Search
`
November 8, 2024

Posted on

MISO Adds Web Features to New Meeting Schedule

MISO is debuting more online interactions after scheduling fewer stakeholder committee meetings at the beginning of the year.

During a special Tuesday workshop, MISO’s Alison Lane said the RTO has launched more comprehensive, 18-month rolling workplans for its stakeholder committees and a webpage to review stakeholder feedback on agenda items and the grid operator’s responses.

The features are meant to augment the abbreviated meeting schedule. (See Stakeholders Call for MISO to Rethink Pared-down Meeting Schedule.)

Lane said MISO will continue with consent agenda items at meetings. She said although these post-only documents will not get staff presentations, stakeholders can still pose questions and strike up discussions during meetings. The RTO said the post-only items are meant for “self-explanatory, non-controversial” updates.

Clean Grid Alliance’s Rhonda Peters said some tariff and business practice manual changes have been “inappropriately” relegated to a post-only format when they merited dialogue.

Natalie McIntire, also from Clean Grid Alliance, asked that staff leave sufficient discussion time for post-only agenda items.

Lane said MISO’s stakeholder relations team will begin keeping records on how long it takes to move through agenda items to better plan meetings.

Lane said topics that don’t receive much stakeholder attention on the feedback webpage will be closed out. Topics that draw more responses or disagreement will receive more discussion time at upcoming meetings.

Stakeholders can use the feedback page to receive email notifications on agenda items that they want to closely monitor.

Staff said they have also streamlined the MISO Dashboard, formerly the issues-tracking tool, so it’s easier to keep up with committees’ focus areas.

Lane asked stakeholders to reach out to MISO with their thoughts on the webpage’s features.

Coalition of Midwest Power Producers’ Travis Stewart asked the RTO to consider giving stakeholders longer than the requisite two weeks after meetings to provide written reactions to discussions and presentations. Lane said the grid operator will likely stick with the two-week comment deadline to post “beefier” feedback responses that better explain staff’s reasoning behind their positions.

MISO is resisting stakeholder calls to shelve its new stakeholder committee schedule, which puts fewer meetings on the calendar. Multiple committee chairs have warned that more infrequent meetings won’t give the RTO enough time to flesh out the changes it needs to make to keep up with the energy industry’s rapid transformation.

In May, MISO is due to check in with stakeholders and examine whether the new meeting schedule is working well enough to permanently continue.

During a Wednesday Steering Committee meeting, exiting Market Subcommittee Chair Megan Wisersky said she hopes stakeholders continue to evaluate whether fewer meeting dates are sufficient.

Posted on

Carbon Capture Needed for ‘Last-mile Decarbonization’

Carbon capture went mainstream in 2021.

According to the Clean Air Task Force (CATF), 51 carbon capture and storage projects were announced in the U.S., more than the total of all projects announced in the previous three years. The industry got a federal stamp of approval as the Department of Energy’s Office of Fossil Fuels became the Office of Fossil Fuels and Carbon Management.

The Infrastructure Investment and Jobs Act (IIJA) provided yet another boost, with more than $12 billion in funding for a range of carbon capture pilot projects, pipelines and research that could help push those 51 projects toward completion and operation.

“We’re really looking at carbon management technologies as part of a system of decarbonization options and a decarbonization portfolio,” said Lee Beck, CATF’s international director for carbon capture. “It’s really an option that we need to be commercialized as soon as possible to have multiple options or technologies available … to enable communities and regions to really choose technology pathways to net zero that are suitable to their individual social, political, economic and resource circumstances.”

Speaking at a Tuesday press briefing sponsored by the Carbon Capture Coalition, Beck was part of a panel of advocates and corporate executives arguing for carbon capture as essential for decarbonizing certain industrial sectors with high emissions, such as steel and cement manufacturing.

Industry accounts for about 23% of U.S. carbon emissions, and “over half of the emissions in the sector are inherent to physical or chemical processes” involved in manufacturing, said Jessie Stolark, public policy and member relations manager for the nonpartisan coalition.

Carbon capture offers “a unique solution to reducing emissions in the sector in a timeframe consistent with midcentury net-zero targets,” she said.

Echoing Stolark, Virgilio Barrera, director of government and public affairs for cement manufacturer LaFargeHolcim, described the particular decarbonization challenges his company faces.

“You can electrify everything, use alternative fuels and you would still be generating 50% of your emissions,” Barrera said. “That’s because it’s a chemical transformation of taking raw material — in this case, limestone — heating it up and converting it to … cement.

“The key for us to reach net zero is really getting carbon capture, utilization and storage projects online,” he said.

The company has received DOE funding to help develop carbon capture projects at two plants, one each in Colorado and Missouri, he said.

Continued Opposition

The strong project pipeline notwithstanding, the U.S. only has about a dozen commercial-scale CCS projects online at this time, according to the Global CCS Institute, and some environmental groups continue to voice strong opposition to the technology, arguing it doesn’t work and is too expensive.

In July, more than 500 environmental organizations published an open letter calling on lawmakers in the U.S. and Canada “to recognize that carbon capture and storage is not a climate solution. It is a dangerous distraction driven by the same big polluters who created the climate emergency.”

But environmental groups in the coalition, such as The Nature Conservancy (TNC), maintain carbon capture technologies are needed to keep climate change under 2 degrees by 2050. New technologies to reduce industrial emissions “are either in the very early stages of research or not broadly deployed in the marketplace,” said Jason Albritton, director of climate and energy policy at TNC.

“If we’re going to reach the ambitious goal of net zero by 2050, we really have to be working now to set the stage on how to address these hard-to-eliminate emissions, the emissions we often call ‘the last-mile decarbonization’ because they are so important, but we don’t yet have the solutions broadly deployed,” he said.

A recent analysis from the General Accounting Office offered further criticism of carbon capture. The GAO found that since 2009, the Department of Energy had invested $1.1 billion in 11 carbon capture projects, only two of which are still operating. Of the others, one ended operation in 2020 and eight were never built. The GAO recommended better oversight and monitoring by the DOE and Congress.

Stolark and others have countered that the difference between then and now is the 45Q tax credit, which provides per-ton credits for CCS. In 2018, Congress expanded the credit, setting it at $50 per ton for carbon sequestered in underground geologic formations. To qualify, projects must begin construction by Jan. 1, 2024, and meet certain capture thresholds. For example, industrial facilities must capture at least 100,000 metric tons per year.

That expansion triggered the growing project pipeline, but the further revisions to 45Q in the stalled Build Back Better Act are needed, Stolark said. The coalition is supporting changes that would increase the credits and slash capture thresholds. For example, carbon stored in geological formations would qualify for credits of $85/MT, and the credits for direct air capture projects would range from $130 to $180/MT and come with a direct-pay option.

In addition, if passed, BBB would decrease capture thresholds to 18,750 MT annually for power plants, 12,500 MT for industrial facilities and 1,000 MT for direct air capture.

These “enhancements” to 45Q “are necessary to close the cost gaps for deployment of carbon capture technologies across sectors including steel, cement and refining,” Stolark said.

Not One-size-fits-all

The global food processing company ADM (NYSE:ADM) is one of CCS’s success stories, said Colin Graves, the company’s vice president for innovation.

The company has been sequestering carbon 1.5 miles underground in Decatur, Ill., for 10 years, Graves said. “To date, we’ve sequestered over 3.5 million tons of CO2, which is the equivalent of removing 750,000 cars from the road for a full year,” he said.

Along with other energy efficiency and renewable energy initiatives, CCS has allowed ADM to reach carbon neutrality for its U.S. flour milling operations, and the company is looking to decarbonize more of its industrial processes, Graves said.

“This is an excellent example of the potential of this technology and the cascading effects that it can have for many different industries and products,” he said.

But part of the challenge going forward is that carbon capture is not a one-size-fits-all technology, said Beck of the CATF, responding to reporters’ questions. “It really comes down to the plant level, to the application level; if you’re producing hydrogen, if you’re decarbonizing a refinery, if you’re decarbonizing a cement or steel plant,” she said.

For emissions produced by ammonia, ethanol or natural gas processing, CCS technologies may include compression and dehydration or the use of membranes or physical solvents, said a report in Chemical and Engineering News. Chemical solvents may be used for carbon emissions from coal or natural gas-fired power plants.

That means the cost per ton of different technologies may also vary widely. A Rhodium Group study found that the $50/MT 45Q tax credit pencils out for CCS technologies used for ammonia and ethanol processing, but the BBB’s $85/MT level is needed for cement, steel or refineries.

Another big question is how much underground sequestration does the U.S. have? Stolark said that the DOE has a carbon storage atlas, originally compiled in 2012, showing the country has the capacity to store at least 2,400 billion MT of carbon dioxide.

Posted on

Fast-moving Bill Seeks to Win Hydrogen Hub for Wash.

A bill zipping through the Washington State Legislature aims to boost the state’s prospects for landing one of four national “clean” hydrogen hubs to be funded under the federal Infrastructure Investment and Jobs Act (IIJA).

The State Senate unanimously passed Senate Bill 5910 on Feb. 12, advancing it to the House Environment and Energy Committee, which held a hearing on the legislation Tuesday.

Sponsored by Sen. Reuven Carlyle (D), the bill would create an Office of Renewable Fuels within the state’s Department of Commerce to support development of electrolytic hydrogen and other alternative fuels.

According to a bill summary, the new office would collaborate with other state agencies to accelerate market development of renewable fuel and hydrogen projects along their full life cycle, in part by supporting research and development around production, distribution and end uses. It would also identify ways to best deploy the fuels to support the state’s climate change mitigation and adaptation efforts.

The office would also be expected to take a role in boosting job creation and improving “economic vitality” while partnering with “overburdened” communities to ensure they benefit from clean fuels development. It would also review the state’s existing renewable fuels and hydrogen initiatives and support public-private opportunities that encourage adoption of clean fuels.

The office is expected to coordinate efforts with local state and federal governments, the private sector and universities.

The bill would additionally allow proposed hydrogen production projects the choice of applying for permits from the state Energy Facility Site Evaluation Council, rather than local governments. It would also authorize municipal utilities and public utility districts to produce, use, sell and distribute hydrogen and other renewable fuels.

Scoring Federal Funding

But SB 5910’s most significant impact could lie in Washington’s effort to land one of the four hydrogen hubs outlined in the IIJA, enacted last year.

The law allocates $8 billion for the creation of at least four hydrogen hubs across the country, as well as $1 billion for the domestic manufacture of the electrolyzers needed to convert water to green hydrogen. The U.S. Department of Energy will solicit proposals for the hubs until May 15 and select the four sites a year later.

“The legislature finds that Washington state is strongly positioned to develop a regional clean energy hub meeting the criteria of the IIJA and that … state funding assistance may help to promote and strengthen applications to DOE for federal funding,” the bill summary said.

Washington is likely to face stiff competition from other Western states also hoping to score a hydrogen hub. Southern California Gas and the Los Angeles Department of Water and Power are already unrolling some of the most advanced plans for creating such a hub, even without the promise of federal funding. (See related story, SoCalGas Proposes Hydrogen Pipelines.)

But with its ample water supplies and massive network of hydroelectric facilities, Washington is a promising contender. The state currently has one hydrogen production plant under construction near East Wenatchee, which will use Columbia River water as its source. The plant, to be operated by Douglas County Public Utility District near the Wells Dam, is scheduled to go online this spring. A hydrogen fueling station is on the drawing board for near East Wanatchee, and another is in the works for public transit buses in Lewis County, about 25 miles south of Olympia.

On Tuesday, five people testified in favor Carlyle’s bill, and no one testified against it.

“Our region is well positioned to become a hydrogen hub,” said Logan Bahr, state relations manager for Tacoma Public Utilities.

Dave Warren, representing the Washington Green Hydrogen Alliance and the Renewable Hydrogen Alliance, said, “We’re competing with New York and California on being a hydrogen hub. But this is ours to lose.”

He added that while the bill would provide $500,000 to set up the Office of Renewable Fuels, it does not include money to help hydrogen producers apply for the appropriate permits.

The bill “is embracing innovation and opportunity — opening them up instead of restricting them,” said Dan Kirschner, executive director of the Northwest Gas Association.

At an early February hearing before the Senate Ways and Means Committee, some testifiers also contended that the proposed office would help small businesses transition to using hydrogen as a fuel.

Meanwhile, poised for a full House vote is House Bill 1792, which would establish sales and use tax exemptions for the production of electrolytic hydrogen and for the sales of the electricity used to produce the fuel.

Posted on

Maine Legislators Rethink Electric Utility Accountability in Bill Hearing

Maine’s legislators began the task this week of sorting out how Gov. Janet Mills’ recently proposed utility accountability bill differs from a similar one she vetoed last year and whether it does enough to protect consumer interests.

The bill’s supporters say it would provide enhanced regulatory tools for ensuring that the state’s investor-owned utilities deliver reliable and affordable electricity services. But opponents say the Maine Public Utilities Commission already has the authority to keep utilities in line.

“No matter what party you identify with, or what part of the state you live in, I think we can all agree that more transparency and accountability for the transmission and distribution monopolies is a smart and much needed step forward,” Sen. Stacy Brenner (D) said during a Joint Energy, Utilities and Technology committee public hearing Tuesday.

Brenner, who sponsored the governor’s bill (LD 1959), co-sponsored another utility accountability bill (LD 1708) last year that moved quickly through the legislature in June despite the governor’s concerns. Mills vetoed LD 1708 in July, saying that it was an important but hastily drafted piece of legislation.

While both bills contain a central provision allowing regulators to force the sale of an IOU if it does not meet certain service metrics, they diverge on the metric specifics and other methods of accountability. Mills’ proposal would establish future performance guidelines to determine a utility’s fitness to serve, and the previous bill looked primarily at historical utility performance.

Each bill addresses a potential utility asset sale differently. Mills wants the PUC to consider bids from potential buyers while also looking at a proposal for a consumer-owned utility (COU) from a state-appointed committee. Regulators would decide whether a COU would provide the best service to consumers.

LD 1708, on the other hand, sought to put the assets directly in the public’s hands via a COU, without consideration for outside bids. Supporters of the consumer nonprofit model for Maine want the public to have more say in the business of electricity generation and distribution.

Allowing the PUC to set new performance metrics would only “shelter what should be a public process in a place where the public has very little access or ability to influence the outcome,” said Sen. Nicole Grohoski (D), who co-sponsored LD 1708.

Maine Public Advocate William Howard, who supports the governor’s bill, agreed with Grohoski in hearing testimony.

“There is an element of a closed club that handles most of the litigation before the PUC … and it makes it very difficult for outsiders to understand much less participate,” Howard said. “That is something I’m going to be working on.”

Other Provisions

The governor’s bill would strengthen the PUC’s authority for levying fines for poor service, establish financial audits and expand utility whistleblower protections.

“I think [protections for whistleblowers] may be the sleeper piece of this bill,” Howard said. “I am very confident that the additional protections in this bill will lead to future whistleblowers, and that will help us control costs.”

Under the bill, the PUC could “crack down” on Central Maine Power (CMP) and Versant Power through a provision that doubles current penalties, from $500,000 to $1 million or 5% of revenue to 10%, according to Dan Burgess, director of the Governor’s Energy Office. But regulators already have leeway in setting fines, according to Sen. Steven Foster (R).

The penalty provision, Howard said, would be tied to performance metrics as an administrative procedure rather than hiding within a rate proceeding as set out by current guidelines.

“The headline will not be ‘CMP or Versant rates raise 9%’; the headline will be ‘CMP or Versant penalized for X million dollars for poor service,’” he said. “That will get their attention.”

In Opposition

Our Power, a nonprofit that supports the creation of a COU to replace CMP and Versant, is concerned about the reliance the governor’s bill puts on regulators for utility accountability.

“In crucial decisions, [the commission] too often has to rely on whatever information is selectively provided by utilities,” Andrew Blunt, legislative director at Our Power, said in hearing testimony. “It is simply the wrong body to look to for true accountability.”

The nonprofit is behind a citizen initiative launched last August to force a public vote on LD 1708. By January, the group had collected 60,000 signatures for the initiative, but that was not enough to make the November ballot.

Mills’ proposal, Blunt said, gives the state’s IOUs a “blank slate that they do not deserve.” The performance metrics in the bill, he added, are “astonishingly weak” and would not set minimum standards in statute.

CMP President Joseph Purington opposed the governor’s bill during the hearing, saying that the legislature “already got it right.”

“The PUC has the authority it needs to do its job to ensure safe, adequate service at just and reasonable rates,” he said.

In recent history, he added, the PUC imposed the “largest financial penalty in Maine utility history” for CMP’s poor service quality. CMP responded by reorganizing, and it is now “meeting and exceeding some of the most stringent metrics in the industry,” he said.

Posted on

200-MW Solar Project in Upstate NY Concerns Locals

Upstate New York residents are concerned that the proposed 200-MW Garnet Energy Center solar facility will diminish their quality of life, harm wildlife and endanger groundwater (20-F-0043).

The application for a certificate of environmental compatibility and public need for the 2,000-acre project in the town of Conquest is flawed in many ways, Eugene D. Moretti, a resident of neighboring Cato, said in written comments.

“Aside from the obvious complete, permanent elimination of hundreds of acres of agricultural production, as well as the devastating impact of deforestation and draining of wetlands, there are several very specific problems with the plans of the applicant,” Moretti said.

All residents of the affected area rely on private wells, and the developer proposes to construct PV panels, fencing, inverters, switching stations, storage units and substations at 250 feet from private dwellings.

“The idea that ground disturbance of that scale and variety will not have a detrimental effect on private wells is, of course, patently absurd,” Moretti said.

The New York Board on Electric Generation Siting and the Environment held two virtual public statement hearings in February on the project, which is being developed by a subsidiary of NextEra Energy (NYSE:NEE). The board has set a May 1 deadline for comments. The project would be located on land owned by Garnet Energy or leased from private property owners.

The interconnection facilities would include a 345-kV switchyard connecting the project to the adjacent 345-kV Clay-to-Pannell transmission line owned by the New York Power Authority, which will own and operate them upon project completion.

Jobs, Traffic, Wildlife

Local grain farmer Donald Waterman supports the project, citing it as a chance for landowners to continue in energy production after the corn-to-ethanol plant in Fulton closes.

“I appreciate that [Garnet] was a voluntary project with the landowners choosing to sign on,” he said.

The project also would provide local jobs and will help the state achieve its renewable energy goals, said Tom McHale, a member of Laborers Local 633.

“I urge you to do everything possible to help make this project a reality. The jobs this project creates will provide good pay and benefits to sustain our families now and into the future,” McHale said.

Some people who live close to the proposed areas are concerned about heavy truck traffic and dust.

Paul and Brenda Bramble said they live within a quarter-mile of the construction drop-off area and are extremely concerned about noise, traffic, safety and traffic delays, among many other issues.

“What will be done to minimize noise and vibration during and after construction of the solar facility? Will work be limited to daylight hours, or will it take place 24/7? Where will employees park, and where will construction vehicles access and exit the construction site?” they asked.

The project involves clear-cutting of forests, destruction of wetlands and spraying of most vegetation, which will split animal families, said Maureen J. Doyle of Jordan. Beaver will lose sticks and leaves they use to build their dams, while wolf, coyotes and foxes will lose beaver as a source of food, she said.

New York’s State Environmental Quality Review Act requires all state and local government agencies to consider environmental impacts equally with social and economic factors, Doyle said. She asked how the state’s Department of Environmental Conservation is addressing compliance with the law.

The size of the project makes for a huge impact to current land usage throughout Conquest, an impact compounded by the project’s noncontiguous design to obtain enough land to meet their 200-MW generation goal, Robert Vogel, chair of the town’s planning board, said in six pages of comments.

The Siting Board should require that far fewer than the more than 20 specified sites throughout the town be covered with solar panels, and even with reduced generation, Conquest will “have done its fair share in contributing to New York’s green energy goals,” Vogel said.

Projects like Garnet should not be being built in upstate, where agriculture and eco-tourism are vital to the regional economies, said Brian Wilson.

“If downstate wants them so much, they should be building these sites in Brooklyn,” Wilson said.

Posted on

Biden Marks Progress on US Clean Energy Supply Chains

President Biden on Tuesday ramped up efforts to build out U.S. clean energy supply chains with a series of announcements focused on the mining, refining and recycling of critical minerals, including the lithium and cobalt used in batteries for energy storage and electric vehicles.

“China has spent several years cornering the market on many of the materials that power [these] technologies,” Biden said during a virtual roundtable with state and federal officials and corporate executives. “That’s why I committed us to build a clean energy supply chain stamped ‘Made in America’ … using products, parts and materials, as well as minerals right here that are in the United States of America.”

Biden’s first announcement was a $35 million grant from the Department of Defense, which will help MP Materials in Mountain Pass, Calif., build out an end-to-end supply chain to refine and process rare earth minerals needed for the magnets used in EVs and wind turbines. According to a White House fact sheet, China controls 87% of the global market for these magnets.

MP is planning to invest another $700 million in the project over the next two years, said CEO James Litinsky. In December, the company announced it had signed a long-term agreement with General Motors to provide magnets for its EVs, including the GMC Hummer EV and the Chevrolet Silverado EV.

Litinsky noted that the MP facility will be an environmentally friendly operation, with a “dry tailing process” that recycles 95% of the water it uses. By 2025, the facility could be producing magnets for 500,000 EVs per year, he said.

The other big announcement came from BHE Renewables, which will soon start operations on the first phase of a demonstration project that will extract lithium from geothermal brine at the company’s geothermal plants located at the Salton Sea in Imperial County, Calif. The second phase of the project, which will refine the lithium for battery manufacture, is being funded in part by a $14.9 million grant from the Department of Energy, which is being matched by a similar amount from BHE.

“If both these demonstration projects are successful, we would then be in a position to begin construction of our first commercial plant in 2024 and by 2026 be commercially extracting lithium from our geothermal brine,” said Alicia Knapp, president and CEO of BHE.

According to the White House fact sheet, BHE’s commercial-scale lithium extraction in Imperial County could produce 90,000 metric tons of lithium per year.

The BHE projects have been the centerpiece of California’s efforts to create a “Lithium Valley” in Imperial County, which has historically high unemployment rates and was hard hit by the COVID-19 pandemic. BHE has committed $25,000 for scholarships to support science, technology, engineering and math (STEM) education in the county, Knapp said.

The company is also working with local schools to develop training programs, internships and “hands-on opportunities at our site to help prepare local residents for future careers in geothermal or lithium,” she said.

California Gov. Gavin Newsom called the development of a lithium supply chain in Imperial County “a hinge moment” and potential game changer. The state intends to follow up on the local efforts with a “community benefits package focusing not just on the economic opportunity but making sure the growth and inclusion strategies include local hires [and] local benefits in a sustainable way,” he said.

Circular Supply Chains

While largely overshadowed by Russia’s invasion of Ukraine, the roundtable and accompanying announcements were intended to mark the one-year anniversary of Biden’s Executive Order 14017, which ordered a multiagency evaluation of vulnerabilities in the U.S. supply chain.

Building out domestic supply chains is critical for Biden to achieve his goal of a 100% clean energy electric system by 2035 and a net-zero economy by 2050.
The International Energy Agency has estimated that lithium demand could see a 40-fold increase by 2040, with a 20-fold increase projected for cobalt and nickel.

The report issued after E.O. 14017 underlined the risks of China’s dominance in lithium-ion battery supply chains and called for an “an end-to-end coordinated supply chain strategy.”

The White House fact sheet included other announcements not mentioned during the roundtable.

Nevada-based Redwood Materials is partnering with Volvo and Ford on a pilot project that will collect and recycle end-of-life EV batteries to extract lithium, cobalt, nickel and graphite. Closing the loop, the company is also partnering with Ford on a second recycling plant in Tennessee and will begin construction on a cathode manufacturing plant in Nevada this year.

According to a recent press release, the company’s goal is to create a circular supply chain that will produce enough battery components to power 5 million EVs by 2030.

In addition, DOE will invest another $140 million from the Infrastructure Investment and Jobs Act to fund a demonstration project to help build out supply chains for rare earth elements (REEs) and critical minerals (CMs). According to a request for information released Feb. 14, the goal of the project is to design, construct and operate “a first-of-a-kind, domestic demonstration facility that produces REEs and CMs from domestic resources that include unconventional and secondary sources, such as coal waste materials.”

“Applying next-generation technology to convert legacy fossil fuel waste into a domestic source of critical minerals needed to strengthen our supply chains is a win-win,” Energy Secretary Jennifer Granholm said in a statement released with the RFI. “We are moving ideas from the lab to the commercial stage and demonstrating how America can compete for the global supply chain to meet the growing demand for clean energy technology.”

The administration is also launching an effort to update the 150-year-old Mining Law of 1872, which still governs the mining of most critical minerals on federal lands. The Department of the Interior on Tuesday announced the formation of an interagency working group that will focus on legislative and regulatory changes to mine permitting.

The department issued a list of fundamental principles that, the White House said, “will promote responsible mining under strong social, environmental and labor standards that avoids the historic injustice that too many mining operations have left behind.”

‘A Tall Order’

The response to Tuesday’s announcement from energy groups was mixed.

Andrew Reagan, executive director of the industry advocacy group, Clean Energy for America, praised Biden for delivering on his efforts to ramp up clean energy supply chains. “Producing more of these critical minerals and materials in America will mean even more families in America will enjoy the benefits of clean energy, sooner and swifter,” he said.

Sheila Hollis, acting executive director of the United States Energy Association, called the announcements “a shot in the arm” for U.S. clean energy supply chains, but she also pointed to significant obstacles ahead. With global supply chains already set up, it will be “a tall order” for the U.S. to develop the supplies of critical minerals it will need and build out new processing and manufacturing facilities while it is still reliant on imports, Hollis said.

“Multibillion-dollar supply chains do not move overnight,” MP Materials’ Litinsky agreed. “It’s going to require capital. It’s going to require perseverance. It’s going to require strong coordination between the upstream and downstream, and most importantly it’s going to require a commitment from leadership across the board.”

Posted on

Hydrogen-powered Commercial Air Service on the Horizon

A UK-based developer of hydrogen-fueled airplane motors expects to offer aircraft manufacturers a zero-emission electric powertrain as early as 2024.

ZeroAvia’s first hydrogen-electric powertrain would equip aircraft capable of flying 10 to 20 passengers.  By 2026 it hopes to produce a larger motor for regional flights carrying up to 80 passengers. The company assumes its customers will use green hydrogen, produced with renewable energy, as fuel.

ZeroAvia has attracted the attention of commercial carriers, including United Airlines, Alaska Airlines, and Amazon Air in the U.S. and British Airways in the UK. United in December invested an “equity stake” in the company and expects to buy 100 power systems. Alaska also invested in the company in October and will work with ZeroAvia engineers “to scale the company’s existing powertrain platform,” the airline said in a release.

Speaking Tuesday at a webinar hosted by German hydrogen marketing company Mission Hydrogen, Julian Renz, head of program at ZeroAvia, dismissed battery-electric aircraft as impossible to scale up for use in larger aircraft because of battery weight. He argued plant-based jet fuel was not completely emissions-free and similarly dismissed burning other forms of hydrogen as a source of pollution.

“What we envision is renewably powered hydrogen electric aviation. What we focus on is the propulsion system, where you have the hydrogen fuel tanks on board the aircraft, [and] you convert that hydrogen into electricity in a fuel cell system that gets you enough electricity to power an electric motor,” he said. “The only exhaust is water vapor.”

By 2024, Renz said, the company plans to win certification for a 600-kW electric powertrain capable of propelling a 10 to 20-seat aircraft about 200 nautical miles. The company is targeting 2026 as the year it will offer a 2 to 5-MW system for regional aircraft flying 500 miles or more.

“I want to be clear … that we think we have to start with commercial applications as soon as possible, both to really push the regulator as well as to push the infrastructure provision and the technology providers so that they see a near-term use case they can commercialize,” Renz said. “And obviously also, as a young company in this space, we can only live on revenues, ultimately. So that’s what we are trying to get to as fast as possible to then launch new programs.”

ZeroAvia has also received a grant from the state of Washington’s Department of Commerce to create a research and development laboratory in Seattle, he said.

The company flew a small commercial grade aircraft in September 2020 powered by a 250-kW system as a “technology demonstrator,” he said. This spring, company test pilots will fly a hybrid two-engine aircraft, with one engine being traditional prop jet and the other a fuel cell electric motor powered by on-board hydrogen.

“If we hit our technical milestones, you can see that these financial partners have enough leverage, enough capital available, to see us through to certification,” he said. “That is really the most important thing for us.”

Posted on

NJ Plans ‘Flagship’ R&D Innovation Center for Wind

The New Jersey Economic Development Authority (EDA) on Wednesday will close the search for a consultant that the agency hopes will help create a world-class offshore wind research and development testing facility to enhance the state’s quest to become a coastwide offshore wind manufacturing and supply chain hub.

The authority is looking for well qualified firms to help develop a three- to five-year strategy to accelerate innovation for the offshore wind industry at the state’s Wind Institute, the EDA said in a request for proposals outlining the project.

The Wind Institute, a yet to be created authority that would lead state efforts to grow the industry, is one of several initiatives designed to bolster New Jersey’s plan to create a hub that will support not only the state’s own wind industry, but also provide materials, equipment and technology for other wind projects along the East Coast. Other support for the effort includes the business expected from the award of leases for three offshore wind projects off the state’s coast and the launch of a wind port specifically designed to underpin the industry, the New Jersey Wind Port, on the Delaware River in Lower Alloways Creek.

The winning contractor will support the Wind Institute’s mandate to “champion research and innovation that unlocks market potential” and create a “flagship” center for “offshore wind technology research and innovation,” according to the RFP.

New Jersey officials, who believe they already have a first-mover advantage from the state’s rapid push to build a wind industry, also hope to gain an edge through technology development. The release likens the proposed R&D facility to well known New Jersey research facilities developed in the past, such as Bell Labs in Murray Hill and Princeton Plasma Physics Laboratory, a U.S. National Laboratory.

“The Innovation Center will be instrumental in ensuring that New Jersey leads on world-renowned offshore wind technology research and innovation,” EDA CEO Tim Sullivan said in a release announcing the project in January. The facility, he said, will also make sure the state “harnesses the environmental and economic benefits of the rapidly growing offshore wind sector.”

The EDA, with a Wednesday deadline for proposal submissions, expects to award the contract in June. Under that timeline, the contractor would begin work in July.

The successful applicant will win a five-month contract with a three-month extension option to do work that includes providing background review and market analysis, a feasibility analysis and implementation plans, according to the RFP.

The state’s lofty ambitions to become a regional player in the offshore wind industry face strong challenges from other states. The Port of Virginia is looking to create a staging and preassembly area, and US Wind, which is developing a wind project off the coast of Maryland, recently announced plans to develop 90 acres of waterfront in Baltimore County into an “offshore wind deployment hub.” Developers in New York and Connecticut have plans for staging and assembly facilities in those states.

In June 2018, the U.S. Department of Energy designated the New York State Energy Research and Development Authority (NYSERDA) as administrator of the National Offshore Wind R&D Consortium. The project has since invested $47 million in wind research, with states including Maryland, Virginia, Massachusetts and Maine joining the consortium, according to DOE.

Coastal Wind Projects Advancing

New Jersey’s plans are backed by its growing wind sector. The solicitation process for the flagship R&D facility closes on the same day that the U.S. Bureau of Ocean Energy Management (BOEM) starts a lease auction for six wind projects in the New York Bight. (See BOEM to Auction Six New Lease Areas in NY Bight.)

Separate from the bight projects, the New Jersey Board of Public Utilities (BPU) in June awarded leases for two offshore wind projects: Ocean Wind II, located about 14 miles from the New Jersey shoreline, which will generate 1,148 MW, to be developed by Danish developer Ørsted; and Atlantic Shores, with 1,510 MW of electricity in an area between 10 and 20 miles off the Jersey Shore near Atlantic City, to be developed by a joint venture between EDF Renewables North America and Shell New Energies US. (See NJ Awards Two Offshore Wind Projects.)

Those awards followed the BPU’s award in 2019 of Ocean Wind, an 1,100-MW project off the state’s coastline, also developed by Ørsted. The state is aiming to create 7,500 MW of offshore wind generating power by 2035 and expects to start a third solicitation later this year.

The state has set aside $350 million in tax credits to companies that make major investments in the sector and has allocated $500 million to the New Jersey Wind Port, which broke ground in September. The port is expected to include space for nacelle manufacturing and a 30-acre marshalling area for component assembly and staging. (See NJ Ramps up Wind Sector Support.)

The proposed R&D facility is expected to support and complement those plans. The EDA said it is looking for the successful contractor’s proposal to execute a range of tasks, among them:

  • leverage existing facilities and assets in New Jersey in developing this facility and clustering opportunities;
  • support and foster emerging innovations and solutions to offshore wind market challenges and opportunities;
  • incentivize clustering and anchoring of offshore wind research and innovation investments and activities around and near the flagship research facility;
  • support opportunities for New Jersey-based businesses to expand and/or transition their product or service offerings for utilization in the offshore wind supply chain; and
  • capitalize on New Jersey’s existing expertise and reputation for research and innovation across multiple sectors such as cleantech, information technology and life sciences.

In a related but separate move, the EDA at its Feb. 9 monthly meeting approved a memorandum of understanding with Salem County to provide $100,000 to create an office of economic development in the county, in which the New Jersey Wind Port is located. The project, funded from the wind port budget, is designed to “catalyze the economic benefits of this once-in-a-generation investment within the county.”

Clean Energy Loan Programs

The two wind sector measures are among several clean energy initiatives launched by the EDA this year. The board, at the Feb. 9 meeting, also approved an MOU with the New Jersey Treasury that will enable the authority to participate in the U.S. Treasury’s State Small Business Credit Initiative. The state is eligible for $255 million funded by the American Rescue Plan Act, and one of the projects under consideration for the funds is a Clean Energy Business Financing Program, according to the agreement.

The EDA is planning to allocate $80 million to the financing program, which will offer loans that provide a $1 match for every $1 in private funds going to small businesses that are accelerating the deployment of clean energy technologies and result in the creation of new permanent jobs in New Jersey.

The agency is also looking to launch a Jersey Green Fund that would provide new bridge financing loans for clean energy projects that are “cost effective and leverage private capital,” it said in a statement. The fund, which was first floated in Gov. Phil Murphy’s 2019 Energy Masterplan, will focus on the difficulties that commercial energy efficiency contractors face. These contractors are often called in to do work on projects funded by the BPU and energy utilities but often face liquidity problems because they are not paid for the work until a “performance period of proven energy savings” expires, the EDA said.

The EDA at the end of January closed a request for information process seeking specific insights to help shape the program on financing availability and the cost of capital challenges faced by New Jersey’s energy efficiency contractors.

Jane Cohen, executive director of the state Office of Climate Action and the Green Economy, said the fund will play a role in responding to the steady rise in energy efficiency contracting activity expected in the next three years because of Murphy’s clean energy policies.

“Having a go-to resource that small contractors can draw from to help fund projects helps our state accelerate plans to reduce its reliance on fossil fuels and grow an equitable green economy,” Cohen said.

Posted on

Retail Anti-competition Bill Hits Snag in Arizona

A bill that would close the door to electric retail competition in Arizona has hit a snag in the state legislature.

House Bill 2101 sponsored by Rep. Gail Griffin (R) cleared two committees but failed 26-29 on the House floor on Feb. 14. Lawmakers approved a motion from Rep. Andres Cano (D) to reconsider the bill within 14 days. As of Tuesday, the bill hadn’t been voted on again.

HB 2101 would repeal a 1998 law that was intended to give customers a choice of electricity service providers in the service territories of both investor-owned utilities and consumer-owned “public power entities” (PPEs).

But the competition envisioned by the law never materialized. Although the Arizona Corporation Commission (ACC) adopted rules to allow competition, the rules were shot down by a 2004 appellate court ruling.

Now, proponents of HB 2101 say competition should be rejected to maintain reliable electric service.

During a committee hearing last month, many bill supporters cited the February 2021 winter storm in Texas that left millions of residents without power for days in subfreezing temperatures and contributed to the deaths of more than 200 people. Customers have retail electric choice in much of Texas.

“I’m not ready to gamble on a company that may not have a smart group of implementers,” said Rep. Teresa Martinez (R), a member of the House Committee on Natural Resources, Energy and Water. “We’re literally playing with people’s lives when it comes to water and energy.”

Others expressed concerns that allowing competition would lead to “cherry picking” of lucrative accounts.

With competition, Arizona’s existing utilities would serve as providers of last resort, being left to serve the costliest customers, said Molly Greene, senior director of state and local government relations for Salt River Project. The Tempe-based PPE with more than 1 million customers supports HB 2101, Greene said.

“The bill protects customers by eliminating the antiquated, defunct provisions that were contemplated a quarter century ago and never materialized,” Greene said.

Clean Energy Offerings

But Travis Kavulla, vice president of regulatory affairs for NRG Energy Inc., said there would be safeguards to protect customers in the event of electric competition in Arizona. NRG is an energy producer and retailer, as well as the parent company of Green Mountain Energy, which wants to do business in the state. HB 2101 would cut off that opportunity, Kavulla said.

NRG customers continue to pay utilities’ rates for upkeep of the grid, Kavulla said. In addition, Arizona customers would pay a “standby fee” for utilities’ prior investments in generation.

“Monopolies don’t like to be competed against, and in my experience they will do or say anything to deprive their customers of a choice in provider,” Kavulla said in written testimony to the committee.

Green Mountain Energy provides customers with 100% renewable energy. In contrast, Kavulla said, Arizona’s monopoly utilities have lagged in providing renewable energy.

The House NREW committee passed HB 2101 on a 10-2 vote on Jan. 18. The House Rules Committee then voted 8-0 in favor of the bill on Feb. 7.

Meanwhile, a companion bill in the Senate, SB 1631, was passed Feb. 16 by the Senate Committee on Natural Resources, Energy and Water on a 5-4 vote.

Green Mountain Application

Green Mountain Energy submitted an application to ACC in August to provide competitive electric generation services within the territories of the state’s largest investor-owned electric utilities, Arizona Public Service Co. and Tucson Electric Power Co.

Green Mountain Energy is licensed to provide electric service in 11 states, according to the application.

In its application, Green Mountain said it would offer annual fixed-price contracts to residential customers. Commercial and industrial customers would have a choice of fixed-price or indexed-price contracts. Green Mountain is asking the commission to approve a maximum price for the company’s electric generation services.

The application is on hold while the commission waits for an attorney general opinion on how to proceed.

Posted on

SoCalGas Proposes Hydrogen Pipelines

Southern California Gas proposed plans Thursday for what could be the largest green hydrogen infrastructure in the nation, with pipelines moving hydrogen from solar farms in the Mojave Desert and other inland areas to customers in the Los Angeles Basin.

The preliminary plan submitted to the California Public Utilities Commission proposes “one or more trunk transmission pipelines that would run from green hydrogen generation sources,” where renewable resources would be used to manufacture hydrogen, an energy-intensive process.

“The project would benefit ratepayers and the state by advancing California’s net zero goals, increasing use of clean fuels” and help to “facilitate the ultimate closure of [SoCalGas’] Aliso Canyon underground gas storage facility,” site of a massive natural gas leak in 2015, the utility’s application to the CPUC said.

SoCalGas asked the commission only for a memorandum account to keep track of expenses, for possible cost recovery later, as it pursues early-stage research and development. It requested that the CPUC approve the account by July. But it said the proposal was significant enough, “given the innovation and broad environmental benefits … [that] SoCalGas believes it important to provide the commission and the public with information about the project and its context in this first filing.”

“In one or more subsequent filings, SoCalGas expects to seek commission approval of the project and recovery of just and reasonable costs incurred,” it said.

SoCalGas is the largest gas utility in the U.S., with 5.8 million customer accounts and more than $3.6 billion in sales in 2020, according to the American Gas Association.

Hydrogen Hub

The application added to the focus on Los Angeles as a center of green hydrogen development.

The Los Angeles Department of Water and Power (LADWP) is converting its coal-fired Intermountain Power Plant in Utah to an 840-MW combined cycle natural gas-fired facility. The plant will be capable of burning a fuel mixture consisting of 30% hydrogen when it opens in 2025, transitioning to 100% by 2045, the utility has said.

A report published last March by the National Renewable Energy Laboratory — titled “LA100: The Los Angeles 100% Renewable Energy Study” — showed that LADWP will require a large amount of dispatchable generation closer to home to reach a 100% clean-energy goal and replace four outmoded natural gas plants that need to be rebuilt or retired.

The Los Angeles City Council voted in September to require that 100% of the electricity used in the city be carbon-free by 2035, establishing a 2030 deadline for replacing the gas-fired plants.

And the Green Hydrogen Coalition has been leading development of a green hydrogen hub in Southern California. The goal of the HyDeal Los Angeles initiative is to deliver green hydrogen for the Los Angeles Basin at $1.50/kg by 2030.

In a probable boost to that effort, the $1.2 trillion infrastructure bill passed by Congress in November provides $8 billion for development of four green hydrogen hubs in the U.S. and $1 billion toward domestic production of the electrolyzers needed to produce hydrogen, part of the Department of Energy’s Hydrogen Energy Earthshot initiative. (See ‘Ecosystems’ Needed to Drive Green Hydrogen Growth.)

SoCalGas said its new plan, called “Angeles Link,” could provide the green hydrogen needed to convert the four outdated gas plants to cleaner generation and displace up to 3 million gallons of diesel fuel per day, if heavy-duty diesel trucks are replaced by hydrogen fuel-cell trucks.

“As contemplated, the Angeles Link would deliver green hydrogen in an amount equivalent to almost 25 percent of the natural gas SoCalGas delivers today,” the utility said in a news release.

LADWP praised the effort.

“We are encouraged that SoCalGas is embarking on a major project that will help make green hydrogen a reality here in Los Angeles,” LADWP General Manager Marty Adams said in the SoCalGas statement. “Developing a source of safe, affordable green hydrogen is key to achieving our clean energy future by 2035, while ensuring the reliability we all need and depend on.”

Spotty Record

California is legally mandated to replace all fossil-fuel generation serving retail customers with clean-energy resources by 2045 and to reduce greenhouse gas emissions 40% below 1990 levels by 2030. How a partial replacement of natural gas with green hydrogen might play out under the mandates is untested and could prove problematic.

SoCalGas said in its application that green hydrogen could help decarbonize “‘hard-to-electrify industries,’ electric generation and the heavy-duty transportation sector” while advancing “progress toward net zero goals.”

The CPUC has yet to take any action regarding SoCalGas’ application.

The utility has wrangled with its regulator in recent years, being punished for misdeeds — including a nearly $10 million fine earlier this month — that the pipeline announcement appears geared to partly offset in the public eye.

SoCalGas’ past run-ins with the CPUC include the long-running Aliso Canyon controversy, which resulted in a CPUC investigation and continued oversight. It also generated last year’s $1.8 billion legal settlement between plaintiffs, SoCal Gas and parent company Sempra Energy.

In April 2019, the CPUC fined SoCalGas $8 million for failing to send out prorated customer bills in a timely manner, resulting in higher bills and extending the billing period for many customers.

On Feb. 3, the CPUC fined SoCalGas $9.8 million for misspending ratepayer funds for advocacy work on building codes. The commission had prohibited such activities in 2018 after its Public Advocates Office determined SoCalGas inappropriately used ratepayer money to fight energy-efficient building standards.

In its proposed decision, the CPUC said SoCalGas had shown “profound, brazen disrespect for the commission’s authority” during the investigation and deserved to be penalized.

The company said in a brief statement it was reviewing the decision and looked forward to “further engagement.” It has 30 days from the issuance date to challenge the ruling, after which the proposed decision becomes final.