National Grid Wins Approval for $15.6M Geothermal Demo

Massachusetts regulators on Thursday gave National Grid (NYSE:NGG) the go-ahead to study geothermal district energy as an alternative to replacing natural gas pipes that leak.

The Department of Public Utilities (DPU) issued an order approving the utility’s $15.6 million, five-year demonstration program, saying it could inform the state’s efforts to understand the role of gas distribution companies in achieving its 2050 climate goals.

Participating buildings will incur a monthly charge by rate class: $60 for residential, $45 for low-income residential and $90 for commercial and industrial. The program will include the installation of up to four shared-loop geothermal systems, each serving 20 to 40 residential or commercial customers, or a combination of both.

Where National Grid seeks to avoid replacing leak-prone gas lines, participating customers must discontinue gas service and switch to electric appliances. Project funding will be available to help customers that need to replace natural gas appliances, such as stoves.

National Grid has one year to file an implementation plan for DPU approval. Each system could take 12 to 24 months to construct, according to the utility’s initial program filing.

In its order, the department acknowledged the contribution of information on geothermal technology provided during the proceedings by the nonprofit Home Energy Efficiency Team (HEET). It also encouraged National Grid to consider HEET’s recommendations for the program, which included using control software for integrated data acquisition and sharing program data publicly where possible.

“We hope to assist [National Grid] to come up with the standard metrics for the project … so that we can have normalized data,” Audrey Schulman, HEET’s co-founder and co-executive director, told NetZero Insider. “We’re also hoping to provide design assistance … to give them more expertise on tap to make sure that they have the information they need.”

HEET’s other executive director, Zeyneb Magavi, is credited with developing and refining the idea of installing ground-source heat pumps in gas utility rights of way to serve multiple buildings.

“We would like to continue to advise on the whole project process to make sure it’s done well and de-risked for all … so that we can evaluate [the projects] as a method that we might very much need in the future,” Schulman said.

Federal Funds

Gov. Charlie Baker signed a bill Dec. 13 authorizing $4 billion in American Rescue Plan Act funding that includes the study of geothermal district demonstration projects in the state.

The Massachusetts Clean Energy Center (MassCEC) will receive $5 million for the study, which will include National Grid’s projects and Eversource Energy’s $10 million geothermal district demonstration project that the department approved last year.

Working in collaboration with researchers, nonprofits and universities, MassCEC will seek to:

model the system design and operation of proposed networked geothermal demonstration project sites;
monitor the thermal energy storage potential of sites;
create a public project data bank;
disseminate recommendations and best practices for rapid scaling and optimization;
provide projections of scaled-up site impacts on heating, emissions, health, customer bills and other variables;
engage and educate stakeholders in potential project host communities; and
perform feasibility studies for communities interested in serving as project hosts.

The stimulus funding also allocated $150,000 to Michael Walsh, a senior research scientist with the Institute for Sustainable Energy, to study the thermal heating transition in Massachusetts.

December 21, 2021November 13, 2023

New York Issues 10 GW Solar Roadmap for 2030

New York officials on Friday announced the release of a roadmap outlining expanded programs to achieve 10 GW of distributed solar in the state by 2030 (Case No. 21-E-0629).

The state defines distributed solar as projects under 5 MW, including rooftop installations and community solar projects. The new framework builds on New York’s solar energy progress so far, with installed distributed solar and projects under development already totaling 95% of the current state goal of 6 GW by 2025.

“Strengthening our commitment to solar energy will help build healthier, more resilient communities while catalyzing quality, good paying new jobs in this thriving sector of our clean energy economy,” Governor Kathy Hochul said in a statement.

The New York State Energy Research and Development Authority (NYSERDA) and the Department of Public Service (DPS) submitted the roadmap to the Public Service Commission for public comment.

The expanded NY-Sun initiative aims to incent the construction of at least 1,600 MW of new solar capacity to benefit disadvantaged communities and low-to-moderate income New Yorkers, and proposes that at least 450 MW be built in Con Edison’s service territory covering New York City and parts of Westchester, increasing installed solar capacity there to more than 1 GW by the end of the decade. NYSERDA also proposes that at least 560 MW be advanced through the Long Island Power Authority.

Progress Toward 6 GW Mandate (NYSERDA) Content.jpg

An overview of the progress made toward the 6 GW target, by development phase, market sector, and region. Most of the progress to date has been in the Upstate region for C/I onsite and community solar projects. | NYSERDA

The proposal would require workers associated with projects supported by NY-Sun that are greater than 1 MW be paid the applicable prevailing wage, although projects that submitted their initial utility interconnection application prior to the Dec. 17 filing of the roadmap would be exempt from that requirement.

NYSERDA and the DPS estimated that the new solar push would direct $600 million in investments toward disadvantaged communities, with the Climate Leadership and Community Protection Act (CLCPA) mandating that at least 35% of the benefits from the state’s renewable energy spending go to such communities.

The proposal estimates that the solar program expansion will spur $4.4 billion in private investment and create 6,000 additional solar jobs across the state.

A study commissioned by the New York Climate Action Council’s Just Transition Working Group last month predicted that the state’s clean energy sector will add at least 211,000 jobs this decade and nearly 350,000 by midcentury, and that 10 new jobs will be created for every job displaced through 2030 by the state’s transition away from fossil fuels. (See NY Predicts 200K+ New Clean Energy Jobs by 2030.)

Questions and Answers

To ensure funding for the incremental 4 GW target, NYSERDA proposes ratepayer collections of nearly $1.5 billion through 2032. The cost of up-front incentives would be distributed across utilities proportional to load via a Clean Energy Fund surcharge.

Funding would not require new processes or ongoing settlements between utilities or NYSERDA. NYSERDA’s cashflow analysis has been updated to reflect the projected expenditure forecast of the $1.47 billion.

“Assuming collections occur over the 11-year period of 2022-32, the average levelized ratepayer bill impact is 0.79%,” the roadmap said. “The levelized impact on residential bills would be $0.71 per month. Expenditures, collections, and ratepayer impact are forecasted to peak in 2024. The 2024 bill impact is calculated at 1.07%, with an average 2024 statewide residential bill impact of $0.92 per month.”

The Public Service Commission on Thursday approved NYSERDA’s 2022 Clean Energy Standard compliance period administrative budget in the amount of $30.2 million, up from $28.4 million this year (Case No. 15-E-0302).

PSC Commissioner Diane X. Burman, one of two Republicans on the seven-member commission, said that while it’s reasonable that the NYSERDA team must grow as the workload continues to grow, the commission needs to engage in more discussion about how the state will deal with legislation that creates significant cost drivers.

“I believe very strongly that we should look at the proper resources, staff resources across the board,” Burman said. “I’m tired of it just being NYSERDA who we’re looking at … I’m left with blanks.”

Under the same CES proceeding, nuclear energy advocacy group New York Energy and Climate Advocates on Dec. 7 submitted to the PSC a query regarding differences between NYSERDA’s analysis of the steps needed to meet CLCPA goals and analysis of the same subject by NYISO.

The letter signed by Leonard Rodberg referred specifically to a presentation of clean energy integration scenarios and analysis provided by NYSERDA and consultancy Energy and Environmental Economics (E3) at the Oct. 1 meeting of the Climate Action Council, and to the Climate Change Impact Phase II study conducted by Analysis Group on behalf of NYISO in September 2020. (See New Analysis Sets Low-carbon Focus for NY Climate Plan.)

“In our view, both analyses reveal an unrealistic buildout of intermittent, low-energy-density, low-capacity factor sources and related infrastructure that warrants the consideration of alternatives if New York hopes to meet its climate goals,” Rodberg said. “We also recommend better coordination between agencies involved in crafting energy policy and entities charged with maintaining the reliability of New York’s electric grid.”

Rodberg said in the letter that since Oct. 1 he had written three times to Carl Mas, NYSERDA’s director of energy and environmental analysis, and received no reply to his questions.

One question concerned NYSERDA’s estimate of up to 126,047 GWh annual solar generation by 2050, which Rodberg said corresponds to a capacity factor of “almost 22%. However, the capacity factor of solar PV in New York is poor, only 14% for fixed panel and only 20% for tracking panels. How does NYSERDA explain this discrepancy? … Did NYSERDA inadvertently use capacity factor data for a different state?”

In response, NYSERDA told RTO Insider that it has provided an “unprecedented” level of transparency around the Integration Analysis presented to the Climate Action Council, with the most up-to-date inputs and key drivers published on the CAC resource website. The analysis team has conducted an in-depth study of the performance and cost of solar-PV technology specific to New York, the agency said.

NYSERDA said the state’s solar PV capacity factors range from 13 to 21%, depending on the NYISO Zone (based on variation in solar irradiance by geography) and installation configuration, with large utility-scale tracking projects able to harness more power than fixed roof-mounted systems.

December 21, 2021March 13, 2024

PJM PC/RMC Briefs: Dec. 14, 2021

Planning Committee

Interconnection Process Proposals

Members praised work done by PJM in the stakeholder process in the development of new rules for the interconnection process, as four proposals were brought to last week’s Planning Committee meeting.

Jack Thomas, of PJM’s Knowledge Management Center, provided a first read of the new interconnection process proposals from the work done at the Interconnection Process Reform Task Force.

An issue charge for work to be completed was approved at the April PC meeting, with task force meetings starting later that month. (See “Interconnection Process Reform Endorsed,” PJM PC/TEAC Briefs: April 6, 2021.)

Key work activities include studies related to the interconnection process and costs related to network upgrades; improving and clarifying the use of interim agreements; the process for rules and requirements for new service requests; and ways to reduce the interconnection queue backlog.

Stakeholders also discussed how PJM will transition to a new interconnection process. Thomas said a separate slate of transition proposals is still being developed and will be presented for a first read at the January PC meeting.

PJM conducted a poll in November on the proposals, with a total of 625 companies responding, including 280 member companies. The PJM proposal received the highest level of support, with 83% of all responding stakeholders supporting the measure and 86% support from PJM members. The next most popular proposal was a joint effort from Open Road Renewables and Cypress Creek Renewables, which received 60% support from all stakeholders and 33% support from PJM members.

A proposal from RWE Renewables received 35% support from all stakeholders and 22% support from PJM members. Finally, Clearway Energy’s proposal received 29% from stakeholders and 16% from members.

More than 90 design components were included in the matrix developed at the task force.

Thomas said details common to all four proposals included moving away from the concept of “first come, first served” projects in the queue to a “first ready, first served” concept. Thomas said the change will ensure projects that are ready to be built are prioritized instead of allowing speculative projects to fill the interconnection queue.

The proposals would add language that if a facility study isn’t needed and no network upgrades are necessary for a project, then it could move to the final agreement stage early, speeding up the process. The study window for projects is also proposed to be scheduled for 710 days, or just under two years.

Three separate phases are being created to go through the interconnection process with different milestones attached to each phase. Thomas said at the end of each phase, there will be a decision point for customers to either continue with a project or abandon it and remove it from the queue.

Prior to proceeding to the final agreement, Thomas said, a customer will need to have all security deposit amounts submitted, 100% control of the building site, the attainment of all necessary state, county and local permits and the completion of all state jurisdictional interconnection requirements.

Jason Connell, director of infrastructure planning for PJM, said the RTO has spent most of the year putting together a proposal that is “workable” and “achieves a level of consensus” from the task force. Connell said PJM used an “enormous amount of feedback” from stakeholders to formulate the proposal.

“This moves the PJM interconnection process into a new stage where we can provide customers more cost certainty [and] timing certainty and make sure the projects that are ready to move ahead into construction and interconnection do so,” Connell said.

Matthew Crosby of Cypress Creek thanked PJM for their leadership in the task force. Crosby said its proposal wit Open Road largely mirrored PJM’s except for state jurisdictional issues. It would give interconnection customers “more flexibility,” Crosby said, allowing project customers to post a security deposit and grant extension rights in the event of delays outside of the control of customers.

Iker Chocarro of RWE said there were five different issues his company wanted to “improve upon” in their proposal compared to PJM’s. Those issues included:

site control language alignment;
affected-systems studies coordination;
interconnection service agreement execution timeline;
study methodology and coordination; and
public policy and state agreement approach alignment.

Chocarro said RWE recognized that the last two items were likely out of scope from the issue charge, but he encouraged PJM to address and coordinate with stakeholders on those issues in the future.

Paul Sotkiewicz of E-Cubed Policy Associates said PJM did an “absolutely fabulous job” in running the stakeholder process in the task force and that their actions should serve as a “model going forward” as other issues are debated. He said its proposal “strikes the right balance” of where it needs to go in the future in the interconnection process.

“This has been a really good experience, and I hope the rest of PJM can replicate the process that’s been done here,” Sotkiewicz said.

Brian Kauffman of Enel North America said PJM has “put a lot of work” into the stakeholder process on the interconnection process issue and “appreciated the time and energy” spent in the task force.

John Brodbeck, senior manager of transmission at EDP Renewables North America, said he witnessed a “very level-headed and consistent effort” by PJM to improve the interconnection process and would like to see new rules implemented as soon as possible.

Alex Stern, director of RTO strategy for PSEG Services, said he was “impressed” by the level of discussion that took place between stakeholders with diverse perspectives, as well as PJM, both in task force meetings and offline to develop proposals and reach consensus.

“I think we landed in a good spot, and I think you’ll see a number of the transmission owners supportive of the PJM approach,” Stern said.

Thomas said the process in the task force was difficult but ultimately fruitful.

“At the beginning we did start off polar opposites, and I think we’ve managed to get really close to the equator and get packages forward that everybody will be able to live with,” Thomas said.

The committee will be asked to vote on the proposals at next month’s PC meeting.

Generator Deliverability Proposal

Jonathan Kern of PJM’s transmission planning department provided an update on a timeline for the development of a proposal to change the generator deliverability test.

Kern said PJM has agreed to conduct two sets of studies. The first is on the baseline in the 2026 Regional Transmission Expansion Plan summer, winter and light load assumptions, and the second is on an interconnection queue case using commercial probabilities to get an idea of the long-term implications of new rules.

All the work PJM is doing to provide transmission results and complete the studies is “customized,” Kern said, with staff developing power flow models and completing an “extensive” revision to the in-house generator deliverability code. He said the in-house work has resulted in delays in the completion of the generator deliverability testing.

PJM is planning on providing a first read of the proposed generator deliverability changes at the Feb. 8 PC meeting.

“We have to make sure all the new rules are reasonable, both on an individual unit basis and collectively,” Kern said.

Apex Clean Energy’s Richard Seide asked if there will be any FERC filing involved in the process by PJM because of the potential for “significant changes” and impacts to customers.

Kern said that will come down to whether the changes will be considered planning assumption changes. He said typically in the past, PJM handled planning assumption changes through manual adjustments that didn’t require any revisions to governing documents of FERC filings.

Kern said work currently being done in PC special sessions on capacity interconnection rights for effective load-carrying capability resources will also help to determine whether a FERC filing is needed or not.

“Depending on how that process works out, we may or may not have to make a filing,” Kern said.

Sotkiewicz said the generator deliverability issue “dovetails with a lot of market and resource adequacy reliability issues.” He said he can imagine scenarios in which capacity is being purchased that is not deliverable or could be backed down at PJM’s direction because there’s not enough transmission to deliver the energy on the system.

Sotkiewicz said there should be a more holistic discussion beyond the PC, possibly involving a joint meeting with the Market Implementation Committee.

“As we’re having these discussions, it becomes more apparent that this is beyond a Planning Committee technical issue that we’re dealing with,” Sotkiewicz said.

Preliminary 2022 Load Forecast

PJM is anticipating “accelerated load growth” compared to last year’s forecast as the 2022 load forecast is finalized this month, largely driven by the development of data centers in Virginia.

Tom Falin, director of resource adequacy planning for PJM, reviewed the preliminary 2022 load forecast results; the final results are expected by the end of the year. The long-term load forecast includes peak demand and energy forecasts for all zones, load deliverability areas and PJM over a 15-year forecast period.

The preliminary 15-year annualized load growth rate in the summer months for 2022 is estimated at 0.4%, Falin said, compared to 0.2% in the 2021 load forecast. However, 2025’s rate is estimated to be 0.5% lower than in last year’s model, driven by improvements in modeling.

Preliminary 15-year annualized load growth rates in the winter months for 2022 are estimated at 0.6%, compared to 0.2% in the 2021 load forecast. Falin said behind-the-meter solar growth in PJM reduces the load impact modeling for the summer months by about 0.3% per year.

Summer peak average annual growth (2022-2037) | PJM

Falin said the 2022 methodology changes in the forecast included enhancement to the sector models like residential, commercial and industrial customers to “better capture granularity.” PJM specifically looked at industrial intensity, a measure of the electricity demand per unit output, and the industrial makeup of individual zones to have a better idea of the types of industry.

Summer and winter forecast comparisons (PJM) Content.jpg

PJM summer and winter forecast comparisons between 2021 and 2022. | PJM

“A steel plant is going to be much more energy intensive than electronics manufacturing,” Falin said.

PJM also made improvements to better capture weather response in the summer and winter. Falin said the impact of the two modeling changes was “not great,” and there were changes to the model in the last few years that had a larger impact.

Falin said the model parameters included a behind-the-meter solar and battery forecast for the first time. He said the amount forecasted was “extremely small,” at 30 MW across the RTO, but PJM is “trying to get ahead of the game” as more storage comes online.

“That is something that could expand significantly in the future,” Falin said.

In the forecast adjustment parameter for different transmission zones, PJM received information from Dominion about the addition of data centers in Northern Virginia. Falin said the planned data center projects could amount to as much as 2,800 MW of additional load by 2025.

“Past Dominion forecasts have underestimated the growth in data centers to some extent, so PJM has to be sure to capture that,” Falin said.

Risk Management Committee

Bankruptcy Protections Issue Charge Endorsed

Stakeholders unanimously endorsed an issue charge at last week’s Risk Management Committee meeting to examine changes to PJM’s bankruptcy process with members.

Jess Troiano, senior counsel for PJM, reviewed the revised problem statement and issue charge addressing potential bankruptcy protection opportunities to be made in the tariff.

Troiano said PJM currently has several steps it can take regarding bankruptcies, including retaining all payments due as cash security for all obligations; suspending and/or terminating transmission service; and limiting, suspending and/or terminating market participation.

PJM has handled 15 bankruptcy proceedings in the last three years, Troiano said, with the RTO having to secure outside representation with its bankruptcy counsel to protect its interests. PJM hasn’t suffered any “catastrophic loss” resulting from the bankruptcies, but its outside counsel and in-house staff identified areas in the tariff that the RTO can “fortify” to create stronger protections against future bankruptcies.

Some of the possible enhancements identified include:

distinguishing between liquidation and reorganization in bankruptcies;
requiring designation of PJM as a critical vendor upon bankruptcy filing;
establishing an obligation to replenish collateral for post-petition activity;
adding language with respect to priority interest in collateral; and
strengthening recoupment language.

“We are not limited to these five, and we’re not beholden to these five,” Troiano said.

Work on the issue charge will begin at the January RMC meeting and is expected to take four months.

December 21, 2021June 14, 2023

WECC Warns West Heading for Resource Shortfalls by 2025

The Western Interconnection faces threat of widespread resource shortfalls by 2025 largely because of increased variability in demand and generation, according to WECC’s Western Assessment of Resource Adequacy (WARA), released Friday.

“Both demand and resource availability variability are increasing, and the challenges they present appear worse now than they did in the 2020” WARA, WECC said. “Resource adequacy risks could get worse before they get better if action is not taken immediately to mitigate near-term risks and prevent long-term risks.”

Higher Demand Meets Variable Generation

WECC introduced the WARA last year to supplement NERC’s Long-Term Reliability Assessment (LTRA) because of concern among Western stakeholders that NERC’s analysis did not capture all the risks that the Western Interconnection faced. (See Western RA Planning Must Change, WECC Says.) Like the LTRA, the WARA attempts to identify the biggest threats to the bulk power system over the next 10 years.

This year’s LTRA, also released on Friday, noted emerging challenges to electric reliability from severe weather events and the move toward weather-dependent renewable resources. (See NERC Identifies 10-Year Challenges from Weather, Resource Mix.) WECC’s report also highlighted these issues, noting that while the interconnection’s “baseload” resources — coal, nuclear and natural gas — are expected to remain “relatively flat in terms of capacity” for the next decade, the capacity of solar resources is set to nearly double over the same period largely because of “new clean energy mandates and … customer demand.”

Forecast of the Western Interconnection resource mix (WECC) Content.jpg

Forecast of the Western Interconnection resource mix, 2022-2031 | WECC

Although the new resources are technically sufficient to satisfy peak demand, their variability means registered entities cannot guarantee their availability at all times. In addition, increased use of electricity for transportation, heating and cooking means higher demand for these unreliable resources to meet. Consequently, WECC warned that none of its five subregions will “be able to eliminate the hours at risk for loss of load even if they build all planned resource additions and import power.”

To mitigate loss of load, the report’s authors suggested periodically recalculating the planning reserve margin (PRM) anytime there is a substantial change to demand or resource availability to reflect the dynamic nature of the modern grid more accurately. Alternately, WECC could switch from the peak demand PRM that it currently uses, which is calculated based solely on the peak demand hour, to a higher fixed PRM, which the authors hope would ensure entities are prepared for sudden changes in load or generation at any time.

New Study Methodologies Tested

For this year’s WARA, WECC also sought to “deepen the analysis of resource adequacy and provide an assessment of specific scenarios” by adding a deterministic scenario analysis to augment the traditional probabilistic analysis. This study focused on the impact of various extreme scenarios on the ability of balancing authorities to import energy.

WECC tested entities’ export and import behavior across the interconnection under three scenarios: one in which demand and generation for the year conform to the most likely conditions; high demand, simulating one-in-33-year demand level; and drought case, simulating both high demand and no energy from Glen Canyon and Hoover dams. All three scenarios model the same time period: an evening hour in June 22, chosen because it “represents a time of high demand and resource variability.”

Under normal conditions, excess energy generated in the north and east moves toward the south and west, so energy flows out of Arizona, Montana, the Northwest and Northern California and flows into southern Nevada, New Mexico, Southern California and Mexico. But the deterministic analysis “showed dramatic changes in power flow … in both the high demand and drought cases,” WECC said.

During high demand, regions are able to bring reserve resources online to help serve the increased load; Colorado and New Mexico switch from importing power to exporting, while Northern California must switch from exporting to importing power to serve its higher demand. The drought case puts a bigger strain on the system, with Colorado, Arizona and parts of Utah now unable to export power and New Mexico having to increase exports to supply those areas; in addition, more energy must flow out of the Northwest into California to make up for the loss of the two dams.

Despite the growing challenges, WECC sounded a note of hope in the report by noting that there is still time for utilities to address these issues. But the RE warned that action is needed sooner rather than later because options will become more restricted as time goes on.

“Entities have many more options to address resource adequacy issues in the five-to-10-year time frame than in the near-term,” WECC said. “However, it is critical that entities act now to address years five-10 because the magnitude of the resource adequacy challenges increases with time. If the current long-term issues are not addressed immediately, they may be insurmountable when they become near-term issues.”

December 21, 2021

NJ Adopts EV Truck Sales Mandate

New Jersey’s Department of Environmental Protection (DEP) announced Monday that as part of the state’s effort to cut carbon emissions, it has become the third state to adopt rules based on California’s Advanced Clean Truck (ACT) regulations, which require truck manufacturers to meet increasing electric vehicle sales targets.

The rules require manufacturers of vehicles weighing more than 8,500 pounds to sell an increasing number of electric trucks after 2025, so that by 2035, they account for 55% of class 2b and 3 trucks, 75% of Class 4 to 8 trucks and 40% of truck tractor sales.

ACT also requires manufacturers to provide annual sales reports to the state and requires “large entities including retailers, manufacturers and government agencies” to file a one-time report on their truck fleets. That information will provide a foundation on which state officials can create plans for increasing the use of electric trucks in the future.

The penalties for failure to comply with the fleet reporting requirements start with $2,000 for the first offense, rising to $30,000 for the fourth and each subsequent offense.

New Jersey’s adoption of the rules, which originated in California and were first enacted there in June 2020, follows similar adoptions in Oregon on Nov. 17 and Washington on Nov. 30, according to the Natural Resources Defense Council. (See Enviros, Industry Urge Oregon’s Swift Adoption of Clean Truck Rules.)

Hayley Berliner, clean energy advocate with Environment New Jersey, called the adoption “a great holiday gift” from Gov. Phil Murphy.

“To reach our climate goals, and make our communities healthier, we need to move to an all-electric future,” she said. “The Advanced Clean Truck rule is a huge step in that direction.”

Health vs. Expense

The adoption of the rules follows months of public hearings, with vigorous support from environmentalists, who argued that the rules are essential to cutting carbon emissions. A smaller, but equally vehement, opposition from business and truck manufacturing groups argued that the rules are too aggressive and that neither the state’s trucking sector nor charging infrastructure and incentive programs are ready to handle a mandated increase in sales. (See NJ Electric Truck Rules Face Many Questions.)

Kathy Harris, clean vehicles and fuels advocate for NRDC, said New Jersey will see a “see a myriad of health, climate and economic benefits with the implementation of the ACT rule.”

“With the adoption of the ACT rule, New Jersey’s medium- and heavy-duty [MHD] truck market will be shifted away from using dirty fossil fuels to zero-emission technology,” she said.

But Allen Schaeffer, executive director of the Diesel Technology Forum, said the state’s move would harm and slow down the effort to cut emissions.

“This means higher costs for new trucks with fewer vehicle choices,” Schaeffer said. “They have also effectively disadvantaged other available and more affordable options like the use of low-carbon renewable biodiesel fuels that could be doing more to lower GHG emissions right now.”

He added that “even if the most optimistic of all policy, funding, technology and infrastructure scenarios fall into place, the time frame for zero-emission heavy-duty vehicles to make up a majority percentage of the commercial trucks on New Jersey roads and streets is going to be measured in decades, not years.”

Ray Cantor, a vice president at New Jersey Business & Industry Association (NJBIA), one of New Jersey’s largest business groups, said it remains opposed to the rules, in part because the costs of embracing them will be too high for trucking companies.

Disproportionate Pollution

Transportation accounts for 42% of carbon emissions in New Jersey, and increasing the number of EVs on state roads is key to Murphy’s plan of cutting New Jersey’s carbon emissions by 80% of 2006 levels by 2050. The state’s master plan, released in 2019, assumes that 75% of medium-duty trucks and 50% of heavy-duty trucks will be electric by 2050.

“Transportation emissions remain the largest source of climate pollution in New Jersey, which disproportionately impair the air quality and public health in underserved communities,” DEP Commissioner Shawn LaTourette said in a statement announcing the enactment of the rules. He said that although MHD trucks and buses account for only 4% of all vehicles on the road, they make up nearly 25% of transportation-sector greenhouse gas emissions.

There are few electric trucks on New Jersey’s roads despite the state’s efforts to ramp up their use by offering incentives and seeking to increase the number of available heavy-duty chargers. The New Jersey Economic Development Authority said in October, for example, that applications in the first phase of its New Jersey Zero Emission Incentive Program would put 148 vehicles on the road for the $15 million incentives available. (See ‘Last-mile’ Deliveries Drive Demand for NJ Truck Incentives.) That’s a tiny number compared to the 220,000 Class 3 and above trucks in the state, as estimated in a report compiled by the NRDC.

Truckers in New Jersey, like those around the nation, cite the lack of MHD charging sites as a key obstacle to greater use of electric trucks. Other barriers include the short range of existing electric trucks — only up to around 250 miles — and the high cost of the vehicles. (See Port NY-NJ Cites ‘Hurdles’ to Employing EV Trucks.)

Electric trucks supporters, in response, say that the technology, and selection of available trucks, is improving, and that eventually they can be cheaper because of lower maintenance and fuel costs. (See NRDC Report Predicts a Decline in NJ’s EV Truck Costs.)

Raising EV Truck Sales

Under the ACT rules, manufacturers accrue “deficits” based on their sales in the state that are neither zero-emission nor near-zero-emission vehicles. The calculation of deficits is based on factors including the model year, the weight class group and whether a vehicle is considered a tractor.

To follow the law, the manufacturer must accrue credits that are equal to or exceed the value of deficits it accrues in a particular year. Credits will be awarded for the sale of a vehicle in New Jersey that is zero emissions or near zero emissions, with the value of the credits based on the weight class.

Each year after 2025 through 2035, the value of deficits increases, based on sales percentages set out in the rules, forcing the manufacture to sell more EVs to remain in balance with deficits or to otherwise obtain credits.

Still, for all their support for the law, both NRDC and Environment New Jersey said the law is just the first step needed to cut emissions in the state.

“Cleaning up tailpipe pollution from thousands of trucks on New Jersey’s roads is one of the best ways to improve the health of communities from Newark to Cape May,” NRDC’s Harris said. “The ACT rule does not require zero-emission trucks or limit the use of dirtier trucks across the state, so further policies are needed to better address the pressing needs in those impacted communities.”

December 21, 2021December 14, 2023

PJM MRC/MC Briefs: Dec. 15, 2021

Markets and Reliability Committee

Synchronous Reserve Endorsed

Stakeholders at Wednesday’s Markets and Reliability Committee meeting endorsed a PJM proposal to improve the deployment of synchronized reserves during a spin event.

The proposal, which was developed from discussions in the Synchronized Reserve Deployment Task Force (SRDTF) and endorsed at the November Operating Committee meeting, received a sector-weighted vote of 3.77 (75.4%), surpassing the necessary 3.335 threshold for endorsement. (See “Synchronous Reserve Endorsed,” PJM Operating Committee Briefs: Nov. 4, 2021.)

Ilyana Dropkin, an engineer in PJM’s performance compliance department, reviewed the proposed solution and corresponding tariff and Operating Agreement revisions addressing synchronous reserve deployment.

Synchronized reserve events are emergency procedures triggered by PJM to maintain grid reliability in accordance with NERC’s Resource and Demand Balancing (BAL) standards. The RTO invokes those procedures under conditions such as the simultaneous loss of multiple generating units or a sudden influx of load.

The SRDTF examined ways to secure controlled deployment of synchronized reserves throughout emergency events by using tools such as real-time security-constrained economic dispatch (RT SCED) to maintain consistent pricing and dispatch signals. Dropkin said the goal was to ensure BAL compliance during the recovery process and maintain a reliable transition in and out of emergency events and to define clear rules and expectations that address how PJM operators approve RT SCED cases around a synchronized reserve event.

PJM’s proposal creates an intelligent reserve deployment (IRD), a SCED case simulating the loss of the largest generation contingency on the system and for which approval of the case will trigger a spin event. The proposal takes the megawatts of the largest generator contingency and adds them to the RTO forecast to simulate the unit loss. PJM can then flip condensers and other inflexible synchronized resources cleared for reserves to energy megawatts and procure additional reserves to meet the next largest contingency.

Some of the significant changes over the status quo in the proposal include updating the economic basepoints to replace all-call instructions, Dropkin said, along with having active constraints controlled by IRD so that deployed resources don’t have negative impacts on the constraints.

PJM is looking at a phased approach for IRD, with an initial phase of six to 12 months beginning as soon as March.

IRD updates will be provided at OC meetings beginning next year, including a review of performance metrics and solicitation of feedback and a finalized deployment approach and adjustment for upcoming reserve market changes.

“IRD is an out-of-the-box solution that seamlessly integrates into PJM’s existing dispatch applications,” Dropkin said.

Mike Bryson, PJM senior vice president of operations, said the RTO has always been focused on recovering reserves as quickly as possible “to be ready for the next bad thing to happen.” Bryson said the proposal retains that focus for reliability issues.

Susan Bruce, counsel to the PJM Industrial Customer Coalition, said the ICC “continues to have concerns” with the proposal. Bruce previously brought up issues with the proposal at the November MRC meeting, saying IRD didn’t appear to be the correct solution. (See “Synchronous Reserve Deployment Stakeholder Initiative,” PJM MRC/MC Briefs: Nov. 17, 2021.)

“As PJM goes out to get reserves that we’re going to call ‘shortage,’ I think it is problematic from our perspective and a just and reasonable rate perspective,” Bruce said.

Market Monitor Joe Bowring said he believed the status quo was preferable to PJM’s proposal because the IRD will result in “inefficiently high prices.” Bowring said RTO load under IRD would continue to increase by the largest contingency megawatts even though “that’s generally too big” and results in overresponse during spin events.

Sean Chang of Shell Energy said his company supported PJM’s proposal because it “takes a step in the right direction.”

The proposal will have a final endorsement vote at the January Members Committee meeting.

Regulation Market Senior Task Force Endorsed

A new senior task force aimed at examining PJM’s current regulation market design was unanimously endorsed by stakeholders as discussions continue on how to advance a short-term solution to the undefined regulation mileage ratio calculation issue debated for several months.

Danielle Croop, senior lead market design specialist at PJM, reviewed the problem statement and issue charge first presented at the November MRC meeting. (See “Undefined Regulation Mileage Ratio Calculation,” PJM MRC/MC Briefs: Nov. 17, 2021.)

Croop said the language in both documents was similar to language that created the former Regulation Market Issues Senior Task Force that last met in 2017. Stakeholders at the June 2017 MRC meeting agreed on a proposal developed in the task force that changed compensation in the regulation market. (See PJM Regulation Compensation Changes Cleared over Opposition.) The proposal was ultimately rejected by FERC. (See FERC Rejects PJM Regulation Plan, Calls Tech Conference.)

The proposal to look at the regulation market design came in response to stakeholder feedback at the October MRC meeting after stakeholders rejected two different proposals to change the undefined regulation mileage ratio calculation in Manual 28 and the tariff. (See “Regulation Mileage Ratio Fails,” PJM MRC/MC Briefs: Oct. 20, 2021.)

Regulation mileage measures the amount of movement the regulation control signal requests of a resource; it is calculated for the duration of the operating hour for each regulation control signal.

PJM’s performance-based regulation market splits the dispatch signal in two: RegA for slower-moving, longer-running units; and RegD for faster-responding units that operate for shorter periods, including batteries. If a signal is “pegged” high or low for an entire operating hour, the corresponding mileage would be zero for that hour.

The RTO has witnessed an increase in the frequency and duration of RegA signal pegging, highlighting a potential problem in the regulation mileage ratio calculation. The RegA mileage can be set at zero for a given hour and create a divide-by-zero error in the calculation of the mileage ratio.

PJM proposed setting the RegA mileage floor at 0.1 instead of zero, which would provide a solution for the division ratio and still maintain market design objectives while having no impact on the regulation signal design, operations or regulation market clearing.

The Independent Market Monitor proposed a cap of 5.5 on the realized mileage ratio in all hours instead of 0.1, indicating the cap would eliminate the current undefined mileage ratio result that PJM is attempting to address.

Members said other larger issues with the regulation market needed review besides the undefined regulation mileage ratio calculation, and PJM said it supported a broader review through a new task force. (See “RTO to Propose Review of Regulation Market,” PJM MIC Briefs: Nov. 3, 2021.)

Key work activities in the task force issue charge include regulation market education, evaluating the benefits factor curve and proscribed RegA/RegD commitment percentages, and proposing any modifications to the regulation market to address issues raised in the evaluation. Expected deliverables include potential modifications to the regulation market and changes to the tariff, OA and manuals resulting from the regulation market modifications.

Areas up for evaluation include signal design, performance scoring, regulation market clearing and regulation settlement.

Croop said the review is expected to take 12 months and would start sometime in the second or third quarter of 2022.

“This will really give us the opportunity to evaluate any operational or market components of the regulation market design,” Croop said.

Adam Keech, PJM vice president of market design and economics, discussed the next steps the RTO was examining to resolve the undefined regulation mileage ratio calculation issue. Keech said PJM had a couple conversations with the Monitor since the November MRC meeting to find a compromise between the proposed RegA mileage floor values of 0.1 and 5.5, but did not come to a compromise.

“We’re just coming at this issue from two different angles,” Keech said. “It’s just two different views on how to tackle this issue.”

If a short-term solution cannot be determined and a divide-by-zero error in the calculation of the mileage ratio occurs, Keech said, PJM would make a Section 206 filing with FERC to propose a replacement rate for the specific occurrence of the undefined mileage ratio.

Paul Sotkiewicz of E-Cubed Policy Associates said he was interested in having discussions on market designs but didn’t want to see a RegA mileage floor number “picked out of a hat” without justifying the chosen value.

“We’re not prepared to support just any number just for the sake of getting a number in there,” Sotkiewicz said.

Bowring said the current regulation market design is not working properly, and the undefined mileage ratio is “one symptom of it.” He said a short-term fix would be the best outcome for now to solve for the problem while stakeholders discuss the broader issues.

“There is no magic to the exact number,” Bowring said. “It’s really up to the judgment of the participants to pick that number.”

Tariff Revisions Rejected

Stakeholders rejected proposed revisions to attachment DD of the tariff endorsed by the Governing Document Enhancement and Clarification Subcommittee after being pulled from the consent agenda.

The committee voted against the revisions with a sector-weighted vote of 2.17 (43.4%), coming under the necessary 3.335 threshold for endorsement.

The revisions included removing section 6.2(c) of the attachment because FERC affirmed PJM’s position that this section of the tariff was no longer applicable and encouraged the RTO to remove the provision as part of its next tariff clean-up filing.

In a complaint filed in June, Jackson Generation alleged that PJM violated section 6.2(c) of attachment DD by failing to file a report concerning the minimum offer price rule (MOPR) offer floor and other mitigation determinations made in connection with the Base Residual Auction for the 2022/23 delivery year within seven days of the deadline for the submission of sell offers into that auction (EL21-82).

FERC denied the complaint, saying the requirement to file a report detailing any determinations was “only applicable to the mitigation determinations that are ‘identified in such sections as subject to the procedures of section 6.2(c),’” and that several provisions contained in the section “no longer state that they are subject to the procedures of section 6.2(c).”

The commission previously ruled in favor of Jackson Generation in a related filing in which the company challenged the rejection by PJM and the Monitor of its request to use an asset life of more than 20 years in calculating the plant’s unit-specific exception to the MOPR. (See PJM Must Consider Longer Asset Life for Generator.)

Jeff Whitehead of Eastern Generation requested that the revisions be pulled from the consent agenda, saying that issues surrounding the unit-specific review process and the market seller offer cap (MSOC) for the upcoming BRA have created a desire among some stakeholders for more transparency in the process. (See PJM Requests Rehearing of MSOC Change.)

Whitehead said many of the negotiations on the unit-specific offer levels are “happening behind closed doors,” and market participants of FERC don’t have a “very clear view of exactly what the standards for review are.”

Sotkiewicz made a motion to table the vote on the tariff revisions until the sunset of the Resource Adequacy Senior Task Force and discussions on the MOPR are complete. Sotkiewicz, who represents Jackson Generation, said the company continues to disagree with FERC’s finding that section 6.2(c) was an “orphaned” part of the tariff and could be removed.

“The plain English is actually quite clear that there needs to be a report filed,” Sotkiewicz said. “We need to shine some light on this.”

The motion to table failed in a sector-weighted vote of 3.329 (66.5%), narrowly missing the necessary 3.335 threshold for endorsement.

Stu Bresler, PJM’s senior vice president of market services, said he appreciated the stakeholder discussion on the issue, adding the RTO will now examine next steps.

“I hear a very common desire for transparency in this area, so we will work towards that and figure out how to move ahead,” Bresler said.

Solar-battery Hybrid Resources Endorsed

Stakeholders unanimously endorsed the proposed solution and corresponding tariff and Operating Agreement revisions to address market participation by solar-battery hybrid resources.

The proposal, which updates PJM’s governing documents and manuals, was originally endorsed at the August Market Implementation Committee meeting with 99% stakeholder support before coming to the MRC. (See “Solar-Battery Hybrid Proposal Endorsed,” PJM MIC Briefs: Aug. 11, 2021.)

Andrew Levitt, of PJM’s market design and economics department, reviewed the RTO’s solar-battery hybrid resources issue. Levitt said PJM conducted a prefiling meeting with FERC staff in September, and the commission made suggestions to reconfigure the language to increase its chances for approval. (See “Solar-battery Hybrid Resources,” PJM MRC/MC Briefs: Nov. 17, 2021.)

One suggestion called for the term “hybrid resource” in the tariff to be structured as a largely independent resource-neutral category and not specifically about solar-battery resources.

Levitt said the proposal was intended to clarify energy and ancillary services market participation rules, including metering and telemetry and basic operational requirements, with the tens of gigawatts of solar-battery mixed technology facilities currently in the PJM queue.

PJM was hoping to present the exact tariff language presented at the November MRC meeting for a vote, Levitt said, but staff found some “minor clerical errors.”

Levitt said the RTO hopes to go live with the new energy market model for hybrid resources in mid-2023.

A final vote on the proposal will take place at the January MC meeting.

Consent Agenda

As part of the consent agenda, the committee endorsed several revisions to:

Manual 6: Financial Transmission Rights, conforming to the joint PJM-stakeholder proposal addressing auction revenue rights (ARR) and financial transmission rights (FTR) endorsed at the October MRC. The changes were initiated after the GreenHat Energy default in 2018, including a six-month review by an independent consultant and work done at the ARR/FTR Market Task Force. (See Stakeholders Endorse PJM ARR/FTR Market Changes.) Seven stakeholders abstained from the vote on the Manual 6 revisions.
Manual 10: Pre-Scheduling Operations resulting from a periodic review. The revisions were endorsed at the November Operating Committee meeting. (See “Manual Changes Endorsed,” PJM Operating Committee Briefs: Nov. 4, 2021.)
Manual 14B revisions resulting from a biennial review. The revisions include the addition of a new section that features details about the incorporation of end-of-life needs in the Regional Transmission Expansion Plan, which were part of the tariff attachment M-3 discussions. (See “Manual Endorsements,” PJM PC/TEAC Briefs: Nov. 2, 2021.)
Manual 14D: Generator Operational Requirements resulting from a periodic review. The updates featured the addition of several new sections, including one describing eDART modeling requirements. (See “Manual Changes Endorsed,” PJM Operating Committee Briefs: Nov. 4, 2021.)

Members Committee

Sector Selection Challenge Process

Stakeholders questioned a proposal at Wednesday’s Members Committee meeting seeking to change the way members can be challenged on their chosen sectors in PJM.

Sharon Midgley, Exelon’s director of wholesale market development, presented proposed revisions to the sector challenge process in the OA during a first read.

The issue of sector challenges has been a source of discussion at the Stakeholder Process Forum for the last 18 months. In 2020, Exelon and FirstEnergy requested that PJM more actively police stakeholder selections after the disclosure that an LS Power affiliate was improperly voting in the RTO’s senior committees. (See Exelon, FE Ask PJM to Tighten Sector Selection Process.)

Under current rules, Midgley said, “questionable” sector selections of an existing member may only be challenged one time per year, coming within 30 days of the Annual Meeting. Challenges to a new member’s sector selection must be made within 30 days of the new member joining PJM.

In the last three years, Midgley said, PJM has required changes to the sector selections of 14 members, determining that a sector modification was warranted for 88% of challenges.

The proposed solution calls for revising Section 8.1.3 of the OA, saying any member may request that PJM review the qualification of another member to participate in a sector “if the basis for such challenged member’s qualifications have not been subject to a sector challenge review in the prior 24 months, unless there is a material change in the challenged member’s business interests with PJM.”

The revised language also calls for removing the 30-day requirement from the Annual Meeting. Midgley said the requirement can be “challenging” for stakeholders to do “proper investigative work” on a sector challenge.

“We’ve got over 1,000 members, and sometimes just a simple email with their name doesn’t really tell you much about the business that they’re in or the interest they have in PJM,” Midgley said.

Bruce said the ICC has “concerns” about the proposal, and that members make “personal” decisions about how they want to engage with PJM in the stakeholder process. He said PJM has done a lot of work in recent years on the “know-your-customer” efforts and has taken a “harder look” at sector selections for members.

Bruce said she worries that stakeholders’ ability to use the challenge process at any time of the year could become a “way of affecting voting outcomes.”

“I worry about the integrity of our voting and our stakeholder engagement if there’s a threat that someone may be sector challenged before an important vote,” Bruce said.

Steve Lieberman, assistant vice president of transmission and PJM affairs for American Municipal Power, said the OA changes read “like we have a solution in search of a problem.” Lieberman would rather see changes focused on the appeals process to a sector challenge.

The committee will vote on the proposed changes at the January MC meeting.

Sector Elections

Stakeholders unanimously endorsed the slate of sector representatives for the 2021/22 Finance Committee and the 2022 sector whips.

The new Finance Committee members include: Susan Bruce, PJM Industrial Customer Coalition (End-use Customer); Jeff Whitehead, Eastern Generation (Generation Owner); Bruce Bleiweis, DC Energy (Other Supplier) and; Alex Stern, PSEG Services (Transmission Owner).

The 2022 sector whips include: Adrien Ford, Old Dominion Electric Cooperative (Electric Distributor); Greg Poulos, Consumer Advocates of the PJM States (End-use Customer); Michael Borgatti, Gabel Associates (Generation Owner); Brian Kauffman, Enel N.A. (Other Supplier); and Sharon Midgley, Exelon (Transmission Owner).

December 21, 2021June 14, 2023

EPA Rules Will Slash Vehicle Emissions, Rev up EV Market by 2026

U.S. Environmental Protection Agency Administrator Michael Regan on Monday rolled out stringent new vehicle emissions standards, stating confidently that getting the U.S. light-duty fleet to an average of 40 miles per gallon by 2026 would be achievable even without the electric vehicle tax incentives in the now-imperiled Build Back Better bill.

“When we look at the technical analysis we’ve done, the conversations with the automakers, what we’re proposing today we believe is historic and we believe is capable” of being achieved, Regan said in response to reporters’ questions at a signing ceremony for the new rules. “That’s not to say that we’re not going to continue to fight tirelessly for those incentives that are in the Build Back Better proposal. But nevertheless, we believe that we proposed a rule that is doable. It’s affordable. It’s achievable.”

Prospects for passing the $2 trillion budget reconciliation package screeched to a halt on Sunday when Sen. Joe Manchin (D-W. Va.), the critical swing vote in the evenly divided Senate, said he could not support the bill in its current form. (See Manchin Says ‘No’ on Build Back Better.)

The new rules replace the Safer Affordable Fuel Efficient (SAFE) rules put in place by the Trump administration in 2020. Under those rules, automakers would only have had to reduce tailpipe greenhouse gas emissions 1.5% a year and achieve a fleet-wide fuel efficiency of 32 mpg by 2026, according to an EPA fact sheet. The new rules call for emissions cuts of 10% over the SAFE standard in 2023, and then cuts of 5%, 7% and 10% in 2024, 2025 and 2026, respectively.

Transportation electrification will be essential for reaching those goals, with the EPA projecting that hybrids will account for 12% of U.S. light-duty vehicles by 2026, and EVs, 17%, according to the fact sheet.

“In model year 2026, these standards will be the most ambitious standards in United States’ history,” Regan said. “We estimate that through the year 2050, this program will save American drivers up to $420 billion on fuel costs, gas that you won’t have to put in the tank, and avoid more than 3 billion tons of greenhouse gas pollution.”

Gas savings would also offset the higher cost of electric or more efficient vehicles by about $1,080 over the lifetime of a 2026 model year vehicle, the EPA estimated.

But other speakers at the signing ceremony focused primarily on the impact the new rules would have on public health, especially for children at risk for asthma or other respiratory disease caused by air pollution from cars.

Nsedu Obot Witherspoon, executive director of the Children’s Environmental Health Network, spoke of her own experience, riding in an ambulance with her youngest child, who suffers from asthma. “When you see your child struggling to breathe, take their next breath, we all become helpless, unable to provide them the security that they deserve,” Witherspoon said.

“Asthma is still the No. 1 chronic illness among children,” she said. “If you cannot be healthy enough to be in school to learn, that creates another ripple effect related to a child’s educational journey, their ability to focus and remain engaged. Childhood asthma is also a key environmental justice issue and has been as African-American and Latinx children witnessed higher incidence rates of asthma.”

EV Stocks Tumble

The final rule Regan signed today is even more stringent than the proposed rule the EPA released in August, which called for a 2026 target for fleet efficiency of 38 mpg. But new standards also provide flexibility for automakers “to help them meet standards in ways that are most appropriate and cost effective for individual companies,” according to the fact sheet.

CO2 compliance targets (EPA) Content.jpg

EPA final fleetwide CO2 compliance targets, compared to the rules proposed in August and 2020 and 2021 rules. | EPA

For example, companies can carry over credits they may have accrued for “overcompliance” in 2017 and 2018 and apply them to meeting the 2023 and 2024 standards. Automakers can also receive extra “vehicle multiplier credits” for accelerating their rollout of zero- and near-zero emission vehicles, which could benefit the U.S. automakers, such as GM, that have already committed to a full transition to EVs.

At the same time, the rule sees a major role for vehicles with advanced, high-efficiency engine technology, predicting they will comprise more than half of the 2026 light-duty fleet.

But hitting the rules’ ambitious goals will require “a substantial increase in electric vehicle sales, well above the four percent of all light-duty sales today,” according to a statement from John Bozzella, CEO of the Alliance for Automotive Innovation, an industry group representing most U.S. automakers. “Achieving the goals of this final rule will undoubtedly require enactment of supportive governmental policies, including consumer incentives, substantial infrastructure growth, fleet requirements, and support for U.S. manufacturing and supply chain development.”

Significantly, EV stocks took a 7% tumble on Monday, according to CNBC, as the market reacted to Manchin’s abandonment of the bill.

Industry analysts ClearView Energy Partners are predicting that to get Manchin’s vote, a slimmed down Build Back Better might have to sacrifice some clean energy incentives. Manchin has previously spoken against one of the bill’s provisions: an additional $4,500 tax credit for union-built EVs.

Pedal to the Metal

Reactions from Democratic lawmakers and a key union leader supported the stricter standards. In an online statement, Sen. Edward Markey (D-Mass.) said he had urged the EPA to go beyond the August proposal and called for the agency to “put the pedal to the metal” to go even further in the next cycle of vehicle emissions standards.

Rep. Frank Pallone (D-N.J.), chair of the House Energy and Commerce Committee, similarly praised the stricter rules, but his email statement carefully skirted the status of Build Back Better.

“Paired with the investments in the bipartisan infrastructure law, this action will accelerate the process of transforming our transportation sector to the benefit of public health and the environment,” he said.

Ray Curry, president of the United Automobile, Aerospace and Agricultural Implement Workers (UAW), called the new rules a “win-win” for union members and other workers. “Well thought-out regulations, such as the Biden Administration’s emission rules today, will promote long-term U.S. investments while they protect and expand good-paying union jobs in vehicle production and advanced technologies that will allow manufacturers the flexibility necessary to meet these standards,” he said.

December 21, 2021November 24, 2023

NH EE Plan Approaches 2nd Year without Funding Certainty

New Hampshire is about to enter the second year of its 2021-23 Triennial Energy Efficiency Plan without a firm budget in place, and EE industry members are concerned about the consequences for their businesses.

In a Nov. 12 order, the PUC threw out a proposed triennial plan and a settlement agreement that would have more than doubled spending, saying it placed “an enormous burden on New Hampshire ratepayers.” The PUC instead directed the state’s utilities, which developed the plan and administer the efficiency programs, to submit a new EE budget with spending “similar to the 2018-20 plan.” It also ordered system benefit charges funding the programs to decline by almost half by 2023 (DE 20-092).

The proposed triennial plan is the second installment under the state’s Energy Efficiency Resource Standard established in 2016.

Response to Order

New Hampshire stakeholders’ responses to the PUC order came in rapid succession in December.

On Dec. 7, the nonprofit Clean Energy NH (CENH) led a group of EE industry members in filing an emergency motion in New Hampshire Superior Court for a temporary injunction staying the order, calling the PUC’s ruling “arbitrary and capricious.”

The effect of the PUC’s order “defunding” the 2021-23 budget will “deprive all Granite Staters of the decreased electric and gas rates and decreased emissions of airborne pollutants that come from using energy efficiently,” the petitioners said.

CENH filed a companion complaint to its Dec. 7 emergency motion asking the Superior Court for immediate emergency relief to prevent layoffs in the efficiency sector and harms that “will imminently worsen prior to the holidays.”

State utilities have already suspended energy efficiency work orders, said a Dec. 6 affidavit of William Newell, owner of weatherization firm Newell and Crathern. If the PUC’s order stands, he said, the company will have to lay off most of its employees by the end of the year. Other businesses that work with the state utilities to provide program services said in affidavits that they have contracts for the New Year that are under threat if the PUC does not stay its order. A court date for the complaint is set for Dec. 27.

Eversource Energy (NYSE:ES), other state utilities and advocates and the New Hampshire Department of Energy (DOE) filed motions Dec. 10 for rehearing or clarification.

In orders on Dec. 6 and Dec. 13, the PUC provided some clarity on petitioners’ immediate questions about the order and stayed a Dec. 15 filing deadline, but it has yet to rule on the request for rehearing. The PUC has until Jan. 10 to respond to the rehearing requests.

New Budget

Under the settlement filed in December 2020, the utilities’ total 2021-23 budget request was $378.4 million, a $202.4 million increase over the 2018-20 budget of $176.2 million.

Proponents of the plan said the increase was justified because it would reduce energy costs and provide customer net savings.

Adopting the plan “will result in a net reduction of system costs for delivering energy services of more than $600 million,” said David Hill, managing consultant at Energy Futures Group, in October 2020 testimony on behalf of CENH. The bill savings for customers, he said, would be $1.3 billion over the three-year plan.

In the original plan, a bill impact analysis showed that the proposed three-year budget would reduce the utilities’ long-term revenue requirements by $470 million.

The PUC, however, said the budget goes against the commission’s preference for market-based mechanisms and proposed “ratepayer-funded energy efficiency that is entirely utility sponsored.” In addition, the commission determined that the utilities did not prove that the new budget is just, reasonable and in the public interest.

The commission ordered the EE programs funded for 2021-23 “at a level consistent with the previous triennial plan.”

The commission noted the energy efficiency portion of the system benefits charge (SBC) rose from 0.198 cents/kWh in 2017 to 0.528 cents/kWh in 2020, a 167% increase. The proposed settlement would have increased the charge to 1.259 cents/kWh for commercial and industrial customers and .863 cents/kWh for residential customers by 2023.

Instead, the commission limited the EE portion of the SBC rate for all rate classes to 0.528 cents/kWh in 2021, the same as 2020, declining to 0.373 cents/kWh in 2022 and 0.275 cents/kWh in 2023.

“While the overall level of the 2021–23 plan will be similar to the 2018–20 plan, consistent with the commission’s longstanding preference for gradualism in ratemaking, the rates set by the commission … will descend gradually year-on-year until they return to a reasonable level, and transition toward market-based programs,” the commission said.

It directed the utilities to identify EE programs “that provide the greatest benefit per unit cost with the lowest overhead and administrative costs within the approved budget and file a program proposal” for the commission’s review.

In compliance with the order, the utilities on Dec. 15 and Dec. 16 filed a new budget for the three years of $183.9 million. The new budget starts at $81.9 million for 2021 and declines to $44.9 million by 2023. But they said they “maintain all arguments and positions made in the joint motion for rehearing, clarification and stay” of the order.

State of the PUC

The PUC responded to the settlement proposal at the end of December 2020 with an order that maintained the existing budget until the commission reached a final decision. That final decision was expected by February 2021 but didn’t come until Nov. 12, nearly a year overdue for the January 2021 effective date of the 2021-23 plan.

Now, stakeholders are concerned that the commission’s final order on the plan only further delays implementation, hindering the utilities’ ability to continue funding programs and projects already in process.

CENH said that emergency relief is necessary because the PUC is “incapacitated,” and motions filed in the docket, therefore, might not reach a resolution until 2023.

Of primary concern to the petitioners is the commission’s ongoing flux since it became part of the newly formed Department of Energy in July. Newly appointed commissioners, CENH said, do not have the “institutional knowledge” necessary to rehear the case or have a conflict of interest.

The commission’s order was signed by then-Chair Dianne Martin, who resigned on the day of the order to take a job in the state court system and Commissioner Daniel C. Goldner, now the chair, whose term expires in 2025.

Carlton Simpson, a former attorney for utility Unitil was confirmed by the New Hampshire Executive Council on Nov. 10 to complete Martin’s term. Commissioner Pradip Chattopadhyay was appointed in December to a full six-year term expiring in 2027.

The state’s consumer advocate told the PUC in September that Chattopadhyay should not participate in triennial plan proceedings due to his prior work in the advocate’s office at the docket’s start in 2020. Chattopadhyay, who received approval for his seat earlier this month, filed a memorandum in the docket on Tuesday saying he would not recuse himself from the case. He worked as a senior advisor for the commission from August to December.

His work at the advocate’s office, he said, did not include access to information related to the plan that would be inappropriate to know as a commissioner. The Consumer Advocate, however, filed a motion on Friday seeking Chattopadhyay’s disqualification from participation in the docket, saying his position was high ranking in the advocate’s office and as such, he would have been privy to docket details in both formal meetings and informal conversations.

Governor’s Input

In a Dec. 14 letter to DOE Commissioner Jared Chicoine, Gov. Chris Sununu applauded the DOE for seeking a rehearing, but he also agreed with the PUC’s assessment of the settlement agreement.

“Had the proposed settlement agreement in this docket been approved, New Hampshire’s ratepayers would have seen significant increases to the system benefits charge — increases as high as 168% for some commercial and industrial customers over the 2020 rates,” he wrote.

The order, he said, also presented operational complications for the state’s energy efficiency programs, saying there are “legitimate questions” about the effect of the order for state programs in the “very near future.”

Sununu urged the PUC to address stakeholders’ concerns about the order.

December 20, 2021November 13, 2023

CAISO Reevaluating WEIM Resource Sufficiency Test

The Western Energy Imbalance Market Governing Body met twice last week, once by itself and once in a joint session with the CAISO Board of Governors, receiving briefings in both meetings on potential changes to the interstate market’s resource sufficiency test, which is being re-examined in a stakeholder initiative.

The test is meant to ensure that each WEIM participant enters a trading hour with enough capacity and ramping capability to supply its own needs and to prevent participants from “leaning” on the market to meet internal demand.

Participants raised objections to the test, including the recent addition of components that account for the unpredictability of weather-dependent resources such as solar and wind generation, transmission outages and other variables. Some contended the “uncertainty” components skewed results and led to periodic test failures, including by CAISO during intervals last summer.

A revised final draft proposal in the resource sufficiency evaluation (RSE) enhancements stakeholder initiative was released Thursday, when the board and governing body met in joint session. CAISO Vice President of Market Policy and Performance Anna McKenna provided a briefing on the proposed changes, as she had done in the governing body’s regular meeting Wednesday.

Stakeholders had four areas of concern over test accuracy, McKenna said.

“The first category is with regards to the measurement of uncertainty used in the capacity test,” she said. “After hearing more concerns about the current measurements that we use to capture uncertainty and the adders that we’ve put into the test, we are now considering suspending … uncertainty in the tests.”

Participants also raised concerns around demand response resources, capacity counting rules and consideration of load conformance.

CAISO planners had proposed increasing penalties for including demand response resources in the sufficiency test that do not materialize, but they now recommend shelving that plan because the penalties could have a “detrimental impact on how (participants) use demand response,” McKenna said.

A third category of stakeholder concerns involved CAISO’s proposed rules for counting resources toward the sufficiency test. CAISO still intends to enhance the counting criteria “so that the resources that are used to count to meet the test … can better reflect their actual reliability,” McKenna said.

The fourth category of concerns involves “how conformance of load forecast, which is done by our operators, can trigger EIM transfers to meet the [resource sufficiency] test,” McKenna said. CAISO continues to believe that understanding and adjusting for the impact of load forecast is important, but additional analyses showed complexities that deserve further testing and evaluation, she said.

“So, we’re proposing to take that additional time with regard to this one item,” McKenna said.

CAISO already had extended its timeline for the RSE initiative to take stakeholder comments into consideration and now plans to submit a final proposal to the board and governing body in a joint meeting Feb. 9.

Thursday’s joint meeting was the first to be held under new governance rules adopted by the CAISO and WEIM in August. The vote on the sufficiency test will among the first joint decisions under the new rules. (See CAISO Agrees to Share More Power with EIM.)

A meeting on the latest draft RSE draft proposal is scheduled for Dec. 21, with stakeholder comments due Jan. 10.

The WEIM now has 15 participants with seven more scheduled to join in the next two years, eventually accounting for more than 80% of load in the Western interconnection. Participants have amassed more than $1.7 billion in benefits since the market started in 2014 by buying and selling excess power across state lines.

CAISO is undertaking a major effort this to year to expand the real-time market to a day-ahead market (EDAM), further increasing cooperation among the West’s 37 balancing authorities.

December 20, 2021June 14, 2023

Jones Working to Restore Confidence in ERCOT

Brad Jones 2021-12-17 (RTO Insider LLC) FI.jpg

DALLAS — Brad Jones, ERCOT’s interim CEO, opened his conversation Friday with the Dallas Friday Club as he always does on what he calls his Listening Tour: stepping away from the podium and eschewing the use of a mic. The better to wander the stage and connect with his audience.

“This will take about two and a half hours,” Jones said, drawing a few laughs.

His story began on Feb. 15 during a winter storm, “one you’ve never seen and one your grandparents never saw.” Jones, retired from the electric industry at the time, says he was on his couch and watching television coverage of the winter storm disaster that left millions without power and caused human and financial suffering.

“Things have changed for me, haven’t they?” Jones said in a quick aside.

“Were you in Texas?” asked a voice from the back of the room.

“Yes.”

“Did you have power?”

“Electricity, but no water.”

It’s that mixture of charm, humor and candor that serves Jones well as he explains to Texans what happened to the grid during the storm and why it won’t happen again. Several members of the public affairs organization exchanged smirks as Jones began his comments. An hour later, most everyone in the room was listening in rapt attention.

Jones admitted to ERCOT’s poor communication during the storm, when “each piece of the market was telling different stories.” He said the subfreezing temperatures shut down almost 50 GW of the grid operator’s capacity — more than the 48-GW demand peaks CAISO sees on its hottest days, he said — and left the grid within about 10 minutes or so of a black start situation when generators automatically shut down.

“Things would have been much more difficult to manage,” Jones said.

He explained the lack of interconnections with neighboring RTOs wouldn’t have helped much, as they were experiencing the same emergency conditions. That led into an explanation of why ERCOT, “an island to itself,” is exempt from FERC jurisdiction.

When Jones began taking questions from the audience, he was asked how Texas can again say it has the best grid in the nation. He said his flippant answer is that New York has had three blackouts and California two while the Lone Star State has not had one.

“The real answer is simple,” he said. “We have to show the country we’ve changed the way we operate.”

Jones mentioned the RACE acronym he uses to denote “reliable, affordable, clean electricity.” Until the February storm, he said, RACE had been turned into CARE.

“For 20 years, we let the market dictate what we need for reliability,” Jones said. “We need to move reliability back to the front. That will be how we change.”

Jones handled every following question with similar ease. When the luncheon concluded, he took time to visit with the diners that stayed behind before doing on-camera interviews with the local media.

Asked if he is the perfect spokesman for this role as the communicator in chief, Jones laughed loudly.

“It’s an extremely important role,” he said. “The reason I came back to ERCOT after the winter storm was so ERCOT can begin to restore confidence among Texans in what it does.”

Jones served as ERCOT’s COO before leaving to take the top job at NYISO. He has watched the industry from afar since abruptly leaving New York for personal reasons in 2018. (See Brad Jones out at NYISO.)

The Brad Jones Listening Tour continues. Dallas was the 13th stop, with four more on the schedule. That is expected to change, however. Jones has yet to come across a city council or town hall that he won’t attend.

Contrast that with Texas Gov. Greg Abbott, who has guaranteed the grid will not fail this winter. While Jones has been crisscrossing the state, Abbott held a closed-door meeting Thursday with “Texas energy providers” to discuss the grid’s reliability and “preparedness ahead of the winter season.”

The governor’s office said in a statement that Abbott and “energy leaders” discussed actions already taken and improvements made by both the providers and the state, including updated winter preparedness plans, meetings with plant managers and “winterization of all components of the power grid.”

The office also said several providers “discussed their efforts to ensure that natural gas supply is available this winter to fuel power plants, including on-site storage of natural gas and designation of natural gas facilities as critical to ensure they maintain power during energy emergencies.”

NRG Energy (NYSE:NRG), Vistra (NYSE:VST), Calpine and several pipeline companies were among those involved in the meeting.

434 MW Back for Late Winter

ERCOT will have an additional 434 MW of gas-fired capacity to play with before this winter is over, thanks to a pair of decisions related to retired power plants.

Vistra told the grid operator on Friday it is bringing its 69-MW Wharton County Generation facility out of retirement and making it operational as of Feb. 4. The plant, located southwest of Houston, was decommissioned and retired last December after a forced outage. (See “Luminant, 1 Other File NSOs with ERCOT,” Vistra to Shut down Another Texas Coal Plant.)

ERCOT and CenterPoint Energy, the interconnecting transmission service provider, may delay the proposed return date if any studies, testing, metering or facility upgrades are necessary.

NRG notified ERCOT on Dec. 14 that Gregory Power Partners — a three-unit, 365-MW facility near Corpus Christi currently under seasonal mothball status — will change the start date of the operating period from May 1 to Jan. 1.

The plant was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. NRG returned it to seasonal operations in 2019. (See ERCOT Approves Seasonal Plan for NRG Cogen Units.)

The announcements will help make up for the loss of almost 500 MW of capacity following recent suspension-of-operations notifications filed by the cities of Austin and Garland for aging gas-fired generators. ERCOT approved the notices earlier this month. (See “500 MW to Depart Market,” ERCOT Briefs: Week of Nov. 1, 2021.)

The 405-MW Austin unit will be available through the winter before being retired.