedures is a good indication of whether a state is set up to support clean energy growth.”

But according to the FTG scorecard, a majority of states aren’t adopting the necessary policies and best practices. Following New Mexico, only six states received a B ― Arizona, California, the District of Columbia, Illinois, Michigan and New York ― while 15 squeaked by with a C. A total of 30 were given Ds or Fs.

Those results indicate “real disarray across the country,” said Sachu Constantine, executive director of Vote Solar. “A lack of consistency, a lack of transparency, a lack of best practices across the whole country, and this comes at a critical moment when you look at what the [Inflation Reduction Act] is doing, what it’s signaling about the direction we want to go.”

The landmark legislation, signed into law last August, provides billions in tax credits for solar, wind and energy storage, both grid-scale and distributed, as well as manufacturing tax credits to support the build-out of domestic supply chains. The IRA also ensures many of these credits will be available through 2032, to provide certainty for the industry.

But, Constantine said, the impact of those dollars could be undercut “if we don’t have clear, transparent, useable interconnection standards.”

Freeing the Grid outlines 10 best practices, ranging from “rule applicability” — meaning that interconnection rules cover all distributed generation, including energy storage — to “dispute resolution” — that is, having a process in place to resolve disputes over the upgrades a utility may require a developer to make or pay for.

States are almost evenly split on the storage issue: 24 include storage in their interconnection rules, while 26 don’t. A similar gap appears on dispute resolution, where 28 states have a process for resolving disputes but only 13 require their public utility commissions or other entities to provide ombuds services to track and facilitate the dispute resolution process.

Uneven DER Landscape

Long and costly interconnection processes can delay or sink a DER project, particularly if a utility asks a developer to pay for millions of dollars in system upgrades. A recent study of storage interconnection processes found that in Massachusetts alone, more than 1,600 storage or solar and storage projects had either incomplete or withdrawn interconnection applications in 2022, versus fewer than 400 complete or approved. (See Report: Storage Projects Stymied at Distribution System Interconnection.)

The state received a C from FTG, partly because it does not include storage in its general interconnection rules.

Developing best practices to streamline interconnection of distribution-level solar, wind and storage is another point of resistance, especially from utilities, Constantine said.

“Historically, utilities have had to keep the lights on,” he said. “That’s all they really thought about, and modern technology, like these distributed technologies, kind of upset that paradigm a little bit because now other generators and different kinds of end users are trying to connect into this grid. There are some quality and inertia [issues], but they are operating to older standards and older practices.”

For example, only five states have adopted interconnection regulations that specify a date by which DERs must comply with IEEE 1547-2018, the industry standard for ensuring the safe interconnection and interoperability between DERs and utilities’ electric power systems.

The figures on other key streamlining measures also reflect the uneven DER landscape developers face across the country. Rooftop installations under 10 kW are eligible for a simplified review in only 17 states. FTG found only two states where projects can receive streamlined processing based on their export capacity, as opposed to their nameplate capacity.

Basing interconnection on export capacity can be critical for storage projects because some utilities base their evaluations of such projects on worst-case scenarios rather than on how they actually operate. While most storage projects charge during off-peak hours, a utility might require studies assuming they will only charge during high-demand peaks.

Constantine said he believes part of the problem is the gap between the speed at which technology is advancing and utilities’ traditional aversion to risk and change.

“Part of what we’re seeing in these grades is simply the time it takes for a utility to turn itself around,” he said. “Technology has caught up, and utilities are still trying to … understand that they can operate safely, that they can operate efficiently based on the technical capabilities of the technology that we’re deploying. …

“We’re 10 years on from the major ramp-up in the solar market, and we’re already several years into the battery era. We can’t really say with a straight face that we don’t know how these things are going to operate. We know how they are going to operate, and the standards ought to reflect that.”

A Higher Grade for Hawaii?

While state regulations provide an important benchmark, both Hernandez and Constantine acknowledge that FTG does not always capture the interconnection policies and practices of individual utilities, Hawaii being a major case in point.

FTG gave the state a C but noted that its “updated interconnection practices … have not been reflected in the state’s interconnection tariffs.”

Hawaii was among the first states to adopt a 100% renewable energy target — 2045 — and with its self-contained island grids and high levels of rooftop solar, the state has been a pioneer in DER planning and integration. According to Hawaiian Electric, the state’s main utility, rooftop solar now provides just under 15% of the state’s power, or close to half of all renewable power across the islands.

But rooftop also represents more than 90% of all solar installations in the state, and Hawaiian Electric has periodically come under fire for interconnection delays, such as in 2015, when it was faced with a backlog of 3,000 projects.

“We didn’t have a lot of the tools we have in place now,” said Blaine Hironaga, a supervisor for the utility’s distribution planning. “Hosting capacity was somewhat getting off the ground, and we were concerned about the amount of penetration that was hitting the grid. … So, it was taking some time to do those reviews. … We didn’t have a good process in place to conduct the reviews at the volume we were receiving.”

Fast forward and Hawaii has adopted performance-based ratemaking, under which Hawaiian Electric receives incentives for meeting specific interconnection goals. The state also has a range of rate plans for solar owners, in some cases limiting how much power they can export to the grid.

Ken Aramaki, director of transmission, distribution and interconnection planning, said interconnection reviews can be processed in 15-20 days, relying on “more advanced modeling” of the distribution system and “hosting capacity analysis.”

“We do sort of annual hosting capacity analyses of all the circuits, so we know how much can be added to the distribution system,” Aramaki said. The utility also uses a range of databases to cross-check its technical reviews, he said.

To further streamline interconnection, Hawaiian Electric also performs group or cluster studies, with “a model checkout process ahead of time” to ensure all the members of a group have all the information and system modeling needed before the utility begins the group study, Aramaki said.

The FTG score “doesn’t recognize the level of sophistication required and the technical complexities to get these high renewable numbers,” he said. “We do really complex modeling ahead of the rest of the industry because we have to.”

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MACRUC Panels Discuss Myriad Challenges Facing PJM

FARMINGTON, Pa. — The Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) 28th Annual Education Conference last week at the Nemacolin Woodlands Resort focused on interregional transmission planning, resource adequacy and the risks posed by extreme weather.

Panelists on June 27 discussed the resource adequacy concerns PJM outlined in its “Energy Transition in PJM” white paper released in February. (See PJM Board Initiates Fast-track Process to Address Reliability.)

PJM Vice President of State Policy Asim Haque said the analysis found concerns around the balance between generator deactivations and new entries. As it considers how to address those challenges, he said PJM must balance the interests of member states and regions with diverse priorities.

“I do think that this is overarchingly an engineering problem that we all need to try to collectively solve together,” he said.

Glen Thomas, president of the PJM Power Providers (P3) Group, said that when the Reliability Pricing Model (RPM) was adopted, there was an expectation that the value of capacity would clear at the cost of new entry (CONE), which is currently about $300/MWh. Recent auctions, however, have been clearing much lower, which he said sends a signal for generation to retire.

That has resulted in few new resources being built and generators deactivating, including the 2.2-GW Homer City coal generator in Pennsylvania shuttering this month, Thomas said. He argued that the dynamic has contributed to a decline in reserve margins over the past several years, from above 20% to falling into the single digits.

“You should not be sending a retirement signal knowing what we know now,” he said.

Thomas said improving the outlook for reliability will require revising how PJM accredits resources to ensure the amount of capacity they are able to offer is accurate to their reliability contribution and reworking the market seller offer cap (MSOC) to allow generators to represent their full risk as a capacity resource.

Haque said there has been agreement that the current clearing price is not sending appropriate price signals. PJM’s Board of Managers initiated the Critical Issue Fast Path (CIFP) process to solicit stakeholder proposals to overhaul the capacity market, with the goal of submitting a proposal to FERC in October. (See PJM Continues CIFP Discussion of Seasonal Capacity Market Proposal.)

“The goal should not be to increase prices; that should not be the goal of any market construct. The goal as we see it should be to continue to provide resource adequacy” while keeping costs effective for consumers, Haque said.

Ohio Public Utilities Commissioner Dan Conway said decarbonization is an important focus of his job, but maintaining reliability is his “first and last.” As thermal resources, especially coal-fired, have retired, he said the new resources coming online lack the same reliability attributes and present a looming risk of more regular curtailments and shortfalls.

He said he believes the competitive model formed by PJM offers the best path forward, saying that neighboring MISO is largely vertically integrated and is closer to the edge than PJM.

Vistra CEO Jim Burke said the thinking around renewable resources has shifted from a technology supplementing existing thermal resources to displacing them. As that transition continues, he said far more nameplate generation will need to be developed to replace the same amount of capacity, owing to renewables’ lower accreditation.

“The scale of this is one of the biggest things that I’d just like to emphasize. We’re nowhere near a one-to-one trade,” he said.

While much of the discussion in PJM has been on the pace of new development, Burke said ERCOT has seen a large amount of investment over the past 20 years but continues to have reliability concerns during peak loads, noting that Texas was experiencing a heat wave straining the grid as the conference was ongoing.

“We’re $100 billion in, and we’re still checking the app everyday,” he said, referring to ERCOT’s mobile dashboard.

Interregional Transmission Spotlighted

During a June 26 panel on interregional transmission planning, discussion centered on how new transmission buildout — especially between RTOs — could address growing risks from extreme weather.

The Brattle Group’s Joe DeLosa III said the company’s analysis has found that additional transmission could have provided about $1 billion in value during the December 2022 winter storm — also known as Winter Storm Elliott — paying itself in just the four days of the storm. Despite the benefits, he said new lines largely aren’t being built in part because the multidriver approach doesn’t capture independent transmission needs, and the sequencing of how needs are considered creates a patchwork of regional projects.

Resolving cost allocation disputes poses a challenge to transmission development, but DeLosa pointed to MISO’s planning process as a success in realizing benefits that are greater than the costs. For it to work in the Mid-Atlantic, he said close collaboration will be needed between states, RTOs and FERC.

Jeff Dennis, deputy director for transmission at the U.S. Department of Energy’s Grid Deployment Office (GDO), said his staff are focused on exploring improvements that can be made beyond the RTO-level, such as siting, permitting and other processes that can be streamlined to get transmission built without compromising on environmental justice communities.

In a study the GDO plans to release this fall, investment trends and wholesale price differentials were used to identify constraints, with preliminary results suggesting that new transmission would provide significant value when storms are stressing the grid.

Looking at scenarios with high clean energy penetration and high load growth, the study’s preliminary results find that there is significant need for interregional capacity transfer capability, particularly between the Midwest and Mid-Atlantic. As much as double the current transfer capability could be needed, as well as additional interchange between the Mid-Atlantic and Southeast.

Barbara Tyran, of the American Council on Renewable Energy, said much of the U.S.’ solar and wind potential lies between the Mississippi River and the Rocky Mountains, but only a fraction of it could currently be connected with load centers on the coasts with existing transmission.

FERC’s Jessica Cockrell said cost allocation has to balance planning and the needs of merchant generation to avoid eroding the value of projects. When considering how capacity transfer can be mandated between regions, she said that operational agreements can be reached to determine the share of capability on each line that can be used to flow power from one RTO to another.

David Townley, director of public policy for CTC Global, said grid-enhancing technologies such as reconductoring, dynamic line ratings, fast power flow controllers and energy storage can be used to get more out of existing infrastructure without needing to get new developments through the siting and permitting processes. One of the challenges with installing those technologies is a lack of understanding among utilities in how they can be used, he said.

Utility Executives Discuss Extreme Weather Impacts

Executives from some of the largest utilities in the Mid-Atlantic discussed how extreme weather could impact their operations, as well as how differing policies across the states in which they operate interact together and with federal law.

Dominion CEO Robert Blue said the company was able to maintain service throughout its PJM footprint during Elliott, but it implemented load shedding in other regions. That experience has led it to consider adding LNG storage to some of its large gas-fired generators to address some of the fuel security issues seen during the storm.

Exelon CEO Calvin Butler Jr. said the number of severe weather events has tripled in its region, especially microbursts that come in with minimal warning and put tens of thousands of customers without power. He said improvements in communications have reduced response times, and drones are now being used to detect obstacles that could prevent crews from using a route to access a repair site, aiding in sending the right equipment to where it’s needed.

“What we are finding is the storm forecasts are less and less predictable,” he said.

John Crockett III, president of LG&E and KU Energy, said wind storms are also posing an increasing challenge. High winds during Elliott contributed to three hours of load shedding, along with issues with an interstate pipeline causing some gas generation to be unavailable. A storm in early March brought wind speeds exceeding 60 mph and left around 400,000 customers without power.

Butler said Exelon’s decision to shift to multiyear planning in some states has allowed greater transparency and collaboration, with more detail than annual rate cases. The intervenor process is also changed with multiyear plans, allowing discussion of how rates interact with the policy goals of a state or intervenor.

While the federal government has made billions available to promote its climate and reliability goals, Butler said its actions haven’t always matched its ambitions. Both there and at the state level, legislation is interacting with decades-old regulatory frameworks, which he said can sometimes impede policy goals.

Lightning Round Discussions on Key Issues

During a series of lightning round discussions, several speakers shared their thoughts on the potential of green hydrogen, congressional bills addressing permitting authority, how investors view the state of the energy markets, and an upcoming report on coordination between the gas and energy industries being written by the North American Energy Standards Board (NAESB).

Bank of America’s Julien Dumoulin-Smith said investors are expecting costs for wholesale energy, interconnection and new generation — particularly offshore wind — to generally rise in the PJM region over the coming years.

He predicted that there will continue to be ample capital available for new developments, but the cost of capital is likely to rise with interest rates. Offshore wind installation costs, for example, could double because of interest rates, while concerns linger about whether the ships and logistics required to put the turbines in place are sufficient for looming projects.

“There’s clearly capital available in both debt and equity capital markets, and I think you’re going to see a lot of traditional equity getting raised in lieu of debt in this environment,” he said.

With rising interconnection costs and a growing gap in the valuation between clean and thermal assets, he said some resources are now worth just the value of their interconnection, reducing their prospects for continued operations.

“In this day and age, I don’t think you’re going to see a lot of tolerance if there are operational issues. If you see other issues on gas plants today, you’re going to see people favoring to take them out,” he said.

Constellation Discusses Hydrogen Development

Constellation Energy Executive Vice President Kathleen Barron said hydrogen offers a potential solution to several areas of the economy that have proved challenging to decarbonize, but remains uneconomical for the time being.

“We have proven technology; we know how to do this; companies are actually already doing this at one of our sites in New York, using nuclear energy to make hydrogen using electrolysis,” she said. (See related story, Constellation Gives Details on First-in-nation Pink Hydrogen Production.) “The problem is the cost of doing that is about three to four times what a customer is going to be willing to pay to use hydrogen as a substitute for natural gas.”

Barron said the Infrastructure Investment and Jobs Act provides funding for hydrogen hubs to jumpstart the production and transportation infrastructure necessary for mass industrial use of hydrogen, but the “additionality” clause in the law could pose a roadblock. The clause requires that only new clean energy can be used to power the electrolyzers, but she said it would require a doubling of the amount of renewable power currently available and to use that energy only to produce hydrogen.

“We’d need to double the size of today’s renewable grid and use it only to make hydrogen — not use it satisfy state [renewable portfolio standard] programs or to satisfy the EPA rules that are coming. … If we really want to try to tackle emissions in other sectors, and we want to use hydrogen, we’re going to need to use” existing generation, she said.

Nuclear makes hydrogen cost-effective because of its steady supply of power and the existing transportation infrastructure that tends to be in place at those facilities,” Barron said. Nuclear plants also tend to be further from population centers and have land available around them, raising the possibility of placing electrolyzers behind generators’ interconnection meters, a configuration the company has been proposing through the PJM stakeholder process. (See “Discussion Continues on Capacity Offers for Generators with Co-located Load,” PJM MIC Briefs: June 7, 2023.)

NextEra Evaluating Hydrogen Uses

NextEra Energy Resources Vice President of Development Ross Groffman also spoke about how green hydrogen could be used for industrial decarbonization. Some of the initial uses the company is developing projects for are green ammonia production to create agricultural fertilizer and liquid hydrogen as fuel for long-haul trucks and buses.

Hydrogen could also be used in steel and chemical production or blended into the fuel for natural gas generators, he said.

Intermittent resources sited alongside hydrogen could also be used for energy production when generation exceeds the amount of power the electrolyzers consume. Using hydrogen to fuel combustion turbines will play a central role in the future of decarbonizing the grid, Groffman predicted, and the NextEra is already investing in projects to explore technologies.

“It’s an important part of the long-term view of how some of these plants will run. It’s not going to happen in the next year or two; this is longer term, but it will be a key part of how the long-term green grid will perform,” he said.

Congress Considering Siting and Permitting Legislation

Christina Hayes, executive director of Americans for a Clean Energy Grid, shared her views on a slate of bills being considered by Congress that would address how the federal government interacts with siting and permitting of energy infrastructure. Some of the proposed legislation would offer transmission tax credits “as a kind of hook to getting siting and permitting handled more broadly.”

Hayes said there’s also a growing recognition of the need to incorporate community benefits and other impacts on where projects would be developed, both for pipelines and transmission.

With renewable standards now widespread not only among states, but also utilities and corporations, she said many are coming around to the need for more transmission to be built.

When considering the impact to their ratepayers, she said regulators could be more thoughtful when considering approval of transmission projects that would benefit other states, saying those could be viewed as an “insurance policy” for their future reliability.

NAESB Drafting Recommendations on Gas-Electric Coordination

Robert Gee, co-chair of NAESB’s Gas-Electric Harmonization Forum, gave an update on the recommendations being drafted with the aim of improving the coordination between the two industries. He encouraged all interested parties to either submit written comments or participate in the meetings, of which there have already been a dozen.

There are both operational and structural issues that impact the ability for gas generators to procure fuel during emergency conditions, Gee said, leading NAESB to consider creating a commercial standard or emergency protocols.

“Generators are not able to access gas during critical peak periods for a number of reasons. One is that they don’t have firm contracts, generally for economic reasons. Second, there’s inadequate information regarding available pipeline capacity and little to no transparency on certain parts of the system,” he said.

Gee reviewed a handful of the 17 recommendations that the forum is currently considering, which include increasing the transparency and communication around the status of interstate pipelines, ensuring that gas markets are fully functioning around the clock to allow generators to prepare for peak demand during emergency periods, and synchronizing the gas and electric markets to align the electric industry’s day-ahead procurement schedule with how generators procure fuel.

The forum is also considering recommending re-evaluation of whether out-of-market solutions are needed.

“We rely on competitive markets to basically give us the ability and tools to address this issue of trying to access gas during critical peak periods. We think it’s time to reconsider out-of-market solutions; weigh them carefully; see whether they work; see what they offer solutions to,” he said.

Gee said thought also is being given to recommending that two studies be commissioned by FERC and NERC to look at whether markets currently offer proper incentives for generators to procure firm fuel contracts during emergency conditions and to develop more gas storage infrastructure.

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Former FERC Commissioners Share Outlooks with MACRUC

FARMINGTON, Pa. — Several sitting and former FERC commissioners shared their views on the future of RTOs and the relationship between state and federal regulators during the Mid-Atlantic Conference of Regulatory Utilities Commissioners (MACRUC) annual educational conference last week.

Speaking during the opening sessions of the conference June 26, acting FERC Chair Willie Phillips said cyber and physical security, the changing resource mix, extreme weather risk and the challenge of building the transmission necessary for the clean energy transition are some of the most critical issues the states and commission are likely to face in coming years.

From left: Suedeen Kelly, Jason Stanek, Philip Moeller, Richard Glick and Robert Powelson sit on a panel discussing the relationship between state and federal regulators on June 28. Stanek, who served as chair of the Maryland Public Service Commission, moderated while the panelists were each former FERC commissioners. | © RTO Insider LLC

Former Commissioners Suedeen Kelly, Philip Moeller, Robert Powelson and Richard Glick, the last of whom served as chair until January, sat on a June 28 panel discussing how communication between state and federal regulators can be improved. That forum was moderated by Maryland Public Service Commission Chair Jason Stanek, a former FERC senior staffer.

Both panels were asked how FERC should respond if it concludes that state policies are jeopardizing reliability by causing resources to retire without adequate replacement capacity. Glen Thomas, president of the PJM Power Providers group, asked Wednesday’s panel if the commission would take action in such a scenario.

“In this situation where you have a state policy that is causing pretty significant impacts in other states, is there a role for FERC here? Is this a situation where FERC just shrugs its shoulders and says, ‘Well it’s a state; it gets to do what it wants to?’ Or is this a situation where FERC recognizes the interstate impacts of a state’s action and can do some things to balance the equity?” he asked.

Kelly said the grid requires resources that are dispatchable, a characteristic that renewables largely lack. Until enough utility-scale storage can be developed, she said, thermal resources will have to be retained to maintain reliability.

“If you aren’t at the point where we can dispatch all of our renewables, we need our tried-and-true dispatchable generators, including gas-fired. As much as the community may not want carbon emissions, I think it’s important to educate the community that you can’t have 100% green without storage and in the meantime, we need other ways to ensure our renewables are dispatchable,” she said.

Former FERC Chairman Richard Glick | © RTO Insider LLC

Glick said FERC’s ability to delay retirements is limited and the industry may need to find out-of-market solutions to ensure enough capacity remains available.

“You do have to have market reform, but I also think you have to engage — and I think you’re seeing it more increasingly frequently — you have to have out-of-market solutions to keep plants around, to take other actions to keep the lights on while the [development of] transmission’s underway, [and] while battery storage technology comes into play,” he said.

Powelson said shutting down units could have a cascading effect that impacts other states and requires increased use of reliability-must-run (RMR) contracts.

“We’re all in this together, and my concern is we move too fast and we start having these out-of-market RMR contracts, and that’s not good for consumers; that’s not good for the long-term future of grid reliability,” he said.

When asked about the future of coal plants, Phillips said they will likely continue to play a role for at least the next five years. Gas-fired resources will likely continue operating years past that, while coal units will see economic pressure to deactivate.

Speaking on Monday, Phillips said streamlining the path for building new transmission could provide the “biggest bang for the buck” in getting new generation on the grid. Much of the nation’s infrastructure is over 50 years old and will soon need replacement. He said it may be necessary for RTOs and regulators to begin using a 20-year planning horizon and to explore regional planning. The commission may also explore interregional transfers, he said, pointing to the benefits the capability provided during the February 2021 winter storm.

Also, many projects are designed with a single purpose and don’t consider additional benefits that could be realized.

“We do have projects that sit in silos. They’re siloed because of reliability, they’re siloed because of economics or jobs; what I would like to see are more multivalue projects,” he said.

Fixing Cost Allocation

One of the challenges Phillips anticipates is how to address cost allocation, which he said the commission will likely be addressing in the near future.

On Wednesday, Glick said interstate transmission projects can be difficult to plan when the cost allocations and benefits for each state do not match. While Congress is discussing providing FERC with preemptive siting authority on some lines, he said buy-in from the states will lead to a better outcome.

“The current approach to siting — obviously it can be problematic because there are some cases where some states may not have as much of an incentive to site a line if they feel it’s going to benefit another state, but they’re going to have to pay a significant share of the cost. So fixing the cost allocation problem is a big part of it,” he said.

Kelly said the commission has seen growing opposition to projects, including a convergence across the political spectrum as conservative landowners and liberal environmentalists turn to FERC to push against developments. She said developers of projects such as the West of Devers line in California or Western Spirit in New Mexico were able to build transmission to clean energy by engaging in dialogue with local communities.

“Both of those have been characterized by intense working with the community to try and understand what the communities’ opposition or problem with it is and accommodate it,” Kelly said. “Oftentimes that accommodation comes not just in changing the siting, which is oftentimes what we did at FERC when we were talking about natural gas pipelines, but in spending the money necessary to take care of some of the concerns in communities that were going to be impacted.”

“One thing that we should think about as regulators — state and federal regulators — is can we be a force to further the discussions of transmission developers with the communities and maybe be part of that and facilitate that,” she said.

FERC and EJ

Following the commission’s roundtable on environmental justice last month, Phillips and Glick both spoke about the importance of listening to communities’ concerns and ensuring that the benefits of the clean energy transition are felt by all.

Phillips said it’s a personal priority of his, being from Alabama where he grew up in the shadow of heavy industry. He said FERC has streamlined the permitting process to create a legal obligation for communities to be given a voice. Not enough of the public is participating in hearings, he said, but the commission’s Office of External Affairs is working on improving its consultation process.

Glick recounted visits he made to Port Arthur, Texas, and Lake Charles, La., to view the impact polluting industry has had on residents there. While those aren’t FERC-regulated industries, he said it showed the potential consequences when environmental justice isn’t considered.

Hearing from residents and putting conditions on FERC orders to address communities’ concerns during the FERC process can also avoid legal challenges to its decisions and help get projects built easier, Glick said.