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Exclusive: California IPP considering hydrogen options for gas generation portfolio

A California-based IPP is considering burning hydrogen in the thermal plants it acquires, as well as in a portfolio of gas peaking assets it is developing in Texas and the western US.

Nightpeak Energy, the Oakland-based IPP backed by Energy Spectrum Capital, is planning to have wide optionality to burn hydrogen in the gas plants it acquires, as well as in quick-start peaking natural gas assets it is developing in Texas and the western US, CEO Paris Hays said in an interview.

“There’s just not a lot of places in this country where you can procure enough hydrogen at a reasonable price to actually serve wholesale electricity customers,” Hays said of the existing hydrogen landscape.

Still, OEMs are figuring out in real time which of their deployed fleet can burn hydrogen, he said. Studies on blending seem to be yielding positive results.

“That’s great news for a business like ours, because we can have optionality,” Hays said. When interacting with equipment providers, conversion to hydrogen is an important, if expensive, discussion point.

“We want to be in a position to be able to do that for our customers,” Hays said. “We can offer a premium product, which is kind of rare in our business.”

Nightpeak recently purchased Saguaro Power Co., which owns a 90 MW combined cycle power plant in Nevada. That facility is a candidate for hydrogen repowering, Hays said, though that’s just one option for an asset that is currently cash-flowing well.

The Nevada facility is close to California, which notably is a market with a demonstrated appetite for paying green premiums, Hays said.

“We wouldn’t manufacture hydrogen ourselves, we would be a buyer,” he said. “This is one path that any plants we own or develop could take in the future.”

Nightpeak has yet to announce any greenfield projects. But Hays said the company is developing a portfolio of “quick-start” natural gas generation projects in ERCOT and WECC. Those assets, 100 MW or more, are to be developed with the concept of hydrogen conversion or blending in mind.

Proposition 7, which recently passed in Texas, could present an opportunity for Nightpeak as the legislation’s significant provisions for natural gas development has pundits and some lawmakers calling for the assets to be hydrogen-ready.

Investor interest in being able to convert gas assets to burn hydrogen reflect an important decision-making process for Nightpeak, Hays said.

“Does it makes sense to just buy a turbine that only burns natural gas and may be a stranded asset at some point, or would we rather pay and select a turbine that already has the optionality?” Hays said. “Putting price aside, you’re always going to go for optionality.”

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Strata Clean Energy launches P2X platform

Strata’s initial projects will produce ammonia derived from renewable energy, while future projects will focus on alternative e-fuels.

Strata Clean Energy, a renewable energy developer, is building a Power-to-X (P2X) development and technology platform to decarbonize segments of the modern economy where direct electrification is not viable, according to a news release.

The P2X platform leverages the firm’s state-of-the-art, hourly-matched, renewable energy supply solutions to produce low-carbon hydrogen derivatives (ammonia, e-methane, and SAF) critical to the hardest-to-abate industrial, agricultural, and ocean freight and aviation markets.

“Strata will transform non-dispatchable clean energy into carbon-free alternatives for the modern industrial economy. Our structured power products and merchant BESS development track record underpin our differentiated approach to serving large loads which require hourly matched renewable energy supply,” said Mike Grunow, EVP & general manager, P2X, Strata Clean Energy. “For the past 12 months, we have been actively siting projects in ideal locations for logistics, water rights, permitting, energy cost, and grid interconnection. Our team is quickly advancing site engineering with Tier 1 partners, and we are accelerating talks with long-term buyers of the low-carbon intensity commodities. We are going to make this a reality.”

Strata’s initial projects will produce ammonia derived from renewable energy, while future projects will focus on alternative e-fuels that can reduce greenhouse gas emissions where no other alternative exists. As a 1:1 replacement for natural-gas-derived ammonia, low-carbon-intensity ammonia can be the workhorse of the zero-carbon economy as it lowers the shipment cost of green hydrogen by a factor of 30.

“For the past 15 years, Strata has been instrumental in bringing over 270 utility-scale solar and storage projects online,” commented Markus Wilhelm, Strata’s CEO. “In the coming decade, regional grids will be loaded with unscheduled wind and solar. Converting a fraction of this generation into zero-carbon, alternative fuels is the next step in the global energy transition to a net-zero future.”

In the fourth quarter of 2022, Strata P2X began recruiting a dedicated team of experts from the petrochemical and utility sectors to play critical roles in advancing the company’s ambitious goals. Among the new hires is KJ Plank, Chief Innovation Officer, who is building out the technology, engineering, energy, and procurement teams within P2X at Strata.

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CIB providing $277m for Varennes biorefinery JV

CIB will provide a loan of $277m to a joint-venture partnership between Shell, Suncor, Proman and the government of Québec.

Canada Infrastructure Bank will provide a loan of $277 million to a joint-venture partnership between Shell, Suncor, Proman and the government of Québec that will enable construction of Canada’s largest biorefinery, the Varennes Carbon Recycling facility, according to a news release.

The $1.2bn facility will include an electrolyzer which will supply clean hydrogen and oxygen to convert more than 200,000 tonnes of non-recyclable waste and residual biomass into biofuels with a capacity of up to 130 million litres annually.

The project will be using Enerkem’s proprietary thermochemical process.

This is CIB’s first project from its low-carbon fuels, carbon capture utilization storage and hydrogen initiative.

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Air Products to build commercial-scale hydrogen refueling station in Edmonton

The hydrogen refueling station will be Air Products’ first in Canada and the first commercial-scale hydrogen refueling station in Alberta.

Air Products, the world’s largest producer of hydrogen, plans to build a multi-modal hydrogen refueling station near its new net-zero hydrogen energy complex under construction in Edmonton, Alberta, Canada.

The hydrogen refueling station will be Air Products’ first in Canada and the first commercial-scale hydrogen refueling station in Alberta. The station plans were announced today at the Canadian Hydrogen Convention during a fireside chat with Eric Guter, Air Products’ Global Vice President, Hydrogen for Mobility.

“This station is the next step in Air Products’ commitment to Edmonton and the province of Alberta and will serve as a model that can be replicated throughout Canada to grow the hydrogen economy, reduce emissions and assist Canada on its path to achieving net-zero by 2050,” said Guter. “Canada is well-positioned to be a leader in the clean energy future, and we are proud to build on Air Products’ investment in Western Canada to help accelerate the use of hydrogen as an emissions-free transportation fuel across the nation.”

The hydrogen refueling station is supported in part by $1 million (CAD) in funding from Natural Resources Canada’s Zero Emission Vehicle Infrastructure Program.

The new station will include two hydrogen refueling lanes with dispensers for heavy-duty vehicles such as commercial and municipal trucks, and Air Products’ own truck fleet, with a filling time on par with conventionally fueled heavy-duty trucks. In addition, the station also will have two fueling positions for light-duty hydrogen fuel cell cars. The state-of-the-art, high-capacity, high-efficiency station is scheduled to open in early 2025 and will be available to retail customers. Using proprietary compression technology, the station will have a capacity of up to six tonnes of hydrogen per day. It will be located in Northeast Edmonton near Air Products’ transformative new $1.6bn (CAD) net-zero hydrogen energy complex.

The complex will use an advanced process technology that enables the cost-effective capture of more than 90 percent of carbon emissions for permanent sequestration safely underground. In addition, to avoid the indirect emissions associated with using grid electrical power, the project includes a 100 percent hydrogen-fueled power generation unit. This unit is oversized to power the production facility and supply clean power to the Alberta grid.

The complex also will be integrated with neighboring Imperial Oil Limited’s new renewable diesel facility, using innovative engineering. Imperial will produce renewable diesel from locally sourced non-petroleum feedstocks, using a process that produces a biogenic renewable off-gas (ROG) by-product. This ROG will be used as a feedstock within the Air Products hydrogen complex, displacing natural gas and further enhancing the overall carbon emissions profile. The combination of utilizing a renewable feedstock and power export more than offset the remaining 10 percent needed to achieve net-zero at the new hydrogen production facility.

The net-zero facility will connect to Air Products’ existing 55-kilometer pipeline network in the Alberta Heartland to help refining and petrochemical customers reduce the carbon intensity of their operations and products.

Air Products also has announced plans to open a new project delivery office in Edmonton. The Global Engineering and Manufacturing Technology Equipment office will be a cross-functional space including engineering, product, process gas, and air separation unit product line functions.

Air Products currently operates three hydrogen production facilities in Alberta, and also operates a hydrogen production facility, a 30-kilometer pipeline network and a liquefaction facility in Sarnia, Ontario.

Air Products works across all facets of the hydrogen value chain, including production, distribution, storage and dispensing and has been a pioneer in hydrogen fueling for decades.

The company operates the world’s largest hydrogen pipeline system, located in the U.S. Gulf Coast, and is a world-class liquid hydrogen supplier. Air Products has hands-on operating experience with over 250 hydrogen fueling station projects in 20 countries and the company’s technologies are used in over 1.5 million fueling operations annually.

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Biomass-to-hydrogen developer in talks for development capital, series A

A California developer that uses woody biomass to make green hydrogen is in discussions to raise capital for project development and a series A funding round.

Yosemite Clean Energy, a California-based biomass-to-hydrogen start-up, is in discussions with potential investors to raise development capital for projects and a series A round.

The company is currently seeking around $20m of development capital that would help advance woody biomass-to-hydrogen projects to FID, CEO Tom Hobby said in an interview.

Hobby said he is also in discussions with strategic capital partners about a series A funding round. The company is not using an advisor for the capital raise, Hobby said, but is working with the law firm Kilpatrick Townsend & Stockton.

The company has so far raised less than $2m at the corporate level from friends and family and an additional $5m – including grants – for projects, Hobby added. The development capital as well as the series A raise would be conducted at the project level.

Yosemite has signed a letter of intent and term sheet for offtake from its first project in Oroville, California, which will produce approximately 24,000 kg per day (2,760 MMBtu) of green hydrogen from woody biomass, and is set for FID later this year. Hobby declined to name the offtaker but described it as a “global trading house.”

Hobby, whose family has lived in the Sierra Nevada for generations, emphasizes the company’s role as a partner with local communities to help manage forest waste, which has served as fuel for explosive wildfires in recent years.

“It’s de-risking their communities from catastrophic wildfires,” he said.

Design incentives

Under the original design for the Oroville facility, the company had planned to produce 31,000 kg per day of RNG and 12,200 kg per day of green hydrogen. But due to incentives for green hydrogen in the Inflation Reduction Act, the company has pivoted to a hydrogen-only design, Hobby said.

The $3/kg incentive for green hydrogen in the IRA created “additional value for no real capital cost differential,” he said.

Yosemite’s second project is in Toulumne County, California and will follow a design substantially similar to the Oroville facility.

The company employs dual-bed gasification technology licensed from Austrian firm Repotec, while Primoris is doing detailed design and engineering.

The technology takes wood and creates a medium-strength BTU gas that can be used to make different products, Hobby said. “Once it’s in a gaseous form, we can use it for a lot of purposes: we can take it to make power, we can produce hydrogen, we can use the Fischer-Tropsch process to make second-generation biofuels like aviation fuel, and we have a patent that can do hydrogen and RNG.”

Project ownership

Meanwhile, Yosemite has hired a Texas-based firm to help raise capital for projects, which are estimated to cost $250m at the outset, but could decline once efficiencies are achieved, Hobby said.

The company’s project ownership model is unique in that it seeks to bring in local wood businesses – in logging, land clearing, and orchard removal – as providers of biomass and also equity investors in the projects.

“To have their investment and their wood at the same time is huge,” Hobby said.

In raising capital for the projects, in addition to equity and debt investors, Yosemite is evaluating a mix of sources in the tax-exempt bond market as well as lower-interest loans from within California and export finance solutions. The company recently received two $500,000 Forest Biomass to Carbon-Negative Biofuels grants from the California Department of Conservation.

Hobby would like to build 50 woody biomass plants in California, which would utilize approximately 5 million tons of the 35 million tons of waste woody biomass available annually in the state.

“Our goal is not to have to truck and ship wood more than 50 miles,” he said. “If you put circles around every place in California that’s a decent wood basket […] I think we could sign about 50 facilities across the state.”

The company is also planning to expand beyond California to other states with a low-carbon fuel standard, Hobby said.

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Exclusive: Additional details revealed on e-fuels equity raise

A US e-fuels developer is in the midst of a Series C raise with BofA Securities advising.

E-fuels developer Infinium is raising $300m in a Series C capital raise that launched last year, according to a source familiar with the matter.

BofA Securities has been engaged to advise on the process, as previously reported by ReSource. The amount of the capital raise was not previously reported.

Infinium and BofA did not respond to requests for comment. 

Infinium recently announced the existence of Project Roadrunner, located in West Texas, which will convert an existing brownfield gas-to-liquids project into an e-fuels facility delivering products to both US and international markets. Breakthrough Energy Catalyst has contributed $75m in project equity.

Infinium, which launched in 2020, closed a $69m Series B in 2021, with Amazon, NextEra and Mitsubishi Heavy Industries participating. Its Project Pathfinder in Corpus Christi is fully capitalized.

About a dozen projects, split roughly 50/50 between North America and the rest of the world, are in development now. The company is always scouting new projects and is looking for partners to provide CO2, develop power generation and offtake end products, an executive said previously.

A CO2 feedstock agreement for a US Midwest project with BlackRock-backed Navigator CO2 Ventures was recently scrapped after the latter developer cancelled its CO2 pipeline project.

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Feature: Why blue hydrogen developers are on the hunt for livestock-based RNG

The negative carbon intensity ascribed to livestock-derived renewable natural gas could allow blue hydrogen production to meet the threshold to qualify for the full $3 per kg of hydrogen tax credit under section 45V. The viability of this pathway, however, will depend on how hydrogen from biogas is treated under the IRS’s final rules.

Lake Charles Methanol, a proposed $3.24bn blue methanol plant in Lake Charles, Louisiana, will use natural gas-based autothermal reforming technology to produce hydrogen and carbon monoxide, which will then be used to produce 3.6 million tons per year of methanol while capturing and sequestering 1 million tons per year of carbon dioxide.

And if certain conditions are met in final rules for 45V tax credits, the developer could apply for the full benefit of $3 per kg of hydrogen produced. How? It plans to blend carbon-negative renewable natural gas into its feedstock.

“Lake Charles Methanol will be a large consumer of RNG to mitigate the carbon intensity of its hydrogen production,” the firm’s CEO, Donald Maley, said in written comments in response to the IRS’s rulemaking process for 45V.

The issue of blending fractional amounts of RNG into the blue hydrogen production process has emerged as another touchstone issue before the IRS as it contemplates how to regulate and incentivize clean hydrogen production.

The IRS’s proposed regulations do not provide guidance on the use of RNG from dairy farms in hydrogen production pathways such as SMR and ATR, gasification, or chemical looping, but instead only define clean hydrogen by the amount of carbon emissions.

In theory, a blue hydrogen producer using CCUS could blend in a small amount – around 5% – of carbon-negative RNG and achieve a carbon intensity under the required .45 kg CO2e / kg of hydrogen to qualify for the full $3 per kg incentive under 45V. 

This pathway, however, will depend on final rules for biogas within 45V, such as which biogas sources are allowed, potential rules on RNG additionality, incentive stacking, and the appropriate carbon intensity counterfactuals. 

Furthermore, a potentially separate rulemaking and comment period for the treatment of biogas may be required, since no rules were actually proposed for RNG in 45V on which the industry can comment.

Like the treatment of electricity within 45V, there appears to be some disagreement within Treasury about the role of RNG in the hydrogen production process, with some in the Democratic administration perhaps responding to the view of some progressives that RNG is a greenwash-enabling “sop” to the oil and gas industry, said Ben Nelson, chief operating officer at Cresta Fund Management, a Dallas-based private equity firm.

Cresta has investments in two renewable natural gas portfolio companies, LF Bioenergy and San Joaquin Renewables, and expects RNG used in hydrogen to be a major demand pull if the 45V rules are crafted correctly.

A major issue for the current administration, according to Nelson, is the potentially highly negative carbon intensity score of RNG produced from otherwise vented methane at dairy farms. The methane venting counterfactual, as opposed to a landfill gas counterfactual, where methane emissions are combusted as flared natural gas (therefore producing fewer GHG emissions than vented methane), leads to a negative CI score in existing LCFS programs, which, if translated to 45V, could provide a huge incentive for hydrogen production from RNG. 

“Treasury may be struggling with the ramifications of making vented methane the counterfactual,” Nelson said.

Divided views

The potential for this blending pathway has divided commenters in the 45V rulemaking process, with the Coalition for Renewable Natural Gas and similar companies calling for additional pathways for RNG to hydrogen, the promulgation of the existing mass balance and verification systems – as used in LCFS programs – for clean fuels, and the allowance of RNG credit stacking across federal, state, and local incentive programs.

Meanwhile, opponents of RNG blending noted that it would give an unfair economic advantage to blue hydrogen projects and potentially increase methane emissions by creating perverse incentives for dairy farmers to change practices to take advantage of the tax credits.

For example, in its comments, Fidelis New Energy speaks out forcefully against the practice, calling it “splash blending” and claiming it could cost Americans $65bn annually in federal incentives “with negligible real methane emission reductions while potentially driving an increase in emissions overall without proper safeguards.”

Fidelis goes on to state that allowing RNG to qualify under 45V results in a “staggering” $510 / MMBtu for RNG, a “market distorting value and windfall for a select few sizable industry participants.”

Renewables developer Intersect Power similarly notes the potential windfall for this type of project, since the $3 credit would be higher than input costs for blue hydrogen. “Said another way, hydrogen producers using natural gas and blending RNG with negative CI will be extremely profitable, such that it would encourage the creation of more sources of RNG to capture more credits,” according to the comments, which is signed by Michael Wheeler, vice president, government affairs at Intersect.

Stacking incentives

In its initial suggestions from December, Treasury introduced the possibility of limiting RNG that qualifies under 45V from receiving environmental benefits from other federal, state, or local programs, such as the EPA’s renewable fuel standard (RFS) and various state low carbon fuel standards (LCFS).

In response, the Coalition for Renewable Natural Gas said that it does not “believe it is the intent of the Section 45V program to limit or preclude RNG from participation in” these programs. 

“In particular, a hydrogen facility utilizing RNG to produce clean hydrogen as defined in Section 45V program should be eligible to claim the resulting Section 45V tax credit, and not be barred or limited from participating in the federal RFS or a state LCFS program, if the RNG-derived hydrogen is being used as a transportation fuel or to make a transportation fuel (e.g. SAF, marine fuel, or other fuel) used in the contiguous U.S. and/or the applicable state (e.g., California), respectively,” the organization wrote.

Various commenters along with the Coalition for Renewable Natural Gas stated that the incentives should work together, and that the EPA has “long recognized that other federal and state programs support the RFS program by promoting production and use,” as Clean Energy Fuels wrote.

Cresta, in its comments, noted that the 45V credit would result in a tax credit of $19.87 per MMBtu of RNG, while almost all potential dairy RNG build-out has a breakeven cost above $20 per MMBtu — in other words, not enough to incentivize the required buildout on its own.

Including this incentive plus environmental credits such as LCFS and RINs could get RNG producers to higher ranges “where you’re going to get a lot of buildout” of new RNG facilities, Nelson said.

In contrast, Fidelis argues that the ongoing RNG buildout utilizing just the existing state LCFS and RFS credits is proof enough that the incentives are working, and that 45V would add an exorbitant and perverse incentive for RNG production.

“To demonstrate the billions in annual cost to the American taxpayer that unconstrained blended RNG/natural gas hydrogen pathways could generate in 45V credits, it is important to consider the current incentive structure and RNG value today with CA LCFS and the EPA’s RFS program, as well as with the upcoming 45Z credit,” Fidelis writes. “Today, manure-RNG sold as CNG with a CI of -271.6 g CO2e / MJ would generate approximately $70 / MMBtu considering the value of the natural gas, CA LCFS, and RFS. The environmental incentives (LCFS and RFS) are 23x times as valuable as the underlying natural gas product.”

In its model, Fidelis claims that the 45V credit would balloon to $510 / MMBtu of value generation for animal waste-derived RNG, but does precisely explain how it arrives at this number. Representatives of Fidelis did not respond to requests for comment.

RNG pathways

As it stands, the 45VH2-GREET 2023 model only includes the landfill gas pathway for RNG, thus the Coalition for Renewable Natural Gas and other RNG firms propose to add biogas from anaerobic digestion of animal waste, wastewater sludge, and municipal solid waste, as well as RNG-to-hydrogen via electrolysis.

According to the USDA, “only 7% of dairy farms with more than one thousand cows are currently capturing RNG, representing enormous potential for additional methane capture,” the coalition said in its comments.

Even the Environmental Defense Fund, an environmental group, supports allowing biomethane from livestock farms to be an eligible pathway under 45V, “subject to strong climate protections” such as monitoring of net methane leakage to be factored into CI scores and the reduction of ammonia losses, among other practices.

However, the EDF argues against allowing carbon-negative offsets of biomethane, saying that “doing so could inappropriately permit hydrogen producers to earn generous tax credits through 45V for producing hydrogen with heavily polluting fossil natural gas.”

First productive use

In issuing the 45V draft guidance in December, the Treasury Department and the IRS said they anticipated that in order for RNG to qualify for the incentive, “the RNG used during the hydrogen production process must originate from the first productive use of the relevant methane,” which the RNG industry has equated with additionality for renewables under 45V.

The agencies said that they would propose to define “first productive use” of the relevant methane “as the time when a producer of that gas first begins using or selling it for productive use in the same taxable year as (or after) the relevant hydrogen production facility was placed in service,” with the implication being that  “biogas from any source that had been productively used in a taxable year prior to taxable year in which the relevant hydrogen production facility was placed in service would not receive an emission value consistent with biogas-based RNG but would instead receive a value consistent with natural gas.”

This proposal is opposed by the RNG industry and others planning to use it as a feedstock.

“Instituting a requirement that the use of RNG for hydrogen production be the ‘first productive use’ of the relevant methane would severely limit the pool of eligible projects for the Section 45V PTC,” NextEra Energy Resources said in its comments.

Nelson, of Cresta, called the “first productive use” concept for RNG “a solution in search of a problem,” noting that it’s more onerous than the three-year lookback period for additionality in renewables.

“Induced emissions are a real risk in electricity – they are a purely hypothetical risk in RNG,” Nelson said, “and will remain a hypothetical risk indefinitely in virtually any scenario you can envision for RNG buildout, because there’s just not that many waste sites and sources out there.”

The issue, Nelson added, is that if RNG facilities are required to align their startup date with hydrogen production, the farms where RNG is produced would just continue to vent methane until they can coincide their first productive use with hydrogen.

The Coalition for Renewable Natural Gas argues that the provision “would cause a significant value discrepancy for new RNG projects creating a market distortion, greater risk of stranded RNG for existing projects, added complexity, and higher prices for end-consumers.”

The Coalition proposes, instead, that Treasury could accept projects built prior to 2030 as meeting incrementality requirements “with a check in 2029 on the market impacts of increased hydrogen production to determine, using real world data, if any such ‘resource shifting’ patterns can be discerned.”

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