Lordstown Motors (NASDAQ:RIDE) announced late last week that the first two of 50 electric pickup trucks it plans to produce and sell this year had rolled off the assembly line at the former General Motors production plant in northeast Ohio.
But the future of the Endurance model and the company is still in question.
The sprawling factory is now owned by Taiwanese manufacturer Foxconn, which agreed to assemble the Endurance when it bought the 6.2 million-square-foot plant in 2021 for $230 million.
Foxconn is also planning next year to begin manufacturing a small electric car, the PEAR, designed by Fisker. The company has also announced plans to produce an electric tractor in the facility for a small California startup.
Lordstown said in a statement that the 50 trucks it expects to deliver to customers this year are “part of the first batch of up to 500 saleable vehicles we intend to build.”
“We will continue to build at a slow rate as we address remaining part pedigree and part availability issues. We expect to increase the speed of production into November and December,” CEO Edward Hightower said. The Endurance has been crash tested, but the results must still be certified.
The company also noted in a simultaneous filing with the U.S. Securities and Exchange Commission that its production and delivery schedule is dependent upon raising additional capital.
“We expect to deliver approximately 50 units to customers in 2022 and the remainder of the first batch in the first half of 2023, subject to raising sufficient capital,” it said.
The company expects to end the third quarter with “cash and cash equivalents of approximately $195 million” and would continue to explore “capital-raising alternatives,” including partnership discussions with Foxconn, according to the filing.
TEMPE, Ariz. — FERC Commissioners Mark Christie and James Danly spoke last week about the West’s pursuit of greater regional coordination, with Christie praising the region’s “organic” efforts to form one or more organized markets and Danly warning against RTOs that fail to promote competition and reliability.
The commissioners made their comments at the fall joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body, where CAISO, SPP and the Western Power Pool (WPP) pitched their planned market and reliability programs.
CAISO is planning an extended day-ahead market (EDAM) for its real-time Western Energy Imbalance Market (WEIM). SPP launched its Western Energy Imbalance Service (WEIS) and is developing Markets+, a bundle of services that stops short of a full RTO. And WPP’s Western Resource Adequacy Program (WRAP) has attracted participants from across the Western Interconnection. It expects to begin a preliminary phase of operations soon as it awaits FERC approval.
“You’ve got a lot of options in the West now that are percolating up, and what characterizes every one of these options — the WEIM, the WEIS, the Markets+, the EDAM and [the WRAP] — is that these are all organic, that are coming from you,” Christie said. “FERC didn’t tell you, ‘Here it is. Do it.’ They’re being developed by you … to meet your needs, and I think that’s what’s so exciting. I’m a big believer in organic, evolutionary change [that is] bottom-up … and not being forced down from FERC.”
Christie recommended Western stakeholders look at “another organic development,” the Southeast Energy Exchange Market (SEEM), an automated bilateral 15-minute market set to launch later this year.
What’s important to recognize, he said, is that the West does not have to choose between no cooperation and an RTO.
“That’s not the binary choice that you face,” Christie said. “There are a lot of points on the continuum, and it’s for you to pick and choose what points makes sense for you.”
Christie, a longtime utility regulator in Virginia before he joined FERC, urged Western regulators to protect the public’s interests when considering their utilities’ plans to join organized markets.
Oregon PUC Commissioner Letha Tawney, who shared the stage with Christie and moderated the discussion, asked how state regulators could balance their roles of making neutral decisions on regulatory matters before them and advocating for the public’s interests when dealing with organizations such as CAISO, SPP and WPP.
Christie, a founding member of the Organization of PJM States Inc. (OPSI), said a “critically important topic” would be whether to form similar advocacy committees of state representatives in the West.
“It is unrealistic to think that states are not going to be cooperating and working with your fellow state regulators,” he said. “I mean, whatever you choose in the West — whether it’s just an energy market, an energy market plus a day-ahead market, [or a] full RTO with all the bells and whistles — whatever you choose you really need an organization like OPSI” empowered to have an advocacy role.
Governance and cost-allocation are among the issues sure to be argued over, he said.
“Cost allocation in a multi-state RTO with radically different [state] policies is an extremely difficult nut to crack,” Christie said. “And you all are sitting out here in the West … [where] every state not named California has a concern about who gets to appoint the board.”
Danly Speaks
In a separate session, Danly warned that joining an RTO could have significant drawbacks, especially if the RTO cannot ensure it has adequate resources or fair competition.
“I often think that people are not quite perfectly aware of the costs and benefits that market participation has,” Danly said.
“There are undeniable benefits that the markets have delivered,” he said. “They have driven costs for power down. There are efficiencies of scale that are so attractive that even those regions that do not want markets have, as in the case of SEEM, tried to capture as many of those benefits as they can. And that may well be the model that’s used going forward, that people creep right up to the line of a full-on RTO but don’t quite cross that threshold.”
Even so, the costs of joining a market can be “multiple,” Danly said.
“My admonition to any state or utility that’s contemplating joining markets in the West … [is that] you to do it with your eyes fully open,” he said.
A frequent CAISO critic, Danly pointed out the ISO’s problems as recently as last month in maintaining resource adequacy during summer heat waves. On Sept. 6 the utility declared a stage 3 energy emergency, instructing utilities to arm for load shed. It narrowly averted rolling blackouts after the California Governor’s Office of Emergency Services sent out a text alert to millions of cell phones telling residents to “conserve energy now” or “power interruptions may occur.”
The message reduced demand by 2,100 MW in 5 minutes, the U.S. Energy Information Administration said Wednesday.
CAISO has declared energy emergencies the past two summers and initiated rolling blackouts in August 2020.
“One of the biggest [drawbacks of organized markets] is what I think are the fairly evident failures of some of the markets to ensure resource adequacy,” Danly said. “And this is something that in the West you’re well aware of because of very recent experience in having had a squeaker with the hot weather in California [and] merely having made it through that with the lights on.”
Markets that incentivize and subsidize certain types of resources, lowering costs, impede the competition that makes a market work, he said.
“If you have a market structure that does not insulate itself correctly [from anti-competitive forces], then what you’re going to find, as we see for example in New England, is that the jurisdictions in which the market operates are acting to undermine the very premise of the market,” he said.
New England, long troubled by tight natural gas supplies in winter, is facing a more limited supply this year because of the war in Ukraine and the century-old Jones Act, which prevents foreign-owned tankers from bringing U.S. liquefied natural gas to domestic ports and forces New England to rely on Russian LNG.
“Markets, especially in the case of capacity markets, are there to ensure that a sufficient quantity of capacity is delivered,” Danly said. “That’s done by a series of auctions in which market incentives are supposed to draw people into delivering the quantity and type of resources necessary to ensure that the system remains stable and has enough electricity.
“And yet, when you have state policies enacted that serve to suppress capacity prices, then you find yourself short,” he said. “And right now, we have a market in the Northeast in which the market has told us in public, on the record, in a FERC tech conference that given the constraints under which it operates … it is not possible to use market mechanisms to ensure resource adequacy. That should be a chilling prospect for anybody who is considering participation in a market.”
If reliability is a problem in New England, where states “have similar and in-parallel public policy goals … I would just suggest that people imagine what it would be like to join a full FERC-jurisdictional RTO [in the West where] you would have a market that has to be the ultimate deliverer of services and guarantor of resource adequacy for states as divergent in their public policy goals as, let’s say, Oregon and Utah.”
Pablo Vegas, who took over as ERCOT’s CEO on Monday, remembers well his previous time in Texas over a decade ago.
“There were some changes going on at the time,” Vegas told RTO Insider last week from his previous office in Dublin, Ohio, referring to a “big push” for building out advanced metering infrastructure. As COO of American Electric Power’s AEP Texas subsidiary, it was Vegas’ job to ensure advanced meters were successfully installed.
Of course, things have changed since then. ERCOT transitioned from a zonal market to a more granular nodal construct — Vegas was involved in that too — and a 2011 ice event just before Super Bowl XLV in Dallas that led to rare rolling blackouts across the Texas grid. Two years later, a $6.9 billion transmission build was completed, opening the door to the 47 GW of installed renewable capacity now on the ERCOT system.
Then came February 2021 and an icy storm that knocked out almost half of the system’s winter capacity, primarily thermal generation still unprotected from extreme cold weather after 2011, and brought it to within minutes of a total collapse. Those disastrous events have led to greater regulatory and legislative oversight for ERCOT and a lack of trust among many Texans of its ability to keep the lights on.
A recent survey by Data for Progress found power and grid issues, along with immigration, were considered more important for lawmakers to address than even gun violence and general economic issues. “Higher home energy bills are detracting from Texas voters’ quality of life,” the survey firm said, pointing to the financial effects of ERCOT’s conservative operations posture this summer.
So why take this job? Vegas was asked.
A couple of big reasons, he responded.
“One, working for an organization with a really significant purpose is very compelling. ERCOT operates a market that serves 26 million Texans, and it’s a market that is experiencing some of the most dynamic change in the energy industry, anywhere in the world,” he said. “The opportunity to come in and to provide leadership and influence in that kind of environment, with an organization with that kind of purpose, is extremely compelling.
“Then add that it’s in Texas, where our family had a great experience and truly enjoyed our time when we were there,” Vegas said. “It’s at a point in time where I think the opportunity to influence some of the changes that are going to be going on in the market is right in front of us. As a leader, you’re always looking for those opportunities to drive positive change and to create positive change in the work that you and your teams can do. It was really a very unique and special opportunity that was presented and that I was excited to talk to the board about.”
Vegas said he plans to “engage heavily” in the changes being made to the ERCOT market. The Texas Public Utility Commission is currently overseeing what could be significant revisions to the energy-only market by adding dispatchable generation requirements, a “capacity-light” construct once considered verboten in the state. Lawmakers recently asked to review the new Phase II market design before it’s handed off to ERCOT for implementation. (See Texas Lawmakers to Vet ERCOT Market Redesign.)
“I’m looking forward to seeing the results of the work that the team has been doing as well,” he said, adding that he will work with market participants to ensure that the design’s concept and framework “aligns with the overall goals” of legislation passed last year in the winter storm’s wake.
“I plan to dive in and work with all the market participants to help to define the pathway for implementing those Phase II redesigns and to do so in a way as quickly as we can do it reliably and safely,” Vegas said. “Phase II is looking at the longer-term changes that are needed to ensure that the electric market is going to grow reliably along with the economy and … building deeper agility to respond to significant weather events and stresses on the system like it’s been experiencing over the last couple of years. It’s critical. It’s going to be one of the more significant evolutions in the ERCOT market since the transition from zonal to a nodal market.”
Market participants have provided their input last year on the redesign to the PUC but have largely been sidelined since then. A consulting firm, the same one that proposed the load-side reliability obligation mechanism thought to be the construct’s central part, is reviewing the commission’s market proposal. Stakeholders expect the PUC’s final design to be released in November for additional public input.
Transition Phase
Given the increased political and regulatory direction ERCOT now receives, Vegas knows stakeholder management will be a big part of his job going forward.
“It’s making sure that you know how to collaborate with diverse groups that have diverse interests and priorities. That’s something that I’ve worked through my career,” Vegas said. “Having a deep understanding of the political landscape is important. … My history and my work experience have given me a lot of experience and exposure around stakeholder management. Understanding the importance of collaborating with political people is really all a part of the package.”
The ERCOT Board of Directors announced Vegas’ appointment in August, ending a search that dragged on for months. He replaces interim CEO Brad Jones, who replaced Bill Magness when the latter was fired last year after the winter storm. (See ERCOT Names NiSource’s Vegas as New CEO.)
Vegas, 49, comes to the position having spent the previous six years with NiSource, the last two as COO of NiSource Utilities. He was with AEP for 11 years before that, including his stint as AEP Texas’ COO. His compensation will exceed $3 million, significantly more than the $800,000 Magness earned before he was among the ERCOT board members and PUC commissioners cut loose after the storm.
Born in Peru, Vegas grew up in Indiana. He earned a mechanical engineering degree from the University of Michigan and attended the Harvard Business School’s Advanced Management Program. He and his wife and three children plan to move to Texas.
A background steeped in consulting, management, strategy, IT planning and utility operations would seem to have Vegas well prepared for his new role. He and Jones, who provided a candid public face in the interim, will work together for a transition period that ends after October.
“Brad has been incredibly helpful. I’m grateful to have had the opportunity to transition with him because he is such a knowledgeable and deeply passionate for the work of ERCOT,” Vegas said, noting he has been meeting with Jones every week. “He’s been helping me understand the ERCOT organization; its people; the leadership team. … He has helped me understand how the organization has been implementing the [legislative changes] and the recent operational changes.”
Vegas said Jones has caught him up on the market changes since he was last in Texas. He has also spent time with ERCOT’s leadership team in gaining an understanding of the commercial operations, market operations and back-office support functions.
“My takeaways are that, one, we’re ready. We’re ready for this upcoming season and the winter that’s coming. The changes that have been put in place have been validated and verified. We believe that the electric power providers are ready with the weatherization changes that they’ve made,” Vegas said.
“Two, the operating changes that we’ve made in terms of how we utilize the operating reserves … that those processes are ready and that they’ve been executing well. And three, many of the communications changes that have been made are also ready: … how we let people know when we need a conservation and letting people know what’s going on the grid,” he added.
“The big takeaway is that [Brad’s] handing over ERCOT to me in a very prepared and ready condition to take on this winter and then to take on the Phase II market redesign, when we know what that’s going to be.”
Support for Staff
Not everything is running well at ERCOT. Vegas acknowledged morale is low among staff, saying “it has been a difficult couple of years for all our staff.” Indeed, the grid operator’s 12-month rolling attrition rate has climbed to 12.2%, up from 8.2% in August 2021.
“Responding to a terrible crisis like we came out of is extremely difficult for any organization to maintain that sustained level of operational critical readiness. Such a severe event can be very stressful on an organization,” Vegas said.
He said he will work to ensure ERCOT’s staff know they have the regulators and lawmakers behind them and that they’ve “done a phenomenal job of ensuring the ongoing reliability” through one of the market’s “most challenging summers.”
“They have passed the test with flying colors, and so they should feel good about that. They should feel good about the future because we’re going to continue to invest in the work that they’re doing,” Vegas said. “This next evolution of the market design is going to further deepen the ability to deliver the work that we do reliably, and to support the reliable operations of the grid. Those employees at ERCOT get to be a part of that team that is going to chart that future and how we’re going to solve the challenges that brings and to deliver the next generation of successful entrepreneurs.”
PUC Adds Summer Requirements to Weatherization Rules
Texas regulators last week adopted expanded weather preparation rules for generators and transmission utilities during both summer and winter weather events, building on winterization rules passed last November following the devastating winter storm.
The order sets specific temperature standards for 10 geographically distinct areas in the state and establishes minimum and maximum temperatures at which generation owners and transmission utilities need to prepare their facilities to operate. The standards go into effect in 2023 (53401).
“The grid has to be ready for any weather condition, from extreme heat to extreme cold,” Public Utility Commission Chair Peter Lake said after Thursday’s open meeting. “These rules take that into account by setting the baseline preparation requirements for an operator at some of the most extreme weather conditions this state has experienced and requiring the operator to prepare their generation resources and transmission facilities to be able to operate in those conditions.”
Commissioner Will McAdams filed a memo before the meeting directing staff to add requirements that the industry account for wind chill in their cold-weather mitigation strategies. Power plants must weatherize their equipment to handle wind chills of 0 degrees Fahrenheit in most areas and temperatures of up to 96 F.
“I believe that given the cold weather conditions experienced in Texas during both 2011 and 2021, we should consider enhancing the staff-proposed rule by specifically accounting for wind chill based on a uniform weather zone-dependent standard,” McAdams wrote.
The expanded rule removes an exemption process adopted last year for utilities that could not meet mandatory preparation deadlines from supply chain issues or other acceptable reasons.
It also requires ERCOT to deliver a weather study that examines several weather parameters that can negatively affect the grid. The Texas grid operator must update this study at least every five years to account for variability in weather patterns.
The PUC also adopted a weather emergency preparedness report for the Texas Legislature that evaluated emergency operations plans developed by electric utilities, generators, municipally owned utilities, electric cooperatives and retail electric providers (53385).
The report’s authors reviewed 691 plans to identify best practices and assess the entities’ ability to manage emergencies from severe weather conditions and projected peak season conditions. They found 91% of the entities filed a complete report in a timely manner, the highest score among the seven criteria studied. Other criteria included emergency contacts (80%) and the plan’s content (69%).
PUC Appeals to SCOTUS
Following a closed session, the commission authorized its legal staff to appeal the 5th U.S. Circuit Court of Appeals’ recent decision siding with NextEra Energy’s challenge of Texas’ right-of-first-refusal legislation.
The Texas Office of the Attorney General will represent the PUC in the appeal. As of Friday, a petition for review had yet to be filed with the Supreme Court, a commission spokesman said.
SCT Proceeding Closed
The PUC closed its oversight proceeding on the Southern Cross Transmission Project, saying it agreed with ERCOT’s solutions to its 14 directives to determine whether the proposed DC tie can safely interconnect with the Texas grid (46304).
“Is it fair to say that we, the regulators, have completed everything we can at this point in the process and are handing the baton to the private sector, to run with it as far as it can?” Lake asked Commissioner Jimmy Glotfelty, who responded in the affirmative.
“And that’s an important part of how Texas approaches regulation. We want to take care of business that needs to be done for reliability and for our consumers, and then hand it to the private market,” Lake said.
The Southern Cross project would build 400 miles of double-circuit 345-kV line that would be capable of carrying 2 GW of energy into the SERC Reliability region. SCT has FERC approval and a waiver from its jurisdiction, keeping ERCOT free of federal overview and maintaining its status as an island unto itself.
The PUC opened a new proceeding (54166) requiring regular updates from ERCOT on the project’s development. Coordination and SCT’s market participant agreements must be executed before the Texas side of the project can be energized.
Glotfelty Joins WEIM Regulatory Body
The commission accepted an invitation to join the CAISO Western Energy Imbalance Market’s (WEIM) Body of State Regulators, assigning Glotfelty to represent the state’s interests.
The group provides a forum for state regulators to learn about the WEIM and related CAISO developments “that may be relevant to their jurisdictional responsibilities.” It can express a common position on market issues in the ISO stakeholder process or to the WEIM’s Governing Body.
El Paso Electric is a WEIM member.
The now 12-member body is chaired by Thad LeVar, who also chairs Utah’s Public Service Commission.
Maryland surpassed its greenhouse gas emission-reduction goal for 2020, according to the final data released by the state Department of the Environment.
According to the data, presented to the Maryland Commission on Climate Change during its quarterly meeting Sept. 27, emissions were down 30% below 2006 levels, beating out its aim to reduce GHGs released by 25% over the same period. Even accounting for the pandemic, which lowered expected pollution from motor vehicles, it is projected that emissions would have declined by 26% over the same period, still meeting the goal.
The most significant declines were in the energy sector, credited to the shift from coal to natural gas and renewable power generation. According to the department’s Vimal Amin, electricity-use emissions fell from approximately 43 MMT of carbon dioxide equivalent in 2006 to about 19 million in 2020.
“Two-thirds of our reductions from [2006] to [2020] have come from the electricity sector, and the reductions here are due to a combination of reduced electricity consumption, as well as changes in the generation mix, namely from replacement of coal-fired generation with natural gas and renewables,” Amin told the commission.
Despite the progress, Mark Stewart, climate change program manager for the department, said in-state clean energy generation lags behind being on track to meet the state’s Greenhouse Gas Emissions Reduction Act goals for 2030. One of the principal causes has been a backlog in reviews for new resources in PJM’s interconnection process.
“There’s been a backlog of projects receiving approval from PJM for connection to the grid, and a lot of these projects are renewable energy,” he said. “That PJM backlog has prevented the development of some projects. They’re working on a new system to fast-track some of those projects that are most ready to be implemented, so we’re optimistic that some of that backlog will be relieved within the next couple of years.”
The decline in energy sector emissions has left transportation as the state’s largest source of GHGs, at 35% of 2020 emissions, the majority of which is on-road vehicles. Amin noted that while the sector has also been seeing a general decline, the drop off going into 2020 is attributed to the COVID-19 pandemic.
The state is also currently lagging behind its 2030 goal of having about 800,000 electric vehicles registered in the state, which Stewart partly attributed to the pandemic reducing the inventory of new EVs on the market.
“On-road gasoline consumption is the biggest single source of emissions in Maryland, so we know the transition to zero-emission vehicles is a key component of the current climate plan and of future climate plans for Maryland,” he said.
Commission Reviews Federal Laws and Funding
The commission also evaluated the impact of the federal Inflation Reduction Act and Infrastructure Investment and Jobs Act on state emission goals, as well as how state and partner organizations are coordinating the use of federal funds.
William Ellis, vice president of government and external affairs at Pepco, said two provisions of the IIJA aim to provide resources for utilities to improve grid resilience under climate change. The utility is preparing concept papers that will allow for them to make applications once the submission period opens.
“It’s helping us to just think through and evaluate concepts related to those two topic areas. Some of the things that we’re thinking through are … undergrounding infrastructure, hardening our substations that could be impacted by climate change, as well as just creating a stronger and more resilient grid aimed at reducing outages through automation of controls, as well as enabling greater renewable penetration on the grid,” he said.
State Department of Transportation Deputy Secretary Earl Lewis Jr. noted that authorization of federal funds for the National Electric Vehicle Program was granted last month, allowing the state to go ahead with its work on installing EV charging stations at regular intervals along 23 identified alternative fuel corridors. (See FHWA Beats Sept. 30 Deadline for Approving States’ EV Charging Plans.)
“We’re working to expand Maryland’s robust electric vehicle charging infrastructure that currently has 1,266 charging stations and 3,475 charging outlets as of Aug. 31, 2022,” he said.
The state has also invested $436 million toward its ZEV program, bus pilots and electric bus procurements, with the first buses expected to arrive next year and a goal of converting half of its 700-bus fleet by 2030, Lewis outlined.
Maryland Energy Administration Chief of Staff Christopher Rice said his agency has been working with outside organizations to support their applications for federal aid, such as a $9 million carbon-capture entity paired with a cement factory; Montgomery County seeking 13 hydrogen fuel cell buses for $14.9 million; and a $22.9 million project with the Department of Labor to train workers for offshore wind installation and to upgrade Sparrows Point for OSW deployment. (See related story, Md. County’s Electric School Buses to Provide Synch Reserves for PJM.)
Stewart said that even with the new federal funds, the state’s shift to a goal of reducing emissions by 60% by 2031 under the Climate Solutions Now Act of 2022 leaves a gap in the trajectory of GHG reductions. One of the act’s provisions includes a 20-year global warming potential (GWP), rather than the prevailing 100-year model, which emphasizes GHGs that have a concentrated impact in their first few years after being emitted, most notably methane.
“The IRA did not end up being quite as ambitious as what we modeled last year as federal action, indicating that if we pair state [and] federal action under this framework, we’ll still have a lot of ground to cover to hit 60%,” Stewart said.
Arizona regulators say CAISO’s proposed extended day-ahead market could be a good opportunity for utilities in the state if issues of governance and resource adequacy are satisfactorily resolved.
“Independence of the governing structure is something that will be critical for Arizona,” said Arizona Corporation Commission (ACC) member Justin Olson. “If the CAISO can get that worked out where we have an independent governing structure, and they can address the resource adequacy policies in California, then the CAISO becomes a very attractive market for Arizona utilities.”
Commission Chairwoman Lea Marquez Peterson expressed similar views.
“An independent governance structure will be essential to my support,” Marquez Peterson said.
The comments came during a special ACC meeting on Sept. 21, where CAISO gave a presentation on its proposed extended day-ahead market.
CAISO runs the Western Energy Imbalance Market (WEIM), a voluntary, real-time market that was launched in 2014. Arizona utilities participating in WEIM include Arizona Public Service, Salt River Project and Tucson Electric Power (TEP), which joined in April.
CAISO is exploring an expansion of WEIM through an extended day-ahead market (EDAM). The ISO has been gathering stakeholder feedback on its plan and released a revised EDAM straw proposal in August. (See CAISO Updates EDAM Straw Proposal.)
In August 2021, an enhanced governance framework was approved for WEIM, in which decisions on certain issues are made through the joint authority of CAISO’s Board of Governors and WEIM’s Governing Body. The five members of the board of governors are nominated by the California governor and confirmed by the state Senate. The five members of the WEIM Governing Body are chosen through a stakeholder process, according to Stacey Crowley, CAISO’s vice president of external affairs.
Now, the WEIM’s stakeholder-run Governance Review Committee (GRC) has proposed extending the joint authority model to EDAM, Crowley said. GRC is asking for feedback on what types of decisions should be made through the joint authority.
Marquez Peterson said she’d like to see the joint authority widely applied.
“Ensuring that our voices are heard, and that we have the broadest extent of joint authority — that’s the direction I’d like to encourage,” she said.
Consequences Considered
Resource sufficiency is another issue being hammered out in the EDAM straw proposal. EDAM is not intended as a way for participants to bolster energy supplies when their own resources fall short, said CAISO COO Mark Rothleder. Instead, participants have more options for buying energy, potentially saving money.
The straw proposal would require EDAM participants to pass a day-ahead resource sufficiency evaluation (RSE).
“What exactly [do] you anticipate would be the policy if somebody does not have that day-ahead resource sufficiency?” Olson asked Rothleder.
Rothleder said two possible consequences are being discussed. One of those is a surcharge for failing to meet sufficiency requirements. In addition, he said, stakeholders are weighing whether there should be an “ultimate consequence” for resource insufficiency.
“If things go really bad, should you be able to still rely on those transfers, potentially impacting somebody else?” Rothleder said. “Potentially, the answer is ‘no.’ If you get in that position, and you’re not sufficient on your own, you shouldn’t be able to still rely on those transfers at the same level, or the same level of priority, as someone who did pass.”
Marquez Peterson asked what happens if CAISO is insufficient.
“If we are insufficient, we will follow the consequences,” Rothleder said.
Heat Wave Response
Rothleder also discussed CAISO’s response to the heat wave that scorched California from Sept. 5-9. Rolling blackouts were narrowly averted during the record-setting event, in which CAISO saw demand reach an all-time record of 52,061 MW on Sept. 6. (See California Runs on Fumes but Avoids Blackouts.)
Since the state’s rolling blackouts in August 2020, California has added more than 6,000 MW of capacity, including about 3,700 MW of battery storage. That capacity helped CAISO handle increased loads during the heat wave, Rothleder said. In addition, he said, coordination with other agencies has been improved.
And a few other factors worked in CAISO’s favor, Rothleder said. The heat wave hit the Pacific Northwest a bit earlier, taking some of the pressure off when high temperatures arrived farther south. Hydroelectricity was more available than usual for the time of year. And although temperatures in Arizona reached 107 or 108 degrees, the heat there wasn’t considered extreme, he said.
“This is very alarming to say the least,” Marquez Peterson said. “Without a moderate weather event in Arizona, California ratepayers would have been at public health and safety risk.”
In response to a question from Commissioner Sandra Kennedy, Rothleder acknowledged that CAISO was receiving emergency assistance from Arizona utilities and paying prices above $1,000/MWh.
Sam Rugel with TEP described the situation as “excellent for the ratepayers.”
“Being in the EIM, we were exporting throughout the day, day and night, into the Cal ISO market, in real time,” Rugel said. “And that does roll back to the ratepayers.”
But Rugel said the situation raises questions about resource adequacy.
“As much as this helps the neighbors … they should not be in this situation,” he said.
Regional Markets Explored
The ACC opened a docket last year for the purpose of investigating regional planning, markets and collaboration among load-serving entities in the Western Interconnection.
As part of its research, ACC heard a presentation in August from SPP on its Markets+ proposal, a program under development that will include a day-ahead market in the West.
In September, SPP announced that four Arizona utilities — Arizona Electric Power Cooperative, Arizona Public Service, Salt River Project and Tucson Electric Power — plan to support the next phase of Markets+ development. (See 4 Arizona Entities Commit to Developing SPP’s Markets+.)
ACC’s Utilities Division expects to file a report on regional planning and markets issues by the end of October.
A more than year-long test of 10 hydrogen-fueled semitrucks demonstrated that the vehicles can perform roughly equally with their 5-year-old diesel equivalents.
However, the maker of the trucks is staying mum about future testing and manufacturing plans.
The test runs at the Port of Los Angeles were financed by part of a $41 million Zero and Near-Zero Emissions Freight Facilities grant awarded by the California Air Resources Board, with the port as the prime applicant. The grant is part of California Climate Investments, a state initiative funded by billions of cap-and-trade dollars.
The Port of Los Angeles has set a goal of producing net-zero carbon emissions from its short-haul trucks by 2035.
A Kenworth truck manufacturing plant in the Seattle suburb of Renton made the trucks. Kenworth is owned by PACCAR, which is based in the Bellevue, Wash.
“We clearly showed that hydrogen is a viable clean fuel capable of powering commercial transportation for customers, matching diesel performance in range and power, with quick refueling for minimal downtime and smooth, quiet operation,” Joe Adams, Kenworth chief engineer, said in a Sept. 22 press release. The test runs ended in August
Toyota Motor North America and Kenworth joined forces to design and build the hydrogen-fueled semis. The trucks are Kenworth T680s built with Toyota hydrogen fuel cell electric powertrains, with water being the only emissions. The trucks went through initial tests at a PACCAR facility in Mount Vernon, Wash.
The Kenworth T680 FCEV truck — dubbed an “Ocean” — was supposed to work comparably with a 2017 diesel engine driving about 200-350 miles a day. The T680 FCEV has a range of more than 300 miles when fully loaded to 82,000 pounds.
The 10 test trucks normally worked one-day hauls around the Port of Los Angeles in the greater Los Angeles area. Toyota Logistic Services, UPS Total Transportation Services and Southern Counties Express were other freight carriers using the trucks.
The trucks frequently handled multiple shifts and ran 400 to 500 miles per day. Swapping out the hydrogen fuel cells took 15 to 20 minutes, according to the press release.
“Hydrogen infrastructure is still in its infancy, so hydrogen fuel is more expensive than diesel to fuel the truck,” PACCAR spokesperson Jeff Parietti said in an email. “We would expect the costs to come down as scale of production/distribution increases. Preventative maintenance is primarily a series of fluid replacements and inspections. So there is the opportunity for reduced maintenance costs over diesel.”
In the press release, Andrew Lund, Toyota chief engineer for zero-emission advanced product planning, said: “The potential for this technology as a replacement for higher-emission powertrains is real and supports both regulatory and society initiatives to combat climate change while helping us achieve our own goals of carbon neutrality.”
PACCAR and Kenworth do not have a prospective price tag for an individual T680 FCEV truck.
In a 2021 interview, port officials said the purchase price for a new diesel semi is $110,000 to $120,000, roughly $350,000 for a battery-powered semi and an estimated $1 million for a hydrogen-fueled semi.
In an email to Net Zero Insider, PACCAR declined to discuss its next testing and manufacturing plans.
MISO and SPP stakeholders expressed their consternation Friday over the RTOs’ proposed cost allocation for their interregional transmission planning initiative designed to ease overloaded generator interconnection queues.
The discord arose during a workshop over allocating costs for the grid operators’ Joint Targeted Interconnection Queue (JTIQ) study.
MISO and SPP plan to assign 90% of the $1 billion JTIQ portfolio to interconnection customers and the remaining 10% to an aggregate of their load. The RTOs said they will allocate a fixed, per-megawatt charge to interconnection customers that affect a facility in the neighboring region to pay for the portfolio. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)
The RTOs are proposing a 5% distribution factor (DFAX) impact threshold on a neighboring system before interconnection requests are considered in a JTIQ-affected system zone and therefore, subject to transmission-cost sharing.
“We want to ensure the cost related to these JTIQ projects … are certain and reasonable,” Clint Savoy, SPP’s manager of interregional strategy, said during the workshop. He said the RTOs continue to believe that a 5% DFAX results in the most equitable cost allocation among interconnecting generation along their seam.
Stakeholders responded by saying MISO and SPP haven’t provided enough analysis that the 5% criterion is the best route.
The staffs said when they employed a 10% distribution factor, generation eligible to share in transmission costs dropped by nearly 60%. When the factor was increased to 15%, eligible generation plummeted by about 80%, making network upgrade costs untenable for the remaining interconnecting generation.
“If you make the zone too small, you could potentially, I think, incent siting generation outside of the zone,” Savoy said.
Some stakeholders repeated calls for an 80-20% split between generation and load assignment. They said load stands to benefit more than the 10% portion of JTIQ transmission costs.
North Dakota Public Service Commission Chair Julie Fedorchak said the 90-10 generation-load cost-allocation split is almost moot because generators will bake their JTIQ upgrade costs into customer bills.
“Those costs will ultimately be paid by the load,” she said.
MISO and SPP are also proposing another regional study for generation projects that: either have a 10% or greater DFAX impact on the neighboring system or who affect a certain number of the neighboring RTO’s substations, based on voltage rating. The RTOs said the study is necessary to monitor new local constraints caused by the incoming generation not covered by the major JTIQ transmission projects. When that happens, the host RTO plans to coordinate with the other RTO and transmission owners to “formulate a mitigation plan to alleviate the identified localized constraints.”
Clean Grid Alliance’s Natalie McIntire said stakeholders have “discomfort” with the cost-allocation proposal because MISO and SPP cannot provide an understanding of the overall costs that new generation will shoulder.
“It’s hard to know how all of these pieces will fit together and whether the result is going to be workable for interconnection customers and will result in viable projects,” she said.
Savoy said though he knows stakeholders would prefer a predicted range of costs, that’s “impossible” to provide at this point.
“This is an incremental step forward. We can’t give you complete cost certainty,” he said. However, Savoy said the JTIQ allocation should lower interconnection customers’ costs and asked stakeholders to at least give the RTOs a chance to improve the process.
David Kelley, SPP’s director of seams and market design, said interconnection customers splitting the costs of larger, “backbone projects” that allow mass interconnections is preferrable to the grid operators’ current affected system study process, where often high-priced network upgrades are designated to individual generation projects.
“We have to come up with a way to fund the transmission needed in this area,” Kelley said. “Basically today, we have an area that generators cannot develop in.”
“We are in agreement that the status quo sucks,” National Grid Renewable’s Rafik Halim said.
Invenergy’s Arash Ghodsian said he was supportive of the initial design but asked for a better explanation of the assumptions of proposed cost assignments’ mechanics.
Many large emitters of greenhouse gases incentivize their executives insufficiently or not at all to reduce those emissions, a corporate watchdog group says in a new report.
The practice of linking executive compensation to progress on environmental, social and governance metrics is growing, with just over half of all S&P 500 companies reporting such a linkage in 2021, the nonprofit As You Sow said in “Pay for Climate Performance.”
The report focuses on the 47 U.S. companies on the Climate Action 100+ list, an investor initiative pressing for change by the world’s largest greenhouse gas emitters. It assigns the companies letter grades based on their inclusion of a climate metric in their 2021 CEO pay package; inclusion of measurable climate metric and measurable pay; and inclusion of climate metric in the long-term incentive plan.
Twenty-five of the companies had no explicit link of emissions to executive pay and got an F, while 17 got a D. Marathon Petroleum, Valero Energy, Southern Co. and American Electric Power got C’s.
Xcel Energy (NASDAQ:XEL) got the one and only B.
“Xcel Energy received a B for linking CEO pay to emissions-reduction performance in its long-term incentive plan, with a measurable amount of pay related to achievement of reduction goals,” the report’s authors wrote.
To get an A, a company would have to align its goals and incentives to the 1.5-degree Celsius warming target of the Paris Agreement. None of the 47 did this, the report found.
Other findings highlighted by the authors:
At most companies offering climate-based pay incentives, the sum involved was a small fraction of the overall compensation package and thus of negligible value as an incentive.
Company proxy reports were short on transparent disclosure, making it difficult to distinguish effective CEO pay links; transparency would increase by linking quantitative climate metrics to measurable pay.
Discretion is rarely used to alter CEO pay for financial metrics and should be equally rare with climate metrics.
Where climate incentives are dwarfed by financial performance metrics, emissions reductions will not be a priority for the CEO.
Climate incentives should be framed as quantitative metrics such as “reduce GHG emissions by 30% by 2030 over a 2021 baseline” rather than qualitative measures such as “progress efforts in support of the energy transition” or “demonstrate leadership.”
The report’s authors also give advice to investors hoping to drive climate progress at a company: “When considering the quality of the compensation and climate link, investors need to concurrently consider the quality of the company climate transition plan and its alignment with CEO pay. Investors should also pay particular attention to the interaction of compensation design and the rigor of the climate metric. A facile understanding of the nuances of compensation or the company-specific transition plan can result in the addition of a metric intended to appease shareholders that inflates pay and nothing more.”
As You Sow calls itself an organization “dedicated to increasing environmental and social corporate responsibility while increasing company value.” The nonprofit, formed in 1992, “envisions a safe, just and sustainable world in which environmental health and human rights are central to corporate decision-making.”
American Electric Power and Liberty Utilities, a subsidiary of Algonquin Power & Utilities, said Friday they have struck an amended sale agreement that cuts the price of AEP’s Kentucky operations by $200 million and extends the timeline to close the deal.
Liberty will now acquire AEP’s Kentucky operations at a reduced $2.646 billion through a purchase of all Kentucky Power’s and AEP Kentucky Transco’s stock. The original deal had Liberty paying a $2.8 billion sale price. (See PSC OKs Sale of AEP’s Kentucky Operations to Liberty Utilities.)
AEP expects to net approximately $1.2 billion in cash from the sale. It said the reduced revenue means that it will likely record a pre-tax loss ranging from $180 million to $220 million in the third quarter.
Liberty and AEP said they will close on the sale in January. The transaction was earlier slated to close by mid-2022. FERC must still approve the sale.
“This sale will provide significant benefits to customers in eastern Kentucky to help offset volatile fuel prices and support economic growth,” retiring AEP CEO Nick Akins said in a news release. “It also will support AEP’s ability to invest in projects throughout our regulated businesses that will enable the move to a clean, more reliable and resilient energy system.”
AEP CFO Julie Sloat, who will succeed Akins on Jan. 1, said that the new timeline will not affect AEP’s planned equity needs or its operating earnings guidance.
