A coalition of builders and other parties has filed suit to revoke new Washington rules that ban the installation of gas-fired space and water heaters in new homes and commercial buildings starting this summer.
The 22 plaintiffs filed the suit Feb. 28 in Thurston County Superior Court. They include the Building Industry Association of Washington, the Northwest Regional Council of the National Construction Alliance, the Central Washington Home Builders Association and several construction companies.
The complainants are contesting regulations the Washington State Building Code Council (SBCC) passed last year and early this year that require builders of new homes, apartments and commercial buildings to install heat pumps for both space and water heating starting July 1. The lawsuit contends that the rules exceed the legal authority of the SBCC, which is appointed by the governor.
“The Council’s sweeping prohibition on HVAC heating energy provided by fossil fuel combustion appliances and the prohibition of all but electric air-source heat pump water heating in … buildings exceeds the statutory authority of the agency,” the lawsuit says. “The rules allow no flexibility in design, construction, and effectively eliminate available heating equipment efficiencies. Furthermore, the rules will have the effect of increasing the cost of constructing and maintaining commercial buildings, which include multifamily complexes, and will not yield the lowest overall cost to the building owner or occupants as statutorily required.”
The SBCC enacted the rules after bills introduced in the Washington House to eliminate natural gas appliances for space and water heating failed in both 2021 and 2022.
Also represented in the suit are the Pacific Propane Gas Association; the Northwest Hearth, Patio & Barbecue Association; an Everett-based restaurant group; a heating and cooling installation company; an individual homeowner in Vancouver, Washington; and a landowner and “prospective building applicant.”
Justin Driscoll, acting CEO of the New York Power Authority (NYPA), met with the New York Senate Energy and Telecommunications Committee last week to discuss how the authority’s duties have evolved and the role of new technologies in decarbonization.
Driscoll told the Feb. 28 live-streamed session about NYPA’s growing “statewide footprint” and how NYPA is the “backbone of the [state’s] grid,” operating 16 electricity facilities, including three hydroelectric and several gas-fired generators, as well as more than 1,400 circuit-miles of transmission.
NYPA also is partnering on the Smart Path Connect, a project to rebuild and strengthen about 100 miles of transmission in the North Country and the Mohawk Valley, and the Propel NY Energy project to improve the grid on Long Island, New York City and Westchester County. Other NYPA initiatives are directed at improving transmission cybersecurity and reducing consumer costs, such as ReCharge NY, Driscoll said.
Sen. Mario R. Mattera (R) questioned NYPA’s investments in battery charging stations, asking “why ratepayers should pay for an investment that is already being made by the private sector.”
Driscoll responded that “we need to use all the tools in our toolbox.”
“Given the enormity of what we’re looking to achieve, I believe NYPA and government can play an ancillary role in the energy transition,” he said.
Sen. Mark Walczyk (R) asked for Driscoll’s perspective on NYPA’s role in the future.
Driscoll said that NYPA’s role is “additive” to what is currently going on in the private sector.
Sen. John Mannion (D) asked whether NYPA was investigating nuclear energy, particularly small modular reactors (SMR).
Driscoll said New York would not be a national leader in nuclear development but that NYPA has interest in the potential deployment of SMR and is following development of the technology.
Mattera asked whether green hydrogen has a future in the state.
“Hydrogen will certainly play a big role,” Driscoll said. “But the question in the industry is really what is the right role.
“It is too early to say whether hydrogen will play a role in the power sector,” Driscoll said, adding there are “big use cases in the heavy industry sector, particularly cement manufacturing or public transportation.”
The discussion on hydrogen follows previous Senate hearings at which senators expressed an openness to innovative technologies.
Sen. Kevin S. Parker (D), chair of the committee, said New Yorkers “are struggling with high cost of heating their homes, lighting their homes, and we need to find ways to address that.”
Parker told Mattera that he supports emerging technologies, such as hydrogen, and that he “doesn’t think we are in different places,” but it is simply a “question of how we get from point A to point B.”
A central New York nuclear power plant is the first in the nation to generate its own hydrogen, Constellation Energy Group (NASDAQ:CEG) and the U.S. Department of Energy announced Tuesday.
The agency and company shared costs on the project at the Nine Mile Point Nuclear Plant, which is one of four DOE hydrogen demonstration projects underway at reactors.
The hydrogen generation system went online in February, several months after its projected late-2022 startup. It produces 560 kilograms of hydrogen per day with an hourly 1.25-MW draw on the 1,907-MW output of Nine Mile’s two reactors.
Hydrogen is used on site for cooling, and previously was trucked in, but Constellation said the output of the new system exceeds the needs at Nine Mile.
Nine Mile is simultaneously working with the New York State Energy Research and Development Authority on a demonstration project that will use hydrogen fuel cell technology to provide long-duration energy storage and is targeted to be operational in 2025.
Hydrogen, which burns without producing greenhouse gas emissions, is potentially a key tool in fighting climate change. It could serve as a form of energy storage and is viewed as an alternate power source for industries and applications that otherwise would be hard to decarbonize.
But the cost of production currently is a barrier to wider use. DOE made reducing that cost by 80%, to $1/kilogram, the central goal of the first of its Energy Earthshots in 2021.
Interest is keen in green hydrogen — derived from renewable energy sources — because generating greenhouse emissions to generate hydrogen limits the net benefit.
So-called pink hydrogen is produced with emissions-free nuclear power and, in some processes, with the excess heat generated by nuclear fission.
Reactors at Nine Mile, Davis-Besse in Ohio and Palo Verde in Arizona are testing low-temperature electrolysis systems. The fourth demonstration project, at Prairie Island Nuclear Generating Plant in Minnesota, is testing a high-temperature electrolysis process that is regarded as more efficient.
DOE provided a $5.8 million grant to the Nine Mile project, which uses a proton exchange membrane made by Nel Hydrogen.
Constellation said the demonstration project could pave the way for large-scale deployments at its other clean-energy facilities.
Constellation has told investors it plans $900 million in capital investments to develop commercial hydrogen production, which it hopes to begin in 2026. It projects a 250-MW hydrogen facility could produce about 33,450 metric tons of hydrogen, more than 90% of which it expects to sell via long-term off-take agreements.
“Hydrogen will be an indispensable tool in solving the climate crisis, and Nine Mile Point is going to show the world that nuclear power is the most efficient and cost-effective way to make it from a carbon-free resource,” Constellation CEO Joe Dominguez said in a news release. “In partnership with DOE and others, we see this technology creating a pathway to decarbonizing industries that remain heavily reliant on fossil fuels, while creating clean-energy jobs and strengthening domestic energy security.”
“This accomplishment tangibly demonstrates that our nation’s existing reactor fleet can produce clean hydrogen today,” Kathryn Huff, assistant DOE secretary for nuclear energy, said in a news release. “DOE is proud to support cost-shared projects like this to deliver affordable clean hydrogen. The investments we’re starting to make now through the Bipartisan Infrastructure Law and Inflation Reduction Act will even further expand the hydrogen market to create new economic and environmental benefits for nuclear energy.”
Last year saw “significant progress” for the ERO Enterprise’s Compliance Monitoring and Enforcement Program (CMEP) and Organization Registration and Certification Program (ORCP), NERC said in the programs’ Annual Report released last month.
The annual reports, released each February, are intended to help NERC and the regional entities track their progress “aligning CMEP and ORCP activities across the ERO Enterprise,” along with identifying trends in resolving violations of NERC’s reliability standards. Starting this year, NERC plans to supplement the annual report with a mid-year report released in August.
According to the report, REs processed 383 instances of noncompliance assessed at either moderate or serious risk last year. This represents a five-year record, although it totals only six more violations than were filed the previous year.
While total noncompliances rose slightly in 2022, the number of repeat violations reported fell. Repeat noncompliance in the report was divided into incidents involving compliance history — referring to “a relevant prior violation of the same or similar reliability standard and requirement” — and aggravation history, defined as “a prior violation that stemmed from similar actions or conduct.”
The 10 standards that accounted for the highest number of noncompliances assessed as moderate or serious risk in 2022. | NERC
Cases with compliance history fell to 198 last year, from 216 in 2021, while the number of cases with aggravation history dropped more both proportionately and in absolute terms, declining from 83 to 54. NERC pointed out that aggravation history averaged around 19% of all moderate and serious noncompliance cases over the last five years.
NERC’s Critical Infrastructure Protection (CIP) standards accounted for seven of the top 10 most violated standards in 2022, just as they did in 2020 and 2021, according to last year’s report. CIP-007-6 (Cybersecurity — systems security management) garnered the most violations with 108, nearly twice as many as the next most cited standard, CIP-010-4 (Cybersecurity — configuration change management and vulnerability assessments). CIP-004-6 (Cybersecurity — personnel and training) came next, with 37 infringements; the same three standards, in the same order, represented the most violations in 2020 and 2021 as well.
The ERO noted that it achieved “substantial reductions” in the volume of unprocessed noncompliance issues last year, having processed “nearly 70% of its open noncompliance from 2019 and earlier and nearly 50% of its noncompliance from 2021 and earlier.” At the end of 2022, out of NERC’s 2,903 open cases, 1,608 — about 55% — were submitted in 2022; the oldest open cases were from 2017, but this represented only three of the total.
Nine in 10 noncompliance issues reported in 2022 were discovered internally, more than at any time in the last five years. The remaining 10% were found either through compliance audits or spot-checks.
Along with enforcement figures, the ERO also included other highlights from last year such as the ongoing implementation of the Align software tool for processing audits, investigations, and other compliance activities, and the ERO Secure Evidence Locker.
Release 4 of Align deployed in the second quarter of the year, with release 4.1 and 4.5 following in the third and fourth quarters respectively. The January issue of NERC’s Align newsletter said release 4.5 is “the final release planned under the current business case,” though the software will continue to be updated under a governance model adopted last year.
The report also listed the CMEP and ORCP priorities for 2023. These include continuing to deliver enhancements to Align, focusing on efficient resolution of noncompliance, tracking completion of registered entities’ compliance oversight plans, and pursuing consistency efforts on penalties, mitigation, training exercises, documentation, and risk assessments.
The electric vehicle manufacturer that once aimed to be the first to offer an electric pickup truck solely to commercial customers is now uncertain whether it will resume production following a second recall to address supply chain and parts quality issues while facing continued financial stress.
Edward Hightower, CEO of Ohio-based Lordstown Motors (NASDAQ:RIDE), told analysts Monday during the company’s call to discuss fourth-quarter and full-year 2022 earnings results that the company is seeking another partner in addition to Taiwanese-based FoxConn Technology Group, an international contract manufacturer.
At issue is the creation of a network of suppliers manufacturing the myriad electrical and mechanical parts not only for the current pickup truck, the Endurance, but also for new vehicles that Foxconn and Lordstown are now beginning to design.
Lordstown announced its first recall and decision to shut down its assembly line on Feb. 23 over an issue in an electrical system component that the company determined could lead to a loss of power while driving. (See Lordstown Motors Recalls Endurance Electric Truck.)
Hightower said the company issued the second recall after a parts supplier said a component in the truck’s brake assembly did not meet specifications. It is now involved in a lengthy root-cause analysis with its suppliers to prevent future problems.
“Our team has also worked closely with our supplier network to root-cause the other post-launch quality issues and develop and implement corrective actions, which have included part quality corrections, part design modifications, retrofits and software updates,” he explained.
And he underscored the importance of finding another partner to make improvements to the Endurance and begin mass production of the vehicle.
“While we continue to pursue partnership opportunities, should we not identify a partner in the coming months, we may decide to pause commercial production of the Endurance until a partner is identified,” he said.
Foxconn has already invested hundreds of millions of dollars in Lordstown, initially agreeing to buy the 25-year-old sprawling former General Motors assembly plant from it in November 2021 for $230 million. A year later, Foxconn invested another $170 million, purchasing about 19% of the company’s shares and gaining two seats on its board of directors. (See Lordstown Motors Gives 2 Board Seats to Foxconn.)
The joint venture did not begin to produce the Endurance until late 2022. So far it has only built 48 trucks and sold only three in the fourth quarter of 2022.
Lordstown ended 2022 with $221.7 million in cash and short-term investments, about $57 million (34%) higher than expected, the company said in a release accompanying the results.
“We expect to end the first quarter of 2023 with $150 [million] to $170 million in cash and short-term investments, excluding any additional Foxconn funding, other equity sales or contingent liabilities.”
VANCOUVER, British Columbia — Utilities shared ways to narrow the impact of public safety power shutoffs (PSPS) — and convince customers of the need for them — at the Western Interstate Energy Board’s Winter Wildfire Meeting last week.
The practice of PSPS — preemptively shutting down power lines to prevent ignition of wildfires — originated with utilities in California but has since spread across the West as a way to mitigate the risk of catastrophic wildfires in the face of climate change.
When Portland General Electric (PGE) initiated its first PSPS in Oregon’s Mount Hood corridor in September 2020, area residents understood the need for the utility’s preemptive measure because they were already feeling the impact of fires burning elsewhere in the state, said PGE Director of Wildfire Resiliency and Mitigation Bill Messner.
“That worked really well in the sense that we did turn off the power, but it also worked really well with the community because they saw smoke and they saw flames, so I think you can put the correlation really quickly together,” Messner said.
The massive wildfires ignited over Labor Day weekend 2020 and burned about 1.2 million acres of dense forest in normally temperate Western Oregon. The fires killed 11 people, destroyed more than 4,000 homes, leveled entire communities and spread within 25 miles of the city of Portland. Portland-based PacifiCorp already has paid out settlements for its role in starting at least one of the fires, but PGE’s equipment was not implicated in any of them.
In 2020, PGE had just one PSPS zone within its 4,000-square mile territory. By last year, the number of zones had grown to 10, including the heavily forested West Hills area in Portland. All 10 were subject to shutoffs at various times last September in the face of high winds and low humidity at the tail end of a dry summer.
“We actually added some other preventative outage areas as we were learning more about what was happening, and we were being proactive in other areas,” Messner said. “I think ‘just be agile’ is probably one of the biggest learnings that you have to have in this space.”
The utility learned another lesson from the unexpected timing of outages, which sometimes had to be initiated at night. “We were turning off power at two in the morning,” Messner said. “Well, sending messages at two in the morning when someone is sleeping is not very helpful.”
Despite the recent history of wildfire, some Oregon electricity customers are unconvinced about the need for PSPS, Messner said. Some of that confusion might stem from how utilities communicate with the public about the reasons for the policy.
“I think one of our challenges … is that we have several utilities in Oregon. Are we using the same words? Are we saying the same thing? Or are we causing confusion with our attempt to not cause confusion?” Messner said. To improve the company’s communication around PSPS, PGE has created the position of “customer manager” within its incident management team, who is tasked with gathering feedback from customers and improving the utility’s communication with them.
Claire Halbrook, director at California-based consultant Gridworks, said effective communication around PSPS requires “teams of people,” which can be challenging to assemble for just one season.
“So where are these resources going to come from if they’re only needed for part of the year? What are they going to be doing for the remainder of the year? Or are we trying to pull people from their day jobs to do this during wildfire season? And what are the disruptions to those teams and normal course of business?” said Halbrook, who previously worked for Pacific Gas and Electric.
Halbrook emphasized the importance of working with impacted communities to ensure essential services remain energized during a PSPS.
“I also would encourage surveying large customers to see who already has backup generation, and how much of their own load it can serve,” she said. “A big thing we did at PG&E in 2020 was work with many of our local hospitals to ensure that they had backup generation and to provide additional support if needed.”
“The communities that are most vulnerable are often the least resourced to engage with us,” said Oregon Public Utility Commission member Letha Tawney, the panel’s moderator.
“Absolutely,” Halbrook said. “I think we’re asking a lot of our communities to engage with utilities on a variety of fronts around emergency management and other topics. [It’s important to make sure the utilities are] providing them the information and resources they need in an easy way, [and] key contacts within your organization [that] they could reach out to with questions. And engaging in education and listening to their questions and concerns is going to be really important.”
Not Just a Western Issue
Tawney asked the panelists what steps utilities are taking to mitigate the impact of PSPS when fire risk is high.
“I think we learned a lot from PG&E,” Messner said. “I mean, to be frank, when they first started this, they were turning the power off at the substation, right? So there were hundreds of thousands of customers being impacted — and then having to deal with communication challenges about that.” From that experience, PGE learned to narrow the impact of outages from a switching standpoint, he said.
PGE in the past three years has sharply increased the number of weather stations it relies on for monitoring conditions across its service territory, Messner said. During the September 2020 event, the utility relied only on weather data from Portland International Airport at the northern edge of the city. Now it gathers information from about 50 different weather stations and solar-powered surveillance cameras to make more pinpointed decisions.
“I don’t think you can underestimate the importance of the mapping and modeling,” said Mike Bartel, vice president of operations at Alberta, Canada, transmission operator AltaLink. “Every time we go around looking at refinements, it either scares me that the model may not be right, and we’re focused in the wrong places, or it gives me lots of confidence because I’ve got a number of weather experts and forestry experts telling me we’re focused in the right places.”
Bartel also pointed to the need to have “boots on the ground” validating conditions, especially on a transmission right of way, to avoid overreacting to information from a weather station that might be located three miles away.
“At this point in time, every utility across the West needs to know which of its lines are at risk, [and] under what conditions,” Halbrook said. “Are these transmission lines, distribution lines, both? Where along the line is there potential for risk? What are all of the customers that are served by that line that will be impacted if it’s shut off? What is the driver of the risks?”
Pointing to recent wildfires in Florida, Messner said he thinks states across the U.S. — not just the West — will one day face the need to implement PSPS on their grids.
“I think climate change is going to come all the way through … so any state that thinks that this is not going to be a tool they need to have in their tool chests, I think they’re mistaken,” he said.
A group pressing Massachusetts’ transition to carbon-free fuels is trying to head off consideration of hydrogen as a wide-scale replacement for natural gas.
Producing green hydrogen in quantities sufficient to supply all the structures now heated with gas would consume all the clean electricity that offshore wind is projected to supply to Massachusetts, according to a report released Monday by Gas Transition Allies, a coalition of more than two dozen organizations, advocates and researchers.
Decarbonizing the power grid and ramping up green hydrogen production would be impossible to do simultaneously by 2050 or even longer, the report concludes.
The report is the latest dispatch in an ongoing competition between environmental advocates and natural gas delivery companies to shape policy and opinion as Massachusetts moves to a net-zero future.
The Massachusetts Department of Public Utilities has drawn comments from all sides of the debate in its investigation (20-80) of the role of natural gas local distribution companies as the state moves toward its 2050 climate goals.
Green hydrogen is the subject of research and development on multiple fronts. It holds promise because it does not produce greenhouse gas emissions when burned, but the cost of production currently is not economical for many purposes.
Also, if the electricity used to produce hydrogen is generated by burning fossil fuels, the climate-protection benefit of hydrogen produced is negated.
This is at the heart of the new report, “Impact of Green Hydrogen Production on the Availability of Clean Electricity for the Grid.”
Key points include:
3.2 GW of offshore wind capacity is predicted to be available for Massachusetts by 2030.
Replacing 100% of natural gas in all Massachusetts structures that now use it as a heating fuel with an 80/20 blend of natural gas and green hydrogen would require 3.9 GW of nameplate offshore wind capacity.
An 80/20 blend would result in only a small emissions reduction that falls far short of state mandates.
Replacing natural gas with 100% green hydrogen would require 19.7 GW of offshore wind power, plus an enormous expenditure on hydrogen-compatible equipment and infrastructure.
Electric heat pumps are a better option — 3.7 times more efficient than hydrogen boilers.
The report bases its calculations on a series of assumptions about the power output of offshore wind turbines and power demand of hydrogen electrolyzers. Some of the data points will likely improve, given the amount of effort being poured into research and development.
For example, the report assumes 43 kWh of electricity will be needed to produce 1 kg of hydrogen, which is low by current standards. But the U.S. Department of Energy in 2021 launched one of its Energy Earthshots, seeking to cut the cost of clean hydrogen production by 80%.
‘Inherent Flexibility’
Two of the natural gas LDCs that will be directly affected by Massachusetts policy decisions told NetZero Insider on Monday they continue to see hydrogen as a potential path to net zero.
Unitil (NYSE:UTL) spokesperson Alec O’Meara said the company was still reviewing the report. He added:
“Regarding hydrogen in general, we very much believe fully endorsing or ruling out any one specific energy solution would be premature at this time. Unitil is a firm supporter of the commonwealth’s stated emission goals, and as a company we are continuing to explore the potential of a wide number of different renewable natural gas options, including hydrogen.”
National Grid (NYSE:NGG) spokesperson Christine Milligan said the company is firmly committed to its net-zero goal, pursuing it through energy-efficiency programs, offshore wind, EV charging programs and, eventually, hydrogen.
“Green hydrogen is currently being demonstrated around the world as a renewable carrier and a means for long-term storage of renewable power. Its inherent flexibility means it can be used synergistically with solar and wind and, if used for heating, might reduce the potential for renewable power curtailments like those seen already in California,” she said.
“With billions of dollars in federal support for clean hydrogen coming through the IRA [Inflation Reduction Act] and IIJA [Infrastructure Investment and Jobs Act], green hydrogen is going to get much more affordable and more abundant in coming decades. We feel it can play a very important role in helping meet our decarbonization goals and has a range of use cases.”
‘Not Well-suited’ for Local Distribution
Other proponents and opponents of green hydrogen have made their points regularly, in Massachusetts and elsewhere.
At a recent press briefing, environmental advocates decried the possible use of hydrogen in New England, calling it inefficient, explosive and leak-prone.
“There are roles for hydrogen, in hard to decarbonize sectors,” said Steven Hamburg, chief scientist at the Environmental Defense Fund. “But hydrogen is not well-suited for thinking about applications in an urban environment for local distribution-related services like what we do with natural gas.”
“If we just keep going with the status quo, with gas utilities continuing to pretend there’s a path to keep the pipes running indefinitely, we’re going to have a utility death spiral where people who can afford to leave the system do. People who can’t leave … are going to be stuck holding the bag and paying ever higher costs,” said Caitlin Peale Sloan, a vice president at the Conservation Law Foundation.
At a recent meeting, ISO-NE board chair Cheryl LaFleur questioned the wisdom of replacing gas systems with hydrogen.
“As far as hydrogen as a complete substitute for gas … that’s a much more expensive system to retrofit than to retrofit the lines to power plants,” LaFleur said.
LANSING, Mich. — Michigan officials and the Big Three automakers are making massive efforts to transition to electric vehicles, but a new public poll shows almost half of Michigan voters oppose the shift, and more than 60% said they would not consider buying an EV in their next purchase.
Of the 600 voters asked, 46.4% supported the overall shift toward EVs, while 44.4% opposed the move, the poll showed.
The poll, conducted in mid-February by the Glengariff Group of Lansing and commissioned by the Detroit Regional Chamber, also showed that more than 44% of the 600 likely voters polled thought the push toward EVs was being driven primary by government regulations and incentives. Just 18% of those polled thought consumer demand was driving the push toward EVs. The poll has a margin of error of 4%.
Both the industry and state are pushing a shift to EVs. Ford Motor (NYSE: F), for example, is preparing to spend $3.5 billion to build a large plant to produce EV batteries near the tourist city of Marshall in Calhoun County. The state is committing to spend some $1.6 billion in incentives to lure the plant, which is expected to employ 2,500 people.
In addition, the state’s Mi Healthy Climate Plan calls for a major increase in EV usage by 2040, including converting 100% of the state’s light-duty vehicle fleet to EVs by 2035.
But the poll shows that support for EVs in Michigan depends on a variety of factors, including the region the respondent lives in, their age and especially their political leanings.
The poll showed voters living in the Metro Detroit area, where the economy remains strongly centered on the auto industry, support the shift to EVs by 53.3% to 32.4%. Those living outside the Detroit area oppose the shift on a basis 40.2% to 50.6%.
The poll also showed that 51.2% of voters between 18 and 29 years old would consider buying an EV, but 74.7% of those older than 65 would not consider buying an EV.
And 56.6% of voters considering themselves strong Democrats said they will consider buying an EV, but 83.9% of those who are strong Republicans said they would not consider buying an EV.
Of those opposing a shift to EVs, 19.6% said the state’s electric grid could not support the vehicles, another 18.4% said the shift would be too expensive and 13.3% said Michigan’s infrastructure could not support the shift to EVs.
Glengariff Group President Richard Czuba said the poll showed voters are getting caught up in the “culture wars.”
“I don’t think we should be shocked to see this, but I do think it’s a challenge for the automakers simply because you’ve got half of the population saying they won’t even consider this,” he said.
Vistra (NYSE: VST) said Monday it will buy Energy Harbor and combine the two firms’ nuclear plants, renewable facilities and retail businesses into a new subsidiary called “Vistra Vision.”
Vistra is paying $3 billion and assuming $430 million in debt, while Energy Harbor’s two biggest shareholders, Nuveen and Avenue Capital, will continue to own 15% of Vistra Vision. Vistra’s fossil assets, which total 24,000 MW of natural gas units and 8,400 MW of coal, will be in a separate subsidiary called “Vistra Tradition.” The deal needs to be approved by the Department of Justice, FERC and the Nuclear Regulatory Commission; Vistra expects it will close later this year.
“Through this creative transaction we will combine Vistra’s nuclear, retail, renewables and battery storage assets with Energy Harbor’s nuclear and retail assets to create one of the largest clean energy businesses in the country,” Vistra CEO Jim Burke said on a conference call with analysts.
Energy Harbor, which was spun off from FirstEnergy (NYSE:FE), owns three nuclear plants in Ohio and Pennsylvania and has a competitive retail power business serving 1 million customers in PJM and MISO. That will be matched with Vistra’s Comanche Peak nuclear plant in Texas, its renewable and storage projects around the country, and its retail business in Texas and other states.
Vistra Vision will have a about 7,800 MW zero-carbon generation, about 5 million retail customers and access to a pipeline of 1,100 MW of additional renewables projects. It would be the second largest operator of nuclear plants in the country with six reactors across its four plants.
With the country navigating a transition to cleaner energy, nuclear provides the unique capability of being both carbon free and available around the clock to serve demand, Burke said.
“The nuclear production tax credit provides significant downside protection while maintaining the ability to capture upside through market volatility and … hedging forward,” Burke said.
The federal PTC for nuclear, part of last year’s Inflation Reduction Act, will effectively give the firm’s four nuclear reactors an earnings floor. It provides revenue support when a nuclear plant’s “gross receipts” are below $43.75/MWh and can contribute up to $15/MWh when gross receipts drop to $25/MWh.
Power prices were much higher when Vistra first considered the deal last summer because of spiking natural gas, but Burke said his firm is doubtful that prices can go much lower and does not expect cheap natural gas, or resulting power prices, to stick around long.
“Our returns on our PTC case are not that much further below the returns that we actually modeled for this,” Burke said. “And we think we’re modeling closer to the downside of the opportunity with still a lot of upside opportunity, depending on how gas and power … behave from this point forward.”
While Vistra Tradition would be home to the firm’s fossil assets, Burke said that Vistra Vision would use its generation to firm up supplies for retail customers as needed.
Keeping the traditional generation around also gives the firm a larger scale, which could help it invest in new technologies as they become viable, he said.
“We’ve got some opportunities with sites to do things with future nuclear technologies, potentially even at existing coal sites and sites that we’re retiring,” Burke said.
The firm’s coal plants are eventually going to retire, but Burke expects the natural gas generators will be needed for a long time to come.
Separating the two businesses gives investors and customers more visibility into the clean energy assets that Vistra has, Burke said, conceding that it might eventually make sense to split the two businesses completely.
“But right now, these are both scaled businesses with some interdependencies, and so I think we’re going to focus on running this in an integrated fashion for a while,” he added.
SAN FRANCISCO — CAISO had just won approval from its Board of Governors last month for a day-ahead extension of its Western Energy Imbalance Market when a state lawmaker introduced a bill a week later to allow the ISO to become an RTO, CEO Elliot Mainzer recalled Thursday in his keynote address at the Energy Bar Association Western Chapter’s annual meeting.
“Some of us thought, ‘Oh boy, we just got EDAM [the extended-day ahead market] done. Wouldn’t it be nice to have a little bit of time just to let that play out and let that evolve?’” Mainzer said. But the “zeitgeist in the West” is one of rapidly evolving efforts to organize the region’s balkanized electricity sector into markets and programs that could lead to RTOs, he said. (“Zeitgeist” is a German word meaning “the spirit of the times.”)
The measure introduced Feb. 8, Assembly Bill 538, by Assemblymember Christopher Holden would allow CAISO to develop a plan for governance independent of California’s governor and legislature, with a governing body that could include members from other states. (See Lawmaker Introduces Bill to Turn CAISO into RTO.)
“The reality is that … outside of California, I think a lot of people who are thinking about making significant additional investments either in the day-ahead market or even beyond … want to see a pathway to independent governance for the ISO,” Mainzer said. “And I think they need to see that as a way to get them comfortable staying with [CAISO and the Western EIM] and continuing to invest and grow with our organization as it evolves.”
Mainzer’s remarks in his keynote address were part of a discussion at the meeting about efforts by CAISO, SPP, the Western Power Pool (WPP) and others to assemble the West’s 39 balancing authorities into mutually beneficial organizations for resource adequacy, transmission planning and market transactions.
About 100 energy lawyers gathered at the historic Westin St. Francis hotel on San Francisco’s Union Square for the chapter’s first in-person meeting since the COVID-19 pandemic began three years ago.
In a panel on resource adequacy, WPP Executive Director Sarah Edmonds described FERC’s recent approval of the group’s Western Resource Adequacy Program, a West-wide RA effort with 18 participants and three more expected to join. (See FERC Approves Western Resource Adequacy Program.)
The order allows the WRAP to move forward with a binding phase of its program, which would hold members accountable for failing to meet their resource requirements as part of the RA pool.
“We are currently working to identify what season WRAP goes binding,” Edmonds said. “The tariff that [FERC] approved allows flexibility for the region to determine which season, winter or summer, between now and 2028, [that] we’re going to select.”
CAISO and SPP executives described their efforts to organize markets in a panel on Western regionalization, while a strategic planner for Arizona’s Salt River Project offered the views of one potential market participant.
Anna McKenna, CAISO’s vice president of market policy and performance, highlighted the success of the Western EIM (WEIM), which has generated $3.4 billion in participant benefits since it began in 2014. The performance of the market, which has dealt only in real-time transactions, is the ISO’s main selling point for utilities to join the EDAM, which would encompass the much larger day-ahead market.
The WEIM has 19 members, including some of the West’s largest utilities such as PacifiCorp and the Bonneville Power Administration. After three new members join this year, it will encompass roughly 80% of load in the Western Interconnection.
“It’s been extraordinarily fruitful for all of us,” McKenna said.
Adding a day-ahead market would leverage the WEIM’s success by allowing Western entities to coordinate their diverse resources — hydropower, solar, wind and thermal generation — into the day-ahead time frame, “which of course, as you can imagine, really unleashes an extraordinary amount of opportunity for our diversity to be really optimized across those footprints.”
A study commissioned by CAISO found the EDAM could produce $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection. (See West Could Save $1.2B a Year in CAISO EDAM.)
The CAISO board and the WEIM Governing Body approved the EDAM on Feb. 1. It still requires FERC approval. The ISO is developing a tariff for stakeholder review and hopes to submit it to FERC later this year.
“With all the attorneys in this room, you guys can’t wait to get your hands on that. It’s coming,” McKenna said to laughter. “One thing I’d like to do is invite you all to really participate closely in that process because one of the benefits we get is your legal input and insights on the documentation we put out there. So please do participate.”
RTO West, Markets+
SPP is planning to offer its own day-ahead energy imbalance market as part of Markets+, a program currently in development, said Paul Suskie, SPP’s general counsel and executive vice president of regulatory policy.
SPP is also planning RTO West, a Western version of its Eastern Interconnection RTO. Nine entities have committed in writing to joining the RTO, including three regions of the Western Area Power Administration and utilities in Colorado and Wyoming.
Markets+ has signed funding agreements with eight Western entities for the program’s first phase, in which stakeholders will help draft tariff language and outline a governance plan. (See related story, SPP Moving Quickly on Markets+’s Development.)
Suskie said SPP plans to apply its governance model — with an independent board, a committee of state regulators and stakeholder groups that develop and vet policy proposals — to Markets+.
“It’s a very effective process [that] … empowers organizations and people to get in the room discussing … issues, to develop the actual tariff language and vote on [what] is ultimately filed at FERC. So, when we make a filing at FERC, it’s language that has been vetted, voted on, debated and amended through the stakeholder process.”
Suskie said he thinks FERC will approve RTO West before Markets+ because the RTO model is more familiar than the novel Markets+ design.
‘Towards an RTO’
The Salt River Project, a participant in the WEIM and one of the utilities that signed a funding agreement for Markets+, wants to “see two really good [day-ahead] market options come forward” from SPP and CAISO to determine which would benefit its customers most, said Josh Robertson, the utility’s director of energy market strategy.
The utility favors an incremental approach to market development, and a day-ahead market is already a big step compared to a real-time market, Robertson said.
“EDAM, potentially the next step, might be enough,” he said. “We don’t know. We might be good with that. But we do value the possibility of moving forward with an RTO, and seeing a pathway towards an RTO will be an important aspect in terms of our eventual decision-making and our engagement,” Robertson said.
As one or more RTOs emerge in the West, independent governance will be key to SRP and others joining, he said, echoing Mainzer’s keynote remarks.
“It’s just really important that these markets have a transparent, independent governance process,” Robertson said. “We don’t want a single entity, region [or] state … to be able to drive the decision-making here. It really needs to be independent and transparent.”
