Washington lawmakers are considering a bill to apply a per-mile charge to electric vehicles to compensate for expected lost gas tax revenue over the next few decades.
The bill (HB 2026) introduced by Rep. Shelley Kloba (D) calls for EVs to pay the state a “road usage charge” of 2.5 cents per mile starting in July 2025. That fee would be mandatory for EVs bought as of that date and voluntary for EVs purchased prior to that date. The mandatory annual fee would be capped at $225, while the voluntary fee would be limited to $175.
The bill would allow certain hybrid vehicles to participate in the road usage charge on a voluntary basis beginning July 1, 2026. The Washington State Department of Licensing and a joint subcommittee of the House and Senate transportation committees would be charged with evaluating the program and recommending improvements to the main House and Senate transportation committees by Jan. 1, 2029.
The money raised by the charges would go to various Washington transportation funds.
The Licensing Department would be required to offer EV owners one or more methods of reporting miles driven, including one based on submittal of periodic odometer mileage. The department also must offer one or more automated reporting methods. The state could use private sector services to manage the process.
At a Thursday hearing before the House Transportation Committee, Travis Dunn, vice president of consulting firm CDM Smith, said Washington’s gas tax revenues are expected to shrink by half by in the next two decades, assuming that 27% of the state’s vehicles will be EVs by 2040.
“Another factor is that cars will become more fuel-efficient and require less refueling,” said Reema Griffith, executive director of the Washington State Transportation Commission.
“HB 2026 gets us on a path to steady transportation revenue,” Rep. Emily Wicks (D) said. “The gas tax is a fleeting revenue source,” testified Jane Wall, executive director of Washington’s County Road Administration Board.
Inslee Wary of EV Fee
However, Gov. Jay Inslee opposes the bill in its current form, said Debbie Driver, Inslee’s senior transportation adviser. One objection was making the EV per-mile charge mandatory in 2025. “It could dissuade people from buying an EV,” she said.
Driver could not predict whether Inslee would veto all or part of the bill, if passed.
In a follow-up e-mail, Inslee spokesperson Mike Faulk wrote: “Our office’s concerns are there are still key untested elements to this policy, including the impact a mandatory [road usage charge] might have on a consumer’s choice to purchase a new EV, privacy concerns and impacts to low-income drivers with longer commutes.”
Faulk wrote that Inslee does not oppose road usage charges but wants more due diligence on the matter — especially on the effects of gas taxes and EV fees on the poor. If low-income families end up paying EV charges, the governor wants those charges to be less than what such families pay in gas taxes, Faulk said.
Faulk also noted that Inslee’s fiscal 2022/23 budget proposal asked for $100 million in rebates to make EVs accessible to low- and moderate-income Washingtonians. The proposed rebates are $7,500 for new EVs and $5,000 for used vehicles. Inslee has proposed an additional $5,000 rebate for people making less than 60% of the state’s median income.
At the hearing, EV interests and some EV owners supported the proposed charge. “It’s a more equitable approach for EV drivers to pay their share,” Peter Chipman, policy director for Plug In America, said.
Meanwhile, a half dozen private citizens testified against the bill, arguing that it would represent an extra unneeded tax.
“It’s too early to make such a systematic drastic change,” private citizen Eric Pratt said. “This assumes everyone will jump on the electric vehicle wagon,” Jeff Pack of Washington Citizens Against Unfair Taxes said.
Kloba said the proposed EV charge replaces tax revenue and does not add to drivers’ tax burdens.
Committee Declines to Recommend Additional FA Changes
The NEPOOL Markets Committee on Tuesday voted against recommending two pieces of a proposal from Competitive Power Ventures to change ISO-NE’s financial assurance rules.
The meat of the proposal, aimed at increasing the consequences for projects that don’t meet development milestones required for participation in the Forward Capacity Market, is under consideration by NEPOOL’s Budget and Finance Subcommittee. It would create new financial assurance requirements for projects that fail to meet certain milestones and add penalties for projects that fail to deliver physically by their commitment date.
But a new addition to the proposal voted on by the MC — to allocate forfeited financial assurance to all buyers and sellers in the market (rather than just sellers) — failed to get the support required for a committee recommendation. Also rejected were changes to the critical path schedule provisions in the proposal.
It was an especially timely conversation this week as a late court ruling on the Killingly Energy Center, which has challenged an RTO determination that it failed to meet development milestones, threw Monday’s Forward Capacity Auction 16 into chaos. (See Killingly Stays Alive After DC Circuit Halts FERC’s Termination Order.)
Committee Discusses ‘Mothball’ Option
The MC also continued work on a proposal by Sigma Consultants to make changes to the resource retirement process.
At Tuesday’s meeting, the discussion was specifically around whether ISO-NE needs a mechanic for resources to “mothball,” or exit service in a way that would later allow them to return from retirement. Sigma’s idea is to remove the “repowering rule,” which requires a minimum investment to re-enter service.
But Sigma’s Bill Fowler acknowledged in his presentation that major questions remain around the plan, including whether it should apply to permanent delists as well as retirements, and how retirement bids should be restructured.
The committee ultimately did not vote on the proposal. Fowler expressed frustration with a lack of responsiveness from ISO-NE.
“At the January MC, the ISO made clear that they are unable to support new stakeholder-driven proposals that are not in the work plan — at least for the foreseeable future,” his presentation said. “To resolve the bidding question, as well as ensure that the overall rule does not raise other concerns, we need ISO support.”
IMM Presents Fall Markets Report
Donal O’Sullivan of the ISO-NE Internal Market Monitor presented highlights from the IMM’s Fall Quarterly Markets Report to the committee.
Electricity costs in New England this past fall were up 67% over 2020. | ISO-NE
Fall 2021 saw large increases in wholesale market and energy costs over the same period in 2020, driven by higher gas prices and slightly higher loads.
A big increase in gas generation over fall 2020 offset a decline in net imports and nuclear generation in 2021.
Real-time reserve payments were up substantially last year over 2020, and uplift payments increased slightly but remained relatively low.
The Vermont House of Representatives’ Energy and Technology Committee has drafted a bill intended to align with the state Climate Action Plan’s call for the adoption of a Clean Heat Standard (CHS).
Committee members will continue to fine-tune the draft before introducing it in the House, Rep. Timothy Briglin said during a Feb. 1 meeting.
As drafted, the bill directs the Public Utility Commission to design and implement a CHS to reduce greenhouse gas emissions in Vermont’s thermal sector, which is responsible for one-third of overall state emissions.
The Vermont Climate Council’s initial climate plan, adopted in December, identified a CHS as a top pathway for decarbonizing building heating. About 70% of the state’s thermal sector relies on natural gas, fuel oil and propane. (See Vt. Climate Council Adopts ‘Initial Climate Action Plan’.)
Entities covered under the CHS would reduce thermal sector emissions by producing or buying clean heat credits to ensure the sector meets the carbon reduction requirements of the 2020 Global Warming Solutions Act. Covered entities would include natural gas utilities and fossil-based heating fuel wholesalers.
To obtain credits, providers could offer services for fuels or technology that reduce GHG emissions, such as advanced wood heating, cold-climate heat pumps, biofuels, renewable natural gas or weatherization. They also could purchase credits or hire a third party to provide clean heat services.
The draft bill excludes switching from fuel oil to natural gas as a qualified clean heat measure.
By September 2023, regulators would need to establish the number of credits — based on volume of sales — needed by providers annually for 10 years, starting in 2024. Updated 10-year plans will be due every three years.
A regulatory proceeding to implement the CHS would begin in August, and the PUC would have a year to finalize and adopt the standard framework.
Providers Respond
If Vermont adopts a CHS, it would put some of the state’s smaller fuel providers out of business, Paul Beauregard, owner of OnSite Propane, told committee members in Feb. 2 testimony on the draft bill.
OnSite, he said, would be “out of business Day 1.”
About 25% of the fuel providers in the market would be in that same position because they do not have a staff to install or service clean technologies, such as heat pumps, according to Beauregard.
“It will literally have tens of thousands of Vermonters scrambling immediately to find a provider to meet their needs,” he said.
Other companies that already have diversified from fuel delivery to meet the interests of customers who want cleaner heating solutions could fare better under a CHS, according to Rob Stenger, owner of Simple Energy.
Stenger has transitioned Simple to fit into what he says is a “wildly competitive market.” In addition to fuel delivery, the company provides HVAC services, blends fossil fuel with biodiesel, and installs solar systems and geothermal and cold-weather heat pumps.
But Stenger said in testimony that counting on companies to pivot like Simple is not a straightforward solution for Vermont.
While cold-weather heat pumps have become popular, they are not a reliable source in the extreme low temperatures of Northeast winters, according to Stenger. Furthermore, the skills needed to install and maintain the systems are not transferable from fossil technologies.
“There’s a ton of technical information and training that goes into selling and installing heat pumps properly and setting the right expectation for consumers,” he said.
New trade professionals are “unskilled and wildly expensive to employ,” he said, adding that it can be years before his company can recoup the investment on that labor. Revenues from fossil fuel delivery allow Stenger to invest in the extensive staff training needed to be a heat pump service provider.
The Energy Co-op of Vermont has adjusted to the energy market in much the same way as Simple, according to General Manager Brian Gray.
The cooperative delivers heating oil, kerosene and wood pellets; installs heat pumps; and performs energy audits and home weatherization retrofits. In the past year, its heat pump, weatherization and wood pellet sales accounted for 40% of revenues and “continue to grow,” Gray said in testimony.
Gray serves as a member of the Vermont Climate Council representing the fuel sector. His role on the council, he said, is to ensure fuel dealers have an opportunity to continue to thrive, and he believes a CHS aligns with that goal while meeting emission-reduction requirements. A CHS, however, will increase the cost of fossil fuels and leave Vermonters that cannot afford to switch to clean technologies with the burden of those higher costs, according to Gray.
Enhancing rebates and financing opportunities for fuel switching, he said, are key to making a CHS work.
The draft bill would direct regulators to “enhance social equity” by ensuring all customers can benefit from clean heat measures. At implementation, one-third of the clean heat credits needed to satisfy the standard would have to come from services to low-income households.
Committee members will hear more testimony on the draft this week.
Maine Gov. Janet Mills introduced a bill Wednesday that opens a new chapter in a long-standing effort to hold the state’s investor-owned utilities accountable for reliable and affordable electric service.
Bill Harwood, Maine’s newly appointed public advocate, applauded Mills for introducing the bill, saying in a statement that it will fill in “glaring gaps” in the state’s regulation of its utilities.
The Act to Ensure Transmission and Distribution Utility Accountability (LD 1959) would direct the Maine Public Utilities Commission to establish a performance report card for the state’s T&D utilities, with the possibility of imposing fines for not complying with performance standards. If a utility “consistently fails” to meet those standards, the commission would decide whether to sell off the utility’s assets, according to the bill.
If the commission were to move forward with divestiture, it would consider bids from potential buyers along with a proposal from a state-appointed committee to create a consumer-owned utility to purchase the assets.
The bill would have set reliability, cost and customer service metrics for the commission to determine whether the state’s two IOUs, Central Maine Power and Versant Power, are “fit to serve” Maine ratepayers. It also would have authorized the creation of a consumer-owned nonprofit, called Pine Tree Power, to purchase a utility’s assets, should it be found unfit.
CMP is owned by Spain-based Iberdrola via Avangrid (NYSE: AGR), while Versant is a subsidiary of Calgary, Canada-based ENMAX.
Our Power, a nonprofit supporting the creation of Pine Tree Power, began a citizen initiative in August to force a public vote on LD 1708. The group has collected 73% of the 60,000 signatures needed for the initiative, Stephanie Clifford, campaign manager for Our Power, said in a Jan. 19 statement.
To make the November 2022 ballot, all signatures were due Jan. 31, but the group said it will continue collecting signatures throughout this year for the 2023 ballot.
Our Power opposes the governor’s new bill for not aligning with the group’s goals, Wayne Jortner, former senior counsel for the Maine Public Advocate and lead petitioner for the ballot initiative, said in a Feb. 3 statement.
“We know all Mainers share our goals: thriving democracy, economic competition, a livable planet, and safe and affordable energy infrastructure,” Jortner said. “That is why our ballot question is built on those principles.”
The governor’s bill now goes to the Joint Energy, Utilities and Technology (EUT) Committee.
Rep. Nicole Grohoski (D), a member of the EUT Committee, does not believe the governor’s bill can provide relief for current high energy costs the way LD 1708 would. Grohoski co-sponsored LD 1708 and is a co-petitioner of the Our Power initiative.
“Maine people work hard for their money, while CMP’s and Versant’s far-off investors sit back in their cushy chairs siphoning off as much as they can get away with,” she said in a statement. Our Power’s referendum “frees us from this abusive relationship and offers net savings of $9 billion … with lower bills starting for us all on Day One.”
Mills received support for her proposal from a bipartisan group of EUT Committee members.
EUT Committee Chair Sen. Mark Lawrence (D) said he is “pleased” to work with the governor and committee members to move the legislation forward.
Signaling its commitment to blocking cyberattacks against U.S. critical infrastructure, the Department of Homeland Security last week stood up its first Cyber Safety Review Board (CSRB) to coordinate security efforts from the public and private sectors.
The CSRB is the product of an executive order issued by President Biden last year in response to the Colonial Pipeline ransomware attack. (See Biden Directs Federal Cybersecurity Overhaul.) At the time, the White House said Biden’s order was intended to “encourage private companies to follow the federal government’s lead and take ambitious measures to augment and align cybersecurity investments with the goal of minimizing future incidents.”
The board’s chair is Robert Silvers, undersecretary for policy at DHS; the vice chair is Google Senior Director for Security Engineering Heather Adkins. Currently there are 15 members; according to the CSRB’s charter, up to 20 people can participate. Representation is required from the departments of Defense, Justice and Homeland Security; the Cybersecurity and Infrastructure Security Agency (CISA); the National Security Agency; and the FBI.
Appointees from Microsoft, Verizon, the FBI, the NSA and cybersecurity firm CrowdStrike have also joined the board, along with National Cyber Director Chris Inglis. The group’s responsibilities are “solely advisory in nature”; it reports to Homeland Security Secretary Alejandro Mayorkas through CISA Director Jen Easterly, who is also responsible for its budget and for convening its meetings.
The board’s objectives are to “review and assess … threat activity, vulnerabilities, mitigation activities and agency responses” relating to significant cyber incidents, which 2016’s Presidential Policy Directive 41 defines as a cyber incident or group of incidents that will likely cause harm to U.S. national security or economic interests, foreign relations, or the liberties or public health and safety of the American people.
‘Most Serious Vulnerability’ Targeted First
For its first review, the CSRB will investigate the Log4Shell vulnerability discovered in December, which Easterly has called “the most serious vulnerability that I have seen in my decades-long career.” The zero-day vulnerability (meaning it was publicly disclosed before the vendor was aware or a patch was available) in Apache’s Log4j software library could allow remote actors to take control of affected systems.
Log4j is open-source software and enables logging of both errors and normal system processes, making it a vital feature for software in industries from gaming to finance. This means it is present in millions of devices and applications worldwide, giving attackers a wealth of opportunities to target a flaw that security researchers say is relatively simple to exploit.
The CSRB plans to issue its first report this summer: The document will review all vulnerabilities associated with Log4j, including threat activity and known impacts; mitigating actions taken by the public and private sectors; recommendations for addressing ongoing vulnerabilities and threat activity; and recommendations for improving general cybersecurity and incident response policies learned from the Log4j vulnerabilities. A public version of the repot will be available “with appropriate redactions for privacy and to preserve confidential information.”
“This is a once-in-a-generation opportunity to reshape how we draw lessons from cyber events and improve for the future,” Silvers said in a press release. “My colleagues on the CSRB are luminaries in the field, and I am honored to serve alongside them as the board’s chair. Together, we will conduct a thorough review and issue recommendations that will enable both our national leaders and the private sector to better secure our country.”
ERCOT comfortably met demand during last week’s latest round of winter weather, a welcome change from last February’s disaster under much more severe conditions.
Demand peaked at 68.9 GW Friday morning, far short of early projections of 75 GW and failing to eclipse record demand of 69.2 GW set during last year’s winter storm. Had demand reached last February’s estimated 77 GW that came after widespread and dayslong outages began, ERCOT would have handled that too, as it had as much as 22 GW of reserve capacity at times.
Customer outages topped out around 70,000 on Thursday, a result of ice accumulation and falling tree limbs on power lines. It was a far cry from the millions that were left without power for days last February. By Monday morning, Poweroutage.us was tracking 7,500 outages in Texas.
The weather helped too. Temperatures were not as low as they were last February, dipping into the 20s rather than single digits, with not more than 3 inches of snow falling northwest of Dallas. Houston’s low Friday was 26 degrees Fahrenheit, double last year’s low of 13 degrees, and sub-freezing temperatures lasted only 18 straight hours, compared to 44 consecutive hours in 2021.
Renewable energy, which initially took the fall from Texas politicians for last year’s shortfall, overperformed last week. Staff said that at times, wind farms were providing nearly a third of ERCOT’s power supply.
The ERCOT grid came within minutes of a total collapse last February as more than 51 GW of mostly thermal generation was rendered inoperable by freezing temperatures and ice. (See ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.)
Legislation passed in the wake of last year’s storm required all generation resources to be weatherized and allowed plants to burn alternative fuels, such as fuel oil. The grid operator released a winterization report last month that said 321 of 324 generation units and transmission facilities passed their inspections.
During a press conference Friday with Texas Gov. Greg Abbott and other agency officials at the state’s emergency operations center in Austin, interim ERCOT CEO Brad Jones said no significant power plant outages were reported — about 7.5 GW — and the number of resources that failed were below expectations.
“We believe the weatherization and our preparations have been extraordinary and are pretty successful,” Jones said.
Even the state’s natural gas system, widely seen within the electric industry as its Achilles’ heel, came through. There were some early production drops that regulators said did not cut into supplies — nothing like the 50% drop in production last year.
“We are operating as expected with natural gas coming into the system,” Texas Railroad Commissioner Christi Craddick said Friday. “Fluctuations in production have been brief and expected.”
The Railroad Commission, which regulates the state’s oil and gas industry, has yet to draft new weatherization requirement that likely won’t be in place until 2023.
Abbott was quick to jump on the grid’s performance. “The Texas electric grid is more reliable and more resilient than it has ever been,” he said during the briefing.
The governor later listed on Twitter the improvements he said had been made to the grid. “Fear-mongers should be ashamed,” he tweeted.
Alison Silverstein | Advanced Power Alliance
“Happily, this storm was not an arctic event, so the bulk power system held up well,” said Alison Silverstein, an Austin-based energy consultant and former FERC and Texas Public Utility Commission staffer. “But Gov. Abbott exaggerates the grid’s readiness for very cold winter weather.”
“Texas got lucky. The weather wasn’t that bad … so demand stayed below projections,” Stoic Energy president Doug Lewin said.
Silverstein told RTO Insider that ERCOT’s grid is “certainly more reliable and resilient” than it was before last February’s winter storm. She credited power plant winterization requirements, the PUC’s restructuring of energy pricing through a lower price cap and a modified operating reserve demand curve, and enabling additional demand response.
But, she cautioned, there is more work to do before the grid can be considered “truly more reliable and resilient.”
“ERCOT needs to better understand and serve short-term fast-ramping operational needs with resources like fast generation, demand response, batteries and virtual power plants. ERCOT also needs to improve its load forecasting and seasonal adequacy assessment methodology,” Silverstein said.
“But the simplest, lowest-cost way to make the ERCOT grid more reliable is to invest in energy efficiency for Texas homes and businesses, because lower, more manageable loads make it easier for the grid to be reliable and resilient every single day,” she said.
Silverstein said her biggest worry is “no one’s sharing the math for how much all of the ERCOT’s conservative operations measures are going to cost or whether the PUCT’s new market proposals are going to work, and at what cost.”
SPP, MISO Handle Demand
SPP returned its Eastern Interconnection footprint to normal operations Friday afternoon, saying it had enough generation to meet demand and available reserves, and that it did not foresee extreme or abnormal reliability threats.
The RTO issued weather and resource advisories earlier in the week but never resorted to conservative operations. Demand peaked at 40.6 GW Thursday morning, well below the grid operator’s record winter peak of 43.7 GW set last February.
Spokesperson Meghan Sever said icing outages and derates of wind resources were significantly less than predicted, as much of the icing occurred south of SPP’s main wind corridor. She credited action steps taken from the RTO’s comprehensive review of its response to the 2021 winter storm and the weather and resource advisories issued last week as helping meet the footprint’s demand.
MISO officials also used lessons learned from previous winter storms to “anticipate operational needs and identify solutions as quickly as possible” in easily meeting demand.
The RTO issued a severe weather alert and conservative operations for its Central region and Arkansas on Feb. 2-4, requesting members update their generation and transmission availability in its outage tracking system.
After two extremely dry years, California’s drought outlook grew more optimistic in December as major winter storms pushed mountain snowpack to 160% of average, but a rainless January and a lack of precipitation so far in February are clouding the prospects for hydroelectric generation this summer.
On Feb. 1, the state Department of Water Resources (DWR) said no snow in January meant the snowpack is now 92% of normal for the date. In the state’s Mediterranean climate, mountain snowpack typically accumulates from December to February and provides water and hydropower throughout a dry spring, summer and fall.
“We are definitely still in a drought,” DWR Director Karla Nemeth said in a statement last week. “A completely dry January shows how quickly surpluses can disappear. The variability of California weather proves that nothing is guaranteed and further emphasizes the need to conserve and continue preparing for a possible third dry year.”
DWR’s State Water Project is the fourth largest power producer in California, and hydroelectric generation historically supplies about 14% of peak summer capacity.
The state’s two largest hydropower-producing reservoirs were below half-full on Sunday. Lake Shasta stood at 36% of capacity and Lake Oroville at 46%.
The 644 MW Edward Hyatt Powerplant at Oroville Dam shut down for the first time in its history on Aug. 5 because the lake had dropped to critically low levels. After the December storms, the plant restarted one generating unit to supply electricity to CAISO’s grid.
The latest U.S. Drought Monitor map shows severe to exceptional drought persisting across much of the West in February. | U.S. Drought Monitor
“DWR anticipates an average outflow of about 900 cubic feet per second, which will generate approximately 30 MW of power,” the department said.
How long even that small amount of generation will last remains in doubt without additional rain and snow this year.
“January has turned out to be much drier than normal for most areas, essentially leveling off any meaningful gains in snowpack made in December,” the National Weather Service said Jan. 31. “A dry start to February is expected across much of the West, likely resulting in drought persistence for many areas.”
Snow water content in California peaked at 60% of normal in 2021 after a similarly dry winter in 2020, CAISO said. The ongoing drought reduced hydropower by 1,000 MW in 2021, the California Public Utilities Commission and California Energy Commission said last summer.
‘Big Hedge’ Against Falling Hydro
This summer’s hydropower supply is questionable, CAISO CEO Elliot Mainzer said in an interview with RTO Insider on Friday.
“We’re likely to be in somewhat better condition, but there is certainly no real sign that this broader trend of drought has really abated yet,” Mainzer said.
“Everybody’s now really carefully watching what February and March are going to hold,” he said. “We still certainly have the potential for some additional precipitation … but it is going to be a critical variable.”
The addition of hundreds of megawatts of solar generation and battery storage should help alleviate a hydropower shortfall, he said. The state drove a massive scale-up in battery storage after the rolling blackouts of August 2020, adding 2,250 MW by the end of last year to store solar power for peak evening use. (See CAISO Sees ‘Explosive’ Growth in Storage in July.)
California’s energy crises in the past two summers occurred during Western heat waves, when air conditioning demand stayed high after sunset, with limited imports available.
A similar scale-up is on track this year, Mainzer said.
“Right now, by June 1, we’re anticipating an additional 2,100 MW of storage, 1,200 MW of solar, 200 MW of wind, 40 MW of hydro, 30 MW of natural gas and 11 MW of biofuels, totaling 3,581 MW, of which 2,180 MW will be available at the net peak” on hot summer evenings, he said.
“So, the big hedge against continued decline in hydro is just working as diligently as possible to get the resources that have been ordered to be procured by the California Public Utilities Commission and other regulatory authorities onto the system,” Mainzer said. “We are super focused on interconnection capacity and working with the utilities to make sure that we get those resources onto the system without delays.”
Seeking a leading role in transportation electrification, Michigan will install the first electric charging roadway in the U.S. next year as part of a massive Detroit redevelopment project with Ford (NYSE: F).
The pilot project will involve up to one mile of roadway in the Michigan Central redevelopment project, which is restoring Detroit’s railway station, abandoned for 30 years until Ford purchased it in 2018.
Michigan Gov. Gretchen Whitmer (D) announced that the state had selected Israeli-based company ElectReon Wireless to handle designing, testing and implementation of the electric charging roadway. The state Department of Transportation will provide $1.9 million in funding, with ElectReon contributing the remainder.
The pilot project will allow charging of moving and stationary vehicles.
“A wireless in-road charging system will be revolutionary for electric vehicles, potentially extending their charge without having to stop,” said state Transportation Director Paul C. Ajegba.
ElectReon is developing technology for buses and trucks on their daily routes (left); slow-moving vehicles such as taxi queues (middle) and static charging at bus terminals, loading docks and parking lots (right). | ElectReon
Tim Slusser, Detroit’s chief of mobility innovation, said the city hopes the wireless charging project will attract other mobility technology companies “to help keep Detroit at the forefront of electric vehicle technology and mobility innovation.”
ElectReon (OTCMKTS: ELSWF) has wireless charging projects underway in Tel Aviv, Israel; Gotland, Sweden; and Lombardy, Italy for electric buses or electric heavy-duty trucks and partnerships with vehicle makers including Renault and Stellantis.
It says its technology would increase EV utilization and allow smaller, lighter batteries while addressing range anxiety.
The company last year announced a five-year, $9.4 million project to provide inductive charging for a 200-bus transit fleet at existing stations near Tel Aviv.
The Michigan Central project is part of an “innovation district” and will involve a public-private partnership with the state spending $126 million in new and existing programs.
In building the roadway, ElectReon will work with Jacobs Engineering Group, of Dallas and Detroit-based nonprofit NextEnergy, which focuses on “smart mobility” and smart grid innovation.
NYISO staff Thursday briefed the Installed Capacity/Market Issues Working Group on the schedule for the ISO’s initiative to develop market participation rules for internal controllable lines.
With no internal controllable lines currently operational in New York, the ISO has only some “bare bones” rules in the capacity market that could structure participation of internal unforced capacity deliverability rights (UDRs), said Amanda Myott, energy market design specialist. There are no related rules for energy market participation.
New York in September selected two transmission projects as Tier 4 renewable resources under its Clean Energy Standard. If approved by the Public Service Commission, the 1,300-MW, 174-mile Clean Path New York transmission project is likely to be the first internal controllable line in the state. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)
NYISO will begin by developing energy market rules and then, based on those rules, evaluate if there are any needed revisions to capacity market rules for UDRs.
“Modeling of internal controllable lines within resource adequacy studies will also be an important consideration when determining ICAP market rules,” Myott said.
The working group will discuss energy market designs through April before beginning to talk about the capacity market that same month. The goal is to have a completed proposal by the end of the year.
TAC Members Look for Direction on Governance Structure, Stakeholder Process
ERCOT market participants again expressed their concerns last week with potential changes to the stakeholder process following discussions during last month’s Board of Directors meeting.
The newly reconstituted board reviewed the grid operator’s corporate governance structure and project portfolio and discussed bylaw revisions and other changes. The directors also pressed staff on the many system projects they are working on. (See “Board Discussions,” Texas PUC Pushes ERCOT on Market Changes.)
It followed a tense Technical Advisory Committee meeting in July, when members pushed back against interim CEO Brad Jones’ proposal to convert the committee into one “comprised of senior-level members from each ERCOT member organization.” An August workshop to discuss TAC’s future membership and its interaction with the incoming board was canceled. (See “Members Push Back Against Revamped TAC Structure, Conservative Ops,” ERCOT Technical Advisory Committee Briefs: July 28, 2021.)
TAC currently has 30 members comprising primarily subject-matter experts representing six different market segments. Some members argued last summer that adding officer-level representatives would only slow the committee’s work down.
Morgan Stanley’s Clayton Greer, representing the independent power marketer segment, asked during TAC’s Jan. 31 meeting whether the board, which met in lengthy executive sessions during the two-day meeting, had given any direction to “reformat” ERCOT’s stakeholder process.
“It sounded like they wanted some change, but there was no direction,” Greer said.
South Texas Electric Cooperative’s Clif Lange, TAC’s chair, attended the board meeting. He told Greer that what he heard was more informational for the board and intended to give the directors comparisons between ERCOT’s and other grid operators’ governance structures.
“Nothing I heard that day gave us any direction for us to do anything at this point,” Lange said. “It’s certainly within the purview of the board to determine how they want to establish their committees and subcommittees. I didn’t get the feeling from the room that there was any immediate move to want to do that.
“Whether board members are discussing that offline, something we’re not privy to, that could be ongoing,” he added.
Greer noted the “pile of stuff that we go through as stakeholders” and asked again whether there was a plan to create a better process or methodology for managing change requests.
“The work that gets done … it can be managed any number of ways,” he said. “We selected [the current process] … because for the most part, it’s been effective. It gives a fair hearing to everything and gives everybody a chance to vote on these things. Without a problem statement or understanding what we’re doing wrong, I don’t get how we can get to a better spot without direction.”
Lange allowed that ERCOT’s stakeholders are “keenly interested” in any decisions the board may make on the stakeholder process’ future, telling RTO Insider that he is optimistic the board “still finds value in the collaborative efforts of stakeholders, ERCOT and the” Public Utility Commission of Texas.
“It would be a shame if the stakeholder process was abandoned or significantly diminished, since extraordinary work products have come forth from that collaborative process over the last 20 to 25 years, including the nodal market design and implementation, real-time co-optimization, and ancillary services redesign,” Lange said. “That all occurred while meeting the challenges of tightening reserve margins and with the unmatched integration of significant renewable and storage assets.
“ERCOT does a great job in identifying reliability and market flaws and in defining the objectives that they want to target to address those findings, but they don’t always have the in-house capability to understand the full ramifications of their objectives,” he said. “Stakeholders collectively see the full range of impacts, including financing, development and construction; wires and generator operation; the retail markets; and ultimately the impact to consumers. It is this expertise, combined with the expertise and policy direction provided by ERCOT and the PUCT, that helps to provide a more comprehensive solution. I strongly hope the new board finds value in the stakeholder process and the debate that has allowed for some very good and comprehensive solutions to be developed.”
ERCOT has already responded to the board discussion by creating a Technology Working Group that provides a forum to share information; review, analyze and develop best practices; and improve market participants’ and the grid operator’s information and operational technology systems and software applications.
The group will be independent of the TAC subcommittee structure, similar to the Regional Planning Group and the Gas Electric Working Group. It’s scheduled to hold its first meeting Thursday.
Staff Rushes Firm-fuel Product
ERCOT staff have drafted a nodal protocol revision request (NPRR1120) that creates a firm-fuel reliability product as directed by state legislation last year and the PUC.
The commission’s first phase in redesigning the ERCOT market calls for a standalone, auction-based product that is procured similar to ERCOT’s black start program. The PUC sees the firm-fuel product compensating dispatchable generation resources that meet a higher standard of “firm” winter-weather resilience and reliability and serving as a stopgap should weatherization not be incorporated into a load-serving entity obligation. (See PUC Forges Ahead with ERCOT Market Redesign.)
Kenan Ögelman, ERCOT’s vice president of commercial operations, told TAC that in order to deliver the service by next winter, staff are focusing on the “long pole in the tent,” which is completing the settlement and billing system’s changes. He said additional requirements will be reflected in a request for proposals that will quickly follow the NPRR’s approval.
“We’re going to take more time to develop and will put those parameters into the RFP to procure the service, Ögelman said. “The commission has asked for more time to weigh in on those parameters.”
Greer pointed out that TAC would be expected to pass the NPRR’s language regardless of its accuracy. “I don’t know how you create a straightforward RFP unless you have on-site storage capacity,” he said, adding that coal piles and nuclear rods should also be considered.
“There is an interest is going beyond on-site fuel oil. We want to leave that possibility open, but that would require another RFP and potential protocol language,” Ögelman said. “There are going to be gaps in the RFP that will make the RFP pretty not standard and non-substantial. There are a lot of requirements for the resources that will have to be in the RFP to get this NPRR through.”
Members and staff agreed to set up a workshop to hash out further details on the NPRR and RFP. In the meantime, the Protocol Revision Subcommittee is scheduled to vote on the NPRR during its Wednesday meeting. Staff hope to have the board consider the measure during its March 7-8 meeting.
RUC Usage Skyrockets
ERCOT’s heavy use of reliability unit commitments (RUCs) last year as part of its conservative operations approach resulted in 4,052 instructed resource-hours and 3,853.1 effective resource-hours, an 18-fold increase from 2020. The bulk of those hours (3,361, or 87%) came to meet capacity needs during the latter half of the year, when the grid operator began deploying more resources sooner to improve the system’s reserve margin following last February’s disastrous winter storm.
The difference between “instructed” and “effective” values is because of resources starting up, shutting down, partial hour instructions or otherwise not being dispatched.
ERCOT only called for 224 RUC instructed resource hours in 2020, resulting in 220.1 effective hours.
Reliability unit commitments have soared with ERCOT’s conservative approach to grid operations. | ERCOT
“Compared with previous years, the size of resources getting RUC’ed has not changed much,” ERCOT’s Dave Maggio said.
Last year, ERCOT issued approximately $5.3 million in make-whole payments, almost exclusively covered through capacity-short charges. The total RUC claw-back charge was about $3.1 million.
The Independent Market Monitor is sponsoring NPRR1092, currently before the Protocol Revision Subcommittee. The measure would reduce the $1,500/MWh RUC offer floor, designed for a market construct where RUCs were expected to be self-committed.
Texas PUC Chairman Peter Lake supports the NPRR and has filed a memo siding with its $75/MWh offer floor. He said that will still allow resources to increase offers in accounting for higher fuel prices and will be consistent with non-spinning reserves’ price floor.
“We expect to expect to see improved performance of self-committed resources,” IMM Executive Director Carrie Bivens said.
Stakeholders Eye Load Resources
TAC and staff agreed to work together in creating a task force and scheduling a workshop to address load resource issues as Texas becomes a haven for cryptocurrency miners and other loads that can add energy to the grid. Several stakeholder groups have discussed load resource issues, including how to price them and whether or they are controllable resources.
Texas Gov. Greg Abbott and U.S. Sen. Ted Cruz (R) have led the charge in encouraging Bitcoin miners to set up shop in the state, where their ability to shut down quickly can help the grid during scarce conditions. The Texas Blockchain Council lobbying group says there are already more than two dozen crypto miners in the state.
“Clearly, when the governor and a U.S. senator invite cryptos to come to town, we need to figure out quickly how we can get them reliably connected to the grid,” energy consultant Bob Wittmeyer said. “This issue is much bigger than crypto, which can potentially add hundreds of megawatts to the grid in a period of months. We need to move pretty expeditiously here. We’ve got [transmission and distribution] issues, different metering configurations, co-location issues and issues with resources that choose not to be controllable load resources. We really need to talk about this from multiple levels.”
Several stakeholder groups have already discussed issues surrounding load resources and floated a scope document for the task force. Staff said they need time to better understand the issues before hosting a “meaningful” workshop.
“We need a basics-type of discussion on what these loads are,” Greer said. “It sounds like a lot of these business plans for these guys involve co-locating with either energy storage or generation, or both.”
TAC agreed with Lange’s proposal to have stakeholders and staff begin laying out ideas and bring them back for the committee’s Feb. 23 meeting. The workshop will be held at the TAC meeting, and the task force could be established in March.
Staff Work to Improve Communications
ERCOT staff worked to ease members’ concerns as last week’s winter storm approached, telling them that internal and external communications have both been improved.
“Right now, everything is business as usual at ERCOT,” Chris Schein, interim communications leader, said in providing TAC an update on the grid operator’s efforts.
Schein said ERCOT now conducts daily calls with market participants’ communicators; it has set up a regular cadence for external messages; and it has completed internal and external audits of its communications practices. The internal audit looked back at ERCOT’s communications during the storm, and the external audit looked forward at best practices to address insufficient staffing, inconsistent messaging, uncertainty among the market’s communicators and flawed energy emergency alert (EEA) communications.
The grid operator had fewer than two staffers devoted to media communications during last year’s storm, “insufficient for an organization the size of ERCOT,” Schein said. Outside contractors will help it “dial up or dial down” communications as needed, he said.
ERCOT has made changes to improve its communications. | ERCOT
“Frankly, ERCOT, under the leadership of Brad Jones, has clearly communicated that we are going to be aggressive in calling for conservation alerts,” Schein said. “It’s an effective tool for ERCOT to use. We’ve been working very hard the last seven months with the news media so they understand conservation alerts do not mean EEAs.”
Mark Dreyfus, who represents several cities in the commercial consumer segment and who requested the update, said communication is a two-way street and that many of his constituents need to trust the messages they’re receiving from ERCOT during an emergency.
“I just don’t think we’re there because of the dramatic loss of trust in the community that occurred [last year] with the storm,” Dreyfus said. “We have to engage with those groups to ensure ERCOT is a trustworthy source of information.”
Indeed, a recent University of Houston survey found that if there are more power outages because of cold weather, 70% would hold the grid operator responsible.
Schein agreed ERCOT lost trust during last year’s winter storm. “I’m not making any judgments as to whether it was worthy or not, but it happened,” he said.
“Building trust takes years; losing trust takes seconds. We are in the process of rebuilding trust. It will take time,” Schein said. “We’re at a phase now where it’s trust and verify. We not only have to say things; we have to live up to things so these various audiences will look at us and say, ‘Yes, they did what they said they were going to do.’”
Lange Re-elected TAC Chair
Committee members re-elected Lange and Just Energy’s Eric Blakey to serve once again as their chair and vice chair, respectively, this year.
ENGIE’s Bob Helton, who nominated Lange and Blakey, said he did so because their leadership during a “very difficult year … got us to some places we needed to go.” Helton, who has served as both chair and vice chair, said he looked forward to working with them to finish up ERCOT’s market designs and other issues.
“We have a lot of ground to cover, particularly with the ongoing market-reform issues and anything else that pops up that is unforeseen now,” Lange said. “We’re looking forward to another great year, and a challenging year, for sure.”
Members also confirmed TAC’s subcommittee chairs and vice chairs for 2022:
TAC unanimously approved its combo ballot, which included two other binding document revision requests (OBDRRs) related to recent PUC orders to reduce the high systemwide offer cap (HCAP) from $9,000/MWh to $5,000/MWh and to raise the operating reserve demand curve’s (ORDC) minimum contingency level from 2,000 MW to 3,000. Both changes were effective Jan. 1. (See PUC Forges Ahead with ERCOT Market Redesign.)
OBDRR037 caps the power balance penalty curve at $5,001/MWh (the HCAP plus $1/MWh), effectively setting the curve’s price at its maximum value when violations are above 100 MW. The measure also reduces the generic transmission constraint shadow-price cap for base case voltage violations from $9,251/MW to $5,251/MW. Gray box language describes how the curve will work with the new HCAP upon real-time co-optimization’s implementation.
OBDRR038 updates the ORDC’s minimum contingency level to 3,000 MW within the relevant methodology document.
The combo ballot also included seven NPRRs, two Nodal Operating Guide revision requests (NOGRRs), an additional OBDRR, two modifications to the Retail Market Guide (RMGRRs), three system change requests (SCRs), and single changes to the Planning Guide (PGRR) and the Verifiable Cost Manual (VCMRR).
NPRR1095: contains revisions that the Texas Standard Electronic Transaction (Texas SET) Working Group has determined are necessary to support the Texas SET V5.0 improvement list.
NPRR1098: establishes reactive power capability requirements for new DC ties interconnecting to the ERCOT system and existing DC ties replaced after Jan. 1.
NPRR1099: grants ERCOT greater authority to move a resource node in the network operations model when deemed necessary to properly reflect point-of-interconnection (POI) changes or resource retirements.
NPRR1102: allows ERCOT to adjust back-casted non-interval data recorder load profiles.
NPRR1111: expands the use of the security-constrained economic dispatch (SCED) base point below the high dispatch limit flag to signify that ERCOT has instructed an intermittent renewable resource (IRR) or DC-coupled resources not to exceed its base point.
NPRR1113: adjusts the real-time ancillary service imbalance payment/charge’s definitions to prohibit double-counting of the regulation-up schedule when calculating capacity in the imbalance settlement for controllable load resources available to SCED.
NPRR1114: establishes processes to assess and collect securitization uplift charges to qualified scheduling entities representing LSEs pursuant to one of the PUC’s two debt obligation orders (52322).
NOGRR234: revises the guide to be consistent with NPRR1098’s reactive power capability requirements for DC ties, specifying DC tie operator responsibilities related to real-time operational voltage control.
OBDRR034: allows ERCOT to move network operations model resource nodes for POI changes or resource retirements.
PGRR099: provides that an entity will not be eligible to begin or maintain a generator interconnection or modification (GIM) if it or any other owner of the project meets any of the company ownership (including affiliations) or headquarters criteria listed in the state’s Lone Star Infrastructure Protection Act. Any entity that seeks to initiate a GIM will be required to submit an attestation confirming that it does not meet the statutory criteria.
RMGRR166: revises the timing for retail electric providers to access the daily switch hold files that are posted by the transmission and/or distribution service providers.
RMGRR169: updates the Texas SET’s continuous service agreement (CSA) bypass validations at ERCOT; allows for rejection of move out (MVO) transactions if the CSA owner and MVO competitive retailer (CR) do not match; allows ERCOT to issue a move in transaction for the appropriate CSA CR when an MVO is submitted; and revises the inadvertent gain process to align with SCR817’s proposed MarkeTrak enhancements.
SCR816: unlocks congestion revenue right bid credit on the same day auction results are posted.
SCR817: adds validations/requirements to existing MarkeTrak subtypes, revises existing workflows and suggests new subtypes to align with current market practices for more efficient issue resolution.
SCR819: improves dispatch of base points to resources to account for the ramping of un-curtailed IRRs.
VCMRR032: clarifies that the average run time per start is calculated by dividing the total running hours by the total number of starts during the 20-consecutive-day period. It ensures that at a minimum, one start will be used in the calculation of the average run time per start when the resource is operating on the first interval of the first day of the 20-consecutive-day period.
