The Renewable Thermal Collaborative (RTC) on Jan. 23 released an Electrification Action Plan that contends electrification should be a major component of any plan to decarbonize industrial thermal energy use.
“When cost-competitive heat pumps, electric boilers and electrified thermal batteries are powered by low- or zero-carbon electricity, they can significantly and immediately reduce emissions,” the report said. “Deployment of improving electrification technologies like high temperature heat pumps can reduce emissions even more over the long term.”
Only 5% of the industrial heat in the U.S. is electrified, so near-term opportunities abound.
Industrial heat pumps (IHPs) can replace fossil fuel-powered systems for applications under 130 degrees Celsius, which represents 29% of industrial thermal demand. Electric resistance technologies can electrify processes up to 1,800 degrees Celsius.
“More than 75% of the emissions from industrial heating come from low- and medium-temperature (<500°C) industrial applications, which are [predominantly] served by natural gas,” the paper said. “These applications include washing, drying, sterilizing, distilling and more and are common in the food, paper and chemicals sectors. Industrial heat pumps, electric boilers and thermal battery systems can replace fossil fuel-powered technologies in these industrial processes to significantly reduce emissions by 2030.”
Thermal energy storage (TES) systems, or thermal batteries, can deliver heat and steam up to 750 degrees Celsius now and should be able to support temperatures of 1,500-1,800 degrees by the next decade.
While the technologies are available now, they are more expensive than producing steam and heat from natural gas due to upfront costs, related infrastructure upgrades and the higher cost of electricity compared to gas.
“Industrial energy buyers seeking to deploy electrification technologies must pay for a variety of expenses throughout project development and operation, including new equipment, process integration, electricity infrastructure upgrades and electricity,” the paper said. “Despite findings that electrification technologies like IHPs and thermal batteries can be cost-competitive with natural gas and that the former may have simple economic paybacks under two years, the cost of electrification remains a significant barrier to adoption.”
The Department of Energy offers incentives that can cut capital costs, but the report said additional federal and state funds are needed to drive electrification.
Power prices are higher than natural gas due to utility rate structures, which increase that difference during peak demand hours.
“These rate structures conflict with decarbonization goals and require policy intervention to reduce the cost of electrification and enable rapid deployment,” the paper said. “Thermal batteries, which can source electricity when it is cheapest, may circumvent the price gap barrier and deliver heat at or below the cost of heat from natural gas combustion.”
Buyers also have less confidence in the electric technologies due to their limited track record. The lack of experience extends to investors, which can translate into higher costs for projects.
“Buyers and investors must see more demonstrations and case studies featuring electrification projects across U.S. industrial applications to become confident in their operational and financial viability, thereby driving demand for these critical technologies,” the report said.
The technologies that can produce industrial heat and steam are in limited supply — as is the workforce that knows how to install and maintain them.
More Grid Resources Needed
Electrified processes also need renewable energy to decarbonize, with widespread electrification of industry potentially doubling demand for electricity. That presents an additional challenge for planners already struggling to transition the grid to cleaner resources.
“The slow pace of long-distance transmission construction and the long wait time for grid interconnections both present significant barriers to meeting increased electricity demand from electrification,” RTC said. “Long-distance transmission and a better-connected, cleaner grid would ensure that industrial facilities [could] access affordable, abundant renewable electricity to meet their needs and protect against outages.”
RTC has set a goal of cutting industrial emissions by 30% by 2030. New federal and state policies to fully electrify will be needed to hit that target.
Federal tax incentives can unlock project opportunities that would otherwise not be viable, and while the Infrastructure Investment and Jobs Act and the Inflation Reduction Act offer a bevy of subsidies for clean technologies, RTC said they were light on industrial decarbonization funding.
“To fill this gap, the RTC is educating members of Congress on the potential for electrification to decarbonize industry,” the report said. “We are also advocating for new investment tax credits to lower costs for industrial end users to electrify and expanded production tax credits that strengthen the economic case for manufacturers to increase supply. Because this will require new legislation, we are laying the groundwork now for action in 2025.”
SPP stakeholders approved congestion-hedging implementation policies last week, six years after first taking up the issue.
“This may be a little more like Groundhog Day because we’re coming back once again with congestion-hedging improvements,” Evergy’s Jim Flucke said during the Markets and Operations Policy Committee’s virtual meeting. “The [Market Working Group] has been working on these improvements for probably about six years now. The Holistic Integrated Tariff Team [HITT] took it over for a while, but it came back to us.
“We’ve worked very hard to find some compromise positions that satisfy the needs of those entities that aren’t getting congestion-hedging rights from their transmission that they’ve purchased. It is not everything that those entities had requested at the beginning, but after six years of work, it is a compromise between the two positions of not wanting anything and the desire to have more balance between market participants,” Flucke added.
The revision request (RR591) would implement congestion-hedging policies already approved by the Board of Directors and Regional State Committee (RSC).
MOPC Chair Alan Myers, with ITC Holdings, reminded stakeholders that the policies already have been decided to head off further discussion.
“What we’ll be talking about today is implementation,” Myers said.
The board and RSC approved a package of eight proposals, designed to increase equity, fairness and financial transmission rights awards among market participants, in July. (See SPP Board/Members Committee Briefs: July 24-25, 2023.)
Since then, the MWG has added language for the annual long-term congestion rights (LTCRs) analysis performed during each round of the auction revenue right (ARR) nomination process to ensure nominated candidate ARRs do not violate any normal transmission-line thermal ratings under normal system conditions.
The group also added language to distribute ARR surplus. This includes an iterative approach to the ARR allocation’s first round and the distribution of excess auction revenues. Once approved by FERC, SPP would allocate 50% of the excess revenue in one year under the old method and 50% under the new method. After that, the new process will take over.
Terry Wolf, whose Missouri River Energy Services has filed a Section 206 complaint at FERC over the issue, said it still does not go far enough.
“Given our situation of having long-term firm service that predated joining SPP and receiving zero LTCRs, we continue to believe it is unreasonable and not consistent with what the precedent is,” he said. “It’s taken too darn long, and it’s not turning quickly enough to provide equity to folks with long-term firm service. I continue to be frustrated by the lack of movement here.”
MOPC Passes Plethora of RRs
MOPC approved 23 RRs and several other documents during the meeting. Myers told the Strategic Planning Committee on Jan. 18 that the agenda’s “volume of approval stuff” required members to “pound through pretty hard.”
“Hopefully, better days are ahead as the rest of our meetings this year will be face-to-face,” he said.
The endorsed revisions included:
The Project Cost Working Group’s RR574, a response to concerns raised by stakeholders that SPP-issued upgrades were delayed past their need date and/or first reported in-service date. The PCWG and staff developed an in-service date delay report and a phased approach to improve transparency and situational awareness. A modified version of the RR that would have extended the original 90-day trigger for PCWG review to 180 days failed. “Extending this time to half a year is not going in the right direction,” the Advanced Power Alliance’s Steve Gaw said. “We should be adding some teeth to some of these cases.” The measure passed with 83% approval.
The Transmission Working Group’s RR577, which clarifies the SPP flowgates that will be automatically included in the RTO’s initial constraint list; establish criteria for classifying facilities as economic needs because of congestion from planned or forced historical outages; and establish criteria for classifying facilities as reliability needs due to pre-contingency or post-contingent facility rating or voltage limit exceedances.
RR578 passed unanimously with two abstentions. It creates a new and “appropriate” uninstructed resource deviation (URD). With an average cost to resources in 2022 of $3.65/MW of deviation proving not to be a sufficient deterrent for dispatch noncompliance, the MWG proposes the URD charge be equal to the real-time deviation above or below the resource operating tolerance multiplied by the absolute value of the real-time LMP.
RR600.3, setting up rates for point-to-point and network service because of Western Area Power Authority’s Rocky Mountain Region and Upper Missouri region having facilities in both interconnections. The associated revenue distribution will be based on the amount of annual transmission revenue requirement specific to the facilities in an interconnection. The revision passed unanimously.
Imports Help Weather the Storm
C.J. Brown, SPP’s director of system operations, told stakeholders that were it not for a record 6.8 GW of energy imports during the Jan. 14-17 winter storm, the RTO would have been in an energy emergency alert.
“We almost got to [7,000 MW] … but 7,000 MW of imports during the storm, which is really impressive indeed, kept us out of an emergency,” he said, delivering an initial report on the event. “If you take away those imports, we would have 100% been in an EEA the entire time Sunday through Tuesday, no doubt about it. If you took away half those imports, we’re probably in an EAA, but we’re definitely on Sunday and Monday, maybe even Tuesday.”
Some of the imports came from ERCOT on Jan. 14, attracted by higher prices in SPP. Power flows went in the opposite direction Jan. 15.
The imports drew the attention of FERC Chair Willie Phillips during the commission’s open meeting Thursday. He said the storm underscored the importance of interregional transmission ties.
SPP wound up setting a peak load record for January at 46.7 GW on Jan. 17, bettering the previous mark of 43.2 GW set in 2018.
Brown said SPP experienced up to 20 GW of conventional resource outages during the event because of frozen coal piles and plant issues along the Missouri River. With wind “screaming” at times and producing 20 GW of energy at its high point, the grid operator was able to meet demand.
“Things just do not operate well in -20 temperatures. They just don’t,” Brown said.
McAdams to Consult with REAL Team
The leadership may have changed within the Resource and Energy Adequacy Leadership (REAL) Team, but it still is focused on addressing SPP’s resource adequacy corporate risk and goals, staff told MOPC.
“It continues to be one of our corporate goals to mitigate this risk and move forward in a valuable and measurable manner for all of the various policies and initiatives we have going on,” SPP’s Casey Cathey said.
Kristie Fiegen, chair of the South Dakota Public Utilities Commission, has replaced former Texas commissioner Will McAdams as the REAL Team’s chair. McAdams resigned from his posts in December. (See McAdams Honored During Last Texas PUC Meeting.)
McAdams will remain involved with the team’s work. He has formed his own consulting firm, McAdams Energy Group, with a focus on energy and infrastructure development. The RSC already has contracted with McAdams’ firm to consult on mitigating the resource adequacy risk within the RSC and the REAL Team, SPP’s Kim O’Guinn said.
Kansas Corporation Commissioner Andrew French has filled McAdams’ RSC seat on the REAL Team. To preserve the team’s regional balance, Texas Public Utility Commission senior economist Shawnee Claiborn-Pinto has replaced Kansas Corporation Commission staffer Shari Albrecht.
Staff credited McAdams with the team’s success last year, which included developing and approving revision requests related to a winter season resource adequacy requirement (RAR) (RR549), performance based accreditation (RR554), and effective load-carrying capability (RR568), and demand response accreditation and fuel assurance policies; beginning an expected unserved energy (EUE) study and the load evaluation portion of the Future Energy and Resource Needs Study (FERNS); and completed the 2023 loss-of-load expectation study.
This year, the team has set its sights on an “appropriate” accreditation of resources, winter season requirements, planning reserve margin (PRM) methodology changes, load forecasting and a future resource mix/EUE study.
The workload includes addressing FERC’s November rejection of SPP’s proposed winter resource adequacy requirement. The commission said the RTO can address FERC’s concerns and resubmit the proposal (ER23-2781). (See “FERC Rejects Winter Requirement,” ‘Therapy Session’: SPP REAL Team Reviews Draft LOLE Study.)
The commission said the proposal did not contain any requirement that a load-responsible entity’s (LRE) resources are expected to be available. It said SPP has not demonstrated it is reasonable to permit LREs to rely on resources that are not expected to be available in the winter season to satisfy their resource adequacy requirements.
“They gave us very tangible feedback,” Cathey said. “From a staff perspective, we have not lost effective dates such that we can still move the ball forward with the winter PRM.”
SPP plans to refile the winter RAR at FERC in April. If approved, it will be nonbinding until the 2026-27 winter.
Members pulled two revision requests off the consent agenda for individual votes but ended up approving both.
Renewable energy interests asked for more transparency into the calculations of RR603, which increase study deposits for new generator interconnection requests using FERC Order 2023’s mandated schedule and adds a non-refundable application fee. The change also increases deposits for surplus, modification and replacement studies.
Staff said a survey of the last seven study clusters indicated costs generally are 10 to 30% more than the current maximum study deposit of $90,000. Under the Order 2023 schedule, most deposits will range from $100,000 to $150,000 and would have covered the average costs for the clusters, they said.
“I’ve asked for the documentation,” Gaw said. He acknowledged SPP has said the study costs are correct but said, “There’s been some degree of concern about how these things have been handled, on the amount of the consultants that have been used and how contracts are done.”
Although the revision passed the Regional Tariff and Transmission Working Groups with just one abstention, staff said they have responded to stakeholder concerns by implementing a request-for-proposal process for special studies; reached out to SPP-approved consultants for pricing and availability; added consultants to the study pool to increase diversity and competitive costs; and performed special studies in-house when resources are available.
MOPC endorsed RR603 with 85.1% approval.
The committee also separately approved a remedial action scheme (RAS) in western North Dakota with a near-unanimous vote. The RAS will provide temporary relief in the Williston load pocket until the Roundup-Kummer Ridge 345-kV line is completed early next year.
Flucke expressed concern over the proposal, saying it is causing TCR underfunding.
SPP’s Micha Bailey said the RAS will help TCR underfunding because it loosens as the impact of that congestion constraint decreases. “That’s going to lessen the amount of congestion on that [region], which then was the amount of money owed to those TCR holders.”
MOPC’s consent agenda included 15 RRs, five of which (RR600.1-RR600.6) are related to western entities integrated into SPP’s RTO. It also included approval to retire the Thunderhead RAS in Nebraska in November; a lessons-learned report on the third Regional Cost Allocation Review; the 2024 Transmission Expansion plan; the 2023 Integrated Transmission Plan’s (ITP) short-term reliability project report; and a 2024 ITP market powerflow models waiver.
The RRs would:
RR560: Move operating criteria language to the system operating limits (SOLs) methodology.
RR583: Allow SPP to nominate LTCRs for federal service exemption and grandfathered agreements carveouts to further mitigate load’s exposure to the day-ahead market’s (DAMKT) congestion costs.
RR587: Correct the virtual energy offer curve from 0 to 100 MW to accurately reflect current pricing.
RR588: Modify the regulation-selection process to include qualified resources that cleared regulation in the DAMKT for the operating hour, reducing their financial risk to competitively offer ancillary services in both the day-ahead and real-time markets.
RR593: Clarify the cost allocation for two Basin Electric substations so that both can correctly be allocated according to the base plan.
RR594: Incorporate improvements mandated by FERC Order 2023 to ensure the generator interconnection process is just, reasonable, and not unduly discriminatory or preferential.
RR595 Close a market design gap related to FERC Order 831’s implementation by using make-whole payments to compensate resources being unable to recover their cost of incremental dispatch in some scenarios.
RR597: Document the DAMKT high-level process used for effective limit application.
RR598: Remove planning criteria portions outlining the methodology to develop SOLs and interconnection reliability operating limits (IROLs) in the planning horizon. This aligns with NERC’s retirement of Mandatory Reliability Standard FAC-010-3.
RR600.1: Clarify for western parties integrating into SPP’s RTO terms and conditions that Attachment AU, which describes the distribution to transmission owners of revenue received from MISO under a settlement agreement, applies to TOs in the Eastern Interconnection.
RR600.2: Include existing non-radial lines, substations and associated facilities operating at 100 kV or above, and radial lines and associated facilities operated at or above 100 kV that serve two or more eligible customers that are not affiliates of each other as transmission facilities in the West under Attachment AI.
RR600.4: Remove Attachment AT and its definition of a contract services agreement between Basin Electric Power Cooperative and SPP, which no longer will be needed with Basin’s integration into SPP’s western RTO.
RR6005: Modify the tariff to refer to a WAPA division where it currently refers to WAPA-Upper Great Plains.
RR600.6: Revise Attachment S, under which transmission providers determine megawatt-mile impacts separately for the SPP East Region and SPP West Region, to also include SPP Region, if needed. Because WAPA’s Upper Missouri and Rocky Mountain Region zones having facilities in both interconnections, some rates for point-to-point and network service and their associated revenue distribution will be based on the amount of annual transmission revenue requirement specific to those facilities in an interconnection.
RR601: Ensure multiday minimum runtime RRs and clean-up RRs (RR382, RR540 and RR569) are accurately implemented and functioning as designed. The revision creates new determinants to represent the effective start-up amount of a resource that will only be used in the evaluation of the day-ahead and real-time multiday minimum run time make whole payment.
PJM has begun studying 308 generation interconnection requests sorted into its Transitionary Cycle 1 (TC1), marking a milestone in the RTO’s shift in how it conducts studies of the grid upgrades necessary for resources in its clogged queue, the RTO told FERC on Jan. 16 (ER22-2110).
The cycle is the first to use the cluster-based approach FERC approved in November 2022. The process groups projects to study what upgrades will be necessary and to allocate costs. In an announcement of the start of TC1 studies, PJM said projects sorted into the cycle are expected to be complete in mid-2025, clearing 46 GW of new generation to move to construction. (See FERC Approves PJM Plan to Speed Interconnection Queue.)
The first step of the transition, the sorting process, resulted in 616 eligible projects being evenly split between TC1 and an expedited “fast lane” process for studying projects with estimated upgrades below $5 million. The fast lane queue is intended to allow projects PJM believes can be studied quickly to progress under the former serialized study and cost allocation process as it shifts studies expected to take longer to complete over to the cluster approach. Study cases for expedited projects are expected to be posted by Jan. 26, and final documentation is anticipated to be complete by the end this year. Projects that have been placed in the fast lane can be moved to TC1 if the short circuit, stability or feasibility analysis determine that more than $5 million is required.
Projects submitted in the AG1 and AH1 queue windows will be required to resubmit their projects to match the transitional rules before being included in Transitionary Cycle 2. Submissions in queue window AH2, which was open between October 2021 through March 2022, will form the first full cycle under the new rules after the completion of the transition.
The FERC-approved interconnection study regime also includes that deposits be made throughout the process to ensure that developers are covering the cost of the studies and to weed out speculative proposals that have been blamed for congesting the queue with requests that may never lead to actual construction. To that end, PJM launched its Queue Scope tool, which allows developers to get a sense of potential upgrades necessary to interconnect a generator at a given location.
In a social media post responding to PJM’s announcement, White Pine Energy Consulting said the RTO has been staying on track with implementing the changes.
“I am looking forward to seeing how well the new interconnection process works, but first we need to get through the transition. PJM has been doing a good job staying on schedule as they implement the first transition cycle,” it said.
FERC put the Tennessee Valley Authority one step closer to replacing its Cumberland coal plant with a new natural gas plant when it permitted a new pipeline Jan. 18 (CP22-493).
Environmental groups have expressed displeasure with FERC’s issuance of a certificate of public convenience and necessity for Tennessee Gas Pipeline’s (TGP) 32-mile pipeline to feed the planned 1,450-MW Cumberland gas plant. TVA has said it could retire the first of two coal units at its 2,470-MW Cumberland Fossil Plant as early as 2026 with the new gas capacity online.
In its approval, FERC denied Sierra Club and Appalachian Voices’ request for a hearing over the need for the pipeline and associated gas plant.
“Commenters assert that additional natural gas infrastructure is unnecessary. Many of these commenters argue that alternative sources of energy should be used to combat climate change and that TVA’s plans conflict with the climate policy of the federal government,” FERC noted. However, the commission said the Tennessee Valley Authority Act bestows the utility’s board of directors with the “exclusive authority” to evaluate the need for generation facilities within the service territory.
FERC asserted that it did its due diligence under the National Environmental Policy Act (NEPA) to approve the pipeline. It said it found no evidence of self-dealing when TGP entered into a binding precedent agreement with the unaffiliated TVA for the project’s full capacity.
The Sierra Club, Appalachian Voices and the Center for Biological Diversity, represented by the Southern Environmental Law Center, filed a lawsuit in mid-June in the U.S. District Court for Middle Tennessee, centered around what they claim were NEPA violations with the pipeline’s planning. The lawsuit claims TVA disobeyed NEPA by committing to a new natural gas plant too early in the process, failing to seriously consider carbon-free alternatives, and ignoring the climate harms and volatile fuel costs the community will bear.
In their FERC protest, the groups repeated claims that TVA signed contracts for final design work on the pipeline before the NEPA process was completed.
SELC, on behalf of Sierra Club and Appalachian Voices, is also challenging a state permit from the Tennessee Department of Environment and Conservation, saying the agency ignored the harm the pipeline will inflict on local waterways. (See TVA’s Cumberland Coal-to-gas Plans Press on over Resistance.)
FERC estimated that TVA exchanging coal for gas at the Cumberland site would cut greenhouse gas emissions by about 7 million metric tons annually.
The commission said that because the pipeline will feed a project that ultimately lowers emissions, it cannot be considered harmful for NEPA purposes.
“A net reduction in the emissions of a pollutant logically cannot cause a significant adverse impact under NEPA,” FERC said.
FERC estimated that the social cost of greenhouse gas emissions from the project could range from nearly -$1.9 billion to -$21 billion, reflectively a net decrease in overall downstream emissions, but it said it was including the figures for informational purposes only. It said its calculations don’t conclusively determine whether the project will have a significant effect on climate change. FERC also said NEPA doesn’t outline criteria on how to come up with monetized values to establish the magnitude of future pollutants.
“The D.C. Circuit [Court of Appeals] has repeatedly upheld the commission’s decisions not to use the social cost of carbon, including to assess significance,” FERC said.
Commissioner Allison Clements dissented from parts of the order in which FERC claimed it was impossible to assess the significance of greenhouse gas emissions. Clements has long argued that FERC hasn’t tried to evaluate methods.
“This is the same language I have criticized many times. It does not improve with age,” she said.
The SELC said FERC’s decision to greenlight the pipeline “ignores the significant and long-lasting damage it will do to the climate, utility customers and Tennessee communities.” The group also blasted TVA’s “massive, multibillion-dollar fossil fuel spending spree.”
“FERC commissioners moved to recklessly rubberstamp this project without fully evaluating the harm this unnecessary pipeline would do to families throughout the Tennessee Valley,” SELC senior attorney Amanda Garcia said in a press release. Garcia added that “clean energy technology is already more cost effective than building new gas plants and pipelines.”
SELC repeated that TVA’s investment in natural gas “works against” the Biden administration’s goal for a carbon-free grid by 2035.
“It is irresponsible and regressive to permit new fossil-fueled power plants and pipelines that will worsen the climate crisis, create more energy vulnerabilities and increase electric bills,” Sierra Club field organizing strategist Amy Kelly said.
A Wisconsin coal plant kept online for the sake of reliability will receive smaller monthly payments from MISO, FERC ruled in a settlement approval last week.
Under the settlement, Manitowoc Public Utilities will collect $880,000 per month, totaling about $10.5 million annually, for the term of its System Support Resource (SSR) agreement on its 63-MW Lakefront 9 unit (ER23-977). FERC said the amount was more appropriate than the $1.03 million in monthly compensation to keep the plant running the utility originally proposed. (See FERC Approves SSR Agreement for Wisconsin Coal Plant.)
Manitowoc Public Utilities will receive about $1.8 million less per year than it requested.
The company’s Lakefront 9 began operating as an SSR in February 2023 after MISO found that thermal overloading and voltage issues could occur on several nearby constraints if the plant was permitted to suspend operations as scheduled. The utility wanted to idle Lakefront 9 until 2026 to convert it to a renewable fuel source.
MISO has one other active SSR designation in its Midwest region. The RTO may keep Ameren Missouri’s 1.2-GW Rush Island coal plant online until sometime in 2025 for reliability reasons. (See MISO Poised to Extend Missouri Coal Plant’s Life.)
MISO enacts its SSRs agreements in one-year increments and evaluates the need for them annually until it finds the system is stable enough to lift them.
ERCOT said Jan. 23 it has increased its executive leadership team with four promotions.
The grid operator said the changes expand on the executive team’s “deep experience and knowledge … to proactively manage the complexities of a rapidly transforming electric grid.” They were effective Jan. 1.
“ERCOT requires focused, value-driven, timely, transformational changes to its tools, technology and processes,” CEO Pablo Vegas said in a statement. “Transformation necessitates innovation, and these organizational changes will continue to position ERCOT as a leader in the electric industry.”
Those promoted are:
Jayapal “J.P.” Parakkuth, senior vice president and CIO, leading the IT group and supporting the development, delivery and operations of technology.
Venkat Tirupati, vice president of dev-ops and grid transformation, will manage technology innovation capabilities to address the complexities of a rapidly transforming grid.
Sean Taylor, senior vice president, CFO and chief risk officer, overseeing ERCOT’s financial health.
Adam Martinez, vice president of enterprise risk and strategy, with responsibility for the ISO’s Enterprise Risk Management program and ensuring strategic objectives are achieved.
The promotions boost ERCOT’s executive team to 14 members, with Vegas, five senior vice presidents and eight vice presidents.
Consulting with host communities at the beginning of planning processes for new clean energy projects would expedite development timelines and prevent unnecessary impacts on vulnerable communities, Massachusetts environmental justice leaders said at a forum Jan. 20.
The meeting was convened by the Massachusetts Environmental Justice Table, a coalition of environmental, civil rights and Indigenous organizations focused on promoting environmental justice policy in the state.
Reverend Vernon Walker, Climate Justice Program Director for Clean Water Action | Massachusetts Environmental Justice Table
The speakers emphasized the negative effects existing permitting and siting procedures have had on vulnerable populations in the state.
“The process has not been working and is not working,” said Paula García, senior bilingual energy analyst at the Union of Concerned Scientists. “Most of the fossil fuel power plants are concentrated in environmental justice neighborhoods, with their associated negative health impacts.”
The coalition is promoting a bill in the state legislature that would make significant reforms to the state’s Energy Facilities Siting Board (EFSB), adding climate, environmental justice and public health to the EFSB’s priorities and introducing representation for environmental justice and indigenous communities.
The bill would also require early engagement and cumulative impact assessments prior to a project’s approval, while expediting the process for approving clean energy generators and storage projects. Top legislators have indicated that permitting and siting reform will be a major focus of an omnibus climate and energy bill this year. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.)
“We support a transition to renewable energy but need laws and regulations that carefully consider the costs, risks, benefits, burdens and needs of hosting environmental justice communities,” said Rusty Polsgrove, an environmental justice organizer at Springfield-based Arise for Social Justice.
Polsgrove spoke about the group’s ongoing fight against Eversource’s contested proposed pipeline project in Western Massachusetts. (See More Environmental Information Required for Western Mass. Gas Pipeline.) Polsgrove said Eversource engaged with the community too late in the planning process, after the company had already spent a significant amount of time and money on planning and permitting the pipeline.
“That’s tokenism,” Polsgrove said, adding that the late engagement prevented meaningful consideration of community needs and existing burdens in the planning process.
John Walkey and Noemy Rodriguez of Chelsea-based environmental justice organization GreenRoots discussed their experiences with Eversource’s community engagement process for the long-fought substation in East Boston.
“We didn’t find out about the plans for the substation until the project was well underway and moving forward,” said Rodriguez, translated into English by Walkey. “When we tried to get involved with the project, the state proceedings were not translated into Spanish.”
Greasing the Skids
Walkey contrasted the community engagement around the substation in East Boston with a battery project in Chelsea, in which the developers solicited input from GreenRoots early in the process.
“They’re interacting with us. We’re helping them grease the skids basically to move this project forward, and we’re pleased with it,” Walkey said.
He added that GreenRoots and other environmental justice activists who long opposed Eversource’s substation in East Boston are “not against electrical substations — in fact, we think if they’re needed, they should be built.”
At the same time, utilities and project developers should work with communities to develop the best solution for all involved, and consider options like efficiency and demand reduction, distributed energy, and batteries, Walkey said.
“We definitely need more capacity, but that capacity can’t be met by using the same tools of the last hundred years,” Walkey said, adding that utilities make significant rates of return on large infrastructure projects, which can disincentivize developing new methods to avoid these large projects altogether.
If the substation in East Boston, sited on the banks of Chelsea Creek, is damaged by climate-fueled flooding, “[ratepayers] will pay to repair it, and [Eversource] will be guaranteed a profit margin off of the repair,” Walkey said.
Eversource and National Grid, the state’s two largest electric utilities, have proposed to build a combined 40 new substations to meet growing electricity demand coming from heating and transportation electrification in the state. (See Mass. Utilities Submit Grid Modernization Drafts.)
In an email to NetZero Insider, Eversource spokesperson William Hinkle said permitting and siting reforms are “critical to ensuring that we can build the necessary infrastructure to help achieve the commonwealth’s decarbonization goals, and greater engagement and collaboration with our communities [are] essential to the process.”
He pointed to Eversource’s proposal with the state’s other electric utilities to create a Community Engagement Stakeholder Advisory Group “dedicated to ensuring communities are engaged early and often in project development and have a seat at the table as key decisions are being made over the next two decades.”
At the same time, Hinkle defended the company’s engagement with communities in East Boston and in Western Massachusetts, writing that the company has “always strived to engage our communities and solicit feedback from key stakeholders on projects.”
The New York Public Service Commission on Jan. 18 approved the establishment of a utility-led working group to identify, study and deploy new clean energy technologies essential for achieving the state’s net-zero goals (20-E-0197).
At its monthly meeting, the PSC approved the Advanced Technology Working Group (ATWG) to vet advanced transmission technologies and develop deployment strategies, as required by the Accelerated Renewable Energy Growth and Community Benefit Act. The law directed the commission to identify system upgrades necessary to achieve the mandates set forth in New York’s Climate Leadership and Community Protection Act (CLCPA).
Proposed by some of the state’s largest utilities, known collectively as the Joint Utilities (JUs), the ATWG originated from their Research and Development Plan for Advanced Distribution and Transmission Technologies (R&D Plan), submitted to the PSC in July 2022. According to the JUs, the ATWG will “ensure that the necessary policies, procedures and standards exist to address technical, process, regulatory and economic concerns related to modern and innovative technologies.”
The ATWG’s primary focus is to explore and analyze technologies that will aid in meeting the CLCPA mandates, concentrating on dynamic line ratings, power flow control and energy storage in the near term.
Additionally, the group will support the Coordinated Grid Planning Process (CGPP), a two-year, six-stage framework initiated by the PSC last year with the aim of enhancing collaboration among New York’s stakeholders and aligning transmission system development with the state’s decarbonization goals. The ATWG will assess the viability of technologies proposed through the CGPP by stakeholders in forums such as the Energy Policy Planning Advisory Council (EPPAC). (See NY Utilities Propose Plan to Coordinate Decarbonization Efforts and NY Policy Council Holds Inaugural Meeting to Discuss CGPP.)
The PSC directed the JUs to submit a revised version of the proposed ATWG plan within 30 days.
Role and Requirements
In their R&D Plan progress report, the JUs highlighted the ATWG’s role in not only examining potential future technologies but also in standardizing their development and adoption throughout New York.
The PSC’s order underscores the ATWG’s importance within the broader transmission planning process, recognizing the group’s “critical role to play in identifying advanced technology applications that will help reduce the cost of new transmission infrastructure developed through the CGPP.”
Additionally, the JUs noted that the ATWG is expected to help “develop tools and methodologies to evaluate and apply advanced technologies as part of potential non-wires alternative solutions.”
ATWG staff held their first technical conference in April, primarily presenting an overview of the group and its objectives rather than discussing any specific technologies. The PSC mandated that the ATWG conduct at least one open call for stakeholders to submit advanced technology proposals before another technical conference, which must be held in the first half of 2024. The ATWG must then file an initial assessment of the submitted proposals within 60 days of the conference’s conclusion.
Starting in 2025, the ATWG must annually publish a calendar of its activities by Jan. 31 of each year. These reports will include assessments of technologies under review, results of relevant studies, budget allocations and recommendations for technology deployment by utilities.
Overview of the ATWG’s role according to the JUs | Joint Utilities
Commissioner Comments
The commission unanimously approved the order, though some commissioners expressed concerns.
Commissioner Diane Burman said she worried about the increasing number of groups and task forces involved in implementing state law, risking diminished public transparency and collaboration. She urged the creation of a single “regularly updated” document that cohesively details all the ongoing work or issues addressed by each of the groups, stressing the need for these efforts to be “coordinated, seamless and not have everybody doing something siloed.”
She also warned state agencies against inadvertently favoring certain technologies or developers over others, saying, “We cannot be picking winners and losers.”
Commissioner John Howard pointed out that while he understood the need to examine “other technologies down the road,” he argued that “this should in no way slow down the progress of what is already available today.”
He encouraged transmission owners and developers to adopt “these very proven and very cost-effective technologies as quickly as possible,” adding that “in pursuit of the excellent, let’s not leave some really good stuff on the side.”
Chair Rory Christian said the PSC’s decision to approve the ATWG “will ensure the state’s investments take advantage of cost-saving and efficient new transmission technologies.”
PJM has hired former Maryland Public Service Commission Chair Jason Stanek to lead the RTO’s state government policy and state solutions teams.
“PJM’s work with states has been critical to helping states preserve reliability of the system as we move forward through the energy transition,” Stanek said in a statement announcing the hire. “I look forward to building on this solid foundation with some insight into what states need to succeed.”
The hiring is part of PJM’s effort to boost relations with state and federal governments by restructuring the State and Member Services departments, led by Senior Vice President Asim Haque, into the Government and Member Services branch.
“Jason brings a wealth of experience to PJM that will benefit both PJM and its stakeholders,” Haque said in the announcement. “He was a thoughtful, knowledgeable and independent regulator who will further bolster the depth and breadth of our engagement.”
Maryland PSC spokesperson Tori Leonard said the commission saw growth in its electric vehicle, renewable energy and consumer protection programs during Stanek’s leadership.
“Chairman Stanek’s tenure was notable for the commission’s embrace of novel ratemaking practices, specifically multiyear plans; promoting retail energy competition with progress on supplier consolidated billing, as well as tougher enforcement against suppliers who violated the commission’s consumer protection rules; greater grid reliability; and advancing the state’s clean energy policies, including investment in energy battery storage, and support for the development of solar and offshore wind,” Leonard said. “As an EV driver and advocate, he was particularly proud of the PSC’s efforts to advance electric vehicle adoption by supporting the build-out of a statewide public charging network.”
Stanek was PSC chair from July 2018 through 2023, during which time he served on several working groups as a member of the National Association of Regulatory Utility Commissioners (NARUC), including its Joint Federal-State Task Force on Electric Transmission and the Electric Vehicle Working Group. He was also a board member of the Regional Greenhouse Gas Initiative (RGGI) and the Keystone Policy Center.
Prior to joining the Maryland commission, Stanek was senior energy counsel for the U.S. House Committee on Energy and Commerce and was branch chief of electric power markets at FERC between 2014 and 2017.
Consolidated Edison has been cleared to undertake another major system upgrade to meet growing electricity demand in New York City.
The state Public Service Commission on Jan. 18 authorized the utility to proceed with its Idlewild Project, a $1.2 billion package that will add two substations and an electrical network in southeast Queens (22-E-0064).
Con Edison serves one of the most expensive and densely built places in the nation, and the cost of transitioning from fossil fuel to electricity likely is to be quite high. In a mid-2023 update, it valued its present investment plan at $11.8 billion.
Commissioner Diane Burman cited the financial impact on New Yorkers from the ongoing series of expensive projects statewide before she cast the lone dissenting vote on the Idlewild Project at Thursday’s meeting.
“I do not think it is sustainable, as we do more electrification — whether it is this company’s territory or other companies’ — that the ratepayers bear the bulk of this,” she said.
In its petition, Con Edison said the Jamaica service network is the largest among its networks electrically and has the highest peak demand. The utility predicts that without changes, peak demand could exceed its 492-MW design capacity by as much as 6 MW in 2026, 30 MW in 2030 and 51 MW in 2032, with peak load shedding starting in 2028.
It proposed to split the Jamaica network into two pieces; build two substations; and transfer 170 MW to the Idlewild Project.
The work not only will address reliability needs as buildings and transportation are electrified but create points of interconnection for future clean energy projects and for the energy storage the utility seeks to add in the area.
Con Edison said it considered non-wire alternatives to the proposal and is pursuing them for 2026-27, but they will be insufficient to meet anticipated growth in the Jamaica network.
Con Edison also said transferring load to neighboring substations was not an option, as they, too, are at capacity.The network includes the nation’s sixth-busiest airport, third-busiest train station and four major bus depots with a combined 700 buses. The Metropolitan Transportation Authority plans to electrify its bus fleet, most of the trains already are electrified, and the Port Authority of New York and New Jersey has set a net-zero emissions target for John F. Kennedy Airport.
In a news release, Con Edison flagged the gradual electrification of medium- and heavy-duty fleets in the area as a driving force behind the Idlewild Project and said air quality would improve as a result.
“By investing in our Reliable Clean City-Idlewild project,” CEO Tim Cawley said, “we are building New York’s clean energy infrastructure while creating good jobs, advancing New York’s climate goals and ensuring that our grid remains reliable for customers in Southeast Queens for decades to come.”
The project budget breaks down to three components:
The new Idlewild Distribution Area Substation, estimated cost $380 million, target in-service date May 2028;
The new Eastern Queens Transmission Substation, estimated cost $592 million, in-service date April 2028; and
The new Springfield Network, cost $242 million, in-service date not specified.
Con Edison serves 3.6 million customers in the five counties of New York City and a suburban county to the north.
