Resource logo with tagline

VC invests in Big Navajo Energy for H2 production on native land

The Arizona-based renewables developer is expanding its ability to produce hydrogen on native land.

Brown Venture Group has invested in Big Navajo Energy, a Navajo-owned and operated company focused on development and deployment of clean energy solutions for tribal and rural communities, according to a news release.

Big Navajo, founded in 2012 and Navajo-owned, is expanding its ability to produce hydrogen from natural resources on native lands for transport to customers on and off tribal land and rural communities.

Brown is a black-owned venture capital firm formed to fund Indigenous, Black, and Latinx technology entrepreneurs.

Unlock this article

The content you are trying to view is exclusive to our subscribers.
To unlock this article:

You might also like...

BASF electrolyzer project gets 134m from European Commission

The European Commission has approved a EUR 134m German measure to support BASF SE in the production of renewable hydrogen.

The European Commission has approved a EUR 134m German measure to support BASF SE in the production of renewable hydrogen, according to a news release.

The aid will support the construction and installation of a large-scale electrolyser at BASF’s Ludwigshafen site, which will have an annual production capacity of 54 MW and produce approximately 5,000 tonnes of green hydrogen and 40,000 tonnes of oxygen per year. The electrolyser is envisaged to start operating in 2025.

The measure will support BASF’s production of renewable hydrogen mainly to replace fossil-based hydrogen in BASF’s chemical production processes. Additional renewable hydrogen produced will be delivered for emerging hydrogen mobility applications like hydrogen-powered trucks or buses.

 

Read More »

House budget bill would repeal clean energy incentives

The Republican budget bill unveiled Wednesday would repeal recently established tax incentives for clean hydrogen and sustainable aviation fuel, among others.

A Republican-led bill introduced in the US House of Representatives would repeal clean energy incentives passed into law as part of the Inflation Reduction Act, according to the text of the bill.

The legislation, unveiled Wednesday by House Majority Leader Kevin McCarthy, would repeal credits for clean hydrogen, sustainable aviation fuel and clean fuel, advanced manufacturing, and clean electricity investment and production, among others.

“Congress should not waste time or energy on political messaging bills that do not advance the national interest,” said American Clean Power Association CEO Jason Grumet in response to the plan. “The American Clean Power Association is interested in working with Republicans and Democrats on permitting reform, energy security, and the real challenges facing the energy sector and our economy.”

The White House budget office also issued a statement in opposition to the bill, noting that it “would repeal tax credits from the Inflation Reduction Act that are leading to hundreds of billions of dollars in private sector investment in the United States and thousands of jobs.”

Read More »

IEA report outlines case for cost reductions in e-fuels

The International Energy Agency assesses needed cost reductions, resources and infrastructure investments for achieving a 10% share of e-fuels in aviation and shipping by 2030.

The International Energy Agency’s report on the role of e-fuels in decarbonizing transport finds that e-fuels’ cost gap with fossil fuels could substantially reduce by 2030, an important finding for the advancement of a family of emerging e-fuel technologies. 

In the report, which was published last month, the IEA aims to assess the implications of growth in e-fuels in terms of needed cost reductions, resources and infrastructure investments of an assumed goal of achieving a 10% share of e-fuels in aviation and shipping by 2030. 

For instance, the cost of low-emission e-kerosene might drop to $50/GJ ($2,150 per ton), making it competitive with biomass-based sustainable aviation fuels – but still 2 – 3x more expensive than fossil-based fuels. 

The costs for low-emission e-methanol and e-ammonia could also decrease, opening the door for their use as low-emission fuels in shipping. Interestingly, the production of e-fuels for aviation will also result in a significant amount of e-gasoline as a by-product, the report notes.

In terms of impact on transport prices, a 10% share of low-emission e-fuels would only modestly increase the cost of transport, according to the report. For example, e-kerosene would raise the ticket price of a flight using 10% of e-fuels by only 5%. 

However, the adoption of e-methanol and e-ammonia in shipping will necessitate significant investments in infrastructure and ships. The overall cost for a fully e-ammonia or e-methanol-fueled container ship would be 75% higher than a conventional fossil-fuel-powered ship, yet this represents just 1-2% of the typical value of goods transported in these containers.

The production of e-fuels generally suffers from low efficiency due to multiple conversion steps and losses, leading to high resource and infrastructure demand, according to the report. Producing significant amounts of low-emission e-fuels could increase the demand for renewable electricity by about 2,000 TWh/yr by 2030. This represents about one-fifth of the growth of low-emission electricity expected in this decade under certain policy scenarios. 

The production of e-fuels can exploit the potential of remote locations with high-quality renewable resources and vast land available for large-scale projects. However, achieving a 10% share of e-fuels in aviation and shipping would require a significant increase in electrolyser capacity, equivalent to the entire size of the global electrolyser project pipeline to 2030.

The accelerated deployment of low-emission e-fuels for shipping would require substantial investments in refueling infrastructure and vessels, especially for e-ammonia or e-methanol. Achieving a 10% share in shipping would demand approximately 70 Mt/yr of these fuels. The financial investment in shipping capacity and bunkering infrastructure would be substantial, yet represent less than 5% of the cumulative shipbuilding market size over the period 2023-2030.

Producing carbon-containing low-emission e-kerosene and e-methanol would necessitate a massive increase in CO₂ utilization, with significant potential synergy with biofuels production. Around 200 Mt CO₂ would be required for a 10% share of e-kerosene in aviation and 150 Mt CO₂ for the same share in shipping if using e-methanol. 

Access to CO₂ is a major constraint for carbon-containing low-emission e-fuels, and the best wind and solar resources are not always co-located with significant bioenergy resources. Direct air capture (DAC) of CO₂ could provide an unlimited source of CO₂ feedstock without geographic constraints, but it is expected to remain a high-cost option in 2030, the report projects.

Read More »
exclusive

Pennsylvania RNG firm outlines strategic outlook

A growing RNG developer, owner and operator based in Pennsylvania is anticipating a liquidity event on the part of its private equity owner — once it has locked down a “critical mass” of projects.

Vision RNG, a developer of US RNG projects, could see its next project reach commercial operations in Tennessee in a line of projects in southeastern and mid-western states, CEO Bill Johnson said in an interview.

Vision Ridge Partners, a private equity firm, is the majority owner of the company. Management owns the remaining minority stake.

The company is still in early stages and would likely need to get something like six projects to COD before a liquidity event.

“Locking down projects creates a lot of value,” Johnson said, noting that Vision Ridge will likely follow a typical private equity monetization pattern.

The company’s project at Meridian Waste’s Eagle Ridge Landfill in Bowling Green, Missouri is fully operational. It uses 1,500 scfm of landfill gas (LFG) and produces 375,000 MMBtu of RNG annually.

That mid-sized project is similar in scale to what is being developed in Tennessee, which will likely be the next project to reach COD, Johnson said, declining to provide details on exact location.

“We’re working on developing other opportunities with some of the largest publicly owned landfill companies in the country,” Johnson said.

Projects require between $20m and $60m in capex, ranging from small to large, Johnson said. Vision Ridge takes care of the company’s equity requirements.

Debt options are being considered on a project-by-project basis, he said. Debt tends to range from 50% to 70% of total spend.
“We’ll look to put reasonable project debt on these,” he said.

Vision has not to date retained the services of an investment bank, Johnson said.

Vision is pursuing opportunities in Kentucky, Alabama, South Carolina and Oklahoma, and will evaluate suppliers of services and equipment for each. The location-agnostic company is also open to new relationships with potential future financial and strategic acquirers.

“If you are a private equity group, you’re a potential buyer of the company at some point, so we would be happy to know them and keep their interest in us up,” Johnson said. An acquirer would not necessarily need to have expertise in RNG.

M&A potential

M&A of projects is an option on the table, Johnson said. But returns are better if Vision develops its own projects; and a more challenging macroeconomic environment makes acquisitions somewhat unlikely.

“With the market premiums being paid, I see us continuing to keep our head down and focusing on organic growth,” Johnson said.

Johnson said he expects to see continued consolidation in the greater market. Many large strategic and midstream companies have yet to make significant buys in RNG.

He pointed to bp’s acquisition of Archaea Energy as a significant milestone in the RNG market.

“There’s quite a number of potential acquirers,” Johnson said. “The market is kind of fundamentally and always will be under-supplied and over-demanded.”

Vision would potentially be open to a merger with a portfolio company of a strategic or PE investor, Johnson said.

Read More »

Exclusive: Waste-to-fuels developer preparing capital raise

A waste-to-fuels developer has lined up an advisor and is planning a capital raise for a project in West Texas, in what is expected to be the first of up to 20 similar fundraising efforts totaling $500m in external capital needs.

Recover, Inc., a Calgary-based waste-to-fuels project developer, is preparing to launch a capital raise for its first US-based projects in West Texas.

The company has lined up CIBC to assist with the capital raise while a large Canadian Crown Corporation is expected to sign on as a lending partner for the debt portion of the cap stack, CFO Shane Kozak said in an interview.

Kozak said he will need to raise $70m – $75m for the West Texas project, which will process waste from oil and gas drilling fluids and recover 800 barrels per day of low carbon intensity diesel fuel from 800 tons of waste.

Existing equity backers Azimuth Capital and BDC will participate in the capital raise, but the company is seeking additional project equity investors to take part in a 60% debt to 40% equity capital structure, Kozak said.

While the cost of the West Texas project is estimated at $55m, the company needs to raise approximately $70m to account for debt servicing and underwriting fees, he added.

Recover has mapped out a strategy to build 20 projects in oil and gas basins across the US, and estimates it will need to raise $500m in external capital over 10 years to fully develop those projects.

Project model

The company already operates a similar facility in Alberta that became operational in 2018, at a cost of CAD 20m and producing about half of what the West Texas project will produce.

“This has been commercially proven in Canada, and we’re going to a better market with a lot more drilling waste production” in the US, Kozak said.

The waste stream from oil and gas drilling contains large amounts of diesel fuel: a typical well will create 400 – 500 tons of waste, 30%-40% of which is recoverable low carbon intensity diesel, Kozak said.

In Texas, the drilling fluid waste often ends up in pits near drilling rigs or in industrial landfills, where it biodegrades over time and emits CO2 and methane into the atmosphere.

“We significantly reduce GHG emissions and create a fuel source that can be reused, and every barrel that we recover is a barrel of fuel that would otherwise have to come from a fossil fuel source,” he said.

Recent changes to Texas policy regarding oil and gas drilling waste could increase the availability of feedstock for the company. The Texas RailRoad Commission, which oversees the state’s oil and gas industry, is seeking to modernize disposal practices that would redirect waste from drilling pits to more centralized industrial landfills.

“The good thing for us is that, in the Permian Basin, about 70% – 80% of the wells use these pits, and our strategy is to build our facility directly on industrial landfills,” Kozak said.

Recover is working with a large landfill management company with operations across the US to develop its facilities, he added. The company does not pay for feedstock, given the synergistic relationship between Recover and the landfill management company.

Read More »

Exclusive: American Clean Power to advocate for ‘grandfathering’ in 45V rules

The clean energy trade group plans to continue promoting the concept of “grandfathering” for early-mover green hydrogen projects in response to IRS guidance for 45V rules, according to industry sources familiar with the plans.

Clean energy industry trade group American Clean Power (ACP) plans to continue championing the concept of “grandfathering” in the green hydrogen sector, arguing that it is critical for the economic viability of early green hydrogen projects under the Inflation Reduction Act’s clean hydrogen tax credits, according to sources familiar with the group’s plans.

Grandfathering would allow these projects to adhere to less stringent annual time-matching requirements before transitioning to an hourly regime.

ACP, through its previously released Green Hydrogen Framework, has proposed to grandfather in the early-mover projects under annual time-matching as long as they start construction before January 1, 2029. That’s in contrast to guidance for the 45V clean hydrogen tax credit that would require renewable energy generation associated with green hydrogen projects to be matched hourly beginning in 2028.

The trade group, which consists of 800 clean energy companies, previously argued against too-soon hourly matching in a November white paper. Representatives of ACP did not immediately respond to requests for comment.

In response to the IRS guidance, ACP is seeking to underscore that, without grandfathering, early projects will have to be designed from the start to meet hourly matching requirements, significantly increasing costs and negating the benefits of annual time matching, sources said.

The notice of public rulemaking on 45V was issued on December 26, and is open for public comment for 60 days. The tax credit rules, which would require strict adherence to the so-called three pillars approach for incrementality, temporal matching, and deliverability, are viewed by some in the industry as overly burdensome.

ACP’s position is that the project finance market can handle some changes midstream in long-term agreements, but not fundamental shifts like transitioning from annual to hourly time matching. 

This switch could lead to a dramatic decrease in green hydrogen production and a concurrent exponential increase in production costs. Investors, anticipating these risks, might finance green hydrogen production agreements as if they were under an hourly regime from the beginning, thereby eliminating the initial benefits of annual time matching, according to the sources familiar.

A Wood Mackenzie study estimates that hourly time matching requirements could result in a price increase of 68% in Texas and 175% in Arizona, for example.

ACP, according to sources, stresses that the absence of grandfathering would create an economic cliff for agreements straddling both accounting systems. This would add to project costs, potentially discourage customer interest in green hydrogen, and hinder the industry’s maturation, the sources explained. In contrast, grandfathering first-mover projects under an annual time matching regime would ensure competitive production costs, driving demand for green hydrogen, the trade group believes.

Moreover, sources explained that ACP’s position is that the transition from annual to hourly matching without grandfathering would likely necessitate assuming hourly matching from the onset in power purchase agreements, leading to higher hydrogen costs from the start. This could delay green hydrogen industry development and give an advantage to blue hydrogen with early adopters, potentially excluding green hydrogen from the market.

Read More »

Welcome Back

Get Started

Sign up for a free 15-day trial and get the latest clean fuels news in your inbox.