India lifts duty on U.S. peas and lentils

By 

Sean Pratt 
  

The 10 percent additional duty on U.S. chickpeas and 20 percent on U.S. lentils were part of a retaliatory package of tariffs in response to the U.S. increasing duties on certain steel and aluminum products from India.| Reuters photo

India is removing the additional duties it has been charging on U.S. peas and lentils since 2018.

The 10 percent additional duty on U.S. chickpeas and 20 percent on U.S. lentils were part of a retaliatory package of tariffs in response to the U.S. increasing duties on certain steel and aluminum products from India.

“After nearly six challenging years of trade disruption, we welcome the opportunity to compete fairly in the Indian market,” Aaron Flansburg, chair of the USA Dry Pea & Lentil Council, said in a news release.

“This move will certainly help our farmers grow more pulses, one of the most sustainable crops worldwide.”

The U.S. was shipping 300,000 to 350,000 tonnes of pulses to India annually prior to the tariffs. That trade has completely evaporated.

Half of the volume was lentils and chickpeas, while the other half was peas, which India stopped importing around the same time as the lentil and chickpea tariffs were imposed.

The council said the United States now has the potential to reclaim its position as a significant exporter to the Indian market in 2023-24.

However, Jeff Van Peerage, president of Columbia Grain International, doesn’t think the U.S. will do much lentil business with India this year.

“The U.S. is virtually sold out of (old crop) lentils,” he said.

As well, the new crop will be smaller than usual. Growers planted 533,000 acres, down 19 percent from the previous year.

Those new crop lentils will likely go to markets like USAID, Europe, South America, Central America and North Africa.

“We’re not going to have a lot of lentils to go to India this year,” said Van Pevenage.

However, there should be opportunities for Canadian green lentils in that market because of two consecutive years of short pigeon pea crops.

“The expectations are that India could import 60,000 to 70,000 tonnes of Laird lentils here in the next four months,” he said.

“Most of that would come from Canada. That’s definitely beneficial to Canadian producers of green lentils.”

Van Pevenage said Canada’s small pulse processing plants have been suffering the past four or five years as much of the yellow pea and red lentil business switched to bulk movement to markets such as Turkey, Egypt, India and Sri Lanka.

“There’s not much room for these small guys in the container business anymore,” he said.

“That’s why you get a lot of these bankruptcies.”

Green lentils tend to move in containers, so that anticipated business to India should help.

Van Pevenage alleges that a lot of U.S. green lentils had been moving to India via Canada and sold as Canadian product to avoid the duties. That practice will come to a halt now that the additional duties have been removed.

Meanwhile, the Canadian pulse industry continues to evolve. Archer Daniels Midland just acquired Prairie Pulse Inc., a cleaning, milling and packaging facility in Vanscoy, Sask.

“We’re excited to strengthen our relationships with Canadian pulse growers through the acquisition of Prairie Pulse,” ADM commercial manager Aaron Brown said in a news release.

He said the addition expands ADM’s capabilities to meet the growing demand for pulse proteins.

“The enduring global trends of sustainability and food security are powering growth in alternative proteins, and ADM is continuing to invest to ensure we’re at the forefront of meeting those needs,” said Brown.

The acquisition doubles ADM’s pulse footprint in Saskatchewan. The company also owns an origination and cleaning plant in North Battleford.

The Vanscoy plant includes 12,000 tonnes of bulk storage, as well as cleaning, milling, sorting, sizing and bagging capabilities. There is also a pulse dehulling and splitting facility that transforms lentils, chickpeas and peas into shelf-ready products

The Western Producer

YOU SOLD OUT THE WHEAT BOARD

Contract issue ‘settled’ for grain handlers

By Sean Pratt
JULY 6,2023

"It seems that grain contracts are very one-sided and actually represent a fairly significant financial risk to producers," said APAS president Ian Boxall. | File photo

A prairie farm organization says it is time for the federal agriculture minister to “weigh in” on grain contract protections for farmers.

The Agricultural Producers Association of Saskatchewan wants Marie-Claude Bibeau to instruct the Canadian Grain Commission to facilitate a meeting between farmers and grain companies with a goal of producing a fairer contract.

“It seems that grain contracts are very one-sided and actually represent a fairly significant financial risk to producers,” said APAS president Ian Boxall.

But grain companies don’t appear willing to chat.

“It’s an issue that is settled in our minds,” said Wade Sobkowich, executive director of the Western Grain Elevator Association.

His member companies are happy with the current commercial system where contracts are tailored to meet the needs and marketing strategies of each individual business.

Agriculture Canada shed little light on where it stands. It said it is modernizing the Canada Grain Act (CGA) to ensure the legislation is fair and responsive to the grain sector.

“The CGA already provides scope for contract arbitration and we are committed to ensuring a level playing field for farmers through the CGA review process,” it said in an email.

But APAS insisted that the playing field is lopsided.

It estimated Saskatchewan growers lost about $60 million when Purely Canada Foods informed 26 farmers in March that it was voiding their gluten-free oat contracts because a processor could not take them.

That incident follows “hundreds of millions” of dollars lost on buyouts, administration fees and legal costs when farmers experienced drought in 2021 and were unable to deliver their contracted production.

Boxall doesn’t want contracts to be so restrictive that buyers and sellers cannot negotiate terms, but he would like to see some standardization in terms of penalties, administration fees and the general layout of contracts.

He wants a contract from Viterra to look the same as one offered by Parrish and Heimbecker, so farmers know what they are signing and do not have to consult a lawyer.

Australia and other countries have adopted standardized grain contracts.

Boxall said producers will always take on some risks when signing contracts, but it has become far too unbalanced.

“Right now, it’s probably 99 percent of the risk to the farmer and one percent risk to the buyer,” he said.

“It seems to be a little bit offside.”

He hopes producers and grain companies can come to terms on a contract where the risk split is more like 80-20 or 70-30, or something similar.

Sobkowich said the APAS suggestion sounds like an attempt to transfer crop production risks to grain companies.

“It (is) a risk that farmers assume, and we think that’s where it rightly stays,” he said.

He rejected notions that farmers take all the risk in grain transactions.

“The producer that made that comment doesn’t understand the risk associated with moving grain through the rest of the system,” said Sobkowich.

He encouraged growers to think about what happens when China bans Canadian canola when ships are en route to that destination, or when there is a washout or blockade of a rail line, or a strike at the port.

“There’s a ton of risk in the supply chain,” he said.

“When there’s a hit down the road with that cargo, you don’t see the grain companies coming back to the farmer.”

Sobkowich said if grain companies are forced to take on some of the production risks of growing a crop, it will result in discounted prices.

Boxall said he is simply asking for a dialogue. He does not want to “ramrod” anything down anybody’s throats.

He believes grain companies will benefit from increased contract transparency because farmers are shying away from forward contracting after the 2021 problems.

“It’s time to find a solution to this longstanding problem,” he said.

Sobkowich said the grain industry is one of the most heavily regulated sectors in the Canadian economy and it doesn’t need further constraints.

He said the existing commercial system for contracting allows companies to be more flexible and responsive to the needs of their customers.

He said the contracting issue has not been the subject of much debate around the WGEA board table despite a series of resolutions passed by Saskatchewan crop organizations calling for fairer contracts.

“Grain companies can’t get together and talk about their contracts with each other,” said Sobkowich.

“That would be collusion.”

Life after the wheat board | The Western Producer

It’s a disaster’

By 

Alex McCuaig

JULY 6, 2023

Saskatchewan Cattlemen's Association chair Keith Day said producers in many areas of the province will struggle to grow enough of their own feed and will be unable to bring feed in because the dry conditions have pushed feed prices up. | File photo

The Saskatchewan Cattlemen’s Association says this year’s dry conditions will likely force more producers to sell animals and reduce their herds, further shrinking the national cattle inventory that has seen a decade-long decline.

The organization is looking for assistance to help stem the trend.

SCA chair Keith Day said producers in many areas of the province will struggle to grow enough of their own feed and will be unable to bring feed in because the dry conditions have pushed feed prices up.

That could cause some ranchers to get out of the business rather than struggling to get through another dry year.

“The further north you go from the Number 1 highway — especially on the west-central part of Saskatchewan — it’s just looking terrible and it’s getting worse every day,” said Day.

Hay crops might be better this year than last, but they will still be below average, he added.

“The green feed crops — anything that isn’t under irrigation in this (south-central) area here — are really not going to amount to anything. They’re a disaster already,” said Day.

“The crops are horrible. There is going to be a shortage of water in places. And even though those spots are smaller than they were, it’s still a disaster,” said Day

Some areas have seen good conditions develop but it’s spotty, with some crops doing all right, but fields nearby parched.

Meanwhile, the market fundamentals of North America’s cattle industry are improving as supply dwindles while demand remains consistent.

“For younger producers, it looks hopeful with the price of cattle. The demand for beef is strong and, going forward, the industry looks like it is worth staying in,” said Day. “But for older producers, and some of these guys are looking at their fourth or fifth year of drought with their grass and feed in short supply, they’ve run out of options.”

Day said he hopes farmers with drought-diminished crops consider turning their fields over for feed.

“Just keep livestock producers in mind when you are wondering what to do with your crops,” said Day. “Another week of plus-30 temperatures and no moisture is going to change a lot of things.”

In 2021, the Saskatchewan government changed its provincial agricultural insurance to make it easier to for low-yield crops to be used as livestock feed.

Day said producers interested in using their crops for feed should reach out to the Saskatchewan Cattlemen’s Association for more information.

Saskatchewan has seen its cattle numbers drop by nearly 20 percent in the past two years with the province hosting the second-largest beef herd in Canada behind Alberta.

The Western Producer

BC

More pay, more benefits, more 'contracting in': The new agreement for SkyTrain workers

Union members that work on the Expo and Millennium lines are expected to vote on the deal later this month

By Bob Mackin | July 7, 2023


The SkyTrain Expo line travelling between New Westminster and Surrey | Chung Chow

The tentative new contract between B.C. Rapid Transit Co. (BCRTC) and SkyTrain workers calls for a 6.75-per-cent pay raise effective Sept. 1.

On June 29, CUPE 7000, which represents workers on the Expo and Millennium lines, reached the agreement with the division of TransLink after 10 days of talks. Details were not announced.

According to a leaked copy of the memorandum of agreement, pay will increase by at least 16.25 per cent over the life of the five-year deal. The union recommends members accept the contract and is holding information meetings via Zoom on July 17, before a vote later in the month.

This follows the April-negotiated contract between Unifor locals 111 and 2200 and Coast Mountain Bus Co. (CMBC) that would see pay increase by between 11.25 per cent and 12.5 per cent through March 31, 2026 at TransLink’s bus division.

The CUPE 7000 deal contains a no-contracting-out clause to protect the jobs of existing SkyTrain workers and the formation of a joint committee of three company representatives and three union representatives to discuss “contracting in” work that is currently contracted out.

Pay will also increase on Sept. 1, 2024 by two or three per cent, based on the 12-month rate of inflation beginning Sept. 21, 2023. Further increases are scheduled at 2.5 per cent annually in 2025 through 2027. The final two years could be higher in order to match whatever general wage increase Unifor members achieve in their next contract from CMBC.

Non-skilled trades workers get a 0.24-per-cent adjustment plus 25 cents more per hour in 2025.

According to an appendix in the contract, which expires Aug. 31, SkyTrain pay ranges from $29 an hour for a parts driver to $58.41 an hour for an elevator/escalator technician. For administrative workers, $28.08 is the hourly rate for receptionists and administrative support clerks and, on the other end of the scale, $57.18 per hour for a control centre instructor.

Workers on duty Sundays will be paid time-and-a-quarter for all work hours beginning Sept. 1. That increases to time-and-a-half in 2026. Workers on afternoon shifts will see their $1.80-an-hour shift differential bumped to $2 an hour on Sept. 1. The nighttime differential increases by $1 to $4 an hour on Sept. 1. By 2027, it will reach $6 an hour.

The company will pay union president Tony Rebelo’s wages for one day a month to a maximum of 120 hours per year and also pay $20,000 to the union for the purposes of bargaining.

The new deal also gives workers eight fully-paid individual sick days beginning Jan. 1, 2024. A maximum of five sick days may be used consecutively. There are various increases to benefits and allowances, such as $2,500 more to see a psychologist or registered clinical counsellor, to a maximum $4,000 a year, and a $500 increase to annual physiotherapy payments, now capped at $1,500.

The maximum $5,000, interest-free loan for entering a residential substance abuse treatment program is tripled to $15,000. Upon successful completion of a monitoring agreement, the company will forgive the loan. The company can recover the debt in the event of failure or forgive 100 per cent of the loan one time during the worker’s employment with the company.

Maternity leave is increased by six weeks to 18 weeks and the contract language is amended to replace references to mother with “birthing parent.”

Similarly, male and female pronouns are out and “they,” “them” and “their” are in. The wording of the fair practice anti-discrimination clause changes sexual “preference” to sexual “orientation” and adds protection for gender expression.

A letter of understanding upholds the provincially adopted United Nations Declaration on the Rights of Indigenous Peoples and contains measures aimed at increasing recruitment, retention and advancement of Indigenous employees. It contemplates an employment equity committee and training for anti-racism and cultural competency.

The Sept. 30 National Truth and Reconciliation Day is added to the list of statutory, paid holidays. Indigenous workers will receive an unpaid day off to observe National Indigenous Peoples Day every June 21. By request, an employee may have an elder or support person of their choice present when dealing with issues affecting Indigenous employees.

A side letter from BCRTC labour relations director Kevin Payne to Rebelo on June 29 says that the union will be given an opportunity to discuss its concerns should the company rescind its work-from-home policy, which was implemented in November 2021.

Another June 29 letter clarifies how the company deals with special leave requests for employees who attend incidents after a person is struck or run over by a SkyTrain.

Affected employees may request time off for special leave through their manager or supervisor to the labour relations department.

“Special leave will only be approved for the remainder of the shift; and if necessary, the shift immediately following the date of incident. Should an employee require additional time off as a result of their attendance at the incident site, they will be required to file a claim with WorkSafeBC,” the letter said.

So-called “dirty work employees” called to don personal protective equipment and clean up after a track level incident involving human contact shall receive a premium of two hours equal to 200 per cent of their normal straight time pay rate.

A new clause about accident/incident investigations says supervisors involved in a safety investigation will only participate as a witness and any statements by an employee will not be used beyond the investigation.

TransLink is studying the feasibility of erecting platform barriers to prevent people from jumping or falling into the track area as it approaches the 40th anniversary of service in two years. A 2001 B.C. Coroners Service (BCCS) report cited a 1994 SkyTrain safety review that estimated it could cost as much as $2.2 million to retrofit each station with platform screen doors.

BCCS statistics show that, between 2008 and 2018, 32 people died of suicide on the SkyTrain system. 

twitter.com/bobmackin

Decarbonizing Hydrogen Will Inflate Alberta Crude’s Quality Discount & Drive It Off The Market

Peak oil demand means lowering oil prices per barrel. In a world that needs to decarbonize hydrogen, Alberta’s product will be too expensive to refine.

DALL·E generated image of a barrel of oil inflating like a ballon, digital art

By Michael Barnard
CLEAN TECHNICA
Published 3 days ago

The fate of the Alberta oil sands is on a lot of people’s minds. As I noted recently, the International Institute for Sustainable Development (IISD) dropped a report making it clear that as peak oil demand arrived, Alberta’s product would be first off the market. I first made that obvious point over three years ago. I’ve made that point in regard to the completely unnecessary Trans Mountain Pipeline (TMX) too.

The quality discount against Brent Crude was already US$14 per barrel in 2021. And it’s only going to get higher, much higher. Why is the subject of this article

Let’s start with the basics. Quite a remarkable number of major organizations, including the International Energy Association, McKinsey, and Equinor have high likelihood scenarios that oil demand will stop growing this decade. Most, with a few oddball exceptions like the US Energy Information Administration, project flat demand through 2050, which makes sense only if you assume that turning the planet into a baked potato is a great idea and haven’t paid any attention to rapid global decarbonization of ground transportation. Others think it peaked in 2019 prior to COVID.

I’m with the projections of last half of this decade, personally, based on what I track globally. Among other things, there’s only one very large crude carrier (VLCC) under construction in the world, against a fleet of over 900 of them. The bulk shipping industry clearly thinks that oil has had its day. I’ve spent time with two global shipping clients discussing the end of bulk oil (and coal and natural gas) shipping, and they are very aware that their business model is coming to an end.

So why will Alberta’s product, and similarly Venezuela’s product, be first off the market? Well, Alberta has a compounded set of problems including a market that’s 94% in the US, the US becoming a net oil exporter today, and the US seeing declining global and domestic markets as electrification sweeps the planet. It’s going to be increasingly focused on locking up domestic demand with its own oil, of course, and only buying the cheapest oil from foreign sellers. That’s not Alberta’s product, so the lack of diversification of demand is going to hit it hard and fast.

The bad strategy behind the tripling of the TMX was that it would unlock the Asian market for Alberta’s product, despite a significant decline in any interest from China from 2010 onward in imports from Canada. I pointed recently out that the Aframax limit on the TMX termination port in Vancouver meant that it was going to be expensive to ship across the Pacific compared to regions that could use VLCC carriers hauling up to double the barrels of oil per trip.

Major energy analysis firm Wood Mackenzie has extended this point, noting recently that the illegal invasion of Ukraine has meant that a lot more of Russia’s oil is flowing to China now, dampening even further any prospects that Alberta’s crude would flow to China. Wood Mackenzie’s analysis is that instead, more of it will flow to California’s southern refineries that can process heavy, sour crude, but I think that’s a very short term market.

Some of the why I’ve explained above, but let’s look at the kicker: hydrogen costs.

What does hydrogen have to do with the price of oil? Well, it gets back to that quality discount point. Crude oil comes in a range of how liquid it is, from stuff that flows like slightly thick water to stuff like tar. That’s light to heavy. Crude oil comes with varying percentages of sulfur which must be removed, from the <1%, referred to as sweet, to Alberta’s 5-6%, referred to as sour. And it comes with a lot of variance in water content and other impurities. Alberta’s product is at the bad end of every scale.

Hydrogen is used to remove sulfur (desulfurization), remove water and other impurities (hydrotreating), and to separate the heaviest crude from lighter components (hydrocracking). Because Alberta’s product is at the bad end of every scale, it requires a lot more hydrogen than other crude oil products.

The vast majority of the hydrogen used in oil refineries today is manufactured from natural gas, with combined upstream fugitive methane emissions and carbon dioxide emissions from the steam reformation process of 8-10 tons of CO2e per ton of hydrogen. That’s why Canada and Alberta are giving Alberta’s oil industry a C$1.6 billion (US$1.2 billion) present in the form of a blue hydrogen facility a few kilometers from Edmonton’s biggest refinery.

Blue hydrogen, as a quick reminder, captures perhaps 85% of the carbon dioxide from the steam reformation process and sequesters it. Almost uniquely for this kind of scheme, the Alberta facility isn’t being used for enhanced oil recovery. Why are the country and province buying an oil refinery a nice shiny new blue hydrogen facility? To hopefully turn that 8-10 tons of CO2e into 1-3 tons of CO2e.

Of course, that doesn’t do a thing for emissions when the oil is used as intended and burnt, as the lion’s share of emissions are from that process, but it certainly reduces Canada’s emissions within its borders, as 80% of Canada’s oil leaves the country. I recently worked out that Canada’s fossil fuel industry is responsible by itself for roughly 2% of annual global greenhouse gas emissions, but Canada doesn’t count 80% of that as its problem.

Is that hydrogen going to be as cheap as gray hydrogen? Not a chance. Will actually low carbon hydrogen manufactured from green energy and water be as cheap as gray hydrogen? Even less of a chance.

What does this mean for the quality discount on Alberta’s product? It’s going up. How much is an interesting question, and there’s sufficient information available to at least make a guess.

Remember that the US$14 quality discount it’s already seeing is without any price on carbon and with unabated gray hydrogen. The gray hydrogen likely costs in the range of US$1-$2 per kilogram. S&P Global’s price map of hydrogen shows US$1 exists in the US for unabated hydrogen, as an obvious example. We’ll go with US$1.50 as a median for unabated hydrogen.

How much hydrogen is required per barrel for desulfurization, hydrotreating, and hydrocracking? The numbers vary, but the range is 1,000 to 2,500 standard cubic feet (scf) for hydrocracking and 500 scf as the median for desulfurization, per a seemingly solid peer reviewed source.

Given that Alberta’s product is at the wrong end of every quality scale, using 2,500 scf for hydrocracking and 750 scf for desulfurization or hydrotreating seems like a reasonable guess. A kilogram of gaseous hydrogen is 423 scf. A little math suggests 7.7 kg of hydrogen per barrel of Alberta’s crude.

The US$14 quality discount starts to make a lot of sense, doesn’t it? 7.7 kg at US$1.50 per kg is US$11.55, within spitting distance of that quality discount.

But once again, hydrogen is getting more expensive. The fossil fuel industry is by itself one of the biggest global emitters of CO2, and its requirement for hydrogen is a big reason why. As a reminder, about a third of all hydrogen used globally is used by oil refineries for these processes, so a lot of pressure is being put on them to decarbonize their own operations. That means, just as it does for ammonia fertilizer, decarbonizing hydrogen.

So how much does blue hydrogen cost? Well, EEX recently launched a hydrogen index, used to get actual data on actual hydrogen deals globally, including blue and green hydrogen deals. It’s good that they are doing the work, but due to the hydrogen-for-energy fallacy there are two problems with the index.

The first is that it represents hydrogen in units of MWh not tons. This is similar to the DNV study for offshore hydrogen manufacturing at wind farms I assessed recently. It’s a problem because MWh and GWh are units of energy, and hydrogen is actually an industrial feedstock that we don’t use as a store of energy due to its great expense. As I noted in the piece on the DNV study, even the best price of US$0.78 per kg of just manufacturing hydrogen found by S&P Global and in Lazard’s levelized cost of hydrogen workups is 1.9 times the cost of imported liquid natural gas (LNG), which is already the most expensive form of imported energy. At minimum energy costs using existing unabated gray and black hydrogen is a part of the reason why we don’t use hydrogen as a fuel today.

The second is that the EU has shifted away from its empirically oriented choice to use the higher heat value (HHV) for manufacturing hydrogen, the energy required to remove water vapor from the hydrogen, to the lower heating value (LHV) which leaves the water vapor in the hydrogen. The HHV for hydrogen is almost 20% more than the LHV.

There are a lot of off-takers for hydrogen. For ammonia, they like very pure hydrogen with very little water to maximize quality of the ammonia, and to avoid the problems of ammonia becoming a caustic gas and killing people. Fuel cells like very pure hydrogen. Unsurprisingly, burning hydrogen with high water vapor levels reduces the efficiencies of combustion a lot, so you pay the price of water vapor coming or going. Hydrogen for use in oil refineries must be very pure, which is unsurprising because one of its roles is removing water in the oil. Even hydrogen for heating types want very high purity hydrogen, with allowable impurities more related to odorants than water vapor. Everybody wants hydrogen at the HHV end of the scale, not the LHV end of the scale as far as I can tell, including China.

As a result, the LHV numbers significantly understate the actual costs of hydrogen required for industrial processes, something which is undoubtedly contributing somewhat to the economic insanity of considering it as a fuel.

But we have costs from the EEX Hydrix index. Blue hydrogen come in at around US$2.70 per kg. Green hydrogen is coming in at around US$8.30. The EEX makes it clear that these are LHV numbers, so getting them to the right numbers requires uplifting them to the the HHV numbers. That makes the prices US$3.20 per kg for blue hydrogen and US$9.80 per kg for green hydrogen. They assert that those costs do include delivery to the end customer, but that’s clearly for very large amounts of hydrogen.

Some other material I saw recently suggested that by 2030, the cost per kilogram of green hydrogen would come down into the US$4.50 to US$7.50 range, but clearly that’s also an LHV number, so those are actually US$5.30 to US$8.90 per kg for actually usable hydrogen. The bottom end of that range is roughly equal to be best case scenario for 2050 out of the unrealistic DNV scenarios by the way.

Okay, now we have both halves of the cost equation for hydrogen for Alberta’s high-sulfur, tar-like, impurity-laden crude oil.

For blue hydrogen, 7.7 kilograms per barrel works out to roughly US$25 per barrel, well over the combined quality plus transportation discount from 2021 of US$21 per barrel. Transportation costs aren’t going to go down much, even if TMX oil ends up in California instead of Houston where most Alberta product goes today. Call it US$6 per barrel transportation discount for a total US$31 per barrel discount.

For green hydrogen, the numbers are much, much worse. At today’s average from the EEX, 7.7 kilograms would cost US$75.50. For comparison, the Brent crude index price is US$76.81 right now.

Assuming the best case scenario for green hydrogen of US$5.30, that’s still US$41 just for hydrogen per barrel of Alberta’s product. That’s US$47 with the lower transportation discount.

In a world awash in cheap to refine and transport sweet, light oil, there is no economic market for Alberta to sell crude at a discount of US$47 per barrel. Even the US$31 discount is deeply economically unlikely.

Suncor’s cost per barrel to manufacture its product is US$23 to US$25. The best case quality discount using blue hydrogen that they pay for without any profit makes that US$54 to US$56.

Peak oil demand means lowering oil prices per barrel. In a world that needs to decarbonize hydrogen, Alberta’s product will be too expensive to refine. The curves mean that Suncor’s product will be first off the market.

SCI-FI-TEK

Scientists find a better way to capture carbon from industrial emissions

by Steve Lundeberg, Oregon State University

Researchers in the Oregon State University College of Science have demonstrated the 

potential of an inexpensive nanomaterial to scrub carbon dioxide from industrial emissions.

 Image provided by Kyriakos Stylianou, OSU College of Science.

 Credit: Researchers in the Oregon State University College of Science have 

demonstrated the potential of an inexpensive nanomaterial to scrub carbon dioxide from

 industrial emissions. Image provided by Kyriakos Stylianou, OSU College of Science.

Researchers in the Oregon State University College of Science have demonstrated the potential of an inexpensive nanomaterial to scrub carbon dioxide from industrial emissions.

The findings, published in Cell Reports Physical Science, are important because improved carbon capture methods are a key to addressing climate change, said OSU's Kyriakos Stylianou, who led the study.

Carbon dioxide, a greenhouse gas, results from burning fossil fuels and is one of the primary causes of a warming climate.

Facilities that filter carbon from the air are beginning to spring up around the globe—the world's largest opened in 2021 in Iceland—but they're not ready to make a large dent in the worldwide emissions problem, Stylianou notes. In a year, the Iceland plant can draw out a carbon dioxide amount equivalent to the annual emissions of about 800 cars.

However, technologies for mitigating carbon dioxide at the point of entry into the atmosphere, such as a factory, are comparatively well developed. One of those technologies involves nanomaterials known as metal organic frameworks, or MOFs, that can intercept carbon dioxide molecules through adsorption as flue gases make their way through smokestacks.

"The capture of carbon dioxide is critical for meeting net-zero emission targets," said Stylianou, an assistant professor of chemistry. "MOFs have shown a lot of promise for carbon capture because of their porosity and their structural versatility, but synthesizing them often means using reagents that are costly both economically and environmentally, such as heavy metal salts and toxic solvents."

In addition, dealing with the water portion of smokestack gases greatly complicates removing the carbon dioxide, he said. Many MOFs that have shown carbon capture potential lost their effectiveness in humid conditions. Flue gases can be dried, Stylianou said, but that adds significant expense to thecarbon dioxide removal process, enough to make it nonviable for industrial applications.

"So we sought to come up with a MOF to address the various limitations of the materials currently used in carbon capture: high cost, poor selectivity for carbon dioxide, low stability in humid conditions, and low CO2 uptake capacities," he said.

MOFs are crystalline, porous materials made up of positively charged metal ions surrounded by organic "linker" molecules known as ligands. The metal ions make nodes that bind the linkers' arms to form a repeating structure that looks something like a cage; the structure has nanosized pores that adsorb gases, similar to a sponge.

MOFs can be designed with a variety of components, which determine the MOF's properties, and there are millions of possible MOFs, Stylianou said. Almost 100,000 of them have been synthesized by chemistry researchers, and the properties of another half-million have been predicted.

"In this study we introduce a MOF composed of aluminum and a readily available ligand, benzene-1,2,4,5-tetracarboxylic acid," Stylianou said. "The synthesis of the MOF happens in water and only takes a couple of hours. And the MOF has pores with a size comparable to that of CO2 molecules, meaning there's a confined space for incarcerating the carbon dioxide."

The MOF works well in damp conditions and also prefers carbon dioxide to nitrogen, which is important because nitrogen oxides are an ingredient in flue gasses. Without that selectivity, the MOF would potentially be binding to the wrong molecules.

"This MOF is an outstanding candidate for wet post-combustion carbon capture applications," Stylianou said. "It's cost effective with exceptional separation performance and can be regenerated and reused at least three times with comparable uptake capacities."

Scientists from Columbia University, the Pacific Northwest National Laboratory and Chemspeed Technologies AG of Switzerland also took part in this research, as did Oregon State chemists Ryan Loughran, Tara Hurley and Andrzej Gładysiak.

More information: Ryan P. Loughran et al, CO2 capture from wet flue gas using a water-stable and cost-effective metal-organic framework, Cell Reports Physical Science (2023). DOI: 10.1016/j.xcrp.2023.101470

Journal information: Cell Reports Physical Science

Provided by Oregon State University New research finds way to scrub carbon dioxide from factory emissions, make useful products