As it moves toward implementing the cybersecurity requirements added to its budget this year, the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) said Friday that it will seek public comment on the best approach to their execution.
CISA’s draft request for information — set to be published in the Federal Register on Monday — stems from the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA), part of the omnibus spending bill passed by Congress and signed by President Biden in March. The bill requires entities “in a critical infrastructure sector, as defined in Presidential Policy Directive 21” — which includes the energy sector — to report relevant cyber incidents to CISA within 72 hours after they occur, as well as when they make a ransom payment to the perpetrators of a ransomware attack. (See Budget Mandates Cyber Reporting for Critical Infrastructure.)
Authority for several key areas within the law is designated to CISA’s director, including defining which incidents are subject to reporting and which additional sectors, if any, are covered by the requirements. CISA must issue a Notice of Proposed Rulemaking within two years regarding the matters left to the director’s discretion, with a final rule to follow after another 18 months that will also specify what content entities must include in their cyber incident and ransom payment reports, as well as the data preservation requirements.
In a statement, CISA said comments received in response to the RFI “will inform the agency’s development of the proposed regulations.” Members of the critical infrastructure community, as well as the public, will have 60 days from the publication of the RFI to submit their feedback.
CISA’s suggested topics for respondents to address include:
definitions, criteria and scope of regulatory coverage, including the meaning of “covered entity”; the number of entities likely to be identified with that label; the meaning of “substantial cyber incident,” “ransom payment” and “ransomware attack”; and the number of ransom payments likely to be made every year;
report contents and submission procedures, such as what information should be required for inclusion in reports, the format of reports and when the deadline for reporting ransom payments begins;
other reporting requirements and vulnerability information sharing; and
additional policies, procedures and requirements.
In addition to written comments, stakeholders may participate in one of 11 public listening sessions, one in D.C. and in each of CISA’s 10 regions. The first listening session will take place Sept. 21 in Salt Lake City, and the last currently on the schedule is planned for Nov. 16 in Kansas City, Mo.; the date of the session in D.C. has not yet been determined.
In the agency’s statement, CISA Director Jen Easterly called the CIRCIA “a game changer for the whole cybersecurity community [that] will allow us to better understand the threats we are facing, to spot adversary campaigns earlier, and to take more coordinated action with our public and private sector partners in response.”
“We can’t defend what we don’t know about, and the information we receive will help us fill critical information gaps that will inform the guidance we share with the entire community, ultimately better defending the nation against cyber threats,” Easterly said. “We look forward to continuing to learn from the critical infrastructure community … to understand how we can implement the new cyber incident reporting legislation in the most effective way possible to protect the nation’s critical infrastructure.”
Nearly 10 years ago, FERC convened a gas-electric conference in Boston to talk about the issues facing New England’s electric grid in the winter.
Last week, the federal agency came to New England again. The room was bigger, and some of the terminology has changed. Energy technology has evolved and, in many cases, improved tremendously.
But the conversation was strikingly similar, according to New England Power Generators Association President Dan Dolan, who was in attendance for both.
“It’s shocking and terrifying how close the notes and talking points we had for that one could be reflected today,” Dolan told FERC commissioners on Thursday at a conference center in Burlington, Vt.
Even the more specific issues around LNG supply have been identified for years, Dolan said, with no tangible action to solve them in the long term.
Experts, analysts and lobbyists laid out the problem for FERC commissioners, who surely knew what it was before they walked into the room: a resource adequacy crisis fueled by New England’s unique geographic and political constraints, which ISO-NE fears will be exacerbated by the states’ push to replace fossil fuels with clean energy.
Largely acknowledged throughout the conversation was that it’s too late to do anything for this winter.
“‘Hope’ is not a strategy,” said Richard Paglia, vice president of U.S. marketing at Enbridge. Later, NERC CEO Jim Robb echoed him: “‘Luck’ is not a strategy.”
But that’s essentially what ISO-NE has accepted as its position for this year: hoping that, like last winter, the region is lucky enough to avoid the most extreme cold, which the grid operator says could lead to rolling blackouts.
An exchange between ISO-NE CEO Gordon van Welie and FERC Commissioner James Danly hinted at one possible move that the commission could make this year: initiating a Federal Power Act Section 206 proceeding to force some sort of action from the grid operator.
But van Welie urged the commissioners to be cautious about that option and only use it if it involves clear direction.
Tomorrow’s Problem
The long-term solution to the region’s challenges depends on who you ask.
The natural gas companies and their allies present at the meeting want to build more gas infrastructure — not necessarily new pipelines, but potential brownfield development, like changing out pipes for larger ones or adding compression, as Paglia suggested.
There was also substantial discussion about making sure that operation continues at the Everett LNG terminal, which ISO-NE highlighted in a recent problem statement, arguing that the facility is vital to the region’s energy security. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal.)
But others say the clean energy transition brings opportunities to maintain grid reliability in the same fell swoop as decarbonization. (See related story, Clean Energy Groups Don’t Buy ISO-NE’s Gas Reliance).
“We’re taking our eyes off the prize,” Liz Delaney, of solar and storage developer New Leaf Energy, told commissioners. “We need to resolve the near-term issue, and it’s complicated, but at the same time we need to focus on the market mechanisms that are going to get us through the energy transition.”
It’s not just long-duration storage that can help, she said.
“Short-duration battery storage does have a role to play in supporting winter reliability. It’s not the end-all and be-all. But we have miles to go in terms of being able to understand how to optimize battery storage,” Delaney said.
Vermont Department of Public Service Commissioner June Tierney also urged policymakers not to skate past demand response as a powerful grid management strategy.
She pointed to the recent energy emergency in California, which saw significant conservation efforts help CAISO avoid rolling blackouts during an unprecedented heat wave. (See related story, California Runs on Fumes but Avoids Blackouts.)
“Let’s not underestimate the people of the United States. Let’s not underestimate the people of New England,” Tierney said. “If they’re called upon, as millions of Californians were on their cell phones, to reduce demand immediately, they will respond.”
FERC Chairman Richard Glick called for a broader focus too, saying that he would like to see a focus on longer-term fixes like new generation, transmission buildout and energy efficiency.
“If we spend all our time thinking about how we’re going to keep the Everett LNG facility open … today will be a failure,” Glick said.
In the end, both the short-term LNG challenges and longer-term clean energy transition got plenty of air time at the forum. But there’s still significant anxiety in the energy sector and among its regulators about what will happen when the thermometers drop and stay low.
“If the lights go out, we’re all to blame. There’s not going to be any finger pointing because we’re all on the hook,” said Phil Bartlett, chairman of the Maine Public Utilities Commission.
NERC has begun planning for next year’s GridEx VII security exercise and is expecting a boost in attendance after participation in the distributed play portion declined for the first time last year.
Speaking at Thursday’s meeting of NERC’s Real Time Operating Subcommittee (RTOS), Laura Brown, director of engagement and security policy coordination at the Electricity Information Sharing and Analysis Center (E-ISAC), told attendees that planners are “looking for … additional support that industry can provide … the [reliability coordinators] in particular.”
The E-ISAC has developed, managed and delivered each iteration of GridEx since the first one held in 2011.
GridEx VI, held from Nov. 16-18, 2021, consisted of a distributed play the first two days involving more than 3,000 people across 293 organizations, and an executive tabletop featuring almost 200 participants from 88 organizations in the U.S. and Canada. (See NERC: GridEx Lessons Already In Use.)
The number of organizations taking part in the distributed play last year was the lowest recorded since GridEx II in 2013, while the 3,000 individuals participating represented fewer than half of GridEx V’s approximately 7,000. Brown said Thursday that the “dip in participation … was in part due to the pandemic as well as some changes that we made to registration requirements,” referring to the fact that unlike in previous years, participants in GridEx VI were only required to register with the E-ISAC to use the exercise tools or access planning materials.
NERC has previously indicated that the registration changes are likely to remain in place for future installments of the biennial exercise and that “future participation numbers are likely to be more comparable to those recorded for GridEx VI.” However, Brown emphasized that “we do expect to see some of those numbers go back up.” While she did not explain her statement at the time, she was likely referring to the relaxation of travel restrictions among many participating organizations.
E-ISAC Reviews Planning Phases
Accompanying Brown to the RTOS meeting was Jesse Sythe, who recently joined the E-ISAC as GridEx program manager. Sythe provided an overview of the GridEx VII planning process, which involves three distinct groups: sponsorship and management, exercise design and development, and exercise planning and execution.
The first group, sponsorship and management, comprises the executive sponsors — NERC CEO Jim Robb and E-ISAC CEO Manny Cancel — and the planning team, which includes Brown and Sythe. Responsibilities of the planning team, according to Sythe, include “gathering input from … other industry groups, developing exercise materials, training, webinars, exercise tools and then drafting the lessons learned report.”
Next is the exercise design and development group, which Sythe called “the bridge between the sponsorship and management lane and … the exercise participants.” The group is divided into a design team, a reliability coordinator team, a subject matter expert team and a training webinar team, and is meant to provide the planners with perspectives on the challenges utilities face every day.
“We don’t always have day-to-day insight into what utilities see in steady state or emergency situations, so the input that we receive from each team helps us to develop the exercise scenario, the materials and all the training webinars that are most beneficial to planners and players,” Sythe said.
The last group involved in the planning process is exercise planning and execution, which includes the lead planners and planners from each organization who adapt the exercise scenario created by the planning team to their particular circumstances. Players are also considered to be part of this lane because they are the ultimate users of the scenario.
The E-ISAC’s planning timeline for next year’s GridEx VII | NERC
Currently planners are in the initial phase of the project timeline, which Brown and Sythe shared at the meeting. This phase involves setting the goal, objectives and timeline of the exercise and developing an outreach plan, expected to last through the next few months. In the midterm planning phase the team will finalize the scenario and develop exercise materials, followed by the final planning phase when the final exercise materials are distributed and the planner training webinar series is completed. The two phases of the exercise will be conducted in November 2023, with the after-action phase to follow.
Carbon dioxide emissions by the 100 largest electric power producers in the U.S. increased 7% from 2020 to 2021, Ceres reported Wednesday in its annual benchmarking analysis.
The jump was attributed to the economy returning to a degree of normalcy in 2021 after COVID-related shutdowns triggered a 10% drop in CO2 emissions in 2020. But Ceres also said the increase highlights the need for power providers to take advantage of clean energy incentives recently put in place by the federal government through the Inflation Reduction Act.
The report added historical perspective that shows progress toward zero-carbon generation, even with the year-over-year increase factored in:
Carbon dioxide emissions were about 34% lower in 2021 than at their peak in 2007.
Sulfur dioxide emissions were down 94%, and nitrogen oxide emissions were down 88% in 2021 from 1990, when the federal Clean Air Act was strengthened.
Zero-carbon generation — renewables, hydropower and nuclear — accounted for 40% of U.S. power generation in 2021, an all-time high.
Power plants emitted 93% less mercury in 2021 than in 2000; federal limitations on mercury and other hazardous air emissions from coal-fired plants took effect in 2015.
The 100 largest U.S. electricity producers own 3,600 power plants that account fmore than 80% of total generation and plant emissions nationwide.
Natural gas remained the leading source of generation in the U.S. in 2021, at 38%, even as coal made a big year-over-year increase to 22%.
That is a reversal from a decade earlier: In 2011, coal accounted for 42% of U.S. power production and gas only 25%.
Nuclear accounted for 19% of power generation in 2021. Renewables accounted for 13%, breaking down to roughly two-thirds wind and one-third solar, with geothermal making a tiny contribution.
Hydropower was last, at 6% of U.S. power generation in 2021.
Ceres is a nonprofit focused on creating an equitable and sustainable future. Its annual benchmarking analysis of power plant emissions is a collaborative effort with Bank of America Charitable Foundation, Constellation Energy Corp. and Entergy, and the National Resources Defense Council.
ERM authored the analysis, which is drawn from generation and emissions data reported by the U.S. Energy Information Administration and Environmental Protection Agency.
“While the power sector has shown marked improvement over our two decades of analysis, we need to see an acceleration of larger emissions cuts across the industry in order to reach our 2030 emissions reduction goals,” Dan Bakal, senior program director of climate and energy at Ceres, said in a news release accompanying the report. “It’s important to recognize how far we have come, but impossible to ignore how far we still have to go to meet our critical 2030 goals set by the Paris Accord. While many of the largest power producers have announced climate commitments and strategies to reduce their carbon emissions, the rapid decarbonization required demands increased ambition.”
CAISO came dangerously close to calling for rolling blackouts Tuesday night but avoided issuing the final order to utilities thanks in part to a jarring alert sent out to millions of cell phones by the governor’s Office of Emergency Services.
A series of shrieking tones was followed by a text that said, “Conserve energy now to protect public health and safety. Extreme heat is straining the state energy grid. Power interruptions may occur unless you take action.”
The unusual alert was sent at 5:45 p.m. after CAISO declared an energy emergency alert 3. An EEA 3 means the ISO is “unable to meet minimum contingency reserve requirements and controlled power curtailments are imminent.”
CAISO CEO Elliot Mainzer summed up Tuesday’s near miss in a media briefing Wednesday, comparing it to a car running out of gas.
“We were well into the reserve tank of the car,” Mainzer said. “We were down to the last gallon there and dipping into our operating reserves. And we typically carry somewhere in the area of 3,000 to 4,000 MW of operating reserves, so we were very, very close to the bottom.”
Demand in CAISO hit a record high Tuesday of more than 52 GW as temperatures broke records across the state, including 116 degrees Fahrenheit in Sacramento, near CAISO’s headquarters.
CAISO saw record demand Tuesday of more than 52 GW. | CAISO
CAISO had ordered utilities to “arm” for load shed when a wave of consumer conservation following the cellphone alert narrowly averted blackouts. (A number of cities experienced outages because of a communications snafu with the Northern California Power Agency, CAISO said.)
Locational marginal prices throughout the state ranged between $1,700 and $2,300/MWh as the crisis continued, according to data posted on CAISO’s website.
The ISO called off the EEA 3 at 8 p.m., posting on Twitter: “Consumer conservation played a big part in protecting electric grid reliability. Thank you, California!”
The 3,500 MW of utility-scale 4-hour lithium-ion batteries installed since the state’s last rolling blackouts in August 2020 performed well and played a role in avoiding worse problems, Mainzer said.
Demand response from industrial users, and the ability to access emergency generation resources under an executive order from last year, played a part, as did more than 6,000 MW of imported hydroelectricity from the Pacific Northwest, CAISO said.
The crisis did not end Tuesday, however. The extraordinary heat wave gripping California is predicted to continue through Friday, with temperatures exceeding 100 F in greater Los Angeles, the San Francisco Bay Area and the inland Central Valley.
CAISO declared an EEA 2 on Wednesday afternoon, asking customers to turn up their thermostats and to postpone using large appliances such as clothes dryers and dishwashers.
Mainzer said the state would need consumers to continue conservation efforts, “hopefully for another reliable evening.”
VALLEY FORGE, Pa. — The price tag on Dominion Energy’s (NYSE:D) “Data Center Alley” transmission upgrades in Northern Virginia has grown by $24.6 million to $627.6 million.
Dominion told the Transmission Expansion Advisory Committee Sept. 6 it needed to increase the scope of the reliability project to clear capacity from two planned substations, including reconductoring seven 230-kV lines and upgrading terminal equipment. The new Wishing Star substation will be constructed near the existing Brambleton substation, while the Mars substation would be sited near Dulles Airport.
The reconducting of 11.4 miles of 230-kV lines totals about $29 million, and the terminal equipment is estimated at $12.65 million. Eliminating upgrades to the Brambleton substation and Loudoun breaker replacements will save $17 million.
According to the immediate needs statement presented by PJM Senior Manager Sami Abdulsalam, data centers in Dominion’s transmission zone in Northern Virginia have been experiencing “unprecedented load growth” since 2018, which is expected to continue past 2027. (See PJM Sees Additional $603M ‘Data Center Alley’ Tx Spend.)
Although Dominion is already working on more than $200 million in supplemental and baseline transmission upgrades in the area, PJM says it expects numerous reliability violations in the 2024/25 timeframe and without additional upgrades it expects there will not be sufficient transmission to serve the load beyond that period. The required service date for Dominion’s solution is June 1, 2025.
Nearly $200 Million in Additional Transmission Projects
FirstEnergy (NYSE:FE) and Dominion presented several other projects to serve new load customers and replace aging infrastructure.
Dominion is planning to construct two new substations for new data centers in Culpeper County, Virginia. The Germanna substation is being considered along the Remington-Gordonsville line at a $55 million cost for a 139-MW data center complex.
Rappahannock Electric Cooperative has asked Dominion to increase capacity at the existing Mountain Run delivery point and to construct a new substation nearby for an estimated $60 million. The project, which is still conceptual, would service a new 350-MW data center.
Dominion also presented a project to rebuild approximately 7.9 miles of double circuit line on the Braddock-Ox line in Prince William County, Virginia, at a $43.5 million price tag in response to the identification of thermal violations on the line.
Other projects:
Dominion is planning to replace two aging transformers, Farmville and Clubhouse, for $6.4 million and $6.6 million, respectively. Both units were constructed in 1981.
Dominion is engineering a new single 230-kV feed for a crypto mining customer in Battleboro, North Carolina, for $750,000.
FirstEnergy is constructing a $4.9 million 230-kV circuit breaker and equipment feeding into a new 230-234.5-kV transformer in Frederick County, Maryland. The installation will supply a new customer request with a 30-MW anticipated load.
FirstEnergy presented a $15.1 million project to build a new Sage Substation, near the Doubs-Eastalco lines in Frederick County, Maryland, to serve a new customer with an anticipated 240-MW load.
PJM Outlines Phase 2 of OSW Study
PJM is embarking on the second phase of an offshore wind transmission study requested by the Organization of PJM States Inc., which will consider scenarios for the injection of 8,600 to almost 20,000 MW into Delaware, Maryland, New Jersey and Virginia.
Phase 1 of the study, released last year, looked at five scenarios to identify regional transmission solutions to accommodate the coastal states’ offshore wind goals, as well as all PJM states’ renewable portfolio standards. It identified costs of $627 million to $3.2 billion for injections of 6,400 to 17,000 MW. (See Tx Upgrades for PJM OSW, Renewables Could Cost $3.2 Billion.)
Phase 2 includes three short-term scenarios (study year 2028) assuming 2,022 or 4,000 MW from Maryland, 3,906 MW from New Jersey and 2,640 MW from Virginia, per state requests. Five additional scenarios target year 2035, most of them using the same injections for Maryland, 7,648 MW from New Jersey and 2,640 or 5,200 MW for Virginia.
The final scenario, requested by Pennsylvania, will assume no offshore wind as a way to separate the OSW cost impacts from that of transmission needed to support other resources needed to meet state RPS requirements.
The new study will use an updated 2022 load forecast and provide a “much more in-depth and granular” market efficiency analysis than Phase 1, said PJM’s Matthew Bernstein. The market efficiency analysis will be performed on at least two scenarios, he said.
The study will include a retirement scenario to offset the increased renewable penetration levels assumed in the studies, based on formal deactivation notices and federal and state policies.
Each scenario will include a generator deliverability thermal analysis for summer, winter and light load conditions and identify transmission solutions for each reliability violation, including costs.
The results of the two scenarios based on current policies are expected to be completed by the end of the year. The sensitivity analyses requested by the states will be available in early 2023, PJM said.
PJM Reviewing Responses to Tx Proposal Windows
PJM received more than 30 proposals in response to two recent transmission proposal windows.
The RTO’s 2022 Multi-Driver Proposal Window 1, which closed Aug. 8, generated 14 proposals from three entities to solve potential reliability violations on multi-driver facilities. The proposals, eight greenfields and six upgrades, ranged from $215,000 to $127 million. None included cost containment.
PJM expects to begin preliminary evaluation of the proposals in early September and complete its selection by the end of the year for board approval in February 2023. PJM will coordinate with MISO in its evaluations.
PJM also received 17 proposals from seven entities in response to Reliability Proposal Window 1, which closed Aug. 30.
The proposals — six greenfield projects and 11 upgrades — ranged in cost from $260,000 to $386.7 million and addresses 275 flowgates. Seven of the proposals included cost containment measures.
NYISO is planning to narrow the scope of its system reliability impact studies (SRIS) and revise its pro forma interconnection agreements in response to resource challenges and the unprecedented increase in the number of generator interconnection requests.
ISO officials outlined the proposed changes at the Sept. 1 Transmission Planning Advisory Subcommittee (TPAS) and Electric System Planning Working Group meeting.
Despite an increase in staffing, the workload for the ISO’s interconnection studies (IS) team has doubled since 2018 when six engineers managed 120+ studies, about 20 per engineer. This year, the ISO’s nine engineers are managing 346+ studies, an average of 40 each.
Productivity also has been hampered as the ISO had to replace five engineers on the IS team between January 2021 and March 2022, meaning two-thirds of the team lacked interconnection experience.
These problems have been exacerbated by labor market shortages, which prevented consultants from taking on more projects, and more customers requiring personalized attention because of their unfamiliarity with NYISO processes, Thinh Nguyen, senior manager of interconnection projects, said.
NYISO attorney Sara Keegan said the volume of interconnection requests is also taxing the ISO’s legal team.
As a result, Nguyen said the ISO plans to eliminate from the SRIS for large facility interconnections the voltage deviation analysis and harmonic analysis and perform other analyses — NPCC A-10 testing, transfer assessments and sub-synchronous torsional interaction screenings — on a case-by-case basis.
The streamlining of the SRIS process is in addition to other changes the ISO has made to address the growing interconnection queue and address the labor shortage, including a salary study that resulted in pay increases for engineers and the planned hiring of staff to help guide project developers through the interconnection process. (See NYISO Details 2023 Budget & Compensation Updates.)
Stakeholders agreed that elements of the SRIS study were redundant for projects that go through class year studies.
In addition, Keegan said the ISO will seek FERC approval for changes to its pro forma interconnection agreements and the creation of a pro forma engineering, procurement and construction (EPC) agreement for some system upgrade facilities (SUFs) and system deliverability upgrades (SDUs).
Keegan said the ISO will propose revising the small (SGIAs) and large generator interconnection agreements (LGIAs) to add placeholders to address recurring variations that have necessitated non-conforming agreements and clarify security, invoicing and oversight cost rules, among other changes.
NYISO large generator interconnection procedure | NYISO
The pro forma EPC agreement would cover SUFs and SDUs not addressed in LGIAs or SGIAs because the upgrades are required for affected systems or for multiple projects, Keegan said. She noted that FERC has approved such an agreement for MISO and has proposed an agreement for affected system in its generator interconnection Notice of Proposed Rulemaking (NOPR) in June (RM22-14). (See FERC Proposes Interconnection Process Overhaul.)
NYISO anticipates presenting the interconnection agreement related tariff revisions at either the Oct. 3 or Nov. 1 TPAS meeting and is targeting Q1 2023 for a Section 205 filing with FERC. NYISO also anticipated additional revisions in 2023 as part of a project proposed by the Alliance For Clean Energy New York and through an expected compliance filing from FERC’s final order on the generator interconnection NOPR.
Nguyen also outlined plans to revise the base case inclusion rules used in the interconnection studies to ensure the studies incorporate transmission and class year projects that may impact each other by using existing system capacity or requiring similar upgrades.
The ISO said it expects discussion of proposed tariff changes through the third quarter. It said written comments should be sent to Kirk Dixon (kdixon@nyiso.com).
RNA Draft Report Finds No Immediate Needs
The 2022 Reliability Needs Assessment (RNA) found that there were no reliability needs on the New York bulk electric grid through 2032.
While the report found the ISO’s grid will meet all reliability criteria based on forecast demand and expected weather, it said the reliability margin could be narrowed or eliminated, based upon changes in forecasted system conditions.
“Delayed implementation of projects in this plan, additional generator deactivations, unplanned outages, changes in load patterns and extreme weather could potentially lead to deficiencies in reliable electric service in the coming years,” the report said.
The report said reliability margins will likely shrink in the future because of the unavailability of simple cycle combustion turbines because of environmental rules, including the state Department of Environmental Conservation’s Peaker Rule, which will reduce nitrogen oxides emissions from CTs in a phased implementation from 2023 to 2025.
“Additionally, significant load-increasing impacts are forecasted due to expected growth in electric vehicle usage, large cloud-computing data centers and other electrification (i.e., conversion of home heating, cooking, water heating and other end-uses from fossil-fuel based systems to electric systems),” the RNA said. “However, additional resources planned to be in-service in the near-term horizon, such as the Champlain Hudson Power Express connection from Hydro Quebec to New York City, provides a boost to the margins. Additionally, the NYISO is forecasting over the next ten-year period a decrease in energy usage due to energy efficiency initiatives and increasing amounts of behind the meter solar generation.”
“While we don’t have reliability needs in the study period, the margins are not far from tipping,” the ISO’s Laura Popa told the two committees.
The RNA is the first step of the ISO’s reliability planning process. The grid operator plans to issue its 2023-2032 Comprehensive Reliability Plan in 2023. Any needs identified in the short-term reliability process in year one through year three will be addressed in its quarterly short-term assessments of reliability.
NYISO requested comments or questions be submitted to either Laura Popa (lpopa@nyiso.com) or Kirk Dixon (kdixon@nyiso.com) by Sept. 6. The ISO is targeting Sept. 19 for its third RNA draft and then submitting the report for board approval in November.
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.
BPU 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.”
BPU 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.
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.
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.
