The Democrat-dominated Washington House voted 56-42 along party lines Monday to send Gov. Jay Inslee a bill aimed at reducing greenhouse gas emissions from air conditioners and large refrigeration units.
Washington’s new law to reduce refrigerant GHG emissions will affect grocery stores, ice rinks and air conditioners. | Shutterstock
“HFCs [hydrofluorocarbons] are an extremely potent greenhouse gas, and while they are still a small proportion of overall greenhouse gas emissions, this bill is the biggest step the Legislature has taken (so far) this year to protect the climate,” Rep. Joe Fitzgibbon (D) said in a press release. Fitzgibbon is the bill’s sponsor and chairman of the House Environment and Energy Committee
Though HFCs dissipate faster, they retain more heat in the air than carbon dioxide.
Fitzgibbon’s press release said the bill would reduce the climate impact of refrigerants used in air conditioners by roughly 70% and in commercial refrigeration systems by about 90%. HFCs account for roughly 4% — or 4 million tons — of Washington’s GHG emissions. The bill is modeled on regulations recently approved by the California Air Resources Board.
If signed by Inslee, HB 1050 would enable the state government to set the maximum global warming potential (GWP) measurements for the gases within all sizes of refrigeration units. It would also require grocery stores, ice rinks and other owners of large refrigeration units to periodically check for HFC leaks.
Maximum GWP is a measure of an HFC retaining heat in the atmosphere compared to a similar volume of carbon dioxide over a 100-year period. The Washington Department of Ecology has tracked a range of GWP for HFCs of 12 to 14,800 times that of carbon dioxide.
The bill establishes an upper GWP limit of 750 for new air conditioning and refrigeration equipment. That standard goes into effect for room air conditioners and dehumidifiers on Jan. 1, 2023. That standard would go into effect for air conditioning systems with variable refrigerant flows or volumes on Jan. 1, 2026.
For other types of refrigeration equipment, the new standards go into effect Jan. 1, 2025, or two years after the State Building Code Council adopts preliminary engineering specifications that the equipment can handle refrigerants under the new GWP standards — whichever comes second. Meanwhile, the bill prohibits a GWP greater than 150 in Jan. 1, 2024, for new refrigerant equipment for ice rinks.
“The extra costs will affect consumers,” Rep. Mary Dye, ranking Republican on the Energy and Environment Committee, said Monday in opposing the bill.
“Reducing emissions from fluorinated gases is one of the cheapest, quickest, most effective ways to reduce our contribution to the global climate crisis,” Fitzgibbon said.
The bill does not affect air conditioners and other refrigeration units currently in use or installed before the target dates.
New Jersey’s Division of Rate Counsel on Monday appealed to the state Supreme Court the dismissal of its suit seeking to block $300 million in subsidies for three South Jersey nuclear units as it continues to oppose a renewal of the subsidies by the Board of Public Utilities.
The ZEC program provides subsidies to nuclear power plants at risk of closure so that they can remain open to generate carbon-free power and help the state meet its goal of reducing greenhouse gas emissions by 80% by 2050. The BPU awarded the $300 million in ZECs to Hope Creek, which is owned and operated by PSEG, and Salem Units 1 and 2, which PSEG operates and co-owns with Exelon. (See NJ Approves $300M ZECs for Salem, Hope Creek Nukes.)
In a separate action on Friday, the Rate Counsel urged the BPU not to renew the ZECs. It argued that the two companies had failed to show that without the subsidies, the nuclear plants would lose money, or that the level of subsidies they are seeking is “affordable to New Jersey retail distribution customers.”
The BPU is expected to vote in the coming weeks on whether to extend the ZECs for another three-year period.
PSEG declined to comment on the Supreme Court petition. Instead, the company referred to its filing with the BPU on Friday that argues that even with the $300 million in ZECs, the companies would not generate enough revenue to cover the “risks inherent in the plants’ operation.” Without a subsidy of the proposed amount, PSEG would “take steps to close the plants,” the company said.
Asked for a comment on the Rate Counsel’s two actions, Exelon referred to PSEG’s response.
Staff Decision Rejected
The three-judge appellate panel made its ruling in response to a suit filed by the Rate Counsel after the BPU first awarded ZECs to PSEG and Exelon in March 2019. The agency, which is charged with protecting ratepayers’ interests, argued that the ZECs were arbitrary and capricious and that none of the plants need them to remain financially viable.
In preparation for the BPU’s 2019 decision on whether to award the ZECs or not, staff found that all three units would operate profitably through May 2022. As a result, staff concluded that they were not eligible for the subsidies.
But the BPU rejected that conclusion. It said the evaluation team had improperly excluded from its calculations consideration of PSEG’s operational and market risks. In dismissing the Rate Counsel’s suit, the appellate court agreed, saying that the legislature clearly intended the BPU to consider the “costs and risks” in considering the eligibility of applicants seeking a ZEC award.
The Rate Counsel told the Supreme Court that it will argue that the BPU made the award based on factors “other than the eligibility criteria” set out in state law. Among the arguments cited by the division were that the appellate court adopted BPU quantification of operational and market risks and costs, rather doing the analysis itself.
It also argued that the appeals court ignored the transcript of the BPU meeting in which commissioners explained the bases of their decisions and “effectively” overruled a past legal decision that required that rates be just and reasonable.
BPU Submissions
The Rate Counsel’s brief to the BPU argues that PSEG’s arguments “fall short” of proving that it needs the subsidy and that it needs to be at the proposed level.
“When the board takes a close look at the evidence in this matter, it is clear that PSEG overstates its projected costs, including the costs of operational and market risks, and understates its projected earnings,” the Rate Counsel said. “PSEG continues to rely on phantom costs that either do not exist or are not paid out as part of its operating expenses.
“Likewise, PSEG understates its revenues, understating both its energy and capacity revenues, while overstating the risk to earning capacity revenues.”
It also argued that PSEG’s calculations of the “emissions avoidance benefits” of keeping the plants open are also flawed because they are based on data for the Eastern U.S. and Canada, rather than areas that directly impact New Jersey’s air quality.
In its own filing, PSEG said that the counsel’s arguments are a simply a “rehash” of those made to, and rejected by, the legislature, BPU and Appellate Court.
PSEG said that the award of $300 million, the “maximum that the current law allows, is justifiable as a bridge to a longer-term solution for these plants that will place them on a firmer financial footing for the duration of their licenses.”
“The continued operation of these plants will significantly reduce carbon emissions and increase the resilience of the state’s energy system, and will do so at a cost per megawatt-hour that is vastly more cost-effective to electric customers than wind or solar,” PSEG said.
“Keeping these plants in operation,” it added, “in fact will keep electricity costs to customers lower than they otherwise would be by hundreds of millions of dollars over the three-year ZEC period.”
Building a net-zero, solar home in Fraser, Colo. — one of the coldest places in the contiguous U.S. — students at the University of Colorado, Boulder, incorporated foot-thick, hyper-insulated walls, sealed on the outside with pine tar, which was originally used for waterproofing on skis, according to student Charlotte Mitchell.
CU Boulder
The SPARC (Sustainability, Performance, Attainability, Resilience and Community) house is one of nine net-zero homes currently being showcased online as part of the Department of Energy’s virtual Solar Decathlon. The homes — all designed and built by student teams at universities in the U.S., Canada, Chile and the Netherlands — provide ample evidence that building super-efficient, comfortable homes that generate as much, if not more, energy as they consume is now possible, affordable and replicable.
“Buildings play a huge role in meeting the [Biden] administration’s goals for addressing climate change, because we can’t transition to this [clean] economy or a carbon-free power sector without reducing the carbon footprint of the building stock,” Kelly Speakes-Backman, principal deputy assistant secretary of energy efficiency and renewable energy at DOE, said at a media preview of the decathlon on Monday.
Since its inception, more than 20,000 students in the U.S. have participated in the biennial decathlons, producing a growing cohort of green architects, engineers and designers, decathlon Director Holly Carr said.
This year’s decathlon, DOE’s ninth since 2002, was originally scheduled for June 2020, with individual college teams building their homes as part of a “solar village” on the National Mall in D.C. Past decathlons have also brought solar villages to California and Colorado, with international spin-offs later this year in China, India and the Middle East.
The COVID-19 pandemic forced a delay and rethinking of the U.S. event, Carr said, with teams building their designs locally — a change that will become permanent and has perhaps allowed the homes to have a greater impact. For example, the SPARC house may become a model for affordable housing in Fraser, said Kristen Taddonio, who is now living in the house and is a board member of the local electric cooperative.
“Because of the cold climate, the build season is really short, and with a universal skilled labor shortage, the focus of development has understandably shifted to high-return luxury second homes,” said Mitchell, who is in her fourth year at UC majoring in architectural engineering. “Additionally, building materials are often less accessible and far more expensive in remote mountain towns, and these factors together drive land and property prices way up and push people out.”
Weber State University’s craftsman-style net-zero house in Ogden, Utah, is already built and occupied. | Weber State University
Similarly, in Ogden, Utah, students from Weber State University partnered with the city to build a craftsman-style, net-zero home on a vacant lot. The 2,450-square-foot, six-bedroom home is now occupied, and the city has asked the university to work on net-zero homes for two more vacant lots, said Jeremy Farner, the faculty adviser for the school’s decathlon team.
Green Building Trends
Green and net-zero building no longer occupies the architectural niche it once did. President Biden’s $2 trillion infrastructure plan includes $213 billion to be used for affordable housing, including building or retrofitting “more than a million affordable, resilient, accessible, energy-efficient and electrified housing units,” and more than 500,000 homes for low- and middle-income buyers. (See Biden Infrastructure Plan Would Boost Clean Energy.)
California now requires all new residential construction to be net zero, with commercial buildings to follow in 2030. Denver in January released its guidelines for new buildings in the city to be net zero by 2030. The guidelines define net zero as energy efficient, all electric, powered by renewable energy and providing demand flexibility for the grid.
The local homes built for the Solar Decathlon almost all fit that description. They are judged on a broad range of criteria, including architecture, affordability, performance, occupant experience and, for the first time this year, their carbon footprint, not only of the structures themselves but all their materials as well. The level of thought, detail and creativity that goes into each house is impressive.
The team at the University of Nevada, Las Vegas designed their Mojave Bloom home specifically for military veterans recovering from either PTSD or traumatic brain injuries. An open layout provides clear sightlines inside and outside the home, team member Ryan Mantei said. Acoustically absorptive ceilings with extra insulation cut down on sudden noise or echoes that could be triggering for the resident, and an internal hydroponic green wall improves air quality and brings nature inside.
The University of Denver is working on the decathlon’s first net-zero retrofit of a 1950s ranch-style house. The project is located on a 100-year flood plain, so the rebuild is mixing energy efficiency with Federal Emergency Management Agency flood plain guidelines.
The variety of styles and locations notwithstanding, the decathlon homes share some common design features, providing a glimpse of evolving trends in green building. Several teams used prefabricated components, like insulated walls, to cut material and building costs. The prefabricated walls of the SPARC house were installed at the site in two days, Mitchell said.
Electric heating and cooling using heat pumps and electric, ductless water heaters were also installed in a number of the projects, along with finished concrete floors that retain heat to help keep homes warm in the winter and cool in the summer. Rooftop solar panels, generally around 7 kW, were ubiquitous, often coupled with storage. The Weber team’s house pairs its solar with a programmable heat-pump water heater that can be used for load shifting, Farner said.
While events like the Solar Decathlon create significant buzz for green architecture, a full transition to net-zero building still faces significant obstacles. Efforts to make net-zero construction the norm in Maryland by 2033 failed in the state legislature this week, with critics arguing that technology and building codes are not sufficiently advanced to support such a goal.
The decathlon provides real-life examples that undercut such arguments.
Green building is a critical piece of “having to deal with our climate crisis in a way that doesn’t prevent people from living the lives they want but rather empowers them to do it,” said David Nemtzow, director of the DOE’s Building Technologies Office. “We cannot succeed with our environmental and global energy policies unless we can also deliver comfort and aesthetic appeal and productivity and durability to the buildings around the country and the world.”
The Indiana Utility Regulatory Commission last week approved a rule change to dramatically cut the net metering credits earned by rooftop solar owners in southwest Indiana.
The commission granted CenterPoint Energy subsidiary Vectren South a new net metering rate of about 3 cents/kWh, slashing the current rate of about 14 cents/kWh for residential and 9 cents/kWh for commercial customers (45378). CenterPoint must file a new rate schedule with the commission before the change can be implemented.
The decision in CenterPoint’s favor could set the tone for Indiana’s entire rooftop solar industry. Four other investor-owned utilities recently filed proposals to reduce reimbursements for distributed solar generation. Only Northern Indiana Public Service Co. has committed to keeping retail rate net metering in place for the time being.
In issuing the decision, the IURC called itself a “a creature of statute” and said the new rate doesn’t violate any laws. It also contended that it does not have the authority to devise a new rate, as some solar developers requested.
The new rate is based on average real-time MISO locational marginal prices of about $25/MWh at Vectren South’s load node in 2019, multiplied by 1.25.
CenterPoint counsel Matthew Rice said the new rate “appropriately provides compensation to the solar customer based on the rate the utility could have purchased the same energy at wholesale, plus a 25% adder.”
CenterPoint’s customers with distributed solar assets will also be compensated at the lower rate using instantaneous billing instead of monthly netting.
Solar array | NIPSCO
Rice said monthly netting “creates a false price signal for customers.”
He said customers in the net metering program currently enjoy an incentive “in excess of the value provided to the system.”
In its request for lower credits, CenterPoint predicted that Vectren South would exhaust its available net metering capacity by the end of 2020. As of Aug. 31, 2020, the utility had about 2,152 kW of capacity available in its program, with 3,236 kW in its queue either approved or awaiting approval. It said it had already freed up capacity by making an underused category reserved for biomass generation available to rooftop solar owners.
Vectren South has a net metering cap of 1.5% of its retail peak load, or about 16.5 MW. If that limit is exhausted before 2022, customers with solar installations will earn the wholesale plus 25% adder rate. The new rate is also set to apply to all customers with systems installed after 2022.
Owners, Installers Protest
The Indiana Office of Utility Consumer Counselor fielded numerous comments that the new tariff will make customer-owned solar generation out of reach. Clean energy proponents Citizens Action Coalition of Indiana, Environmental Law and Policy Center, Vote Solar and Solar United Neighbors also opposed the ruling.
Such a low compensation rate will have a chilling effect on the young distributed solar industry, solar developers said.
Solarize Indiana’s Jay Picking said the rate change will “practically destroy the residential solar market” in Vectren South’s service territory.
Johnson Melloh Solutions Vice President Kurt Schneider, whose company provides solar projects and energy efficiency solutions, said the rate decrease “will undermine the future of JMS’ Indiana solar business.” He said the lower the credit customers receive, the less likely they are to hire solar installers.
Schneider said CenterPoint’s “instantaneous netting methodology will drastically reduce or dry up JMS’ Indiana solar business in Vectren South’s service area,” and that the plan “will more than triple the customer payback [period] from seven to 10 years to about 25 years.”
Schneider asked the commission to minimize CenterPoint’s “brutal treatment” of distributed solar.
Rice countered that instantaneous netting produces rates “that better approximate the cost and reality of serving [distributed] customers because [the] distribution and transmission system must not only meet peak requirements but must also absorb any additional input from [distributed generation] resources without creating failures for its other customers.”
Morton Solar owner Brad Morton said large business customers typically seek a payback period of five to six years, while residential customers look for seven to 10 years. He agreed the new rate would likely draw out the investment recovery period to 25 years or more.
The reduced rate will make customers “extremely reluctant or unwilling to invest in solar, which will be devastating to Indiana’s fledgling solar industry and result in job losses and probable market contraction to an industry just beginning to blossom,” Morton said.
Former adviser to the Office of Consumer Counselor Edward Rutter, now with the Indiana Distributed Energy Alliance, said the longer recovery periods will likely outlast the lifespan of the panels themselves.
EQ Research Principal Energy Policy Analyst Ben Inskeep tweeted that the decision is “incredibly shortsighted” and would “effectively kill rooftop solar for the foreseeable future for all CenterPoint customers.”
Rooftop solar user and advocate Michael Mullett, a customer of Duke Energy Indiana, testified that a 3 cent/kWh rate is “arbitrary and confiscatory.”
The commission, however, ruled that distributed generation owners’ shorter payback periods generate extra costs for the utility’s other ratepayers.
“We find the evidence demonstrates that, ultimately, [distributed generation] customers’ faster payback periods translate to the utility’s other customers paying costs associated with the excess electricity DG customers put on Vectren South’s system — whether needed or not,” the commission said. “Accordingly, we cannot conclude it is just and reasonable for [CenterPoint’s] other customers to subsidize the payback periods of [distributed generation] customers by the continuation of monthly netting as opposed to instantaneous netting.”
The commission also said solar panel owners can partly receive a return on their investment simply by generating their own power and purchasing less from the utility.
Steve Budrow steered his sturdy, 47-foot vessel the Mary B. past the State Fish Pier in Gloucester, Mass., on a cloudy afternoon last week.
In his 25 years as a lobsterman, Budrow has faced many challenges. A nor’easter wiped out $16,000 worth of traps in 2003. The price of bait has skyrocketed. State regulators increasingly are imposing restrictions on when and where lobstermen can set traps to conserve endangered species.
Now Budrow faces the growth of offshore wind development, a situation he could not have imagined when he first began hauling lobster traps in the small rustic fishing town of Rockport, Mass.
The U.S. Bureau of Ocean Energy Management (BOEM) concluded its environmental review of the Vineyard Wind I project off the coast near Martha’s Vineyard last month. A statement from the agency signaled its willingness to approve Vineyard Wind’s construction with a cap on the number of turbines. (See BOEM Releases Final Vineyard Wind Impact Statement.)
The state’s sweeping climate bill signed into law last month requires utilities to procure 5.6 GW of offshore wind, and President Biden’s new infrastructure bill would expand offshore wind on the East Coast to 30 GW by 2030.
But Budrow and other Massachusetts fishermen say constructing offshore wind turbines and embedding power cables into the ocean floor to transmit the wind power threatens their livelihood, along with the livelihood of other waterfront industries on Cape Ann.
“It wears on you,” Budrow said as the Mary B. rounded the breakwater.
About 40 lobster boats gathered last week for a parade protesting the recent closure of all state waters to commercial lobster fishing to protect the migration of North Atlantic right whales from entanglement in trap lines. The right whale’s remaining numbers are estimated to be around 360.
“How does that make sense?” Budrow said. “Lobster fishing is shut down for three months, but the state will allow offshore wind companies to build wind farms near whale habitat.”
Offshore wind projects have not been planned for the waters where Budrow fishes, but tall orders for renewable energy at the state and federal level has Cape Ann fishermen bracing for more interruptions to the fishing, as they try to eke out a living, he said.
Subsea base construction and buried cables will limit the places where 50-ft lobster boats can haul traps and skim the seabed for scallops.
In Maine, the marine resources commissioner forced captains who fish along a survey route for an undersea power cable to move their gear. If fishermen didn’t comply, the state threatened to move the gear out of the way using the state’s Marine Patrol.
Further restrictions from OSW developments are the straws breaking the fishing industry’s back; fishermen off the coasts of Massachusetts and Maine are planning protests and visits to the state house.
“Eventually they are going to regulate us out of business if they don’t listen,” Budrow said.
The fishing community is a tight-knit one. Budrow pulled his boat up alongside other lobstermen as the boats chugged to Ten Pound Island and out to Gloucester Harbor.
Paul Theriault, who has been making a living as a fisherman in Rockport for five decades, said it feels like the industry is being attacked from all sides: politicians, conservationists and offshore wind developers.
“Lobsters are big in Massachusetts, but in Maine lobsters are king” as an economic mainstay for coastal towns, Theriault said.
Massachusetts harvests more than $459 million worth of mollusks, such as sea scallops, annually. Fisheries, seafood processors and vendors employ more than 5,700 people in more than 500 businesses, generating more than $300 million in annual wages, according to the state.
The industry also generates $600 million worth of gross state product annually, with Rockport as one of Massachusetts’s top ports for lobster landings.
“There are thousands of families that will be affected negatively by this project,” Theriault said.
He sits on the board of the Massachusetts Fishermen’s Partnership and meets with OSW developers to explain that the lobster industry in Massachusetts employs crew members, truck drivers, boat builders and captains.
“It’s been challenging to obtain products as one of the local, small lobster dealers,” Anthony Ciarametaro, a wholesale retailer based in Essex, Mass., said at the protest. He works with lobstermen like Budrow and Theriault to sell their catch to restaurants and markets, but fishing restrictions have left supply low.
Response from Vineyard Wind
In response to concerns that offshore wind turbines will encroach on fishing areas, Vineyard Wind reduced the number of turbines it planned to anchor into the sea floor from 106 to 84, and eventually to 62.
“Some fisheries will lose, and some will benefit,” Kevin Stokesbury, a researcher from the University of Massachusetts Dartmouth, said during a recent a webinar hosted by New England for Offshore Wind. He was hired by Vineyard Wind to assess the impacts of offshore wind on the fishing industry and help develop mitigations.
Areas designated for wind turbine construction in the Atlantic overlap with 40% of scallop fishing zones, Stokesbury said. But the lobster fishing industry might benefit from the creation of more subtidal, shallow habitat zones from the wind turbine platforms.
The final environmental impact statement from BOEM for the Vineyard Wind project said that “most potential unavoidable adverse impacts associated with the [project as proposed], such as disturbance of habitat or incremental disruption of typical daily activities, would occur during the construction phase or would be temporary.”
However, the project “could include effects on habitat or individual members of protected species, as well as potential loss of use of commercial fishing areas.”
Vineyard Wind agreed to provide fisheries mitigations for Rhode Island “after multiple discussions and negotiations,” according to the review, including a $4.2 million fund for direct compensation to Rhode Island fishermen for loss of equipment or claims of direct impact.
The project will also provide Rhode Island with $12.5 million to establish a Rhode Island Fisheries Future Viability Trust and work with the Massachusetts Executive Office of Energy and Environmental Affairs to establish a Compensatory Mitigation Fund for $19.2 million and a Fisheries Innovation Fund for $1.75 million.
But fishermen like Theriault say they aren’t satisfied and argue wind turbines should be built on land instead of offshore.
“Putting things in the ocean is cheap because no one sees it,” Theriault said. “But that’s not a good reason to put it there.”
The New Jersey Board of Public Utilities is preparing a draft proposal on how to encourage the installation of EV chargers for heavy-duty electric trucks statewide, as a Newark-based trucking company is developing a project that could significantly advance the use of electric trucks in the Port of New York and New Jersey.
In the coming months, the board expects to release preliminary guidelines for promoting the development of charging sites for medium- and heavy-duty electric trucks and ensuring they are distributed across the state in line with the needs of trucks, buses and other users, said spokesman Peter Peretzman. The evaluation process will be similar to that in guidelines the BPU is close to concluding to set out rules on how and where to locate charging sites for light-duty electric vehicles around the state. (See NJ Looks to Boost EV Charger Numbers.)
The New Jersey BPU will soon release a straw proposal on how to accelerate the statewide deployment of charging sites for electric trucks and buses. | Daimler Trucks North America
The heavy-duty charger proposal and a project that trucking company International Motor Freight (IMF) has under development in the port are designed to put more electric trucks on the road in the state, where 42% of the carbon emissions come from transportation and electric truck use is minimal. The Port Authority of New York and New Jersey, for example, says it has only three electric trucks in service.
Truckers in New Jersey, like those around the nation, cite the lack of medium- and heavy-duty charging sites as a key obstacle to greater use of electric trucks. Other drawbacks include the short range of existing electric trucks — only up to around 250 miles — the high cost of the vehicles and the amount of space taken up by the battery, reducing the cargo area.
Yet industry analysts, including the authors of reports released last month by the Environmental Defense Fund and Lawrence Berkeley National Laboratory, say that technological advances, especially in battery size, mean that electric trucks are becoming more viable and can have long-term economic advantages over diesel. Reaping those benefits, however, will require government support, the reports said.
Limited Delivery Distance
The IMF project, which is designed for the company’s 7-acre yard in the port, was conceived with truck manufacturer Daimler Trucks North America, in part, because IMF’s typical cargo run fits in with the range and limitations of an electric truck fleet. The main business of the 45-year-old company, which has about 145 diesel trucks, is “drayage” trucking, the pickup and drop-off of containers at port terminals and client warehouses and distribution centers.
In February, the project drew support from Gov. Phil Murphy, who awarded $5.9 million from the state Volkswagen settlement to IMF for the purchase of 16 electric trucks and two yard tractors for moving cargo inside the port. The grant was part of $100 million in awards given by Murphy, who aims to position the state to reach zero emissions by 2050. (See NJ Gov. Unveils Green Transportation Plan.)
The IMF project will use Freightliner eCascadia trucks, about 20 of which are in use in test programs in California and collectively have driven 750,000 miles, Daimler consultant Markus Schwenke told the New Jersey Transportation Planning Authority in a February presentation. One of those trucks will be brought to New Jersey for a test in the second half of this year. The truck goes into production next year, he said. The manufacturer expects to deliver the trucks for the project in late 2022 or early 2023.
Several elements in IMF’s business make it a good fit for an electric vehicle project with Daimler, including the fact that customers are asking IMF to lower its emissions, Schwenke said. IMF trucks typically run trips of 100 miles to 150 miles a day, five or six times a week on the New Jersey Turnpike, he said. They include stops in New York, Elizabeth and the Port of Philadelphia, about 90 miles from the Port of New York and New Jersey, which fits easily within the 250-mile range of the eCascadia, Schwenke said.
Newark-based International Motor Freight will test out a Class 8 electric truck for daily trips averaging 100 to 150 miles, picking up and dropping off cargo around the Port of New York and New Jersey. | Daimler Trucks North America
“One hundred to 250 miles fits what IMF is doing as of today for minimum 50% of their operation,” he said. Trucks parked in the IMF yard could be recharged between about 4 p.m. and 2 a.m. to 3 a.m., he said. IMF plans to install 50 charging stations in the yard, with a combined 4 MW of energy and is considering 30,000 square feet of solar panels in the yard to feed power into battery storage, Schwenke said.
“Those batteries in the end can shave peaks during peak hours,” Schwenke said. “We want to be very cautious with withdrawing power from the grid when it’s most needed.” The truck’s 475-kW battery could be charged in two hours if need be, he said.
Adrian G Stewart, a member of Daimler’s electric mobility team, added that the project may include a charger at the Port of Philadelphia to provide “opportunity charging,” even though the port is an easy round trip for the eCascadia from IMF’s home depot.
“Trucks can sometimes have to wait for extended periods of time in the port to collect cargo,” Stewart said. “To make productive use of this time, trucks can be connected to a charger and would then require a shorter, quicker charge when they return home.”
Government Policies
Government support will be key to the advancement of electric trucks, according to the two reports published in March, which suggest that although electric trucks are viable, they have some way to go to before becoming routine players in the market.
A study prepared for the Environmental Defense Fund by consultant Gladstein, Neandross & Associates looked at the delivery demands of two trucking fleets in California and concluded that even under existing range and charging limitations, most of their required trips could be done with electric trucks.
The study analyzed 12-months of trip data from two trucking companies, NFI of New Jersey and Schneider of Wisconsin, from their yards in California. It found that 71% of the 20,500 truck trips begun from NFI’s yard in Chino, many involving the movement of cargo containers to and from the ports of Los Angeles and Long Beach, could be completed by electric trucks fitted with 500-kWh batteries, which are available today. The study found that figure would rise to 93% of trips if a not-yet-available 1,000-kWh battery were used.
The report also concluded that the operating cost over the life of an electric truck was about 60% cheaper than for a diesel truck. However, without government subsidies or other supporting policies, the advantageous costs for the electric truck would be minimal, the report said. “Programs that provide support to reduce infrastructure costs are still needed.”
Of particular importance is California’s Low Carbon Fuel Standard (LCFS) program, which enables clean energy users, including electric truck users, to sell credits to emission producers that want to offset their carbon footprint, the report said. Without LCFS credit sales, “the positive results compared to diesel are erased,” the report concluded.
Long-term Cost Benefits
The Lawrence Berkeley National Laboratory report found that the lifetime total cost of ownership (TCO) of a Class 8 truck, the largest cargo-hauling truck, would be about 13% lower for an electric truck than a diesel truck. While upfront costs of buying an electric truck are greater — about $210,000 compared to $125,000 for a diesel truck — the fuel and maintenance costs are lower for the electric truck, the report said.
That calculation of 13% lower lifetime costs is based on a truck with a 300-mile range, which is about 50 miles longer than the longest range of most electric trucks currently available. But EV costs will fall as battery costs do, from about $135/kWh at present to an expected $60/kWh in 2030, the report said. That would make the TCO for an electric truck 40% lower than that of a diesel truck, the report said.
Key to the sector’s ability to reap those benefits will be government policies to encourage the use of electric trucks, said Nikit Abhyankar, a scientist at the laboratory and one of four authors of the report. Such policies should include incentives for truck purchases, measures that open the way for the creation of heavy-duty charging infrastructure and an effort to set electricity rates for charging at industrial levels, rather than the higher residential rates, Abhyankar said. “All three of them are equally important.”
Opponents of a bill that would put a price on pollution and charge a fee for emitting in New York say the bill replicates work already underway by the state’s Climate Action Council.
“It strikes us that moving forward with this bill is premature,” Ken Pokalsky, vice president of the Business Council of New York State, said Tuesday. “There is an enormous amount of work being done [by the council], and it’s addressing some of the very issues that this bill, in our view, would presuppose answers to.”
The Climate and Community Investment Act (CCIA) would prioritize the investment of funds obtained from payments for emission of greenhouse gases and co-pollutants in disadvantaged communities. The bill’s proponents say it builds on the commitments to environmental justice made in the 2019 Climate Leadership and Community Protection Act (CLCPA).
Rachel Patterson with Environmental Advocates New York said that a bill that would establish a carbon tax in New York builds on the equity commitments made in the 2019 Climate Leadership and Community Protection Act. | N.Y. Senate
“We know that climate change is impacting New Yorkers right now, and the impacts of sea level rise and deadly air pollution are worse for our vulnerable residence, low-income communities and communities of color,” Rachel Patterson, director of climate policy at Environmental Advocates New York, said during a public joint Senate committee hearing on the bill. “By charging polluters for their emissions, we can afford to support families, workers, small businesses and disadvantaged communities in the shift to renewable energy.”
The bill also would allocate funding for community-led energy planning, according to Patterson.
“Underserved communities know what changes need to be made to make their neighborhoods more resilient and improve air quality, and the funds from the CCIA will allow community members to have the power to shape their communities,” she said.
The Empire State Forest Products Association (ESFPA) echoed Pokalsky’s concerns that the bill is premature.
ESFPA believes the bill is missing the integrated analysis called for in the CLCPA, according to Executive Director John Bartow.
“That analysis should be completed before legislative or other financing mechanisms are created,” he said.
Program Costs
The CCIA would require New York to establish an index that lists the social cost of pollution for all regulated air contaminants in the state and set up a system of compliance fees that reflect that index.
The coalition NY Renews estimates that the fee would generate $15 billion per year for reinvestment, at a price of $55 per short ton of carbon dioxide equivalent. The bill also establishes a phased increase in the price. Ideally, the amount that covered entities emit would go down, eventually helping New York meet its 2050 emissions goal of an 85% reduction from 1990 levels.
“The CCIA prices the source of harm to frontline communities for the pollution that causes asthma, premature death and escalating climate crises,” said Raya Salter, lead policy organizer at NY Renews. Investments, she added, would be made in large- and small-scale renewable energy projects, building upgrades, energy retrofits and community-owned power, among other things.
At $55, according to Pokalsky, the natural gas industry would pay an extra $4.2 billion in a year, representing a 26% increase in costs. In addition, he said, the cost for gasoline would be $2.3 billion in a year, representing 55 cents/gallon.
The cost to one paper mill at $55, according to Bartow, would be $32.6 million in a year. Sector-wide, he said, the forest-related economy would pay $1 billion in a year.
“That is not sustainable to many of our business,” he said.
ESFPA has been working with the CAC’s Agriculture and Forestry Advisory Panel to build a role for forest and wood products, Bartow said.
“We need to accept that what we currently make using fossil fuels can be made from biomass, such as diesel to biodiesel, plastics to bioplastics, and petrochemicals to biochemicals,” he said. “We need to decide whether we want to host and grow these advanced bioprocessing facilities and manufacturing plants in our communities and have the jobs and the tax base that comes with them.”
The Maryland legislature failed to reach an agreement to increase the state’s 2030 greenhouse gas reduction target Monday after the House of Delegates and Senate deadlocked over the Climate Solutions Now Act (SB 414).
Sen. Paul Pinsky (D) — lead sponsor of the Senate bill and chair of the Education, Health and Environmental Affairs Committee — persuaded his colleagues to reject House revisions that would have set the state’s 2030 goal at 50% of 2006 levels — a step back from his proposed 60% target.
The House also stripped energy efficiency and solar-ready requirements for large new commercial and residential buildings. Also eliminated was a requirement that all new schools be solar-ready or net zero beginning in 2022. (See Maryland Panel Votes to Boost GHG Goal to 50%.)
“It dramatically changes what this body did over a month ago,” Pinsky said on the Senate floor, contending the House version not only deleted the school requirements from his bill but also eliminated existing “green building” requirements. “So not only was it not a hold-harmless, it was a major step backwards.”
House Speaker Adrienne A. Jones (D) responded with a video calling on the Senate to drop its “posturing” and adopt the “practical, science-based bill” as amended. “I certainly hope the disappointing over-the-top rhetoric of a few doesn’t sink this critical legislation.”
House Speaker Adrienne A. Jones (D) urged the Senate to drop its “posturing” and adopt the “practical, science-based [climate] bill” as amended by the House. The Senate refused. | Adrienne A. Jones via Twitter
Although both houses appointed conference committees to seek a deal, Pinsky and Del. Kumar Barve, chair of the House Environment and Transportation Committee, were unable to agree before the legislature’s 90-day session expired at midnight Monday.
The failure of the bill left the state’s current target, a 40% reduction from 2006 levels, in place.
“This bill would have taken steps in the right direction, particularly with regards to setting a definitive goal of net-zero emissions by 2045,” said Kim Coble, executive director of the Maryland League of Conservation Voters. “Science tells us we need stronger, faster emissions reductions to meaningfully address the urgency of the climate crisis, and statewide polling tells us that’s what Maryland voters want. It is disappointing that for the second year in a row, legislators were not able to pass a comprehensive bill that would adequately address the climate crisis.”
“We were frustrated that the General Assembly didn’t pass the Climate Solutions Act, especially when the Senate took action so early, giving them more than enough time to work out differences,” said Josh Tulkin, director of the Maryland chapter of the Sierra Club. The Senate had approved the bill March 12.
Accomplishments
But Coble and Tulkin noted the legislature did pass bills to provide transit funding, reinvigorate its environmental justice commission and transition the state’s bus fleet to zero-emission vehicles.
“The biggest victories came on transit, where the state finally allocated the six years of funding needed to bring the Maryland Transit Administration [MTA] into a state of good repair,” Tulkin said, referring to HB 114.
Another bill would require the MTA to purchase only zero-emission buses beginning in fiscal year 2023, which is expected to cost the state an additional $25 million annually (SB 137).
The bill would allow the MTA to purchase an alternative-fuel bus, one with reduced emissions compared to a diesel that is not powered by diesel or gasoline, if it determines that no available zero-emission bus meets the performance requirements for a particular use.
The state estimated 40-foot electric buses will cost $948,750 each, including almost $100,000 in charging infrastructure, a $378,750 premium over the $570,000 cost of a diesel bus. Electrified versions of 60-foot articulated buses would have a smaller $209,000 premium at $1.05 million, versus $840,000 for its diesel counterpart.
Forest Mitigation Banks
Tulkin said the legislature “reached a good compromise” on a temporary measure for forest mitigation banks, which have been used by developers to meet replanting requirements by putting existing forests into protected easements.
In October, the Attorney General’s Office issued an opinion concluding that easements on existing forest, in contrast to an intentionally created or restored forest, would not qualify as mitigation banking under the Forest Conservation Act, a position Tulkin said advocates have been arguing for years.
HB 991 would allow developers to continue the past practice for three years but requires them to protect two trees for every one lost to development. In the interim, the state will order a study to consider the impact of the practices and develop a long-term replacement.
Pinsky was able to add to the bill a provision from the climate bill setting a goal of planting 5 million trees by the end of 2030, including at least 500,000 in “underserved” areas.
The Sierra Club says the state is losing about 3,000 acres of forest annually, most of it to development.
The legislature also approved a bill that would require the Department of Transportation (MDOT) to develop an urban tree program to replace trees removed during the construction of certain transportation projects, with priority to those affected by environmental justice issues or “heat islands” (HB 80).
Environmental Justice Commission
Legislators took action to change the composition of the Commission on Environmental Justice and Sustainable Communities, which was created by executive order in 2001 and codified in 2003 (SB 674).
The bill would require members to reflect the diversity of the state, gives it new responsibilities and requires that it meet at least six times per year, including once each in a rural and an urban location. The chairman, previously appointed by the governor, will be elected by the commission.
It would require the commission to use data sets and mapping tools to analyze the impact of current state laws and policies on communities and to coordinate on recommendations with the Commission on Climate Change in addition to the Children’s Environmental Health and Protection Advisory Council. The commission also would be charged with developing a list of potential “supplemental environmental projects” — activity not required by law but that an alleged violator agrees to undertake as part of a settlement or enforcement action — to address environmental justice issues.
RPS Changes
The legislature passed several changes to the state’s renewable portfolio standard, including HB 1007, which creates a carve-out for geothermal systems in Tier 1, beginning in 2023 at 0.05% and increasing annually until reaching 1% in 2027.
The bill prompted a lengthy debate in the Senate Finance Committee on April 10.
Sen. Brian Feldman (D), who sponsored the Senate version of the bill, said the legislation could have a big impact. “I think this is only the beginning for geothermal,” he said. “I think geothermal is where solar was 10 or 15 years ago.”
Supporters said that it had passed with broad bipartisan support in the House (114-21) and had been endorsed by environmental groups and labor unions.
“When you have the environmental folks and labor folks all working together what else can one ask for?” said Sen. Katherine Klausmeier (D). “It doesn’t happen too often. It doesn’t happen often enough.”
But critics said geothermal already is eligible for renewable energy credits under the RPS and said the bill would benefit Google spinoff Dandelion Energy. Sen. Malcolm Augustine (D) sought unsuccessfully to amend the bill into a study.
“Nobody understands this bill,” said Sen. Stephen Hershey Jr. (R), citing concerns from the Public Service Commission. “They have said several times that the methodology in this bill cannot be implemented.”
PSC Chair Jason Stanek cited several “technical concerns” with the legislation in a letter Feb. 18.
Stanek said that to reach the 1% carve-out by 2026 would require increasing the number of RECs by 278% from the current level. “While there are some incentives available through EmPOWER Maryland and other state programs for geothermal systems, there is a substantial risk that sufficient geothermal systems may not be deployed to meet the new requirements,” he wrote. “The cost of the renewable portfolio standard may be more expensive to ratepayers if suppliers need to pay alternative compliance payments in lieu of purchasing RECs for compliance with the law.”
Feldman insisted the commission’s concerns had been addressed by changes in the bill.
Stanek told NetZero Insider on Tuesday that the changes “addressed some, but not all, of our technical concerns.”
“While the bill, as passed, provides the commission with additional time to implement the legislation, we still have concerns regarding how to properly measure the geothermal output for certain types of geothermal systems,” he said. “However, since the legislation would now take effect with geothermal systems installed in 2023 rather than 2022, we have some time to find a solution.”
Lawmakers also approved HB 561, which would expand the definition of Tier 1 renewable sources to include raw or treated wastewater used as a heat source or heat sink for a heating or cooling system connected to the distribution grid.
They also took action to exclude black liquor, a byproduct of paper manufacturing, and any product derived from it from eligibility as a Tier 1 resource beginning Jan. 1, 2022 (SB 65). According to the Department of Natural Resources (DNR), Maryland is the only state in PJM that includes black liquor as an eligible Tier 1 resource besides Pennsylvania.
Electric Generation
Solar power developers got some good news with SB 417, which would set a six-month deadline for the Department of the Environment and DNR to review and make recommendations on a completed application for a certificate of public convenience and necessity (CPCN) for power plant construction. The PSC, which has ultimate authority over issuance of CPCNs, may waive the six-month deadline for “good cause.”
The Sierra Club testified in favor of the bill, saying that the average time for CPCN reviews had increased from nine months to about 18 months. “This prolonged process has contributed to a decrease in the number of CPCNs being granted from eight in 2018 to two in 2019 and three in 2020,” the club said. Meeting the Clean Energy Jobs Act in-state solar energy target of 14.5% of energy will require developers to build an average of 625 MW of solar annually this decade, the organization said. “The slow rate of utility scale project approval resulting from the prolonged and less than optimally productive CPCN review process is one major barrier to accomplishing this.”
Sierra’s Tulkin also praised SB 83, which would prohibit the PSC from issuing a CPCN for a new electric generation plant without considering its impact on GHG emissions, and its consistency with the state’s emission reduction goals.
Other Legislation
The following bills also were approved by veto-proof majorities during the session (three-fifths of those elected):
Electric Vehicle Recharging Equipment for Multifamily Units Act (HB 110): declares void and unenforceable recorded covenants and condominium or homeowners association bylaws that prohibit or unreasonably restrict the installation or use of electric vehicle charging equipment.
Energy Efficiency, Net-Zero Homes, Contract Preferences (HB 70): requires the Department of Housing and Community Development to give preference to applications for funding for a net-zero home from the Energy-Efficient Homes Construction Fund that hire small, minority, women-owned and veteran-owned businesses.
Public Utilities – Net Energy Metering (HB 584): bars the PSC from prohibiting the construction or operation of multiple net metered solar generating facilities located on contiguous lots that are owned by a local government solely because the capacity of the combined systems exceeds the 2-MW limit. The bill applies to generating facilities intended to be used solely for the benefit of the local government, with a maximum capacity of 5 MW. It does not apply to customers of electric cooperatives or municipal utilities.
Clean Cars Act of 2021 (HB 44): increases the Electric Vehicle Recharging Equipment Rebate Program from $1.2 million to $1.8 million annually for fiscal years 2021 through 2023. The bill includes a Republican amendment requiring the Maryland Energy Administration and MDOT to produce a study on the impact of EVs on the state’s Transportation Trust Fund, which is funded almost exclusively by the state gasoline tax.
Montgomery County Community Choice Energy Pilot Program (HB 768): authorizes Montgomery County, the state’s most populous, to begin a community choice energy pilot program beginning in 2024. The county would serve as an aggregator for residents who have not selected an electric generation provider other than the standard offer service supplier.
PJM stakeholders unanimously endorsed an issue charge aimed at developing a cost recovery mechanism for generators forced to upgrade their facilities to comply with certain NERC Critical Infrastructure Protection (CIP) standards regarding interconnection reliability operating limits (IROLs).
PJM proposed allowing generators deemed critical for determining interconnection reliability operating limits to recover required upgrade costs. An IROL is any system operating limit that, if exceeded, could jeopardize the entire grid.
Frogg said PJM is required to develop a list of “IROL-critical” facilities in the fall, and generators on the list may then be required to upgrade their units to meet reliability requirements. He said PJM is solely responsible for creating the list, and generation owners have no control over the IROL-critical designation.
PJM made the proposal on behalf of generator owners because the classification of a generator as IROL-critical is considered critical energy and electric infrastructure information.
“We want to get the generation owners the opportunity to recover costs before the next annual list is created in the fall,” Frogg said.
With the endorsement of the issue charge, stakeholders will study the relevant CIP standards, review how a generator’s status is determined by PJM and consider the types of costs that generators incur from being designated. Stakeholders will look at how other RTOs and ISOs have addressed the issue, such as FERC OKs Payment Rules for IROL Facilities.) Stakeholders will also discuss which costs should be recovered and how, and ensure the entire process is transparent.
Frogg said work on the issue is expected to take three to six months with a recommendation brought to the Markets and Reliability Committee at the end of the process. The Market Implementation Committee will be updated on the work since some of the issues are related to that committee.
In response to a question from Becky Robinson of Vistra, Frogg said PJM isn’t seeking to complete the work ahead of deadline because it anticipates adding an unusually high number of IROL-critical facilities to the list in the fall.
“There could usually be a fluctuation of one or two units, but there’s nothing significant,” Frogg said.
COVID-19 Update
Stakeholders questioned PJM officials about the RTO’s stance on the vaccination of staff for COVID-19.
Paul McGlynn of PJM said as the infection rates started to drop in early March, PJM decided to end the sequestration of its control room operators at the end of the month.
The RTO began sequestration of critical staff in early December as case numbers were increasing, McGlynn said, rotating staff in and out of sequestration monthly.
Control room staff continue to be split between two locations and are practicing social distancing protocols and enhanced cleaning processes, McGlynn said. A third emergency control room set up at the beginning of the pandemic continues to be available if necessary and can be converted to real-time operations from its current training purposes within a few hours.
“Today we’re currently in our normal configuration, operating out of the two main control rooms,” McGlynn said. “Hopefully we’re done with sequestering staff at this stage of the game.”
As far as vaccinations, McGlynn said, access to shots is “improving” while the demand remains high. He said most PJM staff are eligible to be vaccinated.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), asked what importance PJM is placing on staff receiving the vaccine and the impact on reopening the RTO’s campus. Poulos also asked if the vaccine will be mandatory.
McGlynn said that while PJM took early steps to ensure availability of the vaccine to essential staff, it not requiring employees to receive the vaccine.
Paul Sotkiewicz of E-Cubed Policy Associates said he was “concerned” by PJM’s stance of not mandating vaccination and asked whether that could create a potential health and safety problem.
McGlynn said PJM has taken the position that it cannot require employees to be vaccinated. As long as protocols remain in place, including social distancing, the RTO will be able to manage the situation safely, he said.
“There’s a lot of reasons why people choose to be vaccinated, and there’s a lot of reasons why people choose not to be vaccinated,” McGlynn said.
Sotkiewicz said universities in the Northeast are requiring students to receive a vaccine to come back to campuses in the fall. He said because of PJM’s importance in the reliability of maintaining the grid, it would be “perfectly reasonable” to require vaccines for at least essential staff.
“I’m concerned this is setting us up for potential problems down the road,” Sotkiewicz said.
Rebecca Carroll of PJM reviewed the 2020-21 winter operations summary, including the impacts on the RTO from the unprecedented energy emergencies in ERCOT, SPP and MISO in February.
Temperatures in most of the PJM footprint were average or slightly above normal during the winter, while the RTO’s western zones were below average, Carroll said.
Four cold weather alerts were issued during the season, all in February. The alerts occurred primarily in PJM’s western zones, and only two coincided with the mid-month cold snap that gripped much of the middle of the country.
| NOAA/NCEI
During Washington’s Birthday week, the Midwest faced temperatures that dipped as much as 28 degrees below normal lows, while most of PJM’s footprint was spared the extreme cold, experiencing lows much closer to normal.
Top 10 interchange hours — Winter 2020/21 | PJM
Carroll said PJM’s real-time LMPs averaged $29.79/MWh, much lower than previous winters that experienced significant weather-related events, including the 2014 polar vortex ($72.50/MWh) and the January 2018 cold snap ($46.66/MWh). Last winter LMPs hit an all-time low of $21.31/MWh as PJM experienced mild temperatures for most of the season.
Carroll said the “magnitude of exports” constituted the biggest story for PJM during the emergency, with the RTO exporting about 16,000 MW on average compared with the more typical 5,000 MW.
| PJM
During the top-10 peak hours, interchange activity was more than three times above the 2020/21 winter average with PJM exporting more than five times as many megawatts as it was importing, she said. Exports during the cold snap were 2.5 times higher than the 2020/21 winter average, with 68% going to MISO, she said. The 1.6 TWh of exports during the event accounted for 10% off PJM’s entire winter exports.
Carroll called the export numbers “remarkable.”
Manual 03 First Read
Lagy Mathew of PJM provided a first read of changes to Manual 03: Transmission Operations, which are part of a periodic review. Mathew said substantial changes were proposed for the manual, including the addition of Attachment G: Transmission Outage Ticket Best Practices.
Section 3.4.2 and 3.5.4 regarding the nuclear plant interface requirement (NPIR) language changes for eDART nuclear voltage limits also saw significant changes, Mathew said, and PJM received feedback from stakeholders who said they were not ready to implement the changes in their operations.
Mathew said the updated language was not available at the OC meeting because it was still being reviewed by staff. He said PJM plans to bring the updated manual language for a first read at the April Markets and Reliability Committee meeting.
Sharon Midgley of Exelon said she was “not comfortable” with PJM considering the presentation a first read without making the language available for review by stakeholders. Midgley said Exelon is still working on potential implementation of the NPIR language changes and wants to review the language to determine the exact impacts.
PJM delayed a vote on a proposal for changes to the pro forma interconnection construction service agreement (ICSA) after stakeholders at last week’s Planning Committee meeting asked the RTO to take more time and use clearer language.
Mark Sims, PJM manager of infrastructure coordination, reviewed the proposed problem statement, issue charge and tariff revisions addressing the RTO’s concerns associated with the ICSA’s lack of language on supersedure and its current automatic termination provision. Sims presented the issue in March at the PC meeting and later brought it to the Markets and Reliability Committee for a first read. (See “Interconnection Construction Service Agreement,” PJM MRC/MC Briefs: March 29, 2021.)
Sims said the growing interconnection queue volume has created the need for dealing with the issue. PJM wants to “remain focused on efficiency,” Sims said, and have identified improvements in two areas of tariff Attachment P that deal with ICSAs.
Number of new PJM service requests in the most recent new services queue windows | PJM
Section 1 does not contain pro forma language that considers when an ICSA supersedes an already effective agreement, Sims said, causing “increased administrative burden” for PJM.
The tariff provides for automatic termination of an ICSA upon the occurrence of certain conditions, he said, which can occur without PJM’s knowledge. The conditions include completion of construction of all interconnection facilities, a transfer of title, final payment of all costs or delivery of final as-built drawings to the transmission owner. Sims said PJM wants TOs to notify them when the conditions have been met.
PJM received little feedback regarding the supersedure language, Sims said, but stakeholders had several comments regarding the termination provision. Sims said PJM is “revisiting” the tariff language and have engaged in several conversations with stakeholders.
“Our goal is to make it as unburdensome as possible, quick and easy, straightforward and accomplish a solution for the problem we’re trying to fix,” Sims said.
Pulin Shah, director of transmission strategy and contracts for Exelon, asked if there was an “urgent need” by PJM to make the changes. Shah said the language in the issue charge would benefit from another month to discuss its implementation and details, making stakeholders “more comfortable” with the proposed solution. “We need to fully understand what this is going to entail.”
Sims said PJM didn’t see an urgent need for endorsement and was open to a delay.
Carl Johnson of the PJM Public Power Coalition said he would like to see the RTO have more discussions with TOs and “accommodate” any concerns with the language. Johnson said TOs will ultimately be the stakeholders filing comments with FERC if they aren’t satisfied with the tariff language that’s endorsed, so it was important to address problems up front.
Alex Stern, director of RTO strategy for PSEG Services, had provided a friendly amendment to the proposed tariff language at the March MRC meeting. The amendment proposed that the notification obligation be “reciprocal” so that PJM would provide written notice to the interconnected TO and customer generator that the ICSA has been canceled with FERC.
PSEG has been working with PJM to come up with a compromise, Stern said, but they haven’t been able to reach an agreement. “If we can fix this by taking a little bit more time, that would make sense.”
CIR Issue Charge Endorsed
Stakeholders endorsed an issue charge aimed at addressing the capacity interconnection rights (CIRs) of variable resources. The measure passed with 99% support, as only one member voted “no” on the issue charge.
Jonathan Kern of PJM reviewed the problem statement and issue charge. Kern said the RTO made extensive revisions to both documents after receiving “significant stakeholder feedback” when the issue was first presented at the February PC meeting. (See “Capacity Interconnection Rights,” PJM PC/TEAC Briefs: Feb. 9, 2021.)
The RTO engaged in one-on-one discussions with several different stakeholders, who said several items in the key work activities of the issue charge were out of scope and recommended further modifications, Kern said.
Changes include making the effective load-carrying capability (ELCC) analysis, other than those required to incorporate CIRs as inputs to the ELCC calculations, as an out-of-scope item. Kern said the primary reason for the change was to clarify that the bulk of the ELCC analysis will be out of scope in discussions and to specify which portions of the analysis will be in scope.
A second change was making alterations to how PJM conducts its market and operation functions out of scope in the issue charge. Kern said direct inputs that are provided by and processes that are overseen by System Planning to support the market and operation functions will be considered in scope.
PJM also removed items related to winter CIRs and energy and capacity market considerations.
Kern said PJM will now hold a series of monthly discussions with the PC to develop and propose changes to the applicable manuals and governing documents by the end of the year. He said PJM will hold educational sessions and discuss and develop proposals from April to October and present a proposal to the MRC in November.
Interconnection Process Reform Endorsed
Members unanimously endorsed PJM’s proposal to address challenges caused by the increasing interconnection queue volume.
Connell said the interconnection queue volume has more than tripled over the past three years, with PJM going from accepting around 400 projects per year to more than 1,000 in 2020 and even more slated for 2021.
The on-time rates of feasibility and system impact studies have continually improved, Connell said, but the backlog of requests has increased, causing concern for PJM and its stakeholders as the RTO has had to divert resources to finish studies by deadlines.
PJM proposed several key work activities in the issue charge, including interconnection studies, cost responsibility, interim operation and agreements, requirements for new service requests and other opportunities that can “positively impact” the current and future interconnection queue backlog.
Stakeholders suggested a clearer delineation of the “cost responsibility” key work activity at last month’s PC meeting, Connell said, describing it instead as “cost concerns” and splitting discussions between project cost estimates and the cost responsibility for network upgrades.
Ken Foladare, Tangibl | Tangibl
A suggestion of incorporating a target date for having the issue completed was also added to the issue charge. Connell said PJM would like to have the issue finalized by the end of 2021 and have a FERC filing by January 2022.
Ken Foladare of Tangibl said he would “strongly” recommend against having a set deadline and timeline to complete the issue. Foladare said FERC has not given PJM a deadline, so it shouldn’t arbitrarily be rushed.
The interconnection process needs to be examined carefully, Foladare said.
“This is going to affect way too many things,” Foladare said, “and at the end of the day, there’s a lot of dollars involved as well.”
Connell said the concept of having a target date was to give PJM and stakeholders a goal to work toward but that it is not firm. He said PJM is still deciding whether to use a task force for reporting to the PC or scheduling special sessions of the PC to deal with the interconnection issue.
“We are not going to compromise a good process for a time limit,” Connell said.
New Service Reviewed Again
Connell also provided a second first read of the problem statement and issue charge and reviewed draft tariff language outlining the RTO’s proposed “quick fix” to extend its deadline for responding to new service requests. PJM received several comments from stakeholders at the March PC meeting and worked to address issues, Connell said. (See “New Service Requests,” PJM PC/TEAC Briefs: March 9, 2021.)
“We think we’ve arrived at a good solution to be agreeable to all folks,” Connell said.
PJM processes new service requests under several parts of the tariff, Connell said, with the RTO administering two new queue windows each year: one from April 1 to Sept. 30, and another from Oct. 1 to March 31.
Connell said the tariff currently establishes “tight time frames” requiring PJM to review a new service request and issue a notice of any deficiencies within five business days. In turn, he said, interconnection customers are required to respond to a deficiency notice within 10 business days, and PJM is provided an additional five business days to review the response to the deficiency notice.
PJM typically receives 50% or more of the total number of new service requests during the last month of a queue window, Connell said, with most of the requests submitted during the last week or on the last day of the window. He said the short window impacts the ability of PJM employees to perform reviews on time, leading the RTO to seek waivers from FERC to extend the deadline.
In the queue window that ended in September, Connell said, 340 of the 563 new service requests were filed in the last week, including 247 on the last day. Connell said the latest queue window that ended March 31 will have about 700 new service requests.
PJM’s proposed solution is to change the five-day deadline to 15, Connell said, or to “use reasonable efforts to do so as soon thereafter as practicable.”
Stakeholder feedback from the March PC meeting included moving up the closing of the new service queue by about three weeks to allow more review time of the applications by PJM. Impacted stakeholders indicated the new deadline would not affect the model build cycle and analysis of TOs.
Connell said the proposed solution would also provide PJM 15 business days to review the interconnection customer’s response to the deficiency notice.
Stern said he appreciated PJM incorporating stakeholder feedback into the issue charge. He said the previous proposal could have created more backups.
“This revised approach seems like a win-win-win,” Stern said. “It’s probably a win for the queue applicants, those with queue study responsibilities and for PJM.”
PJM will seek endorsement at the May PC meeting.
Transmission Expansion Advisory Committee
Offshore Transmission Study Update
Matthew Bernstein, state policy solutions analyst for PJM, provided an update on the offshore transmission scenario study during last week’s Transmission Expansion Advisory Committee meeting. Bernstein first updated the committee of the work being done to analyze the regional transmission solutions to accommodate state offshore wind goals. (See PJM States Exploring 6 Scenarios in OSW Tx Study.)
PJM was originally looking at six different scenarios for analysis, Bernstein said, but settled on five during the final analysis process.
Scenario 1 is being called a “short-term scenario,” Bernstein said, with a timeline extending to 2027 and includes an OSW injection set of 9,020 MW at various locations on the system. It also includes modeling that factors in generator deactivations and state policy goals through 2027.
Scenarios 2 to 5 have a timeline extending to 2035, Bernstein said, and include injection ranges between 17,620 and 19,620 MW. The four scenarios also include increased locational variability in the injection points.
PJM generation deactivation map | PJM
Bernstein said the injections for the scenarios are “slightly higher” than the currently announced state policies for OSW generation. He said the study will allow PJM to model what the system can handle in addition to what has already been announced.
Based on the initial study findings and feedback from states, Bernstein said, PJM may study up to five additional scenarios. He said the RTO will present results of the scenario studies when they’re completed, which is anticipated in the second half of 2021.
Martins Creek Power Plant in Northampton County, Pa. | Talen Energy
Generation Deactivation Notification
Phil Yum, of PJM’s system planning modeling and support department, provided an update on recent generation deactivation notifications, including a request to deactivate the Martins Creek Power Plant Unit 4, a 17.3-MW oil and gas generation unit on the Delaware River in Northampton County, Pa., in the PPL transmission zone. The deactivation is scheduled to take place by May 31, 2022.
Yum said both PJM and PPL did not identify any reliability impacts or violations from the deactivation of the unit, which Talen Energy owns.
