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H2 Green Steel enters long-term frame agreement for electricity supply

H2 Green Steel and Fortum have signed a frame agreement for electricity trading for the supply of CO2-free electricity for operations in Northern Sweden, including 700 - 800 MW of electrolyzer capacity.

H2 Green Steel and Fortum have formed a partnership that enables H2 Green Steel to purchase Fortum’s carbon-free electricity on both short and long-term bases for its green steel operations in Northern Sweden.

The parties will strengthen the cooperation further in long-term Power Purchase Agreements (PPAs).

The frame agreement is initially planned to include two deals for 2.3 TWh per year: an index-based PPA of 1.3 TWh annually (from 2026) with a five-year hedging horizon, and a fixed price PPA of 1 TWh for up to nine years (from 2027).

Significant volumes of electricity are needed to power the 700-800MW electrolyzer that will generate green hydrogen, which in turn will reduce iron ore to sponge iron that will feed the steel production at H2 Green Steel’s plant in Boden. In this important partnership with Fortum, another big step is taken in support of H2 Green Steel’s ambitious venture and the decarbonization of the steel industry.

H2 Green Steel’s plant in Boden will initially produce an annual volume of 2.5 million tonnes of green steel. In the second phase, the company will ramp up production to about 5 million tonnes. It is expected to start operation 2025.

“The decarbonisation of industrial processes is a fundamental next step towards carbon neutrality. H2 Green Steel is one of the companies paving the way for this green industrial transition in the Nordics. We believe that the complex nature of electrification and hydrogen projects at scale require cross-sectoral partnerships as well as large amounts of clean energy”, says Rikard Dagerbäck, sales manager & strategic customer director, Fortum.

“Fortum takes a frontrunner position among Nordic companies supporting the region’s green industrialization. Despite a historic energy crisis with record-high prices on electricity, Fortum demonstrates true sustainability leadership and takes a long-term view to solve the fundamental issue, namely the climate crisis. We are proud to bring Fortum onboard as a core partner in our energy portfolio and will continue to build our portfolio with long-term renewable electricity at competitive price-levels,” says Luisa Orre, chief procurement officer, H2 Green Steel.

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JERA commences ammonia co-firing tests

JERA and IHI will seek to establish technology for the use of fuel ammonia in thermal power generation with a view toward mainstreaming in society by March 2025.

JERA Co. and IHI Corporation today began a demonstration of large-volume fuel ammonia substitution at a commercial coal-fired thermal power plant.

The testing will be carried out at JERA’s Hekinan Thermal Power Station in Hekinan City through June 2024.

Since October 2022, JERA and IHI have been moving forward in constructing the burners, tank, vaporizer, piping, and other facilities necessary for demonstration testing fuel ammonia substitution at JERA’s Hekinan Thermal Power Station.

IHI has developed a test burner based on the results of small-volume testing of fuel ammonia at the power station’s Unit 5, and JERA has prepared safety measures and an operational framework for the use of fuel ammonia at the power station.

With such preparations in place, the demonstration testing of large-volume fuel ammonia substitution began today at the power station’s Unit 4. The demonstration testing will look at characteristics of the plant overall, investigating nitrogen oxide (NOx) emissions and confirming factors such as operability and the impact on boilers and ancillary equipment.

JERA and IHI, by addressing issues raised through the demonstration testing, will seek to establish technology for the use of fuel ammonia in thermal power generation with a view toward mainstreaming in society by March 2025, according to a news release.

Based on the current demonstration testing, JERA will begin commercial operation of large-volume fuel ammonia substitution (20% of heating value) at Unit 4 of JERA’s Hekinan Thermal Power Station. By establishing the technology for ammonia substitution, JERA will offer a clean energy supply platform that combines renewable energy with low-carbon thermal power, contributing to the healthy growth and development of Asia and the world.

In addition to steadily carrying out the current demonstration testing, IHI will apply the knowledges gained through the Project to establish technology for high-ratio combustion of 50% ammonia or more at thermal power plants and to develop burners for 100% ammonia combustion, deploying the results of the demonstration testing to other thermal power plants in Japan and overseas will contribute to global decarbonization through fuel ammonia.

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PE-backed biomass-to-energy operator on the block

A biomass-to-energy firm with four operational assets in the US and Canada has launched a sale process. The company is also developing 110 MW of co-located BESS projects, with additional revenue streams expected from organic waste diversion, gasification and carbon capture, and heavy-duty vehicle charging stations, according to a sale teaser.

Biomass-to-energy firm Greenleaf Power is for sale.

Denham Capital, the company’s private equity owner, has mandated BNP Paribas to run the process, which launched last week, according to two sources familiar with the process.

California-based Greenleaf is a biomass generation platform with 135.5 MW of fully-contracted renewable generation capacity and remaining weighted-average PPA term length of 9.5 years, according to a sale teaser.

The company’s four operational assets are the 45 MW Desert View Power, in Mecca, California; the 30 MW Honey Lake Power in Wendel, CA; the 23 MW St Felicien Cogeneration facility in Quebec; and the 37.5 MW Plainfield plant in Connecticut.

Greenleaf expects to generate $106m of biomass revenues in 2024, resulting in $24m in expected EBITDA.

According to the teaser, co-located battery energy storage projects amounting to 110 MW are also under development, with CODs expected for 2025 – 2026.

There is potential for additional revenue streams from existing infrastructure and land, including organic waste diversion, gasification and carbon capture, co-location of renewables, and heavy-duty electric vehicle charging stations, the teaser states.

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US fuel cell developer garners tax equity investments

Connecticut-based fuel cell developer FuelCell Energy has closed on tax equity financings supporting at least three fuel cell projects in the US.

Connecticut-based fuel cell developer FuelCell Energy has closed on tax equity financings supporting at least three fuel cell projects in the US.

The company closed on a tax equity financing transaction with East West Bank for the 7.4 MW fuel cell project located on the US Navy Submarine Base in Groton, CT, also known as the Submarine Force. East West Bank’s tax equity commitment, closed in August 2021, totals $15m.

FuelCell Energy installed 7.4 MW of SureSource™ power platforms at the U.S. Navy Submarine Base in Groton, CT to provide a long-term supply of power to an existing electrical substation, according to a news release. The fuel cell plant is part of a multifaceted plan by the Connecticut Municipal Electric Energy Cooperative to provide new power resources and support the desire of the Department of Defense to add resiliency and grid independence to key military installations. The highly efficient fuel cell power generation project minimizes carbon output while providing continuous power to the strategic military base. The U.S. Navy continues to purchase power from CMEEC and Groton Utilities, who in turn purchase the power from FuelCell Energy under a 20-year power purchase agreement.

This pay-as-you-go structure enables CMEEC and the Navy to avoid a direct investment in owning the power plant which will be operated and maintained by the company.

The company also closed on a tax equity sale-leaseback financing transaction for the 1.4 MW SureSource 1500™ biofuels fuel cell project with the City of San Bernardino Municipal Water Department in California with Crestmark Equipment Finance, a division of MetaBank®. Crestmark’s commitment totals $10.2m through a ten-year sale-leaseback structure and further demonstrates the market’s interest in FuelCell Energy’s differentiated ability to use on-site biofuels, to eliminate flaring and deliver carbon neutral decarbonization energy platforms.

A third tax equity investment in 2021 came from Franklin Park for the 7.4  MW fuel cell project located in Yaphank, Long Island, in New York. Franklin Park’s tax equity commitment totals $12.7m following the declaration of mechanical completion of the 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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Exclusive: Inside Strata’s P2X strategy

Strata Clean Energy is seeking to engage with global chemical, energy, and shipping companies as a potential partner for a pipeline of green hydrogen projects that will have FIDs in 2025 and CODs later this decade.

Strata Clean Energy is developing a pipeline of green hydrogen projects that will produce large amounts of green ammonia and other hydrogen derivatives later this decade.

Mike Grunow, executive vice president and general manager of Strata’s Power-to-X platform, said in an interview that the company is investing in the development of proprietary modeling and optimization software that forms part of its strategy to de-risk Power-to-X projects for compliance with strict 45V tax credit standards.

“We’re anticipating having the ability to produce substantial amounts of low-carbon ammonia in the back half of this decade from a maturing pipeline of projects that we’ve been developing, and we’re looking to collaborate with global chemical, energy, and shipping companies on the next steps for these projects,” he said.

Strata’s approach to potential strategic offtakers could also include the partner taking an equity stake in projects, “with the right partner,” Grunow said. The projects are expected to reach FID in 2025.

Grunow declined to comment on the specific size or regional focus of the projects.

“We aspire for the projects to be as large as possible,” he said. “All of the projects are in deep discussions with the regional transmission providers to determine the schedule at which more and more transmission capacity can be made available.”

Strata will apply its expertise in renewable energy to the green hydrogen industry, he said, which involves the deployment of unique combinations of renewable energy, energy storage, and energy trading to deliver structured products to large industrial clients, municipal utilities and regulated utilities.

The company “commits to providing 100% hourly matched renewable energy over a guaranteed set of hours over the course of an entire year for 10 – 20 years,” Grunow said.

“It’s our expectation that the European regulations and more of the global regulations, and the guidance from the US Treasury will require that the clean energy supply projects are additional, deliverable within the same ISO/RTO, and that, eventually, the load of the electrolyzer will need to follow the production of the generation,” he said.

Strata’s strategy for de-risking compliance with the Inflation Reduction Act’s 45V revenue stream for green hydrogen will give asset-level lenders certainty on the delivery of a project’s IRA incentives.

“Right now, if I’m looking at a project with an hourly matched 45V revenue stream, I have substantial doubt about that project’s ability to actually staple the hourly matched RECs to the amount of hydrogen produced in an hour, to the ton of hydrogen derivative,” he said.

During the design phase, developers evaluate multiple electrolyzer technologies, hourly matching of variable generation, price uncertainty and carbon intensity of the grid, plant availability and maintenance costs along with evolving 45V compliance requirements.

Meanwhile, during the operational phase, complex revenue streams need to be optimized. In certain markets with massive electrical loads, an operator has the opportunity to earn demand response and ancillary service revenues, Grunow said.

Optimal operations

“The key to maximizing the value of these assets is optimal operations,” he said, noting project optionality between buying and selling energy, making and storing hydrogen, and using hydrogen to make a derivative such as ammonia or methanol.

Using its software, Strata can make a complete digital twin of a proposed plant in the design phase, which accounts for the specifications of the commercially available electrolyzer families.

Strata analyzes an hourly energy supply schedule for every project it evaluates, across 8,760 hours a year and 20 years of expected operating life. It can then cue up that digital project twin – with everything known about the technology options, their ability to ramp and turn down, and the drivers of degradation – and analyze optimization for different electrolyzer operating formats. 

“It’s fascinating right now because the technology development cycle is happening in less than 12 months, so every year you need to check back in with all the vendors,” he said. “This software tool allows us to do that in a hyper-efficient way.”

A major hurdle the green hydrogen industry still needs to overcome, according to Grunow, is aligning the commercial aspects of electrolysis with its advances in technological innovation.

“The lender at the project level needs the technology vendor to take technology and operational risk for 10 years,” he said. “So you need a long-term service agreement, an availability guarantee, key performance metric guarantees on conversion efficiency,” he said, “and those guarantees must have liquidated damages for underperformance, and those liquidated damages must be backstopped by a limitation of liability and a domestic entity with substantial credit. Otherwise these projects won’t get financed.”

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Exclusive: Coal bed methane producer seeking capital partners

A western US company producing RNG by injecting biomass into coal seams is preparing a Series B and has a line of site to financing and contracting EPC for a series of projects in western coal fields.

Cowboy Clean Fuels, a Wyoming-based RNG producer, is preparing to launch a Series B to reach commercialization, CEO Ryan Waddington told ReSource.

CCF injects biomass feedstock like molasses into the coal seams of spent coal mines about 1,000 ft. below surface, relying on the endogenous microorganisms living in those seams to produce methane, Waddington said. Capex on projects is low, up to $6m each.

The company raised $10m in a Series A and will seek to raise that same amount for a Series B. The company has been assisted by Syren Capital Advisors.

Projects are set up as separate entities under the parent, Waddington said. Six projects, each ranging from 70 to 300 wells, are in the company’s pipeline now in the Powder River Basin of Wyoming and Montana.

“We can replicate this 1,000 times,” Waddington said of the immense number of available wells in the region, which can be acquired cheaply. Additional growth could come in the San Juan region of New Mexico, where coal capacity is being retired quickly.

The fuels could be sold as renewable diesel into markets with incentives, like California’s LCFS, Waddington said. The renewable fuel is significantly (10X) more expensive than natural gas produced as a by-product of oil production. But, CCF is not looking to participate in the LCFS program or the EPA-run RFS program.

“The voluntary market for RNG has really taken off,” he said. A contract for renewable diesel offtake is pending with a Wyoming-based oil and gas company looking to lower its CI score.

CCF’s projects are much larger than a typical RNG project, Waddington said; the first project will produce at some 700 cfpy and include 185 tons of CCS. CCF is looking for EPC providers now.

The executive team of CCF has a minority position of the company, Waddington said. The founders and the management team together have a majority position.

The company’s first 139-well project in Wyoming is awaiting final approval from the federal Bureau of Land Management.

CCF is primarily VC-backed to date. The company received approximately $7.8m through the Energy Matching Funds program of the Wyoming Energy Authority early this year.

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