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November 18, 2024

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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.”

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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.”

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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.

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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.

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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.

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PPL Announces Losses, Dividend Cut in Q4 Call

PPL’s (NYSE:PPL) stock price took a sharp hit Friday as the company announced during its fourth-quarter earnings call that it was cutting dividends in half and missed earnings and revenue targets.

The company announced it will reduce its quarterly common stock dividend to 20 cents/share from $41.5 cents last quarter. PPL’s stock price dropped 7.25% in trading, finishing the day at $26.10.

CEO Vincent Sorgi said PPL’s year was marked by a “strategic repositioning” of the company, including the sale of its U.K. utility business Western Power Distribution for 7.8 billion pounds ($10.7 billion) to National Grid and the purchase of the London-based company’s Rhode Island utility, Narragansett Electric, for $3.8 billion. (See PPL to Sell UK Business, Acquire Narragansett Electric.)

“2021 was very much a transition year for PPL,” Sorgi said. “It was about reimagining PPL and laying a firm foundation for the company’s future growth and success, and I believe we achieved just that.”

Narragansett Purchase

Sorgi said PPL anticipates receiving a final order from the Rhode Island Division of Public Utilities and Carriers regarding the Narragansett acquisition by March. PPL received FERC approval for the purchase in September, but the utility needs final approval from the PUC for the deal to go through. (See FERC Approves PPL Acquisition of Narragansett.)

Sorgi highlighted PPL’s utility experience, customer satisfaction and innovation as reasons the company is confident it will ultimately win regulatory approval for Narragansett’s acquisition. He said PPL has been a “clear leader” in the development and deployment of the kind of smart grid technology Rhode Island will need in achieving its decarbonization goals.

“We think we’ve met the standard for approval in the state, and we are looking forward to the decision coming out from the division,” Sorgi said. “We are all very focused on getting this deal over the goal line and bringing real value to our line.”

Infrastructure and Storm Damage

Sorgi also highlighted PPL’s response to significant storm damage in its service area, including a major December tornado outbreak in Kentucky and the remnants of Hurricane Ida in Pennsylvania in September.

Vince-Sorgi-(PPL)-FI.jpgVince Sorgi, PPL CEO | PPL

More than 500 transmission and distribution poles were destroyed from the storms in Kentucky, Sorgi said, but PPL restored power to most of its customers within 48 hours. Crews were also able to restore power in Pennsylvania despite historic flooding from the hurricane, Sorgi said, and PPL was recognized with an Edison Electric Institute Emergency Response Award for its restoration performance.

“When severe weather struck either in Pennsylvania or Kentucky, we responded quickly and effectively,” Sorgi said. “This performance is the result of the investments we have made in our grid and our dedicated employees who pride themselves on delivering the superior level of service each day.”

CFO Joe Bergstein said the capital investments made in the states last year aided in the support of grid modernization, resilience and reliability. In Pennsylvania, the company focused on distribution reliability and advancing IT systems, while transmission investments included smart relays, equipment monitoring and automation. Kentucky investments were primarily related to replacing aging transmission infrastructure, resulting in a total rate-base growth of about 6% in the state even as rates related to coal-fired generation facilities fell.

Operating Results

Friday’s lowered dividend payment was based on projected earnings per share from PPL’s existing business operations in Pennsylvania and Kentucky and the company’s targeted payout ratio of 60 to 65%. Because earnings from the former U.K. operation are now excluded, using the targeted payout ratio, the dividend was reduced.

The fourth-quarter earnings included special expenses of $29 million linked to the Narragansett acquisition and the sale of its U.K. utility.

The company reported a 2021 net loss of $1.48 billion (‑$1.93/share), compared with $1.47 billion ($1.91/share) in 2020. The earnings losses included special-item after-tax expenses of $2.29 billion ($2.98 per share) attributed to the discontinued U.K. operations, a U.K. tax rate change and a loss on the “early extinguishment” of debt.

However, earnings from ongoing operations in 2021, which excludes special items, was $806 million ($1.05/share), compared to $774 million ($1/share) in 2020. The company reported quarterly earnings of $134 million ($0.18/share), compared with $290 million ($0.38/share) in the fourth quarter of 2020.

PPL reduced its debt position by $3.5 billion, and it completed $1 billion in stock repurchases. Bergstein said the debt reduction was “one of the key financial highlights for 2021,” with a significant amount of the sale of WPD proceeds going to “strengthen PPL’s balance sheet.”

“We had a unique opportunity to establish one of the leading credit profiles in the sector, an attribute we see is increasingly important with the growing capital needs to fund the clean energy transition and now amid the backdrop of rising interest rates,” Bergstein said.

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Con Edison 2021 Earnings Jump 22%

Consolidated Edison’s (NYSE: ED) earnings rose 22.3% to $1.35 billion ($3.86/share) last year on higher electric, gas and steam revenues, the company reported last week.

The company earned $224 million ($0.63/share) in the fourth quarter, compared with $43 million ($0.13/share) in the same period a year earlier, after winding down a loss related to its investment in the Mountain Valley Pipeline.

“Once again in 2021, our employees continued to provide safe, reliable service to our customers throughout the unprecedented challenges of the pandemic, and our focus on delivering investor value remains strong,” CEO Timothy Cawley said in a statement. “Our expanded clean energy commitment reflects our dedication to lead the transition to renewables, gives our customers greater control over their energy use, and builds a more resilient grid.”

Con Edison said it aims to invest in, build and operate innovative energy infrastructure, advance electrification of heating and transportation, and transition away from fossil fuels to a net-zero economy by 2050.

The company last month released an investment plan targeting capital investments this year of about $4.6 billion, and $11 billion in aggregate capital investments over 2023-24.

Con Edison also last month submitted to the New York Public Service Commission a rate case for an 11.8% increase in electric rates and higher gas rates to become effective next January (22-E-0064).

The timing of the rate hike request proved awkward, as within two weeks many city customers were shocked to see sharp increases in their monthly Con Ed bills.

Gov. Kathy Hochul asked Con Edison to review its billing practices; she also announced increased relief efforts to reach low-income New Yorkers, making millions of dollars in aid available.  

“Even though the spikes we are seeing in electricity, natural gas and fuel prices were predicted and are due to severe winter weather, I am calling on Con Ed to review their billing practices because we must take unified action to provide relief for New Yorkers, especially our most vulnerable residents,” Hochul said.

Con Edison also must resolve several regulatory concerns before being authorized to build a new $4 billion substation complex in New York City dedicated to interconnecting offshore wind projects. (See Con Ed to Refine $4B Offshore Tx Plan for NYC.)

In October, Con Edison subsidiary Orange and Rockland Utilities (O&R) entered a joint proposal for new electric and gas rate plans for the three-year period through 2024, subject to regulatory approval.

Con Edison is one of the country’s largest investor-owned utilities, with approximately $12 billion in annual revenues and $63 billion in assets. CECONY is its regulated utility providing electric, gas and steam service in New York City and Westchester County, New York, while O&R serves customers in a 1,300-square-mile-area in southeastern New York and northern New Jersey.

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Report: Challenges Ahead in Maine Power-to-Fuel Pilot Search

Maine has many options and challenges ahead in the search for a pilot project to demonstrate the benefits of renewable power-to-fuel (PTF) facilities for the electric grid, a recent Public Utilities Commission report said.

“PTF facilities and the technologies that are available are highly operational and location specific,” which leaves a lot of open questions before a pilot is identified, said Matthew Rolnick, PUC staff analyst.

While there are extensive PTF studies and pilots in the U.S., most are relatively new and do not have results available yet, Rolnick said during a Feb. 15 Energy, Utilities and Technology Committee (EUT) meeting.

“It’s hard to know when those results will be coming online … so it’s still very early days,” he said.

Rolnick presented findings to the committee from its initial study of PTF pilot program feasibility, as directed by a Maine energy storage law enacted in June. The committee could use that report to inform a pilot program bill in the current session. (See New Maine Law Sets 400-MW Energy Storage Target for 2030.)

As defined by the law, PTF is the conversion of renewable energy to hydrogen, methane or “other fuel.” Possible benefits of PTF to the grid, Rolnick said, include avoiding renewable curtailment by redirecting excess generation to a hydrogen production facility and avoiding investment in transmission and distribution expansion and upgrades.

Generating hydrogen from excess renewable energy generation could support the electric grid while also reducing emissions associated with the thermal sector, the PUC said.

“There may be ways to use PTF to produce gases that could be injected into the existing natural gas infrastructure to provide carbon-free space heating to the roughly 50,000 Maine customers that currently use natural gas,” the report said.

In its review of PTF projects, the PUC identified a small pilot project in New Jersey that is demonstrating the production of hydrogen from solar and its subsequent blending into the gas distribution system. Developer New Jersey Resources (NJR) commissioned the project in October.

The New Jersey Board of Public Utilities approved cost recovery for that project, which NJR estimated will cost $6 million. Initially, the project will offset 180 tons of CO2 per year, the company said in its rate case filing.

Last year, the EUT committee considered but did not pass a PTF pilot bill (LD 9) introduced by committee chair Sen. Mark Lawrence (D). Maine-based Summit Natural Gas testified in support of the bill, saying PTF has the potential to make hydrogen from otherwise-curtailed wind energy in the state for injection into the gas system.

Increasing renewable energy in Maine is causing costly curtailments and the need for transmission investment, Summit said in its Aug. 27 comments to the PUC for the report. Building hydrogen facilities in constrained locations can reduce the impact of grid constraints and delay grid upgrades, the company said in response to a PUC request for information.

The Conservation Law Foundation (CLF) also supported the possible role of PTF in facilitating growth in the clean power sector, but it said in comments to the commission that it is “skeptical” of short-term investment in the technology. Among the nonprofit’s concerns is the risk of “inadvertently encouraging” reliance on fossil fuels.

CLF asked the commission not to recommend the legislature move ahead with a pilot, saying in Sept. 2 comments that the technology is “inarguably expensive.”

The Office of the Public Advocate agreed with the CLF’s assessment, saying that putting a high initial cost for emerging technologies on ratepayers is inconsistent with state law, according to Oct. 20 comments.

With respect to a PTF program, the OPA said, it’s not clear that Maine has “any unique attributes” that make it an “ideal” pilot host.

The PUC supported a pilot program in its report and suggested that the legislature could direct the commission to request proposals that can identify technology costs and benefits.

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FERC Approves Pause of PJM Transmission Constraint Penalty Factor in Virginia

FERC on Friday accepted revisions to PJM’s tariff and Operating Agreement that temporarily remove transmission constraint penalty factor (TCPF) rules in Virginia’s Northern Neck peninsula (EL22-26, ER22-957).

The peninsula, which encompasses Lancaster, Northumberland, Richmond and Westmoreland counties, is normally served by three transmission lines: a 230-kV line from Fredericksburg, a 230-kV from Lanexa-Dunnsville and a 115-kV line Harmony Village. But as part of a transmission upgrade project approved in 2020, PJM placed the Lanexa-Dunnsville line on outage at the beginning of the year.

That immediately created price fluctuations of the TCPF to its default rate of $2,000/MWh in the real-time energy market. PJM on Jan. 31 told FERC that the TCPF rules were creating “unjust and unreasonable energy market rates” for consumers on the peninsula.

The RTO also said the price fluctuations contributed to the default in January of Hill Energy Resource & Services, which had portfolio positions in the financial transmission rights market in the congested Dominion zone. (See PJM Weighs Options on Hill Energy FTR Default.)

TCPFs provide price signals to incent more supply or demand response. But the Northern Neck has a “few relatively small” combustion turbines, PJM told FERC, and load has not “responded significantly enough.” The line outage has resulted in “repeated instances” when no actions can relieve the transmission constraint on the other two lines, causing real-time energy market prices to oscillate between the offers of the CT plants and the TCPF of $2,000/MWh, even in the early morning hours, when behind-the-meter solar resources located on the peninsula are usually enough.

“PJM has shown that under the specific circumstances in the record, the transmission constraint penalty factor is not achieving its intended purpose in the Northern Neck peninsula and is resulting in an inappropriate price signal that establishes high prices without a commensurate benefit,” the commission said. “We therefore agree that it is just and reasonable to stop applying the transmission constraint penalty factor in the Northern Neck peninsula for a limited time.”

The RTO said the situation is expected to continue throughout the life of the project until its completion in December 2023, resulting in “significant increases in costs to load,” without an “amendment to the existing transmission constraint penalty factor rules.”

To solve the pricing issue, PJM proposed setting the transmission line limit “at a level that ensures the offers of the resources being used to control the constraint are reflected in the congestion price in lieu of applying a transmission constraint penalty factor.”

The RTO also proposed providing “regular informational filings” to the commission regarding congestion on the peninsula and to work with stakeholders on reforms to the TCPF rules if a similar situation happens in the future.

PJM requested an effective date of Feb. 1, 2022, one day after the date of its filings, because “recalculating energy market settlements is labor intensive, especially over an extended period of time.”

Protests

Several stakeholders protested PJM’s proposed changes.

Chicago-based hedge fund Citadel argued that PJM failed to demonstrate the existing TCPF rules were unjust and unreasonable. The company said PJM recorded recent scarcity pricing on the same path in August and December of 2020 and August 2021 and did not demonstrate how customers were harmed during those events and did not raise concerns at the time of those events. Citadel said there were 784 real-time intervals of prices reaching $2,000/MWh during the previous outages on the line, which “did not prompt PJM to make an emergency filing.”

DC Energy also said the outages in 2020 and 2021 created “substantially similar conditions on the remaining facilities serving Virginia’s Northern Neck” and argued that “emergency measures to eliminate the scarcity pricing signal were not justified in those circumstances and they are not justified now.”

Citadel also argued that “PJM should focus on ways to accelerate new generation development in this location as opposed to creating uncertainty around existing, market-based price signals.” The company said more than 700 MW of new solar, battery, and solar-battery facilities are planned to come online in the peninsula during or shortly after the period of the transmission outage.

Appian Way said that, because this case involves the Hill Energy default, PJM “may have responded with an excessive and unwarranted level of political sensitivity due to the historical context of the GreenHat” Energy default of 2018.

The commission said that while PJM has an existing process to temporarily relax the TCPF, the existing provisions “do not contemplate the unique scenario presented here.”

“Based on the evidence in the record, we find that PJM’s continued application of the transmission constraint penalty factor to congestion in the Northern Neck region resulting from the Lanexa-Dunnsville-Northern Neck line outage will not produce the intended short-term or long-term responses and, instead, will only result in higher costs to ratepayers without a commensurate benefit,” FERC said.

The commission said it agreed with PJM that new generation resources sufficient to relieve the constraint “could not reasonably be expected to be sited, constructed and complete the PJM interconnection process before December 2023.”

FERC also disagreed with Citadel’s argument that PJM failed to provide enough evidence for its proposal. The commission said PJM provided LMP data for the Northern Neck on Jan. 14, as well as for the period Feb. 1-14. The data were “sufficient to demonstrate the link between high prices and the transmission constraint penalty factor.”

The commission also disagreed with DC Energy’s and Citadel’s assertions that past incidences of high prices in the same area of the Dominion zone “demonstrate that PJM’s current tariff is not unjust and unreasonable.” It said the findings were “grounded in the unique circumstances” in the proceeding.

It directed PJM to submit an informational filing updating the commission on congestion patterns within 90 days of the date of the order and every 90 days after until the Lanexa-Dunnsville line upgrade is complete. The RTO was also encouraged to “consider modifications to its analyses of and planning for transmission outages to prevent such occurrences in the future.”

Danly Dissent

FERC Commissioner James Danly provided the lone dissent on the order, saying he disagreed that PJM met its Section 206 burden to demonstrate the existing transmission constraint penalty factor tariff rate is unjust and unreasonable

“As best I can make out, the high prices required by the tariff in the face of an unresolvable constraint are both too high for PJM’s liking but are simultaneously an insufficient incentive for anyone to do anything about it,” Danly said. “I am suspicious that this is a case of scarcity pricing being allowed in a market tariff only until it actually occurs, and then it must be eradicated. Markets cannot work when high prices that occur by design are disallowed in practice.”

Danly said it “does appear” that there may not be a short-term solution to the pricing issue, but he said he was “skeptical” that three weeks was a sufficient amount of time to make the determination. He said he was also concerned by the “regulatory uncertainty” making the change could cause.

“I cannot imagine how an existing generation resource in PJM can remain in business given the frequency of changes the commission repeatedly imposes on these markets, all tending to reduce prices for existing generation,” Danly said. “Today, we reduce price again, demonstrating to everyone that the mechanisms we put in place to harness market forces will be abandoned when they work as planned.”

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Vt. Maps Fast-charger Buildout for Federal NEVI Funds

With some National Electric Vehicle Infrastructure (NEVI) program guidance in hand, Vermont is already mapping out where it expects to begin building electric vehicle fast-charger stations in the coming year.

The state will receive a $3.1 million NEVI apportionment for federal FY2022, followed by four additional $4.5 million annual installments, said Patrick Murphy, sustainability and innovations project manager at the Vermont Agency of Transportation. The total $21.1 million in funding is Vermont’s part of the $5 billion allocated for NEVI over five years under the Infrastructure Investment and Jobs Act.

After reviewing the federal government’s NEVI guidelines released Feb. 10, VTrans has a preliminary plan to install or upgrade 15 fast-charger stations along federally approved alternative fuel highway corridors.

“Priority must be given to [alternative fuel corridors] … until they are deemed by the Federal Highway Administration (FHWA) to be fully built out,” Murphy said Friday in testimony to the Vermont Senate Transportation Committee.

Each station must have at least four, 150-kW ports and cannot be located more than 50 miles from another qualifying fast-charger station on a corridor. In addition, stations cannot be located more than one mile from a highway exit.

By pairing first-year NEVI funding with American Rescue Plan Act funding, Murphy said, Vermont could “come close within the next fiscal year to building out what’s required under the federal guidelines,” before it can use remaining funding for the state’s existing EV infrastructure goals. The installation cost for four 150-kW ports would be an estimated $413,000.

Vermont has an existing plan to put fast chargers along highways based on prior federal guidance for placement every 50 miles and within five miles of highway exits or interchanges and allowing for lower charging output.

Given Vermont’s rural nature, many highway exits do not have the electric infrastructure to support high output fast chargers within one mile.

“The move from the five- to one-mile distance may result in a number of requests for exceptions,” Murphy said, adding that it might also require other solutions, such as renewable energy and battery storage at some locations.

Fast-charger stations that the state has funded and built already along FHWA-approved corridors mostly have two 50-kW plugs.

“No locations on any of the corridors that we’ve had designated meet the new higher standard,” Murphy said.

NEVI guidelines call for states to complete station installations within six months of securing equipment and installation providers. That timeline, Murphy said, is “faster than any of the projects that we’ve completed to date” and could present certain challenges.

Demand for charging equipment will increase with the amount of NEVI funding that states will receive, he said. And there may be ongoing supply chain issues from the pandemic that could be compounded by Buy America requirements that the federal government has yet to clarify.

Current equipment costs also could increase as demand grows across states, Murphy said.

VTrans foresees additional difficulties arising from requirements of President Biden’s Justice40 initiative, which calls for 40% of investments to benefit disadvantaged areas. The initial guidance for locating fast-charger stations along highway corridors is “pretty prescribed,” Murphy said.

“The one-mile guidance from a highway intersection or exit clearly serves the traveling public for longer trip making, but it won’t always be compatible with a dual concern about making sure that these investments support local communities,” he said.

Murphy expects VTrans will have a draft plan for NEVI funds ready by March for stakeholder feedback, and final state plans are due for submission to FHWA by Aug. 1.