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.
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.
The 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.”
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.”
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%.
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.
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 | 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.
CAISO saw record demand Tuesday of more than 52 GW. | CAISO
