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October 30, 2024

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NJ BPU Backs Utility Benchmarking for 30,000 Buildings

The New Jersey Board of Public Utilities (BPU) approved a new benchmarking program Wednesday that will require 30,000 apartment, commercial and other buildings of more than 25,000 square feet to annually report their water, gas and electricity use in an effort to stimulate conservation and cut energy use.

Approving the initiative in a 5-0 vote, the board said the program is designed to be minimally intrusive for building owners and is necessary as the state shoots for a goal of 100% clean energy use by 2050 as set out by Gov. Phil Murphy. The benchmarking plan was recommended in Murphy’s 2019 Energy Master Plan, and the initial plan triggered a variety of stakeholder concerns, which included the need to protect customer data privacy and the potential burden for building owners and utilities of complying with the program.

Joseph L Fiordaliso (NJ BPU) Content.jpgBPU President Joseph L. Fiordaliso | NJ BPU

Benchmarking “enables commercial building owners and operators to measure and analyze their facilities’ energy (all sources and fuels) and water use and compare performance to that of similar buildings,” the board order approving the program said. “Owners and operators can then assess opportunities for performance improvements that reduce their buildings’ energy use and costs.”

Speaking before the vote, BPU President Joseph Fiordaliso said the goal of the program is to “save and conserve.”

“It was intended to help promote our energy efficiency and to conserve water and operating costs,” he said. “And by doing that, the cheapest energy is the energy we don’t use. The cheapest water is the water we don’t use.”

The implementation of the benchmarking initiative comes as the BPU considers another program designed to gather energy data in the hope that energy users will use it to reduce consumption and cut costs. A straw proposal under consideration by the board sets out rules for the use of advanced meters infrastructure, involving so-called smart meters that automatically collect and transmit electricity use data, providing customers with a real-time assessment of their energy use. (See NJ Eyes Rules to Protect, Gather Advanced Metering Data.)

Which buildings to benchmark?

Under the benchmarking program, aggregated data for the buildings covered by the program — which includes commercial buildings, apartment properties housing more than five families and public buildings — will be provided to the property owner by utilities.  The list of buildings covered by the program will be drawn from the state tax assessment database.

To provide some anonymity to customers, buildings that have four or more tenants or have no single tenant that uses more than 50% of the energy will be able to collect energy use for the whole building and divide it among the tenants. The system, known as the “4/50 rule,” avoids the need to attribute private energy use information to a specific tenant. If a building has fewer than four tenants, or one tenant uses more than 50% of the energy in the building, the building owner must ask each tenant to consent to give the owner the water and energy data.

To help building owners and managers complete the benchmarking requirements, the BPU will develop a Certified Benchmarker program, creating a pool of experts for hire available to help, and also an informational benchmarking website. In addition, the board will create a customer help desk to “support outreach, manage communications with, process requests for exemptions, and perform services as needed for building owners.”

Dianne Solomon (NJ BPU) Content.jpgBPU Commissioner Dianne Solomon | NJ BPU

The deadline by which the first round of benchmarking data must be delivered is Oct. 1, 2023, with a July 1 submission deadline in the succeeding year.

Commissioner Dianne Solomon said that she hoped the program would not unnecessarily burden businesses.

“We don’t want this to be punitive,” she said. “This should be a help, not something that the data and the information should be used in a manner which is punitive on these businesses and individuals. They have a lot of other things to be concerned about in keeping a business operating these days. We don’t want to be one more hurdle that they need to overcome.”

Philip Chao, the BPU officer who presented the plan, said he believed the annual benchmarking process would only take four or five hours per building. The BPU order for the program said the state was not required by law to benchmark its own buildings but opted to include them to “lead by example in benchmarking its buildings in the same manner that commercial building owners do.”

Program rules allow utilities to recover “reasonable and prudent costs” incurred implementing the benchmarking requirements, including “establishing, operating, and maintaining data aggregation and data access services, for the board to evaluate in future base rate case proceedings.”

Stakeholder Concern

More than a dozen stakeholders offered comments on the proposal at a Jan. 6 public hearing and in writing. Commenters included the New Jersey Division of Rate Counsel, the New Jersey Builders Association, utilities such as PSE&G and Rockland Electric Company, and the Natural Resources Defense Council (NRDC).

The question of which buildings should be covered by the program stoked a variety of suggestions and concerns that limiting the buildings covered would be detrimental to program goals.   

In a Jan. 20 letter to the board, NRDC said the exclusion of multifamily dwellings and apartments, public school property, and government buildings would “undermine the achievement of New Jersey’s ambitious decarbonization goals.”

“Effective building energy benchmarking has been shown to be a critical first-step tool to increase building energy efficiency and decarbonization,” the letter said, adding that it “is especially important in New Jersey, where buildings are the second largest source of climate pollutants after vehicles.”

In response, the BPU broadened the buildings covered to include multi-family dwelling and apartments and public buildings. Explaining the decision to include multi-family properties, the BPU said owners are typically “commercial enterprises” and are large users of energy “with tremendous potential to save energy and water and reduce waste of such resources.”

In addition, their inclusion would stimulate energy conservation measures and provide the benefits of “reduced energy bills and energy burdens, reduced greenhouse emissions, improved indoor air quality” and general health benefits that would help renters, including low- and moderate-income residents and those in affordable housing.

South Jersey Industries and the New Jersey Utilities Association (NJUA) expressed concerns about protecting customer data privacy and noted that New Jersey law requires customers to give their consent before a utility can release data to a third party.

“The Utilities are concerned that the release of customer information to third-parties may be violative of customer privacy rules,” the NJUA wrote in a Jan. 20 letter to the board. New Jersey allows a utility to release “individual proprietary information” only when it will be used only for the “provision of continued electric generation service, electric related service, gas supply service or gas related service to that customer,” which does not appear to include a benchmarking program, the letter said.

PSE&G, in a Jan. 20 letter, said it also has “significant concerns,” about the program’s handling of customer data, “in particular upon what basis and to whom specifically the requested customer information can be provided without consent.” The utility, along with other stakeholders, expressed a separate concern that the BPU’s straw proposal suggested enforcing participation in the benchmarking program by saying participation is a “prerequisite” for participation in any other BPU programs, such as energy efficiency (EE) programs.

PSE&G said such an approach could create “an undue burden on the EE programs [that] unfairly punishes building owners, tenants, and utilities for issues that may be beyond their control.”

In response, the BPU dropped the requirement that benchmarking be a prerequisite for involvement in other programs. The concerns about data privacy prompted the BPU to require that utilities provide building owners with “aggregated building level data” to ensure customer anonymity and also to craft the “4/50 rule.”

The BPU staff “recognizes that data aggregation is necessary to ensure the anonymization of individual tenant consumption data,” the order approving the program said.

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NY Funds Long-duration Energy Storage Projects

New York on Thursday announced $16.6 million in funding for long-duration energy storage projects that tie into renewable energy and said it is accepting proposals for $17 million in additional grants for similar projects.

The $16.6 million is divided among five recipients, but most of it will go to Constellation’s Nine Mile Point Nuclear Station on the shore of Lake Ontario, north of Syracuse. The plant will receive $12.5 million to demonstrate nuclear-hydrogen fueled peak power generation paired with a long-duration hydrogen energy storage unit.

The other recipients are:

  • Borrego Solar Systems, $2.7 million to develop, design and construct two standalone energy storage systems and perform field demonstrations of a six-hour zinc hybrid cathode energy storage system in New York City to help demonstrate that zinc hybrid technology is economically competitive with lithium-ion.
  • JC Solutions, dba RCAM Technologies, $1.2 million to develop a 3D concrete printed marine pumped hydroelectric storage system that integrates directly with offshore wind development in support of grid resilience and reduced reliance on fossil fuel plants to meet periods of peak electric demand.
  • Power to Hydrogen, $100,000 to develop a reversible fuel cell system for hydrogen production and energy and to help facilitate the system’s readiness for demonstration and commercial adoption.
  • ROCCERA, $100,000 to evaluate and demonstrate a novel commercially viable solid oxide electrolyzer cell prototype for clean hydrogen production together with a corresponding scalable, more efficient manufacturing process.

Nine Mile Point is a two-reactor facility that can produce up to 1.907 GW of power. In 2021, it received a U.S. Dept. of Energy grant toward demonstration of integrated production, storage and usage on site.

That project, in partnership with Nel Hydrogen, Argonne National Laboratory, Idaho National Laboratory and the National Renewable Energy Laboratory, set out to generate an economical supply of hydrogen for potential use in the marketplace as a carbon-free fuel.

Hydrogen is a natural byproduct of nuclear energy, and a hydrogen storage system was already in place on site. A proton exchange membrane electrolyzer was installed as part of the project.

Gov. Kathy Hochul announced the $16.6 million in funding Thursday at the 2022 Advanced Energy Conference in New York City. She also announced $17 million in competitive funding available for projects that advance development and demonstration of scalable technologies for long-duration energy storage — at least 10 hours’ duration at rated power.

Proposals will be accepted through Oct. 17 and must include only technologies that have not yet been commercialized.

Submissions should advance, develop or field-test hydrogen, electric, chemical, mechanical or thermal-electric storage technologies that will address cost, performance, siting and renewable integration challenges, such as grid congestion, hosting capacity constraints and lithium-ion siting in New York City.

The two pools of grant money come from the Renewable Optimization and Energy Storage Innovation Program administered by the New York State Energy Research and Development Authority.

To date, the program has boosted 356 projects with more than $225 million in funding, resulting in $956 million in additional investments and 46 commercialized products, the Hochul administration said.

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NYISO Offshore Wind Profiles to Plot Development Potential

NYISO this week shared an update on a consultant’s effort to model 20-year offshore wind power profiles that will assess the potential outcomes for greater wind farm development along the Northeast coast.

DNV’s renewable profile modeling will produce three hourly OSW power profiles based on data from 2000 through 2021 for three areas. The designated areas include New York Harbor, Long Island shore and Long Island East End, though they are dozens of miles off those respective shorelines in some cases. These areas will be further broken out into seven zones that represent the potential development areas for future offshore wind projects.

NYISO engaged DNV to conduct the simulated profile study after the National Renewable Energy Laboratory released its updated 20-year wind dataset that included meteorological data but did not include relevant power profiles for those wind farm zones.

The profiles will be built from mesoscale weathering modeling, high-resolution hourly wind mapping, averaged wind farm turbine constructs, NASA’s MERRA-2 global modeling program, and other critical inputs or assumptions that ensure complete buildouts for each development area.

DNV will also use its “WindFarmer” program to create wind turbine power curves that simulate energy production based on the distribution of wind speed and direction, while still accounting for potential losses, such as wake interactions, shutdown history, density variations and extreme weather event disruptions.

The update came during NYISO’s Sept. 7 Installed Capacity Working Group meeting. NYISO is expecting DNV’s final offshore wind power profile presentation early in the fourth quarter of 2022 and plans to make those hourly wind profiles available to the public soon afterward.

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DOE Roadmap Tackles Tough Industrial Carbon Emissions

The U.S. steel industry can cut its carbon emissions almost to zero by 2050 while increasing production by 12%, according to a new Industrial Decarbonization Roadmap the Department of Energy rolled out Wednesday.

Energy efficiency and a switch to low- and no-carbon fuels will drive about two-thirds of those emission reductions, the roadmap says.

While acknowledging the difficulties involved in decarbonizing U.S. heavy industry, such as iron and steel, Energy Secretary Jennifer Granholm said, “The roadmap lays out how the different players in the industrial sector can develop tailored approaches to decarbonization. It’s bold; it’s comprehensive. It takes the long view to 2050, and it details the need to get existing technologies to scale and to continue to invest in applied research and development for next-generation technologies.”

Granholm, along with outgoing National Climate Advisor Gina McCarthy, was speaking at a rollout event for the roadmap, with a panel of industrial sector representatives, including trade, labor, nonprofit and environmental justice leaders. U.S. industry accounted for about 30% of the nation’s carbon dioxide emissions in 2020, according to DOE, and decarbonizing the sector is central to U.S. economic growth and competitiveness, and the achievement of the President Joe Biden’s climate targets, Granholm said.

The president has set ambitious goals for decarbonizing the U.S. electric grid by 2035 and achieving a net-zero economy by 2050, now backed by billions of federal dollars from the Infrastructure Investment and Jobs Act and the recently passed Inflation Reduction Act.

DOE NetZero Roadmap (DOE) Content.jpgThe DOE roadmap lays out pathways to net-zero industrial CO2 emissions for key U.S. sectors: iron and steel, cement, food and beverage, chemicals and petroleum refining. | DOE

“The facts are, we can’t live without the industrial sector, and yet we can’t live with the climate impacts and the pollution impacts, the carbon pollution in particular, that the sector produces,” Granholm said.

“We also know that those externalities affect disproportionately communities of color, poor communities, disadvantaged communities, Black communities, Latino [and] Native American communities, and we have to be honest about that.”

Compiled with input from more than 300 federal, industry and community stakeholders, the roadmap focuses on the five most carbon-intensive manufacturing sectors in the U.S. — iron and steel, chemicals, cement, food and beverage production and petroleum refining. Decarbonization strategies are broken down into four “pillars:” energy efficiency, industrial electrification and low-carbon fuels, carbon capture, utilization and storage (CCUS), and “alternate approaches,” such as direct air capture and reforestation.

The roadmap sees the alternate approaches providing the final 13% of emission reductions needed to get the U.S. to a net-zero economy by 2050. Together, the other three pillars will provide the other 87% of reductions, beginning from a 2015 baseline of 450 million metric tons of industrial CO2 emissions per year.

Granholm pointed to the “cross-cutting” impacts of the different pillars and sectors. For example, carbon capture will be critical for decarbonization of cement making, according to the roadmap. About 65% of the emissions reductions needed to get the sector to near net-zero by 2050 will come from CCUS, the road map says.

But those emission reductions will also help drive a 46% increase in cement production, the report says.

‘Liposuction Solution’

Echoing Granholm, McCarthy — who will be leaving her post on Sept. 16 — emphasized the importance of ensuring the new federal funding and “the work that we’re doing here [are] relevant to people. We have to make sure that we’re improving the lives of real human beings in a way that they can see. We have real resources; we need to show people how we’re going to make it work for them.”

Anna Fendley, director of regulatory and state policy for the United Steelworkers, said the federal government has a key role to play as a “convener, driving collaboration among industry, labor [and] management, because we need to catch the low-hanging fruit, but we also need to do the really big things that are going to be hard but transformational, and invest in jobs in the long-term.”

Robbie Orvis, senior director for modeling and analysis for industry consultants Energy Innovation, said one way to promote worker buy-in is by highlighting that “decarbonizing industry … actually can save industry money and make our goods cheaper, and free up money to pay workers more.”

He also pointed to incentives for reshoring or onshoring industry, such as the production tax credits in the IRA, which will “make sure that as U.S. industries decarbonize, [their] goods are remaining competitive with other countries, particularly those that may not be decarbonizing as quickly.”

Beverly L. Wright, executive director of the New Orleans-based Deep South Center for Environmental Justice, called for equity and justice in planning for industrial decarbonization, which, she said, must start with “the use of science to produce sound technology and industrial development that reduces carbon emissions.”

New technologies must also be carefully evaluated to ensure they do “not harm the environment or communities in ways that exacerbate existing disparities and environmental pollution and health risks in environmental justice and climate-impacted communities,” Wright said.

She was particularly skeptical of carbon capture, raising concerns that it would promote continued use of fossil fuels. It is a “liposuction solution,” Wright said — sucking out fat (or in this case, emissions) that would only come back without systemic changes.

Clean Steel

While voicing strong support for the roadmap and DOE’s outreach to a broad range of stakeholders, leaders from industry trade associations emphasized the advanced technologies they are already using to cut carbon emissions. For example, Philip K. Bell, president of the Steel Manufacturers Association, noted that about 70% of U.S. steel is now produced using electric arc furnaces, which are powered by electricity and have significantly lower carbon emissions than more traditional blast furnaces.

Both Bell and Kevin Dempsey, CEO of the American Iron and Steel Institute, pointed to a growing interest in renewable energy and hydrogen fuels across their industry.

“What’s going to be critical though is that the electricity that is used to power our electric arc furnaces is clean,” Dempsey said. “So, all of the efforts to further decarbonize and produce clean energy, including in particular the incentives that were part of the Inflation Reduction Act, we think are really critical. That’s been a major focus for many of our steel companies, to work with their electricity providers to get that clean energy so we can even further reduce the emissions we have.”

But to build on the funding and incentives in the IIJA and IRA, Rebecca Dell, senior director of the ClimateWorks Foundation, a San Francisco nonprofit, argued that “we need to be building strong institutions in our government in order to effectively implement these laws and make the transition that we have in front of us over decades.

“A startling fact is that there is not a single Senate-confirmed position in the entire federal government focused on the future of American manufacturing or the American-made industrial sector,” Dell said. Work on these issues has been fragmented across different agencies, including DOE, the Commerce Department and the Environmental Protection Agency, she said.

“What we need to be doing is pulling them out and elevating them and strengthening the institutions … that can actually do this work over the long term.”

Other key recommendations in the roadmap include:

  • Investing in multiple low-carbon technologies. Such investments must be “concurrently pursued to ensure viable pathways for industrial decarbonization.”
  • Accelerating deployment of decarbonization technologies through testbeds and demonstration projects “to catalyze and de-risk private sector investments. Low-capital approaches that maximize energy, material, and systems efficiency should be pursued.”
  • Integrating technology into systems and supply chains. “Research will be needed to anticipate the changes in supply and value chains that will result from the transition to a low-carbon economy.”
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ERO Supports FERC Weather Assessment Proposal

With the 2022 hurricane season in progress and the winter months approaching, NERC and the regional entities signaled their support last week for FERC’s proposal requiring transmission providers to outline plans for assessing the vulnerability of their systems to extreme weather and mitigate any identified risks (RM22-16, AD21-13).

FERC introduced its proposal in June as one of two Notices of Proposed Rulemaking inspired by a technical conference the commission held last year on the impact of climate change and severe weather on the electric grid. (See FERC Approves Extreme Weather Assessment NOPRs.) Commission staff introducing the measure said it was intended to fill a gap in bulk power system awareness, created by the fact that conducting extreme weather vulnerability assessments is currently voluntary and not all BPS stakeholders do so.

The proposal would require transmission providers to submit a one-time assessment to FERC detailing how they:

  • establish the scope of their vulnerability assessments;
  • develop inputs;
  • identify vulnerabilities and determine exposure to extreme weather hazards;
  • estimate the cost of weather impacts; and
  • develop mitigation measures to address extreme weather risks.

The NOPR does not apply to utilities that already conduct their own assessments, and transmission providers that do not will only be required to do so once.

Assessments Offer Reliability Benefits

In their joint response filed last week in support of the NOPR, NERC and the REs reminded the commission that “extreme weather events, particularly extreme heat and cold conditions, have threatened the reliability of the electric grid multiple times over the past decade.” Moreover, the ERO noted that the grid is becoming “more vulnerable to the effects of extreme weather” as it transitions to weather-dependent sources of generation.

In addition to considering FERC’s own obligations under the Federal Power Act — as noted in the NOPR — NERC and the REs also suggested that the commission take the ERO’s needs into account in its final rulemaking, particularly in light of the potential benefits to NERC’s reliability standard projects and other reliability-related efforts.

“The ERO Enterprise … agrees that the proposed informational filings would increase transparency into current or planned entity planning practices and facilitate enhanced information sharing and coordination, the benefits of which may extend into enhanced system reliability,” the filing said. The authors requested that any information from utilities’ informational filings that the commission deems too sensitive to be released publicly be shared with the ERO on a confidential basis to help its mission of ensuring BPS reliability.

Industry Feedback More Nuanced

Feedback from other stakeholders was generally supportive, though the responses also contained further suggestions for refinements to the NOPR. For example, Xcel Energy questioned whether FERC’s proposed definition of extreme weather vulnerability assessments is needlessly specific and may rule out many potentially useful reviews.

“The current definition … may omit a significant number of evaluations that, while not couched in the language used in the definition, address specific aspects of the impacts of extreme weather on system operations,” Xcel said, noting that many utilities conduct “myriad types of studies” on current conditions and performance challenges and that, depending on a utility’s circumstances, these could touch on severe heat and cold conditions as a matter of course.

“Without clarifying what this means, exactly, the commission is likely to end up [with] a truncated view of the efforts undertaken to ensure the system can withstand an array of extreme weather events,” Xcel continued, asking that FERC be “very prescriptive in identifying the types of studies it is interested in [in order to] protect entities from inadvertently failing to report or under reporting and, conversely, avoid unnecessarily expanding the record with studies of little or no interest to the commission.”

The Edison Electric Institute also registered some misgivings about the commission’s proposal, despite expressing support for the idea of one-time extreme weather assessments. EEI praised FERC for not requiring assessments from entities that already do so, and for not mandating any changes to how utilities perform their assessments. It urged the commission’s final rulemaking to maintain the NOPR’s recognition that different stakeholders face a range of challenges, and to give utilities a high degree of flexibility in how they follow the requirements.

EEI’s doubts about the NOPR centered on the commission’s plans for the information in the one-time reports, noting that while FERC said the reports “will enhance the commission’s understanding” about transmission providers’ risk assessment, the proposal “does not detail how [FERC] plans to utilize the information included in the reports to accomplish these ends.” The institute said the reports “should serve as an informational tool” and “as the basis for further information sharing and coordination” among transmission providers.

Finally, EEI said FERC should allow utilities more time to prepare their reports than the 90 days following the publication of a final rule, as the NOPR proposed. The institute said in light of the time needed to gather the required information and to vet it for public release, FERC should allow at least 120 days for utilities to respond. Further, EEI said that FERC should not seek public comment on the informational reports as planned in the NOPR. The group called this idea “a departure from precedent” that would punish entities for complying.

“Informational reporting, including the one-time report proposed in the NOPR, is inappropriate for public comment because it threatens to turn good-faith and impartial information sharing into a de facto adversarial proceeding in which entities are compelled to defend themselves,” EEI said. “For this reason, the Commission should not move forward with its proposal to require a post-report public comment period.”

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Growing Pains Continue for Maryland Community Solar Pilot

Maryland’s community solar pilot program continues to face challenges as it seeks to scale up.

As of mid-June, subscriber organizations had applied for authorization to build 711.5 MW of solar generation. But five years into the seven-year pilot, the state has brought only 43 projects totaling 59 MW of capacity online, one-tenth of the 600 MW allowed.

The Maryland Public Service Commission (PSC) summarized the pilot’s status in a recent report to the state legislature, saying community solar has potential and deserves more resources despite its slow growth.

The problems are not unique to Maryland. About 40 states operated community solar programs as of the end of 2021, led by Florida at 1,636 MW, with all but nine states totaling less than 100 MW. In New Jersey, just 17 of 150 approved projects have been installed, with a combined capacity of 35.6 MW, or about 15% of the total capacity awarded. (See NJ Celebrates Completion of First Phase 2 Community Solar Project.) 

What accounts for the anemic actual capacity despite the intense interest?

“The pilot has attracted significant development interest and continues to grow in the number of projects and capacity, but the commission acknowledges that local solar policies and permitting processes have impacted [community solar] development,” PSC Communications Director Tori Leonard said. “Siting projects can be challenging due to local policies and a lack of additional financial mechanisms to build projects on preferred sites such as brownfields and rooftops.”

Subscriber organizations surveyed by the PSC said they were hampered by local zoning, supply chain problems, staffing issues related to the COVID-19 pandemic and challenges related to utility interconnections.

“While community solar has experienced strong growth in recent years, including in Maryland where installations have tripled since the start of 2020, land use obstacles remain the greatest barrier to further community solar deployment,” Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association, told NetZero Insider.

“There is well-organized opposition to solar development on agricultural land at the county level, which means the ability to site solar projects varies widely from jurisdiction to jurisdiction,” he explained. “Siting of ground-based projects is a significant limitation to program implementation, and the added cost and limited incentives for sites on parking lots, brownfields and commercial rooftops for community solar have limited their utilization.”

Potential Unfulfilled

About 97% percent of the energy in Maryland’s pilot has been subscribed to residential subscribers who have seen discounts of five to 10% below retail rates.

In addition to rate savings, the pilot projects could contribute to the renewable energy portfolio standard (RPS) capacity required for photovoltaic solar. Maryland currently has about 1,550 MW of solar, about a quarter of the 6,200 MW needed to meet its RPS requirements in 2030.

The PSC said community solar also can provide system benefits by deferring distribution capacity investments. “However, in order to realize these benefits, there must be some certainty that a DER [distributed energy resource] will be available and producing energy at the interconnected circuit’s peak in order for its capacity to be used in distribution planning,” it said.

The PSC said the muted response had made it difficult to draw conclusions on community solar’s costs and benefits.
“The limited number of operating projects hampers the ability to draw conclusions in areas such as energy market impacts, transmission benefits, impacts to the price of locational marginal pricing energy, and impacts to the standard offer service,” it said.

Projects in Operation

Among the companies trying to make the pilot a success is Summit Ridge Energy, which is developing 90 MWdc in Maryland, enough to power 12,500 homes and businesses. The company says it is the largest owner-operator of community solar assets in the U.S.

Denver-based TurningPoint Energy says it is the leading greenfield developer in the Maryland pilot and will have 40 MWdc of projects in operation in the state by the end of 2023.

On April 30, Summit Ridge and Cedar Ridge Community Church held a ribbon-cutting ceremony to celebrate the completion of a 2.5-MWdc community solar project in Montgomery County. The church signed a 25-year lease on eight acres of its 30-acre property with TurningPoint. At least 30% of the electricity generated by the project must go to low-and-moderate income (LMI) households, Franny Yuhas, director of development for the Mid-Atlantic region at TurningPoint, said in an interview.

On April 21, WeSolar and the University of Maryland Medical System announced a partnership to develop a solar farm in Baltimore City to provide power to the hospital’s facilities and city residents. Michael Schwartzberg, a spokesperson for UMMS, said in an email that the location for the project is yet to be determined.

“Our company’s mission is about equity,” WeSolar CEO Kristal Hansley said in a statement. “Our main goal is to reduce the bills of low-to-moderate-income customers by at least 25%.” WeSolar touts itself as “the nation’s first community solar provider headed by a Black woman CEO,” and says it helped with more than 100 MW in customer acquisition contracts in the Northeast.

The partnership calls for UMMS to pay $10,000 monthly for up to 18 months to help with construction of the solar farm, which is projected to generate 8 MW. UMMS has committed to purchasing up to half of the output. Once the farm is operating, UMMS employees who earn less than $67,000 will be able to buy solar energy for their residences from the BG&E grid at a discount of up to 25%.

Program Extended

Maryland’s community solar program started in 2017. It was originally supposed to run for three years, but in 2019 that was extended to seven years, and it is now set to run until 2024. (See Maryland PSC Seeks to Expand State’s Community Solar Pilot.)

The program could receive a boost from Maryland’s Climate Solutions Now Act of 2022, which provides tax exemptions for community solar projects. New projects are exempt from paying county or municipal property tax as long as they provide at least 50% of their electrical output to LMI customers at rates that are at least 20% lower than the rates charged by the local electric utility company, and are located on a rooftop, parking facility canopy or brownfield, said Susan Casey, a spokesperson for the Maryland Department of the Environment.

The PSC says that when the pilot ends, there should be “a full benefit-cost analysis … in a similar manner to other state programs, such as EmPOWER Maryland,” the state’s energy efficiency program. When the General Assembly is considering future legislation, the commission says, it should seek to maximize LMI consumers’ participation and benefits; coordinate potential projects with electric utilities; and pair projects with energy storage. Better coordination with utilities and the addition of storage could “increase both grid and market benefits,” the report says.

The PSC also says the legislature should investigate local planning and development requirements and seek more funding to lower ratepayers’ costs and locate projects in preferred locations like brownfields and rooftops.

The PSC submitted the report July 1 to the Senate Finance Committee and the House Economic Matters Committee, with public comments due by Aug. 22. The commission will now consider further steps, Leonard said. Linda Forsyth, chief of staff to Senate Finance Committee Chair Delores Kelley (D), said that the committee “won’t be holding any hearings or briefings regarding this issue in 2022.” With Kelley retiring at the end of her term in January 2023, further action will happen only after the Senate president replaces her, Forsyth said. C.T. Wilson, chair of the House Economic Matters Committee, did not respond to a request for comment.

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Texas Gov. Abbott Touts ERCOT’s Fall Resource Adequacy

ERCOT quietly dropped its latest seasonal assessment of resource adequacy on Tuesday, saying it has sufficient installed generating capacity to meet peak demand under normal system conditions this fall.

Had it not been for a press release from Gov. Greg Abbott’s office, the report might have gone unnoticed for days.

Abbott, a Republican who is seeking a third term, has been hammered by his Democratic opponent, Beto O’Rourke, over the ERCOT grid’s near collapse during the February 2021 winter storm and the slow pace of the market reforms.

With Abbott providing a heavy hand, the grid operator’s public communications have shriveled since the storm. ERCOT has not posted a public notice about the seasonal assessment (SARA) since May 2021. The media updates that accompanied the SARA were discontinued after the storm, although ERCOT’s interim CEO and its top regulator have twice appeared for short Q&A sessions.

But Abbott was quick to issue a release Tuesday and tweet an image of himself sitting at the same table with outgoing interim ERCOT CEO Brad Jones, incoming CEO Pablo Vegas, Public Utility Commission Chair Peter Lake and several others. Vegas will replace Jones on Oct. 1. (See ERCOT Names NiSource’s Vegas as New CEO.)

“Met with ERCOT and PUC to discuss the strong position of Texas’ electric grid heading into the fall season,” Abbott posted. “Our grid is stronger and more reliable because of bipartisan reforms we passed and began implementing last year.”

In the release linked from the tweet, Abbott said the state is continuing to monitor the grid’s reliability. It notes he discussed the grid operator’s updated planned outage scheduling process that “ensures Texas’ generational fleet has the necessary time to conduct maintenance operations.”

The shoulder season’s traditional maintenance period couldn’t come soon enough for thermal generators that have been running full bore this summer as part of ERCOT’s conservative operations posture. The grid operator has regularly kept more than 3 GW of operating reserves on the sidelines and dispatched older peaking units as reliability unit commitments.

Scott Bruns (Enverus) Content.jpgScott Bruns, Enverus | Enverus

Scott Bruns, director of markets for energy analytics firm Enverus, likened the situation to having a classic car in the garage.

“These units are typically older units that are not typically run or only run during the summertime when you need to support the system. And this summer, we ran these units much longer than previous years,” Bruns said during a webinar Wednesday on ERCOT’s summer performance. “I like to think of it as like your classic Camaro that you have for cruising. It runs well, but it has a limited number of miles left on that odometer and every time that you drive it, it’s more maintenance or repairs, and it just becomes more expensive.”

And not only expensive for the generation operators, but risky for the ERCOT system.

“So now, what we’re doing is we’re asking these Camaros to spend all the time in the driveway sitting there and idling, when you know that this is just increasing the risk on the system,” Bruns said. “We’re moving to this new future where more intermittent renewables are pulling onto the system and we’re asking all of these classic cars that are sitting out along the system to provide more of these baseload reliability services. And eventually, we’re going to have some issues.”

ERCOT staff does not appear to think that will be a problem. The fall SARA, covering October and November, indicates the system will have over 93 GW of resource capacity available during peak demand hours, more than enough to meet a projected high of 64.9 GW.

The grid operator expects to have 2.6 GW operational battery storage resources. However, they are not currently included in ERCOT’s capacity contribution for fall because they are not expected to provide sustained capacity for meeting system peak loads.

The report includes six risk scenarios that reflect alternative assumptions for peak demand, unplanned thermal outages and renewable output. One of the three elevated risk scenarios (low renewable output) and the most severe extreme risk scenario (high peak load, high unplanned thermal outages, extreme low wind output) would result in rotating outages.

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Clean Energy Groups Don’t Buy ISO-NE’s Gas Reliance

Environmental and clean energy advocates are pushing New England to get off the gas.

In a new white paper and at a press briefing, several regional and national environmental groups challenged the approach taken by grid operator ISO-NE as industry stakeholders head into a high-profile policy forum in Vermont this week.

The groups, which include the Sierra Club, Conservation Law Foundation, Acadia Center and others, say that New England needs to quickly pivot to clean energy, and avoid throwing “good money after bad” by investing more in fossil fuel infrastructure.

The document lays out several clean grid reliability solutions that can be pushed to the front in the short term, including expanding residential demand programs, ramping up commercial and industrial demand response, and boosting energy efficiency.

And it calls on the region to, in the long term, better utilize the existing fleet of renewables, deploy “stacked” battery storage, and make “smart expansions” to the region’s transmission system.

Amid increasingly frequent warnings about the reliability of the region’s grid in winter, New England has clean options, the groups conclude.

“New England’s leaders, with the support of federal agencies like FERC, should be accelerating efforts to deploy alternatives to gas generation that take advantage of the region’s abundant clean energy resources,” the white paper says.

The policy paper was a response to a recent statement put out by ISO-NE, in which the grid operator took a different view.

In its “problem statement” ahead of the FERC forum in Vermont, ISO-NE emphasized that even though the region is moving toward a decarbonized grid in the long-run, natural gas remains a vital generating fuel in the near term. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal)

“Without adequate gas, the region may not be able to meet the demand for home heating and electricity — and, when reliability suffers, the clean energy transition suffers,” the grid operator wrote.

Though all involved agree that New England is moving toward weaning itself off gas in the long run, the grid operator’s message rankled some of its most frequent critics in the environmental and clean energy sectors, who blame ISO-NE for the region’s current reliability travails.

“For years we’ve been presented by the ISO with programs and policies that did not solve any of the perceived winter reliability challenges,” said Phelps Turner, senior attorney at the Conservation Law Foundation, at a press briefing Tuesday.

“It’s our view that if we had spent that time working on the clean energy transition, rather than constant annual fear-mongering, we would be in a much better spot today,” Turner said.

It’s a recurring message from environmental advocates, who feel that ISO-NE has moved far too slowly in following the directives of the New England states to shift to clean energy.

In that vein, the problem statement followed a familiar pattern, said Melissa Birchard, director of clean energy and grid transition at the Acadia Center: It led with identifying clean energy for the region’s long-term needs but then switched to a focus on fossil fuels in the short-term.

“We need to get off this merry-go-round,” Birchard said. “We can’t keep going through this every year and having these incredible costs that consumers are experiencing.”

Managing expectations for Thursday 

The all-day forum scheduled by FERC for Thursday in Burlington, Vt., isn’t expected to produce consensus.

“They’re going to be discussing challenges and not solutions. What are the problems and how do we fix them?” said Mireille Bejjani, an organizer on the Fix the Grid campaign.

But getting a wide variety of speakers and guests in the same room could be a start to more productive conversations about how to move forward, said Caitlin Marquis, director of Advanced Energy Economy.

“We want to see a clear and transparent discussion about what the reliability risks are that we’re facing, specifically,” Marquis said. “What is the time frame of those risks? What are the grid’s needs that we need to be defining?”

In the natural gas sector, there are different hopes for the meeting.

A group of associations representing gas and oil generators and pipeline owners called on New England to build more pipelines and tweak market rules to give generators more certainty.

“We hope this forum will provide an avenue to discuss market design improvements and to develop sufficient natural gas infrastructure for power customers in addition to the manufacturers, businesses, and households that rely on natural gas to power their everyday needs,” the groups said in a statement.

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PJM Planning Committee Briefs: Sept. 6, 2022

Planning Committee Reviews Capital Budget 

The Planning Committee reviewed a $45 million capital budget proposal during its Tuesday meeting, a potential $3 million increase over current funding.

Nearly half of the suggested budget goes toward current applications and systems reliability, with $22 million allocated toward items such as dispatch tool enhancements, data analytics and cybersecurity. Spending on facilities and technology infrastructure would also increase to $12 million.

Less spending is being requested for application replacements and retrofits, which would reduce by a fifth down to $8 million, while new products and services as well as interregional coordination would remain static.

The spending plan will be reviewed by the Market Implementation Committee and Operating Committee this week and will be considered by the Finance Committee on Sept. 22 and 28. The Finance Committee will draft a recommendation letter to the PJM Board of Managers, which will consider approving the budget on Oct. 4.

Reserve Requirement Study Recommends Increasing FPR and IMR

The PC also received a presentation of the 2022 Reserve Requirement Study results, which recommends increasing both the forecast pool requirement (FPR) and installed reserve margin (IRM) compared to the 2021 study results. This year’s study results recommend an IRM of 14.9% for the 2023/24 delivery year, rather than the 14.8% favored in last year’s study for that year, and a FPR of 1.0930 next year, as opposed to 1.0901 recommended in the 2021 study.

The recommended IRM would fall to 14.8% in 2024/25 and continue down to 14.7% for the following two years. The FPR would decline to 1.0926 in 2024/25 and would sit at 1.0918 for the next two years.

FPR Waterfall Chart (PJM) Content.jpg2022 forecast pool requirement (FPR) waterfall chart | PJM

 

The study also proposed winter weekly reserve targets for the upcoming season, recommending 21% maximum monthly available reserves for December, 27% for January and 23% for February. The WWRT was set using RTO-aggregate outage data from the 2007/08 delivery year through last year.

The PC will take another look at the study in October, when it is scheduled to vote on the FPR, IRM and WWRT. From there, the Operating Committee is slated to vote on the WWRT in November, and the FPR and IRM are set to be voted on by the Markets and Reliability Committee and Members Committee in October through November. The PJM Board will consider final approval in December. The study’s assumptions were endorsed by the PC in June, and its load model selection was endorsed in August.

Tx Refunds Could Date Back to 2014

PJM could be required to refund transmission cost allocations dating to 2014 as a result of an appellate court ruling last month that remanded FERC decisions on two North Jersey transmission projects, PJM attorney Pauline Foley told stakeholders.

The D.C. Circuit Court of Appeals said FERC failed to explain why the solution-based distribution-factor analysis (DFAX) method should be used to assign the costs of two North Jersey transmission projects but not for a similar project in Artificial Island, partially supporting appeals by two merchant transmission operators. (See DC Circuit Faults FERC on Cost Allocation of NJ Transmission Projects.)

The case involves $1.3 billion in transmission upgrades authorized by PJM to address short-circuit problems between Public Service Electric and Gas’s Bergen and Linden switching stations and repairs to and around the utility’s Sewaren substation.

If FERC decides not to try to justify its distinction between the projects “we do not have a cost allocation to replace solution based DFAX for the Bergen-Linden and Sewaren projects,” said Foley, who noted the RTO has approved the allocations for the projects in late 2013 and early 2014. “Depending on what FERC determines, refunds could date back as far as 2014,” she said.

Annual Pre-qualification Window Opens for Competitive Planning Process

The annual one-month pre-qualification window for transmission developers seeking to submit projects under the competitive planning process has opened. Applications to qualify as designated entities can be submitted between Sept. 1 through Sept. 30 at ProposalWindow-Prequal@pjm.com.

To remain qualified, participants are required to confirm or update their pre-qualification information at least every three years. The Competitive Planner Tool now contains a new Pre-qualification Submission feature allowing form-based submissions and the ability to attach public or confidential versions of documents.

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Report Updates NY OSW Cable Routing Study

The New York State Energy Research and Development Authority last week issued an update on the potential challenges to routing transmission cables to the fleet of wind turbines planned off the New York coast.

NYSERDA has been working since August 2021 on the Offshore Wind Cable Corridor Constraints Assessment as part of the state’s drive to achieve a carbon-free power grid.

Five OSW projects totaling 4.5 GW are under development in New York; the state’s Climate Leadership and Community Protection Act mandates that 9 GW of OSW generation be in place by 2035.

The assessment is targeted for completion late this year. It seeks to:

  • document the environmental, technical and stakeholder constraints of potential undersea and overland cable corridors;
  • document the opportunities, concerns, impacts and risks of these corridors;
  • inform future policy actions to maximize benefits associated with the new OSW infrastructure;
  • minimize conflicts and impacts while following a timeline that reaches the 9-gigawatt goal by the 2035 deadline.

In its progress report submitted Sept. 1 to the New York Public Service Commission, NYSERDA said the Cable Working Group, which is performing the assessment, broke New York’s waters into four separate areas, each with different characteristics and potential constraints on installation, operation and maintenance of OSW cables.

Offshore, specific zones and subzones were identified with similar characteristics and constraints. On land, zone boundaries were drawn to optimize existing rights of way used for electric or gas transmission, elevated roadways and passenger rail lines in the densely constructed region.

In the South Shore Approach Area — the Atlantic Ocean south of Long Island — commercial fishing, including bottom trawling, recreational fishing and existing utilities (pipelines, telecommunications and transmission cables) present the most significant challenges to OSW cables, the assessment has determined.

In the Long Island Sound Approach Area — waters north and east of Long Island, from Block Island Sound to the East River — marine geology, commercial and recreational uses, aquatic resources and cultural concerns are flagged. There is, for example, a strong tidal currant, shallow zones, scour, boulder fields, a hard seabed, slopes greater than 10%, sensitive resources such as cold-water coral, shipwrecks and, in the westernmost end, anchorage areas.

In the New York Harbor Approach Area — the Upper and Lower harbors and the Hudson and East rivers — surface traffic is a major concern, with federally designated navigation channels and anchorage areas, heavy commercial shipping and passenger ferry traffic, narrowing waterways and the presence of pleasure craft.

In the Landfall and Overland Area — New York City and Long Island, and the places on both where undersea cables would make landfall and interconnect with the grid — the potential constraints are many and varied. Most prevalent is topography, as slopes exceeding 15% exist in all 25 zones designated on shore. There are potential environmental justice concerns in 23 of the 25 zones. Federal Highway Administration review and authorization would be required to site transmission lines along FHA-funded highways. Fish and wildlife habitats, public beaches, recreational fishing and eelgrass are other potential constraints.

The preferred approach would be to avoid negative impacts from all the potential constraints identified, but the assessment suggests steps to minimize or mitigate those impacts that cannot be avoided.

The assessment recommends that OSW cable routing incorporate accepted siting principles and industry experience but also notes that bringing 9 GW of power from the sea to land will require innovation in design, operation and maintenance that goes beyond standards set by previous projects and addresses the specific considerations for each site in New York.

NYSERDA issued a request for information Aug. 30, seeking feedback on whether the draft assessment accurately captures the most significant potential constraints and opportunities arising from the initiative. The comment period closes Oct. 14.