CAISO’s Western Energy Imbalance Market yielded members $418.82 million in economic benefits during the first three months of 2023, up 143% from the same period in 2022 and a first-quarter record.
Cumulative benefits since the 2014 rollout of the market have nearly doubled over the past year, reaching $3.82 billion after three consecutive quarters that smashed records, according to CAISO’s first-quarter benefits report, released Thursday.
The sharp growth comes after four new participants entered the market last year: Avista Utilities, Tacoma Power, Tucson Electric Power and, most significantly, the Bonneville Power Administration, which operates 15,000 miles of high-voltage transmission — about 70% of the network in the Northwest.
The first-quarter benefits report was released about a month later than normal, which the ISO attributed to the need for more time “to review the benefits estimates and the underlying congestion observed in certain areas of the WEIM footprint,” according to a press release accompanying the report.
“Ultimately, no changes to the current methodology have been implemented to estimate the first quarter benefits. The CAISO and its WEIM partners will continue to assess and determine if methodology enhancements are warranted based on various conditions of congestion,” the ISO said in the release.
CAISO itself earned the largest share of benefits during the quarter, at $67.86 million, followed by NV Energy ($47.19 million), Balancing Authority of Northern California — or BANC ($44.63 million), Salt River Project — or SRP ($31.38 million), PacifiCorp ($28.94 million), and Los Angeles Department of Water and Power ($27.99 million).
BANC’s balancing authority area includes the state’s second-largest municipal utility, Sacramento Municipal Utility District, as well as Modesto Irrigation District, the cities of Redding and Roseville, and the Western Area Power Administration’s Sierra Nevada region.
CAISO was the largest net exporter of energy during the quarter, at 1,354,826 MWh, followed by SRP (510,350 MWh), NV Energy (478,330 MWh) and PNM (350,796 MWh). The ISO was also the second-largest net importer, at 848,513 MWh, exceeded only by British Columbia’s Powerex, at 881,791 MWh.
CAISO was also the location of the most wheel-through transfers, at 760,999 MWh, followed by Arizona Public Service (587,198 MWh), the PacifiCorp-West BAA (314,838 MWh) and NV Energy (296,657 MWh). In years past, NV Energy consistently handled the highest volume of wheel-throughs, but the inclusion of more Pacific Northwest WEIM participants appears to be shifting a greater share of those transfers to California. Market members gain no financial benefit from facilitating wheel-throughs, with only the sink and source directly benefiting.
CAISO said WEIM operations helped reduce renewable curtailments by 53,002 MWh during the first quarter, helping to prevent emission of 53,002 metric tons (MT) of CO2. The market has avoided 814,746 MT of carbon emissions since 2015, the ISO estimates.
With the inclusion of the Western Area Power Administration–Desert Southwest region and Avangrid in April, the WEIM footprint now covers 79% of the load in the Western Interconnection. CAISO expects the market to break $4 billion in total benefits this quarter.
CARMEL, Ind. — MISO’s future is all but certain to contain more 765-kV and HVDC transmission lines, experts predicted during a special two-day meeting of the Planning Advisory Committee last week.
“The magnitude and scope of possible system challenges point to the need for a higher-voltage, higher-capacity superhighway or backbone of either 765 kV or HVDC,” said Energy Systems Integration Group’s James Okullo, citing the volatile ramping needs, increased congestion, larger energy transfers and voltage stability issues the resource transition will bring.
He pointed out that MISO is planning for a system with 80% annual renewable penetration within 20 years.
VSC converters | Siemens Energy
Multiple experts said MISO could use grid-forming voltage-sourced converter (VSC) HVDC lines and include them in the second portfolio of its long-range transmission planning (LRTP) effort. They praised VSC-HDVC’s ability to deliver power-flow control, inherent reactive power and voltage support, dynamic stability, and synthetic inertia, and its potential to provide black start system restoration.
“VSC today is not as exotic a thing as it was 15 years ago, and with good reason,” Minnesota Power’s Christian Winter said.
Winter said VSC-HVDC is “uniquely suited for the clean energy transition” because it can move power across long distances while supplying ancillary services. He also said VSCs on the receiving end of transfers can function like dispatchable power plants and can be placed where retiring baseload generation is located.
Cornelis Plet, vice president of power system advisory at DNV, said VSC-HVDC is becoming “the technology of choice” in European countries to achieve reliability while meeting ambitious climate goals. It allows the connection of different synchronous zones and can connect remote loads and remote generation. Europe is finding HVDC technology so useful that total installed HVDC capacity will more than triple in the next decade, he said. While the continent is so far building point-to-point lines, an overlay grid of HVDC lines will realize the full benefits.
VSC has become the “workhorse” of HVDC lines, and the use of line commutated converter technology is disappearing, Plet concluded.
Brattle Group Principal Johannes Pfeifenberger said MISO is “in the best position to take advantage” of VSC-HVDC as it plans its second LRTP portfolio.
“Tranche 2 is the opportunity for MISO to get its feet wet and offers a unique opportunity for MISO to gain the necessary planning, market integration and operational experience with VSC-HVDC technology for possible larger-scale future deployments,” he said.
Pfeifenberger said Europe has discovered that VSC is “so compelling in what it can do” and has cemented itself as the dominant converter technology. He said grid planners struggle with placing a value on the resilience that HVDC can deliver. A well-placed 2,000-MW HVDC line would help Texas address its AC stability limits when it transfers power from the western portion of the state.
“It’s future-proof in a way that would be very expensive to address with AC technology,” Pfeifenberger said. He recommended that MISO adapt its markets to be able to dispatch HVDC lines to capitalize on the “incredible advantage” of alleviating congestion by controlling power flows.
American Transmission’s Bob McKee, representing MISO’s transmission owners, said the RTO’s current 240-GW interconnection queue shows the fleet transition is gearing up. He said he was delivering a “call to action from the TO sector” and encouraged MISO to “be bold” in its planning and consider all transmission solutions.
“I think Winter Storm Uri and Winter Storm Elliott are fresh in our minds, and we realize the importance of a robust transmission system,” McKee said.
McKee also said electrification “just isn’t coming; it’s already here.”
“This is our opportunity to identify a set of facilities that will fit our needs,” he said.
Massachusetts energy providers, consumers and climate advocates presented contrasting visions of what solutions should be included in a clean heat standard (CHS) that is currently being developed by the state’s Department of Environmental Protection (DEP), as shown by public comments published last week.
The development of the standard was endorsed in the final report by the Massachusetts Commission on Clean Heat, and the DEP began development in April, soliciting initial comments from stakeholders on the scope of the process and the standard itself.
Under the basic framework, fuel suppliers would be required to acquire an increasing number of credits associated with verified reductions in emissions from heating. Credits could be bought and sold to help suppliers meet their obligations, while suppliers could also be allowed to meet their obligations through alternative compliance payments.
The goal of the standard is to help Massachusetts align its heating sector with its mandatory emissions limits: The state is required by law to reduce its gross emissions 50% by 2030, 75% by 2040, and 85% and be net-zero by 2050. The state also has emissions sub-limits for different heating sectors, as well as for the gas system, which are set in five-year increments.
In 2018, combustion for heating accounted for about 34% of Massachusetts’ carbon pollution, according to a report prepared for the state by researchers at the Regulatory Assistance Project (RAP), which outlined options for a CHS. The report noted that natural gas accounted for about two-thirds of heating emissions.
Defining Clean Heat
Many of the comments received by the DEP focused on whether alternative fuels should be able to generate clean heat credits.
According to the RAP report, decarbonization options include “weatherization improvements, energy efficiency improvements, heat pumps, clean district energy and other verified low-carbon options, potentially including renewable methane, clean hydrogen, biodiesel, renewable diesel and advanced wood heat.”
Fossil fuel producers and providers argued that the DEP should include a variety of options related to alternative fuels in the standard, while environmental groups said the standard should only incentivize electrification and weatherization options.
National Grid said that “electrification and energy efficiency should be the cornerstone strategies for decarbonizing buildings in Massachusetts,” but it also argued for the inclusion of combustion options within the standard.
“Alternative, low-carbon, non-fossil fuels will play an important role in ensuring families and businesses across the commonwealth have access to decarbonized heat,” National Grid wrote. “Repurposing existing infrastructure, including the existing gas distribution network to deliver low-carbon alternative fuels such as RNG [“renewable” natural gas] and hydrogen can help make the energy transition more affordable by reducing the need for new electric infrastructure construction, which will present affordability challenges.”
The Mass Coalition for Sustainable Energy — a group funded in part by Enbridge, Eversource Energy and National Grid, and whose members include the Associated Industries of Massachusetts, the commercial real estate development association NAIOP and several regional chambers of commerce — called hydrogen and RNG “viable decarbonizing pathways” for heating, adding that “we cannot take those pathways off the table.”
Meanwhile, environmental groups argued that hydrogen and RNG should not be included in the standard.
“Our top priorities for a CHS for Massachusetts are ensuring adequate equity protections and an electrification-only compliance program, particularly for gas utilities,” wrote a coalition of 37 environmental groups, led by the Conservation Law Foundation, Acadia Center, Green Energy Consumers Alliance and Pipe Line Awareness Network for the Northeast. “Alternative gases are not a long-term solution for the buildings sector, so incentives should not encourage buildout of these wasteful processes in the near term.”
Massachusetts sector sub-limits for carbon emissions | Massachusetts DEP
The coalition said that the greenhouse gas emission reductions associated with replacing natural gas with hydrogen and RNG would be marginal, and that a dependence on these fuels would increase the overall costs associated with reaching net-zero emissions.
They also highlighted concerns related to the safety of blending significant quantities of hydrogen into the gas system, along with the public health impacts related to combustion.
“The commonwealth should not fund fuels like hydrogen that pose significant safety risks, when safer appliances like heat pumps are available,” Andee Krasner wrote on behalf of Gas Transition Allies’ Hydrogen and Biogas Working Group. “Hydrogen ignites more easily and has a wider explosive range than natural gas. … It can embrittle steel pipes, and hydrogen has higher permeation rates for elastomeric seals and plastic pipes.”
Krasner added that “biofuels and green hydrogen made using renewable energy have an important role in the future but should be reserved for hard-to-electrify industrial processes. They should be produced preferably on-site or, if not, then as close to the end use as possible to minimize leakage and pollution.”
The Coalition for Renewable Natural Gas — whose members include fuel producers that specialize in RNG, as well as fossil fuel producers, including Shell, Chevron, BP, and pipeline companies such as Kinder Morgan and Enbridge — argued that RNG could cover a major portion of the state’s gas needs.
“The portion of renewable gas serving Massachusetts’ gas system will increase even as total system throughput declines, eventually leading to a smaller gas system which transports only 100% clean fuels to targeted end uses,” the coalition wrote. “Given expected declines in gas system throughput, the use of renewable gas need not lead to net pipeline expansion, beyond connecting these new supply sources to existing load.”
The coalition said RNG from waste sources in Massachusetts such as landfills, manure and wastewater treatment could cover about 10% of existing residential gas demand, 11% of commercial demand or 26% of industrial demand in the state; gasification of organic matter such as agricultural and forestry residues and energy crops could nearly double this total.
While most fuel suppliers focused on alternatives to fossil fuels, Canadian fossil fuel producer Irving Oil argued that the standard should incentivize some fossil fuel heating systems.
“End-use fuel switching should be eligible as a means to comply because a lower-carbon fuel (i.e., heating oil to natural gas) is still an improvement in emission reductions and shouldn’t be discredited,” the company wrote. “Energy-efficient heating systems, including but not limited to combined heat [and] power systems that may use portions of fossil fuels should also be incentivized.”
The RAP report directly discouraged incentives for fuel switching, saying that new pipeline buildout “both adds to the fixed costs of the pipeline grid and delays the ultimate conversion of the building away from fossil fuels,” while the state’s Commission on Clean Heat concluded that “the installation of new fossil fuel equipment and services should not be supported under the CHS.”
Protecting Vulnerable Communities
Public comments from stakeholders largely agreed that the CHS needs to be designed in a way to protect lower-income residents as the costs of the transition mount.
The city of Boston said that the standard should incentivize co-benefits including air quality, workforce development, equity and resilience, and called on the DEP to take on a robust public engagement process.
“Addressing the challenges of climate change presents opportunities for advancing the wellbeing of our residents, communities and economies; a holistic approach to designing programs like a clean heat standard will help identify and take advantage of such opportunities,” wrote Mariama White-Hammond, Boston’s chief of environment, energy and open space.
The environmental group coalition called for substantial adjustments and protections for low-income customers, who represent a disproportionate share of residents of color in the state.
“Perpetuation in the medium to long term of the unmanaged transition off of gas that is already underway will be an inequitable disaster for low- and moderate-income [LMI] gas customers,” the group wrote. It also advocated for targeted protections for renters to prevent gentrification caused by building upgrades.
“Without protections for renters, landlords can use incentives subsidized by ratepayer or tax dollars like a CHS or Mass Save for building upgrades as a pretext for rent increases that force out low- and moderate-income renters from relatively affordable housing units.”
The state’s Commission on Clean Heat recommended that the DEP require fuel providers to “include a specified percentage of credits generated in LMI and [environmental justice] populations and households in their annual compliance filings.”
National Grid wrote that it supports this recommendation, along with dedicating funds from alternative compliance payments to support environmental justice communities.
The DEP will hold its first virtual public meetings on the CHS on June 20 at 10 a.m. and 6 p.m.
After decades of funding research to one day harness the power of nuclear fusion, the Department of Energy this week announced grants to help startups develop commercial fusion reactors.
The agency on Wednesday announced $46 million in “milestone-based” grants to eight competing companies across seven states.
The winners were drawn from a much larger group that applied for the funding when DOE announced the grant program last fall. The grants will be delivered in increments over time as the companies achieve development milestones initially negotiated with DOE.
Noting that $5 billion of private capital is invested in predominantly U.S.-based fusion companies, Energy Secretary Jennifer Granholm said the Biden administration believes commercialization can occur within a decade.
“And so we’ve launched this milestone-based fusion development program, where private companies are going to team up with our labs and with universities and others to work through the scientific and technological challenges with the goal of designing a fusion pilot plant within the next five to 10 years,” Granholm said.
Arati Prabhakar, director of the White House Office of Science and Technology Policy, said the question is not how to achieve that 2030 target but how to meet the administration’s 2050 goals of eliminating greenhouse gas emissions.
She said the partnerships DOE is developing with the grants will be crucial to commercializing fusion.
“I love a big, aggressive, barely feasible goal because it forces you then to figure out what does it actually take to get there. I’ve really been excited watching DOE ask that question about fusion. Having the scientific basis that tells us that we can do this is necessary, but it’s very, very far from sufficient,” Prabhakar said.
“There’s so much more work that has to be done to turn this into something that is a commercial capability that’s consistent, safe and reliable,” she added. The work deals with thermal, materials and radiation issues that much more advanced technology won’t remove the need for, she said.
New York agencies on Thursday kicked off the first in a series of public webinars dedicated to explaining and seeking comment on the state’s proposed emissions-reduction and reporting policy, the cap-and-invest program.
The economywide program is a centerpiece of New York’s clean energy transition and, as proposed, would use money from the auctions of emission allowances to both offset consumer costs associated with the transition and fund clean energy projects needed to achieve the goals set out in the state’s Climate Leadership and Community Protection Act (CLCPA). (See “Cap and Invest,” NY State Reliability Council Executive Committee Briefs: May 12, 2023.)
Hosted by the Department of Environmental Conservation (DEC) and New York State Energy Research and Development Authority (NYSERDA), the meeting covered the current proposed structure of the program, solicited initial public questions, and shared the rulemaking or regulatory considerations on which the agencies want feedback.
The program’s rules and regulations will be written by the DEC in consultation with NYSERDA, which will be responsible for dispersing money collected from auctions to relevant clean economy projects. Roughly a third of those funds will be prioritized for disadvantaged communities to help offset rising energy costs. (See NY Climate Justice Panel Sets Disadvantaged Community Criteria.)
The agencies sought feedback on multiple aspects of the proposal, including the program design, emissions benchmark reporting, compliance verification metrics, applicability of regulations on certain industrial sectors and what other rules should be considered.
The DEC and NYSERDA also want input on how the program’s auctions should be designed and how auction allowances should be allocated to obligated or nonobligated sources.
They also seek comment on what is the applicable threshold to set emissions or operations caps; which industries or other stationary sources, such as large buildings, should report their emissions; and what enforcement mechanisms should be used to track emissions reporting or verification.
Another consideration is how different industries — such as the waste, energy-intensive trade-exposed (EITE) and electricity sectors — should be treated in the program and how the Regional Greenhouse Gas Initiative (RGGI) would fit into New York’s program.
Public feedback can be submitted online or via mail to the DEC’s Bureau of Air Quality Planning at any time, but staff asked that comments or questions relevant to the first webinar be sent by July 1.
Public Questions
The public posed many questions during the webinar.
One attendee asked whether there will be an offsetting criterion as part of the proposal, to which the DEC’s Jonathan Binder responded, “We’re not intending [to have] offsets be a part of this program.”
Another inquired about the difference between obligated and nonobligated entities.
The DEC’s Ona Papageorgiou said, “Obligated entities would be required to purchase or obtain allowances for their emissions, whereas the state will retire allowances for nonobligated entities.”
Papageorgiou also answered a question about whether there was a “floor” to any of the program’s thresholds, saying the agencies are “seeking feedback on thresholds for reporting and compliance.”
Vlad Gutman-Britten of NYSERDA responded to a question about whether allowance trading would be allowed.
“We haven’t made that determination yet, and we are seeking input on whether and to what degree trading should be allowed,” he said.
Another attendee asked if emissions allowances would be strictly for carbon dioxide or the equivalent.
Nathan Putnam of the DEC answered, “These are carbon dioxide equivalent emissions, so the program is going to cover all greenhouse gases in the state of New York, or anything relevant to the CLCPA.”
In an email to NetZero Insider, the DEC said the webinar series “will provide an overview of New York’s potential program and similar programs in other states and jurisdictions designed to reduce greenhouse gas emissions.
“All stakeholder input will be considered as part of program development to ensure the proposed program achieves the core principles of affordability, climate leadership, creating jobs and preserving competitiveness, investing in disadvantaged communities, and funding a sustainable future.”
With the 88th Texas Legislature’s regular session in the history books Monday, and a 30-day special session already underway, the state’s clean energy industry can breathe a little easier again.
“Members, I hope you enjoyed your summer. I sure did,” House Speaker Dave Phelan (R) said as he gaveled his chamber back to business Tuesday.
“It could have been very, very bad,” Stoic Energy principal Doug Lewin, a close observer of the Legislature, told RTO Insider. “The threats were serious and real, and it’s still not great … the worst stuff, the permitting, the cost allocation … that didn’t pass.”
“While more than a dozen anti-renewable energy bills were filed this session, only a few ended up making it through the process,” said Luke Metzger, executive director of Environment Texas. “Some of the measures that would have been most harmful to renewables … thankfully died.”
For that, Metzger and others can thank a broad coalition of environmentalists, industry organizations and business groups, along with House representatives beholden to their constituents, for preventing the renewable energy sector from being kneecapped.
After the Senate tacked on language from bills that had yet to make it out of committee as amendments to the must-pass bill reauthorizing the Public Utility Commission (House Bill 1500), the interest groups worked last weekend with legislators to again eliminate or water down the more onerous language.
Out went language from Senate Bill 624 that would have required wind and solar facilities to acquire special permits from the PUC, a requirement thermal generators wouldn’t face. A firming mandate that would have required renewables to pay for other energy sources when wind and solar aren’t producing was pushed back to the end of 2027 and its cost increases tied to generation portfolios, rather than individual units.
“Over at the Legislature, those people are accountable to consumers and voters. They just can’t ignore what consumers want,” said attorney Katie Coleman, who represents Texas Industrial Energy Consumers.
“I think the language that ended up in 1500 is heading in the direction of trying to have some reliability for renewables in their output, but it’s not as punitive as some of the other proposals,” Lewin said. “I think there’s a lot of what they’re calling firming going on in the market anyway. So, kind of pushing that along, but I don’t think it is going to really be that detrimental to the industry.”
Rather than make renewables pay higher ancillary services fees, HB1500 instead requires that a study first be conducted. It would also end Texas’ renewable energy requirement, or portfolio standard. However, the state met that requirement years ago.
HB1500 also adds a $1 billion annual net cap to the performance credit mechanism (PCM), which since PUC Chair Peter Lake pushed it through in January has been criticized by almost everyone connected to the market — except the large generators that would benefit from it. Various studies have pegged the PCM’s cost at between $5 billion and $12.7 billion a year, which ERCOT has said would flow down to consumers. (See Texas PUC Submits Reliability Plan to Legislature.)
Lake said the commission would wait to see what direction the Legislature offered before pursuing the PCM’s implementation. The PUC got that direction with HB1500, which requires ERCOT to complete an updated assessment of the reliability program and submit a report on its costs and benefits to the commission and Legislature.
The bill also includes 14 requirements to be met before the PCM can be implemented, including one that mandates that ERCOT add real-time co-optimization and ancillary services to the market before implementing the PCM. That would push the latter back to 2025 or 2026.
Other HB1500 requirements related to the PCM include:
Central procurement of performance credits to prevent market manipulation by affiliated generation and retail companies;
Not assigning costs, credit or collateral for the program such that it provides a cost advantage to load-serving entities that own, or whose affiliates own, generation facilities;
Establishing a penalty structure providing a net benefit to load for generators that bid into the PCM’s forward market but do not meet the full obligation;
Not allowing generators to receive credits that exceed the amount of their bid into the forward market;
Removing the bridge solution by the end of the PCM’s first year; and
Setting a single ERCOT-wide clearing price that does not differentiate payments or credit values based on locational constraints.
“There really hasn’t been a lot of support for [the PCM] from any group other than actual existing generators and leadership with the PUC and ERCOT,” Coleman said. “We all want more reliability. Always. I think the Legislature wanted to put some pretty strict parameters around the limits of it. That was something that we worked really hard to get done, along with a pretty broad range of groups.”
Hard Sell
Where this leaves the PCM is anyone’s guess.
During a virtual press conference Wednesday, ERCOT CEO Pablo Vegas said the grid operator’s staff are reviewing legislation that passed and analyzing its impact on the grid. He promised to share more details publicly, “like we often do in our in our open board meetings,” once staff understand the bills better.
“We’re not at a place where we’re ready to discuss that in any detail right now,” he said. “But I can tell you that we share the same goal that the Legislature does, which is to continue to support a reliable and stable grid now and long-term into the future. We’ll continue to work closely, too, with the Legislature to enact what they passed this session.”
The ERCOT Board of Directors next meets June 19-20.
“I think it’s going to be a hard sell to come back and say, ‘Hey, we’ve done this analysis and now the PCM is going to cost $2 billion or $3 billion or $4 billion.’ That’s going to be hard, hard argument to make,” Coleman said.
The Legislature also sent SB2627 to Gov. Greg Abbott’s desk. The bill provides $5 billion to $10 billion in government low-interest loans and completion bonuses to builders of new gas plants. However, SB6, which would have ordered the construction of 10 GW of gas-fired generation at a cost of $10 billion to $18 billion, didn’t make it. Texans will get a chance to pass judgment on SB2627 when they vote on it as a constitutional amendment.
Texas Rep. Todd Hunter and Sen. Charles Schwertner celebrate the passage of House Bill 5. | Sen. Charles Schwertner via Twit
Another bill, HB5, a corporate incentive program to boost infrastructure investment, excludes wind and solar development from tax abatements.
“The landmark legislation package passed this evening will ensure our economic miracle continues into the mid-21st century and beyond,” Lt. Gov. Dan Patrick, who controls the Senate, said in a statement after the bills’ passage.
Lewin points out that very little of the legislation addresses the root causes of ERCOT’s capacity shortfalls during the two most recent storms of 2021 and 2022: the failure of gas supplies to show up in frigid temperatures.
He said a friend asked him after the regular session ended whether the Legislature’s actions meant the grid is fixed.
“No. Not even close,” Lewin said he responded.
“One of the points I’m trying to make leaving this session is that if you don’t focus on the root cause, if all the focus is on renewables, you’re causing problems, which is really where the focus was,” he said. “There was very little focus on the actual problems facing the grid. We’re just going to continue to have a grid that is problematic and leaves us all kind of white-knuckling it through the through the next winter storm.”
A bill to strengthen the integrated resource planning process for Nevada’s electric utilities and require them to look for ways to increase their energy independence has emerged late in the state legislature’s session.
Assemblyman Howard Watts (D) introduced Assembly Bill 524 on May 26, less than two weeks before the 2023 session ends on June 5. The bill was granted a waiver from the usual legislative deadlines.
Watts said the bill is the result of months of discussions with stakeholders who voiced concerns about energy reliability and rising costs to consumers. The bill lines up with Gov. Joe Lombardo’s March executive order calling for the state’s “advancement of energy independence.” (See New Governor Seeks Shift in Nevada Energy Policy.)
One of the key topics of discussion, Watts said, was the concept of the state’s “open position” when it comes to energy supply.
“We have an open position: a level of exposure to the energy market,” Watts said. “By reducing that, we can make sure that we can provide a reliable electricity supply and reduce our exposure to those extremely high energy market costs.”
Watts’ comments came Tuesday during a joint meeting of the Senate and Assembly committees on Growth and Infrastructure. The committees held a hearing on the bill but took no action.
Watts said he has also heard concerns about the integrated resource planning process for electric utilities and the number of amendments filed by NV Energy.
“Amendments have been coming very frequently … some of the projects in amendments are extremely large, and they don’t have the full timeline and the full analysis of the integrated resource plan itself,” Watts said.
Since approval of its 2021 integrated resource plan (IRP), NV Energy has filed four amendments to the plan. The fourth included a proposal for a 400 MW gas-fired peaker plant that NV Energy said was needed to maintain reliability in the face of extreme weather and variable resources. The Public Utilities Commission of Nevada (PUCN) approved the Silverhawk peaker in March on an expedited timeline intended to get the new plant running by 2024. (See Nev. Regulators OK Controversial Gas-fired Peaker.)
Under current law, electric utilities in Nevada must file an IRP every three years. AB 524 would change the requirement to every three years or “more often if necessary.” The bill would direct the PUCN to develop requirements regarding the filing of amendments to an approved IRP.
Currently, an IRP must include scenarios showing how different sets of resources could meet projected energy demand. AB 524 would require the utility to evaluate a scenario “that provides for the construction or acquisition of energy resources through contract or ownership to be placed into service to close an open position utilizing dedicated energy resources in this state and dedicated energy resources delivered through firm transmission.”
The bill doesn’t say that the scenario designed to close an open position must be the one the utility moves forward with. Watts said the wording in the bill, which doesn’t dictate a particular outcome, was a compromise.
‘Dire State’
NV Energy opposes the bill, saying it doesn’t go far enough.
Tony Sanchez, NV Energy’s executive vice president of business development and external relations, called for a strong policy statement from the legislature “indicating that the open position that we currently have … needs to be closed and closed quickly,”
“Because the West is in a dire state of energy emergency,” Sanchez said.
Janet Wells, NV Energy’s vice president of regulatory affairs, called the utility’s reliance on the open market “both risky and costly.”
Wells said that while NV Energy can generate power for about $50/MWh, it paid more than $150/MWh on average in the open market in summer 2021 and even more in 2022. About 30% of the utility’s summer energy comes from the open market, Sanchez said.
The ERCOT Independent Market Monitor’s annual market report on the Texas grid released Wednesday recommends resurrecting a multi-interval, real-time design similar to those used in other markets and re-evaluating and prioritizing it for future implementation.
The Monitor notes that real-time markets rely primarily on online and quick-start resources. It says a real-time market efficiently dispatches online resources and sets nodal prices that reflect energy’s marginal value of energy at every location, but that ERCOT lacks the software and processes to facilitate efficient commitment and decommitment of peaking resources that can start within 30 minutes.
“This is a concern because suboptimal dispatch of these resources raises the overall costs of satisfying the system’s needs, can distort the real-time energy prices and affects reliability,” the Monitor says in its 2022 State of the Market report. “For these reasons, other markets have implemented this type of look-ahead process to optimize short-term commitments of peaking resources.”
The Monitor says the value of access to and optimally using fast-starting dispatchable resources will only grow as do ERCOT’s more intermittent wind and solar resources. A multi-interval dispatch model can meet these increasing ramp requirements by recognizing system needs further into the future and beginning to move dispatchable resources to optimally satisfy, it says.
ERCOT evaluated the model’s potential benefits in 2017 but decided not to move forward because the costs were greater than the projected benefits, according to the IMM. “Much has changed since” then, it says, pointing to a higher level of renewable resources available to the grid operator.
“We believe benefits will be much higher in the future, and this capability will become essential for managing the growing renewable fleet,” the Monitor says.
The proposal is one of five new recommendations added to eight holdovers. Other new suggestions include:
instituting a 100% claw-back of excess market revenues for reliability unit commitments, as the incentives for self-committing resources have changed “dramatically” with the increased frequency of RUC instructions under ERCOT’s more conservative operations posture;
allowing transmission reconfigurations for economic benefits, instead of just for reliability;
changing the linear ramp period for emergency response service summer deployments to three, down from the current 4.5-hour parameter that artificially inflates the reliability deployment price adder; and
modifying the lookback period for operating reserve demand curve mean and standard deviation calculations to a rolling five-year period, which would have saved more than $160 million last year.
The IMM also says real-time co-optimization (RTC), which was postponed after the February 2021 winter storm, should be prioritized, “given its promise to improve pricing during supply shortages” and to better use the existing generation fleet. The grid operator is expected to restart the RTC project this summer, with a new potential go-live of 2026.
The market report finds ERCOT’s markets performed “competitively” and “little evidence” that suppliers exercised market power, with one exception: It says the nonspinning reserve market became less competitive as higher procurements caused large suppliers “to frequently be pivotal,” raising the reserve product’s costs from $385 million to $480 million from August 2021 through December 2022.
ERCOT’s average load grew 9.5% from 2021 and average real-time prices fell to roughly $75/MWh in 2022, down more than 50% from 2021 ($167.88/MWh), almost entirely because of the February storm’s effects. Prices reflected a real-time energy value of $32.2 billion last year.
New Grid Notifications Added
ERCOT on Wednesday rolled out a new notification system it said will provide “clear and reliable” communications with the public and greater transparency on grid operations.
The Texas Advisory and Notification System (TXANS) provides another means for the public to follow ERCOT operations and grid conditions that do not indicate emergency conditions are expected. It introduces two new notifications before NERC-mandated energy emergency alerts (EEAs): an ERCOT weather watch and a voluntary conservation notice.
The weather watch will be issued when possible severe weather and high demand is forecasted in three to five days. It is intended to alert the public to plan ahead in reducing their energy use during higher-demand periods.
ERCOT CEO Pablo Vegas | ERCOT
“This earlier lookahead gives the public notification of possible higher demand due to forecasted conditions,” ERCOT CEO Pablo Vegas said during a virtual press conference. “We’re then asking Texans to keep an ear out for more information should conditions change.”
The voluntary conservation notice will be issued when higher demand and lower energy supply are forecast. It will ask Texans to voluntarily conserve power, if it’s safe to do so. ERCOT will also request that local government agencies implement programs that reduce energy use at their facilities.
TXANS notifications will not replace EEA notices.
“All of the new notices that we are releasing at this point … are times when the grid is in stable and normal conditions and that they’re not in an emergency,” Vegas said. “We want to just help people be aware and informed on what’s going on. We want to be more transparent; we want to be more open and get people more comfortable with hearing from us under conditions that are not emergency conditions.”
PJM is weeks away from the scheduled date for the 2025/26 Base Residual Auction (BRA) without an order from FERC on whether it will be permitted to delay the auction (ER23-1609).
The RTO on April 11 asked FERC for permission to indefinitely postpone the auction, currently scheduled for June 14, to allow it to implement market rule changes now under stakeholder consideration through the Critical Issue Fast Path (CIFP) process. The following three auctions would also be delayed under the proposal, with the schedule returning to its normal three-year advance time frame for the 2029/30 BRA in May 2026.
Under Federal Power Act Section 205, if FERC does not issue an order within 60 days, the filing will go into effect by operation of law. That period ends on June 10, the date on which PJM asked that the changes go into effect. The RTO had said that if the commission does not approve the filing prior to June 10, it will proceed with the auction as scheduled.
PJM had requested expedited consideration with the hope of receiving an order by May 19, which the RTO said would allow it to provide market participants with advanced notice of any delay to the auction and allow them to focus their efforts on the CIFP process.
The filing did not include exact auction dates for the four delayed auctions to give PJM flexibility to incorporate any changes arising from the CIFP process, but it did include an illustrative timeline. Under that timeline, the 2025/26 BRA would be held in June 2024, and the following three auctions would be held every six months after.
Steve Lieberman, American Municipal Power’s vice president of transmission and regulatory affairs, said market participants are having to make decisions about their offers with little clarity about what the future of the auction holds, making it difficult to properly manage where they should focus their time and resources.
“I think we’re all in a tough place here, and it would be good to get some direction one way or another from FERC,” he said. “Nobody in our markets likes uncertainty.”
Comments submitted to the commission on the filing were split, with opponents arguing that a delay would disrupt state procurement auctions and undermine the goal of giving confidence to generation owners about their potential revenues. Opponents also said that the filing was based on speculation that the CIFP process will yield a proposal ultimately accepted by FERC. They argued that the proposal was overly broad by not including the specific dates to which PJM would delay the auctions.
“In theory and practice, it’s clear that shortening the lead time between the auction and the delivery year helps incumbent resources and muddies the market signal needed to incent new generation,” the Organization of PJM States Inc. protested.
Supporters argued that delaying the auction would allow the changes to the capacity market to be implemented with the aim of improving the accuracy of the price sent by the auction.
“While P3 has not traditionally supported delaying important [capacity] auctions, given the need to conduct future capacity market auctions under just and reasonable rules, P3 supports PJM’s filing as an unfortunate necessity,” the PJM Power Providers (P3) Group said in its comments. “The commission’s approval of the PJM filing will allow PJM to address the capacity market concerns and reliability issues in PJM so that auctions for the delivery years 2025/26 and beyond will appropriately send price signals to capacity resources to remain on, retire from or enter the market.”
PJM defended its filing by stating the impact of December 2022’s Winter Storm Elliott and reliability concerns found in its February “Energy Transition in PJM” white paper highlight the need to send price signals that will encourage the generation needed for resource adequacy through 2030.
“While PJM does not take any delay of the capacity auctions lightly, on balance, a limited delay of the upcoming [Reliability Pricing Model] auctions is necessary and appropriate at this time given the region’s recent experience with Winter Storm Elliott and the imminent reliability concerns identified in the Energy Transition ‘4R’ white paper,” PJM said in a May 10 reply comment. “This delay is necessary because sending the correct capacity market price signal is better than continuing to establish inaccurate price signals in an attempt to rush the auction and establish a clearing price for the capacity auction as early as possible.”
The Sierra Club and Citizens Utility Board commented that although they do not have an opinion, they believe the white paper had a flawed outlook on resource adequacy over the coming years. In an affidavit, economist James Wilson argued that it ignored the price signals that future capacity auctions would send as resources retire to construct new generation.
“The [white paper’s] model fails to account for the core feature of the PJM capacity market intended to anticipate and address future potential shortfalls: the capacity market price as determined by PJM’s sloping demand curve,” the comments state.
HOLYOKE, Mass. — ISO-NE has upped its predictions for summer and winter peak loads over the next 10 years, staff told the NEPOOL Power Supply Planning Committee on Wednesday.
The updated forecasts are part of ISO-NE’s annual Capacity, Energy, Loads and Transmission (CELT) report, which projects electricity demand over the next 10 years. They are used by the RTO to help with transmission planning, determining resource adequacy requirements, evaluating the reliability and performance of the grid, and coordinating maintenance.
The most significant changes for this year’s projections related to updates in the methodology of forecasting electrification across the region, with major increases in the projected demand from electrified heating and transportation compared to the 2022 report.
The RTO boosted its projection for winter transportation demand for 2031 from 1,497 MW to 2,820 MW, while the summer projection increased from 1,082 to 1,927. The 2031 winter heating demand projection increased from 1,831 MW to 2,521 MW.
The projected increase in demand from electrified heating and transportation. | ISO-NE
For the heating projection, this year’s report looked at electrification within the commercial building sector, which was not included in last year’s, based on extensive data from the National Renewable Energy Laboratory.
The transportation demand increase reflects the myriad new federal, state and local policies aimed at spurring the transition to electric vehicles. The figure was based on input from state regulatory agencies to assess the extent to which nonmandated electric vehicle targets will be met. The modeling assumes all state EV adoption mandates will be met.
The RTO also adjusted its projections to better account for the effect of cold weather on EVs.
“Energy and demand impacts of personal [light-duty vehicles] were revised to more dynamically incorporate the impacts of weather,” said Victoria Rojo, lead data scientist of load forecasting and system planning for ISO-NE.
Peak demand is calculated using historical weather data for the winter and summer weeks with the highest typical demand. The RTO calculates a gross load forecast — which does not account for the impacts of energy efficiency programs or behind-the-meter solar — as well as a net load forecast, which subtracts these factors from the gross load.
ISO-NE increased its winter gross peak demand for 2031 by about 7% compared to the previous report and increased its summer projection by about 2%. The winter net peak projection for 2031 is approximately 10% higher than the 2031 projection from the previous report, while the summer net peak projection is about 5% higher than that from the previous report.
ISO-NE now projects net summer peak demand to increase to 26,505 MW in 2031, compared to the 24,605 MW the RTO projects for this summer. For net winter peak demand, ISO-NE projects 25,133 MW in 2031, compared to 20,269 MW for this winter.
The data indicate that winter peak load will grow faster than summer peak load and that winter peak load could pass summer peak load in the coming years.
