A developer has scrapped its plans to build a 1,240-MW gas-fired generator in central Pennsylvania after environmental groups challenged the plant’s permits.
“Renovo Energy Center [REC] LLC will discontinue development of the proposed combined-cycle plant in Renovo, Pa.,” the developer said in a statement. “After more than 8 years, we do not see a path to a reasonable conclusion of the project’s air permit appeal, and have made the difficult decision to discontinue development.”
REC submitted its air quality application in December 2019, detailing plans for a combined cycle generator fueled by natural gas or ultra-low sulfur diesel. The Clean Air Council, Citizens for Pennsylvania’s Future and Center for Biological Diversity filed a series of appeals to the state Environmental Hearing Board, arguing that the Pennsylvania Department of Environmental Protection (DEP) had awarded several permits that would allow emissions higher than standards in state law.
The hearing board granted the environmental groups two appeals in August 2022, resulting in a partial summary judgment finding that the sulfur dioxide and volatile organic compound limits were too high in the DEP permits. The company dropped its development plans a week after a third appeal was set to move to hearings, following a filing stating that the parties could not reach a settlement.
“Our lawsuit was about protecting Pennsylvania and this environmental justice community from the additional pollution burdens that this plant would have imposed,” Jessica O’Neill, senior attorney at PennFuture, said in a statement following the project cancellation.
“It is a win for Renovo and for all Pennsylvanians when we realize that the fracked gas industry doesn’t make sense — from an economic, energy or environmental health perspective,” she said. “We will continue to push back against facilities and industries that threaten the health of our communities, our workers and the sustainable energy future that Pennsylvanians want and that our children deserve.”
The appeal argued that the DEP approval contained incorrect emissions limits for volatile organic compounds, carbon monoxide and particulate matter; uses outdated global warming potential factors to calculate emissions; misapplied the cost-benefit analysis required by the state; and stated that emission reduction credits sources from outside the state would be accepted without demonstrating that the credits would meet state requirements.
Clean Air Council Legal Director Alex Bomstein said the DEP has a track record of allowing air permits that exceed limits by relying on a developer’s projected emissions for a generator without conducting adequate analysis to verify the figures. The environmental groups hired an expert for their appeals who found that the plant’s emissions would have caused billions of dollars in public health costs for surrounding neighborhoods, which have been designated an environmental justice community.
The group has also been involved in appealing air permits awarded to Invenergy’s proposed gas-fired Allegheny Energy Center in Pennsylvania, with hearings expected in July.
“The way that society is moving, we’re not going to have many more of the large fossil fuel plants. … The market is favoring renewable energy,” Bomstein said, adding that his group is focusing on trying to combat legislation that would impede development of clean energy.
Local environmental groups cited the impact on residents’ health as the basis for their opposition.
“As a great-grandparent, I’m grateful that this power plant didn’t come to fruition because we are now able to protect what is most important — the health of our children,” Sue Cannon, co-founder of Renovo Residents for a Healthy Environment, said in the statement. “I opposed the power plant because I was thinking about the children in this community, especially my great-grandchild, and what the pollution would do to their health.”
The California Air Resources Board plans to vote Thursday on a regulation requiring new passenger and short-distance switch locomotives to be zero-emission starting in 2030 and new freight locomotives to be zero-emission starting in 2035.
The proposal is meant to reduce emissions. Diesel-powered locomotives emit greenhouse gases, oxides of nitrogen (NOx) and fine particulate matter, with train tracks running through many densely populated areas of the state.
“Exposure to toxic and harmful diesel emissions is known to lead to cancer and increases in asthma, cardiopulmonary illness, hospitalizations and premature mortality,” CARB says on its website. “Communities near rail operations bear a disproportionate health burden due to their proximity to harmful emissions.”
Trains have generally been regarded as a cleaner form of transportation than big rigs, producing fewer emissions per ton of cargo carried. But a CARB analysis shows that as trucks decarbonize, trains will become the bigger polluters.
California’s current emissions limits will make trucks the cleaner mode of freight transportation starting as soon as this year, CARB says. Regulations to be implemented beginning in 2024 will gradually increase the differences between truck and train emissions until trucks are 100% zero-emitting and trains are not, CARB says.
“Results show that as California’s current truck regulations are implemented through 2023, trucks are producing less particulate matter (PM2.5) and [NOx] emissions,” the board’s website says. “By 2023, trucks will be the cleaner mode to transport freight. Beyond 2023, future CARB regulations will further reduce truck emissions, eventually bringing them to zero.”
The state’s Advanced Clean Trucks regulation, adopted by CARB in June 2020, will require truck manufacturers to sell an increasing percentage of zero-emission medium- and heavy-duty trucks in the state from 2024 through 2035.
The U.S. Environmental Protection Agency approved a Clean Air Act waiver for the rules on March 31, clearing the way for the state to launch the zero-emission program starting with model year 2024. (See Groundbreaking California Clean Truck Rules Win EPA Waiver.)
CARB adopted its Advanced Clean Cars II regulation in August, requiring all new cars sold in the state to be zero-emission or plug-in hybrid by 2035. (The EPA restored California’s long-held waiver for passenger vehicles in March 2022, after the Trump Administration revoked it in 2019.) So far, 17 states have adopted California’s clean car rules.
In-use Locomotive Regulation
CARB is tackling locomotive emissions by proposing similar rules. Its “in-use locomotive” regulation would phase out diesel trains and replace them with zero-emitting locomotives over time.
The regulation would require locomotive operators to begin funding their own trust accounts based on emissions starting in 2024.
“The dirtier the locomotive, the more funds must be set aside,” CARB’s website says.
The funds could be used to buy or rent the cleanest “tier” of diesel locomotives through 2030. They could also be used to purchase or lease zero-emissions (ZE) locomotives, to fund ZE locomotive pilot and demonstration projects, and to pay for ZE locomotive infrastructure.
Sierra Northern Railway received a $4 million grant from the California Energy Commission for a hydrogen powered switching locomotive.
Under the proposed regulation, locomotives older than 23 years would be prohibited from operating in-state starting in 2030. “Switchers,” short-haul locomotives used to move train cars, and passenger locomotives with original build dates of 2030 and beyond would be required to “operate in a ZE configuration,” CARB says. More powerful “line-haul” locomotives would have to be zero-emitting if built after 2034.
Where the locomotives will come from remains in question. Only a handful of hydrogen fuel-cell and battery-powered trains are in experimental or development phases in the U.S. and Canada.
Canadian Pacific Railway made test runs of North America’s first hydrogen-powered locomotive last year and is seeking to have two more on the tracks by the end of 2023. (The railroad’s name changed to CPKC on April 14, when it merged with Kansas City Southern.)
The railroad intends to produce its own hydrogen at two railyards in Calgary and Edmonton, including using solar panels to power an electrolysis plant in Calgary that makes hydrogen from water.
In March 2021, the California Energy Commission awarded Sierra Northern Railway $4 million to develop a hydrogen fuel-cell switcher locomotive for use in West Sacramento, California, where it now operates an older high-polluting diesel engine. That project remains in development.
WESTMINSTER, Colo. — SPP Markets+ stakeholders last week kicked off the development phase of the grid operator’s proposed “RTO-light” service offering in the West, heating up the race with CAISO to create a regional market.
Meeting for the first time, the Markets+ Participants Executive Committee (MPEC), comprised of potential participants and stakeholders that have financially committed to drafting the market protocols, tariff and governing documents, agreed to accelerate the timeline to file the tariff at FERC.
MPEC now plans to make the filing by December or early next year. CAISO plans to file a tariff for its competing Extended Day-ahead Market (EDAM) before the year is up.
The Energy Authority’s Laura Trolese, the MPEC’s newly elected chair, said speed is of the essence because some Western entities need to decide between the two markets within a year.
“They need an alternative to evaluate against in order to be able to make that decision,” she told RTO Insider. “While it may seem that we’re racing through this, we have been working on developing a market now for years, and we’ve had these same discussions. Yes, there are some new things, but we’ve had the same discussions and been working on putting a market together for four years together with some of the same faces in these previous efforts, some of the same faces that have been working through the EDAM process.
“We have a lot to draw from and to work from. It’s not starting from scratch and reinventing the wheel,” Trolese said.
The decision was just one of many stakeholders made during the two-day meeting. The MPEC also:
approved extending the participant funding agreement deadline to May 1, allowing as many as four interested parties to formally commit to Markets+’s development;
endorsed the first development phase’s scope of activities, tasks and deliverables;
agreed with SPP staff’s proposal to allow entities to begin participating in Markets+ once FERC approves the tariff next year, even though some day-ahead functions may be unavailable; and
approved stakeholder group charters, leadership and rosters.
The MPEC will oversee four working groups (design, seams, transmission, and operations and reliability) and five task forces that are expected to meet on a three-week cadence. Committee members amended their charters to allow the MPEC to reevaluate membership and voting once new funding agreements are executed.
The committee will meet in-person on a quarterly basis, with briefings to occur virtually as needed. The three-person Interim Markets+ Independent Panel (IMIP) provides final decision-making authority and a link to SPP’s Board of Directors. The panel, all SPP directors, plans to hold its meetings after the MPEC’s.
“The stakeholder process and the governance process that this group is engaged in is an ideal fit for the Western mindset,” said IMIP member John Cupparo, a Colorado native who professes a “don’t-fence-me-in” mindset. “It’s both challenging and rewarding. It will be some ups and downs along the way, but in the end, I think we’re getting a great product.”
“For those of you who haven’t seen it, it’s really an interesting process,” Eric Blank, chair of both the Colorado Public Utilities Commission and the Markets+ State Committee, told his committee Friday. “I really encourage you to watch, even independent of the substance. RTOS in the East that are staff-driven. This is really stakeholder-driven, and people just vote. It’s really unique.”
It’s that stakeholder-driven culture that SPP hopes will be the difference for Markets+.
“I’ve spent an awful lot of time in rooms like this talking about market evolution in the West … but I do believe that this is one that really is going to succeed,” said IMIP Chair Steve Wright, who previously has headed both the Bonneville Power Administration and Chelan (Washington) Public Utility District.
He pointed to the SPP-administered Western Resource Adequacy Program, the West’s first regional reliability planning and compliance program, as laying a “great foundation” in the West.
“Now we’re in a place where we actually had something that really works and we can build even more from that. This governance model, as applied to the West, can produce a market design for the West and by the West. SPP’s role here is not to make the decisions. Our role here is to facilitate and assist you in coming up with a market design that you want.”
The IMIP’s first voting item Wednesday was to approve the MPEC’s endorsement of a change to its voting structure that gives the independent sector a greater voice.
‘Frankensteining’ the Markets+ Tariff
The Markets+ Design Working Group will do much of the heavy lifting over the next few months, working with SPP staff to draft the tariff that will eventually be filed at FERC.
Staff said they have already “Frankensteined” together the best elements of markets previously approved by FERC into boilerplate language. Stakeholder groups will rework the basic tariff language to better fit Markets+’s unique design, with the MDWG reviewing their work.
“I can’t wait for the first ‘Mad Wag’!” SPP’s Chris Nolen said, sounding out the working group’s acronym.
“We started with a blank slate. We’re not bolting Markets+ onto an existing code … it has to fit comfortably and exist on its own. We drafted it that way,” Nolen, a senior attorney and tariff expert, said. “We borrowed pieces that worked well for many other tariffs. It gives us an easier process to justify those scans at FERC. To that end, when we draft this tariff, it should be, at least as I see it, the best tariff yet of the best ones.”
MPEC Leadership Promises Collaboration
Trolese’s first order of business after being elected chair of the MPEC? Adjourning a lengthy discussion for lunch, a move that was greeted with rousing cheers.
Both Trolese and Vice Chair Brian Cole, with Arizona Public Service, said they plan to ensure the committee collaborates on recommendations that benefit the region as a whole.
“My goal is to find ways for all of us to come together, to make decisions together,” Cole told MPEC members. “I don’t want this to sound like a campaign speech, but you’ll have that from me, without exception.”
Trolese said her role is to facilitate decision making and ensure everyone’s voice is heard and “that they’re given the opportunity to be able to express their concerns, but also to make sure that we’re sticking to the timeline that we committed to and we voted on and that we’re able to deliver what we set out to deliver, which is to get this tariff up and filed at FERC by Q1 of 2024.
“I think it will be a challenge to balance speed and inclusion, but I think it’s something that we’re going have to do in order to get this thing up and going,” Trolese said.
Director of Western markets and strategy for TEA, Trolese has spent the past 16 years in Washington with either Bonneville Power Administration or the Public Generating Pool. Much of that time has been spent on market development in the West. Efforts to create an RTO go back to 1995, she said.
“Our success in the West has been incremental,” Trolese said. “The Pacific Northwest has some of the lowest rates in the country, so the value proposition of lowering rates can be a challenging one, when they have some of the lowest-cost power, they have pretty clean power, and they have the lowest rates.”
MSC Gets Down to Business
The Markets+ State Committee wasted little time in getting started, holding a conference call Friday to discuss the MPEC’s actions and the MSC’s next steps.
Blank encouraged MPEC members to contact the group and its support staff with their ideas and recommendations for the development of Markets+.
“The goal of the MSC is to become informed as the process evolves, participate, get our questions asked and answered, get our concerns raised and addressed, and try and limit what happens on the back end,” Blank said.
The MSC is comprised of regulators from nine Western states. However, members amended the group’s charter Friday to allow participation from other Western states and Canadian provinces. The California Public Utilities Commission has asked to join the MSC and British Columbia regulators have also expressed interest.
The Western Interstate Energy Board (WIEB), comprised of 11 Western states and two western Canadian provinces, is serving as the MSC’s support staff. The WIEB has hired as its support AESL Consulting, which provides strategic regulatory and public policy support to public utilities, led by founder Ed Garvey and former MISO executive and Minnesota commissioner David Boyd.
“We have had nothing but offers of support to the extent we need it from SPP. They’ve been very cordial,” Boyd told the MSC. “I won’t put words in their mouth, but I think they recognize the value that regulators bring or have brought to their markets and therefore, the need to do a lot of work on the front end to expedite implementation on the back end. To the extent we need resources, I’m quite confident SPP will be supportive.”
SPP staff already has amended the stakeholder groups’ charters to allow MSC members to participate. They have advisory roles on the working groups and voting roles on the task forces. The WEIB has recommended assigning three commissioners to relevant groups; the board and its consultants will staff each stakeholder group.
The MSC plans to hold another call Friday to vote on the charter amendment and begin making stakeholder group appointments. It will begin its normal cadence of meetings in May.
FERC on Thursday partially accepted NYISO’s second compliance filing for Order 2222, directing the ISO to submit another within 30 days to correct several inconsistencies in its tariff revisions allowing distributed energy resource aggregations to fully participate in its markets (ER21-2460-003).
The commission found NYISO’s revisions listing what constitutes a small generating facility “appear to refer to the same type of interconnection” in two different places. The commission told NYISO to either remove one of the listings or explain why including both is not redundant.
FERC also found that NYISO had revised the definition of energy resource interconnection service (ERIS) in only one of the two relevant sections of its tariff, leaving the other unchanged.
Third, FERC said that NYISO’s revisions concerning market participation agreements, although partially settled, still included language from the first compliance filing that had already been found to be noncompliant. FERC said NYISO needed to remove “language requiring aggregators to attest that the aggregation has been authorized by the distribution utility and relevant electric retail regulatory authorities to participate in NYISO’s markets.”
Lastly, FERC directed NYISO to submit informational filings every six months detailing its stakeholder process in developing ancillary service market rules allowing DER aggregations to participate until Dec. 31, 2024, by which it needs to submit yet another compliance filing that includes the proposed rules. (See FERC Clarifies CAISO, NYISO Order 2222 Rulings.)
FERC partially approved NYISO’s first compliance filing in June 2022, with the ISO submitting its second later in November. In the next month, the commission granted NYISO an extension until 2026 to fully complete Order 2222 implementation, although the ISO said at the time that it might not need that long. (See FERC Gives NYISO Until 2026 to Complete Order 2222 Compliance.)
FERC on Thursday approved the compliance filings of six transmission providers, including those of NYISO and CAISO, with Order 881, though it found that most of them had failed to sufficiently explain their timelines for calculating and submitting their required ambient-adjusted line ratings (AARs).
Issued in December 2021, and upheld in May 2022, Order 881 directed transmission providers to end the use of static line ratings in evaluating near-term transmission service, and implement AARs for short-term service and seasonal ratings for long-term service (RM20-16). (See FERC Orders End to Static Tx Line Ratings.)
FERC did not specify a specific timeline by which transmission providers must submit their ratings, but it did order them to submit their own in their compliance filings. The commission had argued that providers “already manage similar timing issues” regarding other topics such as load forecasts, renewable energy production and generation bid deadlines, and that deadlines for AAR calculation and submission should be “not significantly different” from those they already calculate.
But though it approved their filings, the commission found that Arizona Public Service (ER22-1863), Black Hills Power (ER22-2303), Louisville Gas & Electric and Kentucky Utilities (ER22-2305), and Tampa Electric (ER22-1546) each failed to include such a timeline.
NYISO (ER22-2350) said that it expects to calculate AARs on a 48-hour basis, with submissions by transmission owners to be provided to the ISO hourly. But it also told FERC that it and TOs are “still developing technical procedures describing the mechanics of AAR submissions,” the commission said.
However, in each of these five cases, FERC acknowledged that “these timelines may not be determined until closer to AAR implementation and therefore that additional time may be necessary to comply with this requirement.” NYISO and the four utilities will need to submit another compliance filing by Nov. 12, 2024, ahead of their deadline for implementation of July 12, 2025.
In Tampa Electric’s case, the commission also took issue with the utility’s proposal to backdate its table of contents changes to June 1, 2022. FERC said this plan “could cause confusion because it would reference a section of [its tariff] that is not in effect.” To prevent potential misunderstandings, FERC set the table of contents revisions to take effect on the same day as the new tariff. However, the commission did suggest it was open to a future filing from the utility explaining why an earlier effective date would be justified.
“Our Order No. 881 compliance orders are bright points in today’s meeting,” Commissioner Allison Clements tweeted that afternoon. “They represent the beginning of a bigger opportunity to squeeze more juice out of our existing system at a relatively minimal cost to customers, using grid-enhancing technologies.”
NYISO
The commission had also ordered RTOs and ISOs to create systems and procedures to allow transmission owners to electronically update transmission line readings at least hourly and give TOs the ability to use more advanced dynamic line rating technology, which takes into account more factors than just air temperature when calculating ratings, if they choose.
FERC found that both NYISO and CAISO mostly complied with these directives. But both did not adequately explain certain definitions, the commission said.
Although NYISO provided for seasonal line ratings, it did not “define ‘seasons’ to include no fewer than four seasons in each year,” FERC said. The commission also nixed the ISO’s proposal that its TOs, rather than itself, were responsible for sharing transmission facility ratings and methodologies. NYISO has until June 19 to submit a compliance filing correcting these two deficiencies.
NYISO had also proposed revising its day-ahead market congestion settlement procedures to quantify the impacts of when the ratings employed in the market differed from those used in transmission congestion contract auctions. But FERC rejected this proposal as well, though without prejudice, noting that NYISO could file these revisions as a separate proposal.
“While the commission in Order No. 881 acknowledged a connection between the transmission line rating requirements and financial transmission rights markets, the commission declined to direct any changes to financial transmission rights markets, and therefore these revisions fall beyond the scope of this compliance proceeding,” FERC said.
CAISO
CAISO’s (ER22-2362) proposal only partially complied with Order 881’s requirement that transmission providers post line rating exceptions or temporary alternate ratings on its Open Access Same-Time Information System or another password-protected website, FERC said. And the ISO’s proposed definition of “transmission line ratings” fell short of the order’s requirements, it found.
The ISO had proposed defining “transmission line rating” as the “maximum transfer capability of a transmission line, computed in accordance with a written transmission line rating methodology and consistent with good utility practice, considering the technical limitations on conductors and relevant transmission equipment (such as thermal flow limits), as well as technical limitations of the transmission system (such as system voltage and stability limits).”
“CAISO asserts that the definition encompasses transmission line ratings for electric system equipment that includes more than just overhead conductors … [such as] circuit breakers, line traps and transformers,” FERC noted. But the commission said the definition needed to reflect the order’s wording.
“While CAISO states that its proposed definition encompasses electrical system equipment beyond just overhead conductors, we find that the absence of tariff specificity renders the proposed definition unclear on this point,” the commission said.
FERC said CAISO’s proposal also only partially complied with Order 881’s requirements for designating exceptions and alternate line ratings.
“CAISO proposes to coordinate with [participating transmission owners] in their development of exceptions or alternate ratings for both near-term and longer-term transmission service for the set of circumstances set forth in the pro forma” tariff, the commission noted. “However, CAISO does not propose tariff language stating that exceptions will be re-evaluated by the transmission provider at least every five years, nor does CAISO explain the absence of such language.”
FERC gave CAISO until June 19 to submit another compliance filing for these failings.
New Jersey’s Cape May County has appealed a state Board of Public Utilities decision to grant Ørsted an easement to run a transmission cable from the state’s first offshore wind project to an onshore substation.
The appeal, filed with the state Appellate Division April 5, argues that the BPU committed a “legal error” in concluding that developer Ørsted’s application for the easement for Ocean Wind 1 was not a “contested” case, negating the need for full hearing before an administrative law judge.
The decision “effectively turned the matter into a summary proceeding with none of the procedural and substantive due process protections required in the context of the taking of real property by government … supplanting of the authority of duly elected officials,” the county said in its appeal.
“There was no opportunity for any party to cross examine the witnesses supporting the petition and no opportunity for formal discovery,” the appeal said. “Consequently, the proceedings were fundamentally unfair [and] deprived the Appellant County of due process of law and resulted in a legally unsupportable and unjust result.”
Testing a New Law
The appeal is the second filed against the BPU involving an easement approved for Ocean Wind 1 and is the second to test a new state law approved in July 2021 specifically to assist the advance of offshore wind projects. The law (S3926) allows the BPU to override local government agencies and give permission for developers to site, construct and operate “wires, conduits, lines and associated infrastructure” on public land if they are shown to be “reasonably necessary” to the project. (See NJ Lawmakers Back Offshore Wind Bills.)
Ørsted is seeking to run a 275-kV underground line through the Jersey Shore community of Ocean City, which is in Cape May County, to connect with the PJM grid at a substation sited on a now closed coal-fired power plant in neighboring Upper Township.
To move ahead, the developer needed a temporary 18-month easement and a permanent 30-foot-wide easement to run the same cable across county land in Ocean City, which the BPU granted. (See NJ BPU Grants Second Easement for OSW Project.)
In response to an inquiry about the appeal by Net Zero Insider, an Ørsted spokesperson said the company “will not comment on pending litigation.”
In the earlier case, Ocean City appealed the BPU’s approval of an easement and various environmental approvals allowing the cable to run through the town, including across land improved by state Green Acres funds, which are awarded to develop parks and open space. (See NJ BPU Approves Easement Plan for 1st OSW Project.)
In both cases, the BPU’s approval opens the way for Ørsted to seek easement and permit approval from the New Jersey Department of Environmental Protection, which is needed for the project to get federal backing.
Erasing Home Rule
The BPU’s decisions in the two cases followed several public hearings on each case in which testimony was provided by representatives of Ørsted, Cape May County, the New Jersey Division of Rate Counsel, Ocean City and others, including some local governments that also opposed the easement. Nine South Jersey municipalities in or around the shore opposed the granting of the easement, and the wind projects met opposition from residents, commercial fishermen and tourism sectors that worry about the impact of having visible turbines off the Jersey Shore, a major economic driver for the state.
Opponents raised questions about what other cable routes Ørsted had considered and why it did not opt for any of them. Another issue raised was the estimated cost of pursuing each of the alternatives and whether the developer picked the route it did simply because that route was the cheapest to execute, regardless of the potential disruption to the community. Ørsted argued that the cost was irrelevant because it would pay the bill itself, and not the public.
The Cape May appeal says the “decision of the BPU that easements and consents sought under the petition are reasonably necessary for the construction and operation of the offshore wind project was arbitrary, capricious, and/or unreasonable and must be reversed.”
The decision “effectuated the erasure” of Home Rule — a prized concept in New Jersey that gives local governments authority over municipal affairs — and “disenfranchised the voters of the county,” the appeal said.
The county argued that, prior to seeking the BPU’s approval of the easement, the developer “sent letters to the County of Cape May with vague, ambiguous and conditional demands that left the County incapable of determining what consents or property interests Ocean Wind was demanding from the County.”
The appeal said that Ørsted conducted no appraisal of the value of the county property needed for the easement and failed to give the county all the required documentation required in the procedure, leaving it “without the ability to assess whether consent would be appropriate or not.”
Ørsted testified in the hearing that it had repeatedly held talks with the county and tried to strike an agreement over the permits, but the effort was fruitless because the county apparently did not want a deal.
A New Jersey plan to promote energy efficiency and provide measurable benefits to users encountered scrutiny over cost, impact and effectiveness at two Board of Public Utilities (BPU) hearings this month.
Speakers at the online hearings argued for the need for consumer education, a greater emphasis on heat pumps and larger incentives to persuade consumers to buy electric — rather than gas-fueled — appliances.
The straw proposal for the plan, known as the “second triennium” because it follows a similar plan crafted in 2020, would require the state’s utilities to administer core energy efficiency programs for residential, multi-family buildings and commercial industrial properties. The outline calls for establishing energy assessments and incentives for “whole home” electrification solutions for residential properties and incentives and energy management programs for commercial and industrial properties.
The most contentious issue was the plan’s proposal to change the current management responsibility for the agency’s “comfort program,” which provides energy efficiency upgrades to low-income households at no cost to homeowners. The straw proposal suggests the program should be almost entirely administered by utilities, with “continued oversight” by the BPU, instead of the current situation in which the BPU administers the program and the utilities simply provide the services.
Leila Banihani, vice president of operations at CMC Energy Services, a Pennsylvania clean energy efficiency contractor, said her company has seen the program up close for 15 years. She said utilities are a “trusted source” for the customer and are the best suited to provide advice on how to save energy and money.
“Having the utilities administer the comfort partners program will help create a seamless process for New Jersey customers. The utility and its representatives are in the best position to ensure that each customer maximizes the energy efficiency benefits that are available,” she said, and added that “having the utilities administer the comfort partners program would encourage efficiencies that could stretch the available funding to serve more customers in need.”
But Mamie Purnell, an attorney with the New Jersey Division of Rate Council, suggested that putting utilities in charge could have a negative impact on program costs that fall on ratepayers.
“With that move, the board will retain less control over the budget and the program,” Purnell said. “Additionally, it is unclear whether this move will allow greater coordination with other New Jersey agencies that coordinate health and safety measures that often must be performed prior to weatherization for participants under this program.”
Richard Henning, CEO of the New Jersey Utilities Association, argued that utilities would be able to provide quality service to low- and moderate-income customers.
“Utility management of comfort partners program will allow the utilities to streamline customer entry to the energy efficiency programs,” he said. Such a setup, he said, would “also assist customers in finding the best lowest cost opportunity that they’re eligible for, which will assist in removing barriers to the energy efficiency programs.”
Protecting Ratepayers
The triennium proposal is part of New Jersey’s effort to reach 100% clean energy by 2050. The proposal seeks to create the most effective way to deliver the kind of energy efficiency and peak demand programs that the BPU and other stakeholders consider to be essential for the state to reach its emissions reduction goals.
A third public hearing on the issue was postponed while the agency evaluates the issues raised in the initial hearings and opinions submitted online and prepares answers to the questions raised.
The proposal would require electric and gas utilities to create “demand response” programs that would allow them to manage customer energy usage during periods of high demand, and it also encourages utilities’ “advanced metering infrastructure to the extent possible.” To ensure that elements of the proposal are carried out as planned and are effective, the draft calls for the creation of an Evaluation, Verification and Measurement work group.
Purnell urged the BPU to put more specific measures in the program rules to hold down costs, noting that the cost of the program and an additional 9.6% paid to the utilities is footed by ratepayers.
“Rate counsel believes that the board should in fact mandate rate caps for the cost of the energy efficiency programs,” she said. “The language in the straw, calling for financial discipline for the utilities, is too ambiguous to ensure compliance. In the wake of our current economic state of inflation and rising consumer costs, we urge the board to set guardrails for the utilities that will balance ratepayer costs with the energy efficiency goals of the program.”
Educating Consumers
Other speakers focused on how to create greater impact with the program. Randy Solomon, executive director of Sustainable Jersey and the Sustainability Institute at the College of New Jersey, said he saw figures that show less than 10% of residents eligible to benefit from the program actually do so. One way to improve penetration would be to enlist the help of municipal governments in promoting residential and the “small commercial” programs, he said.
“If you get a letter from your mayor, or from your town, you’re going to open it” and not throw it in the trash as may happen with other types of mail, he said.
Pat Miller, co-founder of building electrification advocacy group NJ 50 x 30 BE Team, said the triennium plan should provide greater education to consumers on the “advantages of electric heat pumps for space heating and cooling” because awareness of the equipment is so low.
“Education and incentives are the biggest factors that these programs must provide in our opinion,” she said. “The funding must be sufficient, both to incentivize consumers to take efficiency and electrification steps and to fund the work necessary for the utilities to run the programs.”
New Jersey incentives for installing a heat pump, for example, are much smaller than those offered by Maine, Massachusetts and New York, she said, adding that “it must be made easier for consumers to choose an electric appliance.”
Jennifer M. McCave, an attorney for Google Nest, encouraged the BPU to include “demand response” programs in the straw proposal, and consider the role of smart thermostats in the initiative. The reason, she said, is that the advanced metering infrastructure (AMI) cited as important in the proposal may take a while to become available.
“In light of the fact that the rollout of AMI meters is likely to take … at least another two or three years to be completed, it is very important to note that demand response programs can be accomplished using smart thermostats without AMI meters,” she said. “And therefore we shouldn’t wait for the complete rollout of AMI to launch demand response programs.”
New York is laying the groundwork to develop the charging infrastructure needed for the larger electric vehicles intended to replace internal combustion trucks and buses on the state’s roads.
The state’s Public Service Commission on Thursday began a proceeding (Case 23-E-0070) that will examine the needs of medium- and heavy-duty (MHD) electric vehicles. Most of PSC’s efforts to date have centered on the light-duty passenger vehicles that account for most of the EVs on the road today.
The proceeding also will try to develop proactive planning approaches to prepare the grid for the demands of charging these larger vehicles. Stakeholder input will help focus the proceeding, the PSC said, but regardless of the final details, it expects to prioritize development in disadvantaged communities that bear the burden of air pollution from diesel-powered trucks and buses.
About 28% of New York’s greenhouse gas emissions are attributed to transportation, the PSC said. The nearly 550,000 trucks and buses registered in the state account for a disproportionately large share of transportation emissions.
But electrifying those vehicles at a fleet scale will require vast amounts of electricity: A single busy highway truck stop would draw as many megawatts as an entire town or a professional sports stadium, by some estimates. (See Study Projects Power Demands of Highway EV Charging Network.)
The challenge in the new proceeding is to anticipate the location and size of the charging facilities and put in place the grid infrastructure to serve them before they begin to strain system capacity.
Case 20-E-0197, in which PSC ordered utilities to proactively plan for the transmission and distribution needs of renewable energy, has a similar goal at the other end of the grid.
PSC Chair Rory Christian noted a kind of circularity in Thursday’s meeting agenda, at which the commissioners unanimously approved construction of an $810 million energy hub in an area of New York City where power demand is expected to ramp up sharply, in part because of EV charging.
The MHD planning effort, he said, will continue that trend with “the goal of making sure that the efforts we put forth are supporting rather than hindering adoption of EVs and the deployment of charging stations throughout the state.”
That order was approved unanimously.
A list of 16 questions is included to guide stakeholder input toward key topics. Responses are due by May 22, and replies to those responses are due by June 25. Based on the input, Department of Public Service staff will prepare a white paper for recommendations for the PSC to consider as it moves the proceeding forward.
The PSC followed a similar path with the make-ready program that focused on light-duty EVs, in Case 18-E-0138, which is now undergoing midpoint review and revisions.
The fate of two LNG developments in Texas that had their approvals remanded to FERC drew out some disagreements among the regulators’ two Democrats in orders posted Friday.
A three-vote majority during FERC’s monthly open meeting Thursday approved the Rio Grande LNG (CP16-454, et al.) and the Texas LNG Brownsville (CP16-116-002) projects to move ahead after the commission conducted some additional analysis on their impacts on local environmental justice communities. Both projects are being built close to each other along the Brownsville Shipping Channel, which is on the southern edge of Texas’ Gulf Coast.
The D.C. Circuit Court of Appeals had remanded FERC’s approvals of the projects in August 2021 in the case Vecinos Para El Bienestar de la Communidad Costera et al. vs FERC. The court directed the commission to do a better job justifying its determinations of public interest and convenience in the two cases.
The Rio Grande LNG is being developed by NextDecade, while Glenfarne Energy Transition is building the Texas LNG project. The Rio Grande facility is expected to go online in 2026 and Texas LNG the year after that.
Chair Willie Phillips filed concurrences to the two orders, saying that FERC adequately responded to the issues on remand by including the projects’ social costs of carbon and broadening the examination of environmental justice communities to those located within 50 km of either of the two power plants.
“While I recognize that certain of my colleagues would have preferred more process or less, I believe that the record assembled throughout the last year is an appropriate middle ground that represents an adequate basis to fully consider the issues the court remanded to us in Vecinos nearly two years ago,” Phillips wrote.
Despite expanding the EJ scope to communities within 50 km of the site instead of just 2 miles, FERC continued to find that neither project would have any significant impacts.
One area where FERC did make some changes was to require both projects to take additional steps after they start partial operations but are still under construction to avoid exceeding National Ambient Air Quality Standards, as two emissions-generating activities would be occurring at the same time.
That mitigation shows how FERC is starting to focus on a complaint it heard at its recent Environmental Justice Roundtable about cumulative impacts of projects, Phillips said. (See FERC Gets Advice, Criticism on Environmental Justice.)
“We heard from several stakeholders, including community groups, about the importance of considering cumulative impacts — i.e., not just the air emissions directly caused by a particular project, but also those emissions in conjunction with the emissions from other sources within the region,” Phillips wrote. “Today’s order takes a critical step toward addressing that concern by requiring that the project sponsors develop a plan to ensure that incremental emissions impacts associated with these projects, on top of all sources, do not cause a NAAQS exceedance, thereby helping to protect communities, including environmental justice communities, that may venture near the projects.”
Commissioner Allison Clements dissented on the orders, saying that FERC should have done supplemental environmental impact statements. Failing to do so renders the orders’ significance determinations unsupportable, she argued. The commission also should have held public meetings to address the projects’ environmental and other impacts.
Expanding the EJ scope identified hundreds of additional communities that never had a proper chance to weigh in on the project, warranting a new EIS, she said.
“The order imposes a new air pollution and monitoring condition that may prevent or reduce NAAQS violations,” she said in each of the orders. “Although I agree that imposing this condition is a beneficial step to take, I cannot conclude that it will be sufficient to reduce cumulative air emissions to an insignificant level because the condition itself is vague, and we have had no public comment on whether it will be effective or what additional mitigation may be needed.”
Clements also argued that FERC was missing a chance to implement its stated intentions from the recent Environmental Justice Roundtable.
“Considering our discussion at the roundtable of how to facilitate EJ communities’ full participation, it is especially disheartening that the order rejects requests to hold public meetings, with Spanish translation, to hear communities’ concerns about the project and our new analyses,” Clements said.
Clements also disagreed with the majority’s explanation for why FERC is not determining the significance of greenhouse emissions associated with the two projects.
The commission included social costs of carbon for the projects, but it said that tool was not designed to measure the impacts of individual projects, so it could not determine whether the emissions associated with the two LNG facilities are significant.
“I do not know whether the social cost of GHGs protocol or another tool can or should be used to determine significance,” Clements wrote. “That is because the commission has not seriously studied the answer to that question. The majority has simply decided the method does not work, with no explanation of why the commission departs from the approach so recently taken in other certificate orders.”
[EDITOR’S NOTE: This article has been corrected to report that NYISO said that new transmission into the Southeastern New York reserve region, not New York City, had increased capacity margins for capacity Zone J (NYC).]
Summer 2023 Capacity Assessment
NYISO on Thursday updated the Operating Committee about forecasted summer conditions, assessing that while it has enough capacity for this summer and the near future, margins are declining over time as the grid transitions to clean energy.
Under its baseline forecasted conditions, the ISO will have about 1,400 MW of surplus capacity. In the event of extreme conditions that would decrease that margin as low as ‑2,300 MW, the ISO is covered by up to 3,100 MW of emergency operating actions.
NYISO is currently conducting site visits to assess readiness for summer conditions and ensure potential outages coordinated with ISO staff to minimize any reliability impacts, said Aaron Markham, vice president of operations.
The ISO expects 652.3 MW of generation to be deactivated by July 1, mostly in Zone J (New York City) as a result of New York state’s peaker rule. About 940 MW of new wind and solar generation is expected to come online throughout the summer. Markham also said that new transmission into the Southeastern New York reserve region
resulted in increased margins for the zone.
March Operations Report
NYISO informed the OC that March was a “pretty quiet month.”
The grid experienced a peak load of 19,881 MW on March 14, which Markham said was “quite a bit lower than the capability period peak.” There were no high-level curtailments.
Installed behind-the-meter solar also “keeps ratcheting up,” according to NYISO, with 84 MW added since the last OC meeting.
Inverter-based Resources Standard
The New York State Reliability Council (NYSRC) briefed the OC about a proposed rule establishing minimum requirements for inverter-based resources (IBRs) over 20 MW.
The NYSRC said their draft rule, PRR-151, is necessary because more IBRs have sought interconnection in New York and recent problems seen in other RTOs show that without sufficient regulatory guidance, these resources can have outsized negative impacts across the grid when not performing properly. (See New York Considering Standards for IBRs.)
The committee approved NYISO’s proposed updates to the regulation requirements for renewable resources and their proposed implementation timelines.
Current and proposed regulation requirements for renewable resources
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NYISO
The ISO said the updated requirements will help balance bulk power concerns as net load grows and intermittent resources increasingly make up most of the state’s energy mix. (See related story, “Renewable Regulation Requirements,” NYISO Seeking to Increase Emissions Transparency.)
The first set of new regulation requirements, Scenario 1, will be implemented on June 1, and the second set, Scenario 2, will be effective June 1, 2025.
NYISO promised to update its presentation to specify Scenario 2’s implementation date and to provide stakeholders with advanced notices should timelines change.
