FERC Approves Public Service Colorado’s WEIS Market Participation
FERC on Friday approved Public Service Company of Colorado’s (PSCo) request to participate in SPP’s Western Energy Imbalance Service (WEIS) market and revisions to its market-based rate tariff (ER23-949).
The commission accepted PSCo’s change in status to join the WEIS market and found that it meets its requirements for both horizontal and vertical market power. Last April, FERC accepted PSCo’s Western joint dispatch agreement with SPP that establishes the legal relationship between SPP and its market participants.
FERC’s March 31 order directed the utility to file in 15 months a market-based rate change in status filing that includes an ex post analysis with 12 months of price separation data to help determine whether the PSCo balancing authority area has become a submarket of the WEIS market.
It also directed the utility to include a price separation analysis between the WEIS market and the PSCo BA in its future Northwest region triennial filings.
“PSCo’s participation in the WEIS market raises concerns of whether the PSCo balancing authority area could become a submarket of the WEIS market,” the commission wrote.
FERC’s approval was effective April 1. PSCo, a subsidiary of Xcel Energy (NASDAQ:XEL), is the WEIS market’s 10th participant. The Western Area Power Administration participates in three of its five regions.
SPP began administering the market on a contract basis in 2021. WEIS centrally dispatches energy from participating resources throughout the region every five minutes.
SPP, MISO Staff Honored for Collaboration
The Energy Systems Integration Group (ESIG) has recognized SPP and MISO staffers as recipients of its 2023 Excellence Awards for their work on the RTOs’ Joint Targeted Interconnection Queue (JTIQ) study.
SPP’s Antoine Lucas, Clint Savoy, David Kelley and Kelsey Allen
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SPP
The grid operators’ staffs were honored for “identifying significant transmission limitations near the SPP-MISO seam” during the study. Their work resulted in five projects that could help reduce congestion and allow additional resources, primarily wind farms, to interconnect with their systems.
Antoine Lucas, SPP’s vice president of engineering, was recognized along with David Kelley, Kelsey Allen and Clint Savoy.
MISO’s honorees were Aubrey Johnson, vice president of system planning, and Andy Witmeier, Sumit Brar and Jeremy Nash.
SPP and MISO are collaborating with the Minnesota Department of Commerce and the Great Plains Institute to seek funding from a Department of Energy program to help cover up to half of the JTIQ portfolio’s $1.06 billion estimated cost. (See DOE Clears JTIQ Projects to Proceed with Funding App.)
The awards recognize global energy professionals for their contributions and accomplishments toward the planning and operation of energy systems in ways that are reliable, economic and sustainable. They were presented during the ESIG’s annual Spring Technical Workshop March 29 in Tucson, Arizona.
Other recipients included Grid United CEO Michael Skelly for his “pioneering efforts to build transmission infrastructure to unlock the nation’s wind energy resources.”
Tri-State Generation & Transmission Association’s Mary Ann Zehr and WAPA’s Lloyd Linke received awards for their service to the ESIG’s Board of Directors and its Advisory Council, respectively.
Little Rock HQ Undamaged in Storms
SPP’s headquarters in Little Rock, Arkansas, escaped damage during a tornado that touched down “just blocks away” Friday as a deadly outbreak of storms ravaged the South and Midwest.
More than 50 confirmed twisters touched down in the region, killing at least 32 people. Another round of storms is expected in the same region Tuesday.
“SPP is saddened by the devastation to our community caused by yesterday’s storms,” SPP tweeted Saturday. “We look forward to joining in restoration efforts and doing our part to serve.”
PORTSMOUTH, N.H. — The first meeting of a new era for ISO-NE’s Consumer Liaison Group featured few fireworks but plenty of substantive discussion of the challenges facing New England’s energy transition.
The CLG, a forum for connecting the RTO with the public, met Thursday, its first gathering since a December vote in which six climate activists were elected to its coordinating committee. (See Climate Activists Take Over Small Piece of ISO-NE.)
“Like the Red Sox, the Consumer Liaison Group is experiencing a reset,” said Donald Kreis, a coordinating committee member and the state of New Hampshire’s Consumer Advocate. “Our record is no wins and no losses. It’s a new day at the CLG, and there’s reason to be optimistic about making consumers have a stronger and better liaison to our grid operator.”
Dan Dolan, president of the New England Power Generators Association, laid out what he sees as the stakes for decarbonization in the region.
“The responsibility we have in New England … is to create a demonstration to other parts of the country and the world that you can move forward on a decarbonized future in a way that promotes economic prosperity, [that it] can be done in a resilient, reliable fashion and maintains affordability for the consumers,” Dolan said.
A running theme of the meeting was identifying areas of agreement between ISO-NE, which has been criticized for moving too slowly on greening the region’s energy mix, and those outside who have been pushing it for years.
“The ISO recognizes that climate change is happening right now, and that we need to reduce carbon emissions to solve this problem,” said Susan Muller, a senior energy analyst at the Union of Concerned Scientists, who spoke on a panel during the meeting.
“It’s really important common ground, and I know there’s a struggle right now to find common ground,” she said.
But where Muller argued the grid operator has not caught up to public sentiment is on the time constraints of climate change, which she said call for rapid action.
“We’re concerned that without the time constraints being factored in, we’ll perpetuate the situation, and we don’t have a lot of time,” she said.
Anne George, ISO-NE’s vice president of external affairs, represented the organization at the meeting, as she’s done many times before. She gave a rundown of key issues facing the RTO, including its recently completed Forward Capacity Auction and two capacity deficiency events from the past winter that have raised questions about New England’s grid in cold weather.
Bob Ethier, a vice president for system planning at ISO-NE, also presented during the event.
“The big thing that I want to convey today is what we are doing to facilitate the transition to clean energy,” he said.
Among those efforts: “a heck of a lot of studies,” as well as providing technical expertise, working on transmission development and supporting interconnection, Ethier said.
Several speakers pointed to siting as another major challenge for the clean energy transition.
New Hampshire State Rep. Michael Harrington, a Republican and self-described “climate realist,” said that New Englanders have shown they’ll fight tooth and nail to prevent projects from being built in their backyards, pointing to the slow progress of the Northern Pass transmission line as one example.
“What’s the message that New England’s sending to the rest of the business world out there? Don’t come here and build anything because we don’t want anything built,” he said.
New Hampshire itself is in a unique position in the region, as multiple panelists noted. Its progress on renewable energy has been slower than in surrounding states, even as the price of that energy has plummeted.
“While right now we might be sort of free riding off the policies of the states around us, pretty soon it means we’re going to be missing the boat,” said Sam Evans-Brown, executive director of Clean Energy New Hampshire.
Michael Giberson, R Street Institute | R Street Institute
By Michael Giberson
FERC must look beyond reliability standards to boost electric industry winter readiness.
Winter Storm Elliott smashed into the Southeastern U.S. last year at just the wrong time, right before Christmas, disrupting both long-planned travel and last-minute holiday shopping. It was a bad time for the affected region’s electric utilities too, as power generators struggled under freezing temperatures while customer demand rose to winter records.
Duke Energy in North Carolina and the Tennessee Valley Authority (TVA) had to cut power to some consumers to help keep the grid from failing. For both power companies, it was the first time they had to employ these extreme reliability measures.
A few days later, FERC, NERC and NERC regional entities announced they would investigate operations of the bulk-power system during the storm. A report will emerge in a few months with useful details on which components failed and which reliability standards were not well enforced. But one may wonder what we can learn from the fifth such joint investigation that was not obvious from the previous four winter storm investigations.
The fourth FERC-NERC winter storm report, examining February 2021’s Winter Storm Uri, summarized the main finding of the earlier three. What have we learned? Small equipment failures — the freezing up of a gauge or a sensing line — can sideline a generating unit; gas supply interruptions were an issue; generation owners sometimes failed to prepare adequately; operators lacked training for extreme winter weather conditions; and utilities need to improve emergency communication practices. All four reports observe these kinds of failures and make similar recommendations.
Coincidentally, in February FERC approved winter reliability standards that address about half of the recommendations from the fourth FERC-NERC winter storm report. The standards are a step forward, said FERC Commissioner Mark Christie, “but the much bigger issue to me is market design.” Does it still support reliability?
The interaction of reliability and markets has always been a concern within restructured regions. Revenue from energy, ancillary service and capacity markets is intended to incentivize enough investment that supply can reliably meet customer demand under a wide range of conditions. Emergency operations help maintain service in extreme cases. At least those are market design goals.
But as has been discovered over and over, emergency operations can undermine market incentives supporting resource adequacy. For example, an RTO might call on demand response resources to help maintain a safe level of operating reserves. If the RTO market interpreted reduction in load as falling consumer demand, then prices fall at a time when resources are exceptionally scarce. The price suppressing potential of demand response programs was uncovered in RTOs a decade ago, but similar problems continue to emerge.
This sort of fine-grained market design work is essential to refining RTO systems. However, the sheer scale of some winter storms suggests attention to the bigger picture is needed too. Texas, the biggest state of the lower 48, was smaller than the winter storms that struck it in February 2011 and February 2021. Even PJM and MISO, the two largest of the RTOs in terms of generating capacity, are too small to handle the biggest winter storms alone. Winter storm readiness requires more extensive and effective interregional ties between RTOs and their neighbors.
Interregional Interties
This feature of the winter challenge leads to the first of two recommendations for winter readiness that go beyond the scope of FERC-NERC investigations: FERC should make interregional transmission projects a high priority. In the just released draft National Transmission Needs Study, the U.S. Department of Energy (DOE) identified over 50 recent transmission needs studies conducted by a wide range of organizations. The draft report concludes that significant system resilience, reliability and economic benefits can be expected from expanded interregional transfer capacity.
Particularly significant, as indicated by the DOE’s report, are expanded interties between the Western and Eastern interconnection in the Plains states and interties between ERCOT to both the west and east. A study by Grid Strategies and the American Council on Renewable Energy concluded “modest investments in interregional transmission capacity would have yielded nearly $100 million in benefits during the five-day event, while most areas could have saved tens of millions of dollars.” A transmission line connecting ERCOT to utilities in the Southeast could have saved lives in Texas during Winter Storm Uri and saved consumers at least $1 billion in energy bills.
Winter Storm Elliott makes clear the need for better interregional coordination beyond RTOs, both for interregional transmission planning and for everyday operations. Utilities in the Southeast region launched a trading platform in 2022 — the Southeast Energy Exchange Market (SEEM) — to help them share excess supplies. When the storm came, however, buying opportunities on SEEM disappeared. PJM and MISO both sent power into the southeast during the storm that helped limit the use of rolling outages in the area.
The Western Energy Imbalance Market (WEIM), operated by CAISO, has not yet been hit by winter storms comparable to Elliott. However, during the August 2020 heat wave, resources participating in WEIM were able to sell into CAISO and helped limit involuntary load shedding in California. The contrasting performance of markets in non-RTO regions may be reason for FERC to take another look at SEEM’s market design. In all regions, RTO or non-RTO, reliability advantages of interregional transmission will remain untapped without a functional regulatory framework that lets private capital flow.
Load Responsiveness
A second general recommendation calls for a renewed emphasis on demand-side engagement in power markets. The new reliability rules approved by FERC in February will require utilities to separate out protected circuits — hospitals, police and fire stations, and circuits providing other reliability protections — from other customers. The move will help ensure the high cost of involuntary load shedding is spread more evenly. However, technology now allows widespread participation in voluntary economic and emergency demand response programs.
PJM deployed cuts of up to 7,000 MW through voluntary load management programs during Elliott. These programs were one reason PJM could avoid involuntary load shedding when demand came in above forecast and generating units were failing at unexpectedly high rates. In addition to RTO programs, companies like Tesla, Sunnova, OhmConnect and Octopus Energy are implementing voluntary consumer response programs that can aid RTOs during periods of grid stress. It is much better for a few thousand customers to reduce use by 1 or 2% than have a few customers unwillingly cut off 100%.
FERC policy endorses active load-side participation in RTO markets, but the limited reach of existing programs, the high cost of involuntary load shedding and promise suggested by new programs mean now is a good time for more focus on customer engagement. Load shedding for bulk system reliability can be reduced by innovative, voluntary retail customer programs. As such efforts span wholesale and retail sectors, state and FERC commissioners should establish a joint effort to reduce involuntary load shedding by better enabling voluntary customer response programs.
Conclusion
Commissioner Christie was on to something when he raised questions about institutional design in the context of winter weather failures, which is outside the scope of FERC-NERC reliability investigations. Reliability assessments are missing some of the biggest aspects of prudent reliability policy. Notably, robust interregional transmission, active demand-side participation and healthy regional market design play key roles in meeting customer needs during extreme winter weather.
Some of the necessary work is simply ensuring emergency operations do not inadvertently undermine incentives to invest in winter readiness. Better mobilizing voluntary consumer responses can substantially reduce the need for involuntary cutoffs. Another part is ensuring effective mobilization of resources on a scale large enough to match winter threats. For example, FERC or Congress could establish interregional planning requirements and remove regulatory barriers to merchant developers to kickstart a woefully underdeveloped system. Competitive, interconnected markets are a reliability imperative.
Michael Giberson is a senior fellow with R Street Institute’s Energy & Environmental Policy Team.
ERCOT stakeholders on Friday coalesced around changes to the operating reserve demand curve (ORDC) as their preference to supplement staff’s proposed bridge mechanism to the new performance credit mechanism (PCM).
During a workshop with staff, the Technical Advisory Committee (TAC) agreed to pursue changes to the ORDC and procuring additional ancillary services as two concepts that could help retain existing assets and build new dispatchable generation until the PCM can be fully implemented — assuming the PCM passes muster with Texas lawmakers.
Committee members quickly eliminated options that included capacity contracts, a manually settled PCM, and a backstop reliability service suggested by Texas regulators that would set aside capacity for dispatch during scarcity conditions.
“These are largely alternative ideas or alternative information that we want to provide to the [ERCOT] board … we’re trying to get to a point where we’re providing incentives for people to come into the market to provide dispatchable generation,” TAC Chair Clif Lange said, referencing legislators’ requests for more thermal generation in the ERCOT market. “I’m looking at it in the context of [2021 legislation in] which the intent was to try to provide additional revenues to dispatchable generation to come into the market.”
ERCOT’s ORDC values the wholesale market’s operating reserves on their scarcity, reflecting that value in energy prices. The curve has been modified several times since it became part of the market in 2014. The value of lost load, which is set equal to the system-wide offer cap, was changed from $9,000/MWh down to the $2,000/MWh low-system-wide offer cap after the 2021 winter storm, then back up to $5,000/MWh in January 2022. The minimum contingency level was also increased in 2022 from 2,000 MW to 3,000 MW.
The ISO’s staff also has proposed changes to the demand curve by targeting increases in operating reserve ranges that are above emergency levels, while avoiding ORDC increases at times of substantial operating reserve surpluses.
As directed by the Public Utility Commission, staff’s goal is improving market signals so they help retain existing assets, add new dispatchable generation, and reduce reliability unit commitments (RUCs) for system capacity. That would fit within the PUC’s requirement that bridging options make minimal system changes and be implemented with a year, fit within the existing market framework, and continue to be hedged by market participants through their energy positions.
Kenan Ögelman, vice president of commercial operations, said staff studied adding multistep floors within the same range of operating reserves, as suggested by stakeholders. Analyzing 2020, a mild-pricing year, and 2022, a higher pricing year, they found that setting floors of 6,500 MW at $20/MWh and 7,000 MW at $10/MWh would have increased revenues by about $500 million. That would align with the additional average revenue the PCM would provide, Ögelman told TAC.
He said the back-cast analysis for 2022 confirms that the multistep floors would direct the revenues largely to dispatchable resources. Setting a floor that first kicks in at the 6,500-7,000 MW range provides a self-commitment incentive better aligned with ERCOT’s conservative operations posture, he said.
“The last ORDC change made no distinction between online and offline reserves,” Ögelman said. “This is focused on online [reserves] and at the kind of scarcity bandwidth where we tend to take RUC actions. The difference really is the focus on online resources only getting the reward. So, if it brings more resources online … that would reduce the need for us to RUC.”
Stakeholders are still considering the additional procurement of ancillary services as an option, though it has received less support than ORDC changes. Dave Maggio, ERCOT’s director of market design and analytics, said increasing ancillary services is not one of staff’s “preferred approaches.”
“It’s much less clear to us how that helps to bridge the gap and … meet some of the criteria that we’ve listed. I don’t think it has any of the same benefits that we’ve been talking about,” he said. “It’s also not as clear … that we would have this … same targeted change in revenues as we were seeing with [our recommendation]. It doesn’t seem to do any of those as well as the preferred solution.”
Staff and stakeholders will share their recommendations with the board’s Reliability and Markets Committee as part of the directors’ April 17-18 meeting. TAC will meet virtually April 10 to agree on its final pitch to the board and, as Reliant Energy’s Bill Barnes suggested, to prevent a TAC meeting from breaking out during the R&M meeting.
“There are a lot of good thoughts behind some of these other options and concerns that I think would be valuable for the R&M to hear,” he said.
The PUC in January recommended to the state legislature that ERCOT adopt the PCM as a reliability addition to its energy-only market to address resource adequacy and operational flexibility challenges. The PCM would issue incentive payments to dispatchable — and primarily thermal — generation that meets performance criteria during the tightest grid periods.
The legislature has pushed back on the PCM and filed a package of bills that includes building 10 GW of gas-fired generation to sit on the sidelines until load shed is imminent. (See Texas Senate Lays out Changes to ERCOT Market.)
Members Honor Walter Reid
Stakeholders and staff paused the workshop to share their memories of the Advanced Power Alliance’s Walter Reid, who died March 24.
Walter Reid | Advanced Power Alliance
A technical and regulatory consultant for APA after a career with the Lower Colorado River Authority, Reid and his booming voice helped set the tone for ERCOT’s stakeholder process.
“Walter has his handprints all over [the stakeholder process] and was an amazing leader in getting us where we are today,” Ögelman said. “He coached me, and he always listened to what I had to say, so I truly appreciate having him in my life and getting to work with him.”
Barnes noted stakeholders don’t have a textbook to guide their work. Instead, they rely on those who have come before to share their knowledge.
“That’s how we grow. That’s how we improve on this market design, and Walter was always generous with his knowledge,” Barnes said. “I think back to the 2008 days when there were a lot of technical issues regarding the integration of wind. He was the leader in getting those changes adopted and was hugely successful in the amount of wind production that has been developed in the state and allowing ERCOT to operate it reliably. We owe it to folks like Walter for the success that we have today.”
“Texas and ERCOT are better places and better markets thanks to his efforts. Renewable energy owes much of its success in this state to the work of Walter Reid,” the APA said on its website.
Credit Group Members Approved
The TAC also confirmed 11 members for its new Credit Finance Sub Group (CFSG), which has been tasked to help ensure that procedures are in place to mitigate credit risk fairly for all market participants.
With the group’s first members confirmed, it can now vote on its leadership. Austin Energy’s Brenden Sager and Reliant Energy’s Loretto Martin are running unopposed for the group’s chair and vice chair positions.
The CFSG, which is still accepting membership applications, is scheduled to hold its first meeting April 21.
The TAC approved the group’s charter during its March meeting. The CFSG replaces the Credit Working Group (CWG), which had reported to the ERCOT board’s Finance and Audit Committee since 2004. TAC agreed to take on credit oversight responsibilities and consolidated the CWG with its Wholesale Market Subcommittee’s Market Credit Working Group and disband the latter. (See “TAC Shares Changes with R&M,” ERCOT Board of Directors Briefs: Oct. 18, 2022.)
Kentucky officials have asked FERC to again shut down American Electric Power’s proposed $2.6 billion sale of its Kentucky operations to Liberty Utilities.
The Kentucky Public Service Commission, Kentucky Office of the Attorney General and Kentucky Industrial Utility Customers said in a March 30 protest that AEP (NASDAQ:AEP) and Canada’s Algonquin Power & Utilities (NYSE:AQN) conglomerate, whose North American assets include Liberty, have yet to address or propose mitigations for the “adverse impacts of the transaction on zonal transmission rates” (EC23-56).
FERC temporarily halted the transaction in December, directing AEP and Liberty to write in more consumer protections before it would approve the deal. AEP and Liberty responded in February by including a five-year freeze on the current return on equity and 55% equity capital structure; a commitment from Liberty to maintain the same credit profile for five years; and a five-year cap on operations and maintenance and administrative costs at the 2022 rate. (See AEP, Liberty Utilities Try Again on Kentucky Territory Deal.)
However, the Kentucky intervenors said that AEP’s and Liberty’s pledge that Kentucky Power and Kentucky Transco would remain in PJM’s AEP East transmission pricing zone “for the foreseeable future” is not good enough to protect consumers from rate increases.
The Kentucky PSC said even if Kentucky Power remains in the AEP East zone, its rates under Liberty’s ownership will increase because the utility will have higher incremental fixed and variable costs caused by “building a new transmission organization from the ground up.” The PSC said the zonal revenue requirement’s extra costs will “far exceed” any savings AEP will experience from shedding its Kentucky operations.
The regulators said that if Kentucky Power is separated from AEP ownership but remains in the AEP East zone, the PSC would lose its ability to use its “retail ratemaking jurisdiction to influence AEP’s decisions” on transmission investment in the seven-state AEP East zone, regardless of the benefit to Kentucky consumers. The commission said AEP-affiliated companies would no longer be under pressure to avoid shifting costs to Kentucky consumers.
“Applicants cannot simply ask the FERC and other stakeholders to accept its ostrich-like approach to the impacts if a move is made, or if it is not,” the Kentucky parties said.
They also argued that AEP and Liberty’s “extensive reliance” on future retail rate benefits aren’t relevant to FERC’s decision because the PSC deemed them necessary to shield consumers from the transaction’s rate hikes.
AEP and Liberty are hoping to close their transaction by April 26. If they fail again to gain commission approval by then, termination rights kick in for the parties.
The EPA on Friday approved a waiver for California’s Advanced Clean Trucks regulation, clearing the way for the state to launch the zero-emission program for medium- and heavy-duty trucks starting with model year 2024.
The regulation will require truck manufacturers to sell an increasing percentage of zero-emission medium- and heavy-duty trucks in the state from 2024 through 2035.
The zero-emission vehicle sales requirements will also apply in states that have adopted California’s Advanced Clean Trucks (ACT) regulation, including Washington, Oregon, New York, New Jersey, Massachusetts and Vermont.
California Gov. Gavin Newsom on Friday called the EPA decision “a big deal for climate action.” Newsom said California will be the first government in the world requiring zero-emission trucks.
“We’re leading the charge to get dirty trucks and buses — the most polluting vehicles — off our streets, and other states and countries are lining up to follow our lead around the world,” Newsom said in a statement.
The EPA waiver was needed because air quality standards in the ACT differ from those of the federal government. California is allowed to adopt and enforce its own vehicle emissions requirements if they exceed federal standards and EPA grants a waiver.
“Under the Clean Air Act, California has long-standing authority to address pollution from cars and trucks,” EPA Administrator Michael Regan said in a statement on Friday. “Today’s announcement allows the state to take additional steps in reducing their transportation emissions through these new regulatory actions.”
Mixed Reactions
The American Trucking Associations (ATA) on Friday criticized the EPA decision, saying it allowed California to create a “regulatory patchwork.”
“This isn’t the United States of California,” ATA CEO Chris Spear said in a statement.
Spear said the regulation’s “technologically infeasible rules” and “unworkable and unrealistic timelines” were setting the stage for a supply-chain crisis.
But environmental groups welcomed the EPA decision.
Heavy-duty trucks account for only about 10% of vehicles on the nation’s roads but have an oversized impact on air pollution, according to the Environmental Defense Fund. The impacts are felt especially in low-income areas and in communities of color, EDF said.
“The Advanced Clean Trucks Rule will save lives, save money for truckers and fleets, save the state billions of dollars in health care costs, and help create thousands of new jobs,” EDF clean transportation attorney Andy Su said in a statement.
Three Waiver Requests
The California Air Resources Board adopted the Advanced Clean Trucks regulation in June 2020. CARB has said that its rule will drive technology development and investment in zero-emission trucks.
In deciding whether to grant a waiver for ACT, the EPA held a virtual public hearing in June 2022 and accepted written comments through Aug. 2.
EPA also granted a waiver on Friday for a CARB regulation that extends emissions warranty periods for heavy-duty diesel trucks in model years 2022 and later.
EPA has yet to decide on a third waiver request from CARB. The Heavy-Duty Low NOx Omnibus Regulation, which CARB approved in August 2020, aims to reduce emissions of nitrogen oxides from trucks. The rule sets new standards starting with the 2024 model year and tightens the standards further in 2027.
CARB has asked EPA for more time before EPA acts on the low NOx waiver request, the federal agency said.
Increasing Sales Requirement
In August, CARB adopted the Advanced Clean Cars II regulation, banning the sale of gas-powered cars in 2035. The rule allows some sales of plug-in hybrid vehicles at that time. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.) CARB must still receive a waiver from the EPA to enforce those regulations.
Advanced Clean Trucks isn’t a total ban on gas-powered truck sales. Zero-emission sales requirements vary by vehicle class. For Class 2b and 3 trucks, such as step vans and city delivery trucks, the rule requires 5% ZEV sales in 2024, increasing to 55% in 2035.
For class 4 to 8 trucks, such as large delivery trucks, school buses and beverage trucks, the 9% requirement for zero-emission new vehicle sales in 2024 grows to 75% in 2035. ZEV sales requirements for Class 7 and 8 tractors range from 5% in 2024 to 40% in 2035.
ACT also includes a credit system in which a truck manufacturer may sell ZEV credits they earn to other manufacturers. Manufacturers may receive early credits for zero-emission trucks sold starting with model year 2021, and certain hybrid electric trucks may earn partial credits.
Under ACT, zero-emission sales requirements for trucks don’t increase after 2035. But a 2020 executive order from Newsom set a goal for all medium- and heavy-duty vehicles in the state to be zero-emission by 2045 where feasible.
In addition to ACT, CARB is expected to vote during its April 27 meeting on adoption of another zero-emission truck regulation, Advanced Clean Fleets.
The regulation would require some or all new trucks added to certain types of fleets to be zero-emission starting in January 2024. The three types of fleets covered are drayage, state and local, and fleets deemed high priority.
Stakeholders told the New York Public Service Commission it should modify utilities’ proposed transmission planning framework, saying the plan lacks independence and could favor local upgrades over more efficient regional projects (20-E-0197).
The PSC received comments from about 20 agencies, companies, nonprofits and trade coalitions. They said the CGPP’s timeframe does not match NYISO processes and that the proposed independent body responsible for advising the PSC lacks diversity. In addition, the methodologies for identifying transmission upgrades appear biased, and advanced technologies were inadequately considered, the commenters said.
Independence of Advisory Group
Stakeholders said the utilities’ proposed make-up of the Energy Policy Planning Advisory Council (EPPAC) would make it a vessel for expanding utility interests.
As proposed, the EPPAC would include a representative and an alternate from each utility, Department of Public Service staff, NYISO, the New York State Energy Research and Development Authority, renewable generation and storage associations, power authorities (New York Power Authority, Long Island Power Authority) and environmental justice community associations.
New York City was forceful on this, writing that the EPPAC “creates an inherent conflict” because of how much control the utilities would have over its processes. It is hard to imagine why the council would advance results “inconsistent with their views, plans and proposals,” the city said, calling it “mostly a plan for the electric utilities to coordinate among themselves with no requirement to incorporate input from others.”
The New York Power Authority said that the proposed EPPAC leaves some sectors with “a reduced opportunity to provide valuable input.”
NYISO, NYPA, Environmental Defense Fund, the Working for Advanced Transmission Technologies (WATT) Coalition, the “Clean Energy Parties” (including the Alliance for Clean Energy New York, Advanced Energy United and solar and battery organizations) and a joint filing by organizations including the Alliance for Clean Energy New York, the New York Offshore Wind Alliance, Natural Resources Defense Council and the American Clean Power Association (“the Alliance”), argued that the PSC should expand the EPPAC with non-utility members to diversify the council.
Synching with ISO Process
Most commenters also said the CGPP, which operates on a three-year life cycle, is incompatible with NYISO’s two-year public policy transmission planning process for identifying and evaluating necessary transmission upgrades.
The CGPP “would not integrate well with existing NYISO transmission planning processes and would not fully reap the benefits available from competition in the identification and procurement of local and bulk solutions to transmission need,” wrote NYPA.
This was echoed by the CEP, the Alliance and EDF Renewables, which proposed a compromise to reduce CGPP to a two-year cycle but complemented with a PSC review lasting no more than six months.
Threat to Competition
Commentators also complained that the CGPP gives utilities control over public policy transmission need processes, threatening competition.
The CGPP turns the “existing FERC-approved system on its head” and gives utilities opportunities “to displace bulk upgrades with smaller, less efficient local upgrades,” LS Power wrote. It would threaten transmission competition and eliminate consumer benefits “including reduced cost per MW of incremental transfer, increased production cost savings, reduced emissions, and cost containment,” LS said.
“Placing [utilities] in charge of selecting a bulk solution raises potential jurisdictional issues and may create inefficient incentives” wrote NYPA. It warned the utilities’ plan gives them the ability to “favor their own projects rather than exposing transmission needs to competitive selection.”
NYISO said the PSC should “require clear criteria for the prioritization of solutions in a multifaceted planning process,” since this provides the CGPP with “clearer workstreams and avoid a preference for local transmission solutions where a regional solution can more efficiently achieve the CLCPA targets and benefit ratepayers.”
EDFR, the CEP, and the Alliance also highlighted this issue, which they said the PSC could address by encouraging greater flexibility in transmission evaluations and increasing transparency in competitive processes.
Grid-enhancing Technologies
Many commentators also said the CGPP should be more open to future technologies, specifically distributed energy resources and energy storage.
The CGPP does not “adequately incorporate the value of grid enhancing technologies” while the CEP argued the proposal “does not establish a clear, transparent, timely or collaborative process for evaluating and including [new] technologies.”
Transource Energy said that the utilities “limited their recommended list of technologies.” The EDF said CGPP evaluations failed to provide “detailed distribution grid planning that will be needed in New York.”
ECOGY Energy, a Brooklyn-based developer, advised the PSC to require more flexibility at the distribution level to improve long-term planning for future technologies, while Transource said the PSC should add several public review processes within the CGPP cycle to review technologies deployed since the last cycle.
The first CGPP cycle is scheduled to start July 1 and end on July 1, 2025.
There are many polarizing issues dividing America today, but support for reliable electricity is not among them. No one is in favor of power outages, and no one should be left in the dark.
Extreme weather events have stressed the grid in most regions of the country over the last decade, and the frequency and severity of these events are only expected to increase in the years ahead. Every type of generation has struggled through these events. To solve this problem, utility commissioners, grid operators and federal regulators must look beyond generation solutions.
The U.S. grid is aging and balkanized. Most regions have limited ties to one another, meaning there is little transmission capacity available to transfer electricity between neighboring areas. Yet studies show interregional transmission lines can serve as lifelines in an emergency — delivering power from unaffected areas to storm-ravaged regions where power plants were forced to halt operations.
As a recent U.S. Department of Energy (DOE) draft study demonstrated, increasing interregional transmission capacity yields the greatest value, improving access to affordable power and helping ensure a reliable supply of electricity. Interregional transmission lines allow grid operators to access more generation resources and are particularly useful for providing additional supply during extreme weather events, according to the DOE. The agency also identified a “pressing need” for more transmission infrastructure.
During Winter Storm Uri in February 2021, an additional gigawatt of transmission capacity between the Texas grid and the Southeast could have saved Texans nearly $1 billion and kept the lights on in 200,000 homes, according to a report from Grid Strategies. Meanwhile, interregional transmission ties allowed the Great Plains and Midwest grid operators to import 15 times more electricity during the storm than the Texas grid, helping avoid widespread outages that killed hundreds in the Lone Star state.
In December 2022, some grid operators in the Southeast were forced to conduct rolling blackouts when power plants came offline because of harsh winter weather. Those outages would have “undoubtedly been far more widespread” had operators not been able to access power imported through interregional transmission lines, according to a Rocky Mountain Institute analysis. Additional interregional capacity would have allowed the Southeast to access available Midwestern generation, alleviating the region’s supply shortage.
Forward-looking studies evaluating the grid under extreme weather conditions predict similar results unless significant interregional transmission is developed. At least 65 GW of new interregional transmission capacity was needed to keep the lights on during simulated extreme weather conditions from 2035 to 2040, according to a recent report by GE Energy Consulting.
American homes and businesses depend on FERC to access reliable, economically efficient energy services at a reasonable cost. To ensure reliability and low prices, commissioners must evaluate ways to remove barriers to and encourage the development of these interregional projects. Three near-term options are available.
First, a minimum interregional transfer capacity requirement would provide significant reliability benefits by producing much needed long-range transmission. FERC, having convened a technical conference on such a standard in late 2022, should pursue a rulemaking to establish a minimum threshold.
Second, the commission should accept Invenergy’s petition and host a technical conference to discuss removing barriers to merchant interregional high-voltage, direct-current transmission lines. FERC’s current transmission-related rulemaking proceedings do not consider the evolving role of these technologies, and a technical conference would allow regulators to consider the costs, impact and utility of such projects, as the National Association of Regulatory Utility Commissioners noted.
Third, the agency should ensure its forthcoming transmission planning and cost allocation rulemaking includes needed reforms that can benefit interregional planning, as well as regional transmission planning. Requiring planning regions to quantify a minimum set of transmission benefits metrics can help eliminate one of the main barriers to planning interregional lines. Going forward, FERC should also lay the groundwork for a future rulemaking focused on reducing obstacles hindering interregional project development.
U.S. grid operators have seen several major system failures in the last several years. Our aging grid has demonstrated it cannot meet today’s demands, leaving millions at risk for extreme weather events in the coming decades. Expanding transmission capacity to ensure customers have constant access to affordable power will require sound policies to strengthen interregional ties. It’s time for FERC to act.
Ted Thomas is founding partner at Energize Strategies and former chair of the Arkansas Public Service Commission.
BALTIMORE — The first U.S. wind farms are being connected to the grid with one-off radial transmission lines, but as the industry grows it will have to follow Europe’s recent example and build out meshed high voltage, direct current (HVDC) systems, experts told the Business Network for Offshore Wind’s International Partnering Forum last week.
“Why are we thinking about doing this?” asked Judy Chang, a fellow at Harvard’s Kennedy School. “Overall savings, reliability, resilience, maximizing the integration of renewables while strengthening the grid through offshore systems.”
The Elia Group, which runs the grid in Belgium and eastern Germany, last year created a new subsidiary called WindGrid to pursue such offshore transmission opportunities.
Having an independent set of eyes looking at the infrastructure needed to connect offshore wind farms has worked well in Europe and now Elia’s new unit is starting to bring that business to the United States market, said WindGrid CEO Markus Laukamp. One of the big challenges in the U.S. is that transmission planning and generation develop at the same time in parallel tracks. That makes it hard to build out the transmission system, which takes longer to complete, he said.
“I think one of the challenges that we see for the U.S. is really to get these things in order so that maybe not next year — maybe five to 10 years — you can do things in the way that makes the most sense for the ratepayer and that is optimizing a coordinated grid,” Laukamp said.
New York is hoping to start planning a meshed offshore grid in tandem with its upcoming wind procurements, said Georges Sassine, vice president of the New York State Energy Research & Development Authority.
Sassine said he has been urging NYISO to run a public policy transmission planning process under Order 1000 to help bring renewable power into New York City both from on and offshore resources. The planning process for transmission should happen at the same time New York is working to procure the offshore wind that needs to be connected to the grid, Sassine said.
WindGrid is building an artificial energy island in the North Sea that will initially help connect wind farms to the Elia Group’s grid in Belgium. It has planned expansions to connect to Denmark and the United Kingdom, said WindGrid’s Thomas Kobinger. His firm is also building a similar project in the Baltic Sea to connect Denmark and Germany with multiple offshore farms via equipment on the Danish island of Bornholm. Such major projects have benefits for the onshore grids they are connected to, Kobinger said.
“We can reduce bottlenecks in the AC system. We can even reduce losses on the AC system. So, there’s a lot of benefits from a system perspective,” said Kobinger.
One idea is to connect wind to shore through shared corridors where multiple wind farms would plug into the same place on the grid onshore. Connecting corridors together in a mesh means that power could flow to multiple cities from one wind farm, said James Ware, senior electrical project manager for Ørsted. Meshed networks can cut fossil generation, avoid congestion, offer more flexibility to the system and can facilitate transfers during emergency situations, Ware said.
“But the question still remains … how far does the benefit go?” Ware said. “And who pays for it? And what is that cost?”
While figuring out where the costs and benefits of the HVDC links flow is tricky, they are obvious enough that many in the United States are already thinking of using them, including Public Service Enterprise Group, said its Offshore Wind Development Manager Rafael Wilches.
The states’ and federal government’s increased offshore wind goals require a “serious” look at multi-terminal HVDC systems, Wilches said.
Getting there will require bringing HVDC vendors, transmission owners, the ISO/RTOs and other stakeholders together to plan out such systems to make sure that different pieces can operate with each other. Funding from the federal and state governments would also help move the ball forward, Wilches added.
The U.S. has a long-term goal of getting 110 GW of offshore wind by 2050, which represents a lot of power that needs to get to land, said Hannah Taylor of the Department of Energy’s Wind Energy Technology Office.
“We need to do that … cost effectively, efficiently, equitably and responsibly,” Taylor said. “And we view multi-terminal systems and HVDC technologies as a pathway to get to that solution.”
DOE has multiple funding opportunities for research and development into HVDC technologies, and its Loan Program Office is available for the next step of helping new technologies reach commercialization, she said. DOE can also convene stakeholders to gather input on how best to interconnect growing offshore wind.
The department’s National Renewable Energy Laboratory is working on a project to help understand the protection and HVDC breaker needs for such off-shore circuits, said Taylor.
“That will be a key technology in realizing multi-terminal DC in the U.S.,” she said.
MISO said it created more than $4 billion in value for its membership over the course of 2022.
That’s according to grid operator’s 2023 Value Proposition, which calculates last year’s collective annual savings for members versus the lack of a resource sharing pool.
MISO said it has saved members about $40 billion since the value proposition was first calculated at about $1 billion in 2007. The RTO said the value proposition shows a $12 return for every dollar of investment in MISO membership.
“I’m proud that MISO continues to deliver substantial benefits to our entire footprint,” MISO CEO John Bear said in a press release. “We spend a lot of time with our members and stakeholders to better understand their needs and ensure alignment as our industry continues to rapidly change.”
As with prior years, MISO said its large geographic footprint accounted for most of the cost savings. It said its ability to share capacity saved members between $2 billion and almost $3 billion.
MISO said its energy dispatch efficiencies, where its real-time and day-ahead markets deploy the most economic resources, saved members from $620 million to $690 million. The RTO also said its renewable resource optimization — which connects low-cost renewable resources where they’re helpful, thus reducing the need for more capacity investment — saved members between $410 million to $480 million.
“We work tirelessly to ensure that our region receives the most out of MISO membership,” said Wayne Schug, MISO’s vice president of strategy and business development. “Reliably building and operating the grid of the future while supporting our members’ sustainability and affordability objectives requires close collaboration. As we advance the work discussed in MISO’s reliability imperative and enable the future grid, we expect the value proposition to grow substantially.”
“Reliability imperative” refers to the responsibility to ensure the clean energy transition occurs in a reliable and orderly manner.
