Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Production from first drilled well is coming. The Eoff PPC #3 well in the Breedlove Field was completed in October and is going through a Flowback Recovery Period (removal of liquids). It was shut down due to freezing temperatures. Management expects full production by the end of February and will disclose flow rates then. The company hinted that it will probably go forward with converting the well to a horizontal well at an additional $1.1 million cost.
Cash is tight. Permex’s cash position is down to $2.5 million, not enough to drill another well. The company is opposed to taking on debt (which we agree with) because debt is the Achilles heel of start-up energy companies should energy prices decline. The company discussed selling acreage but indicated that it neither has a large contiguous field to sell (outside of its Breedlove Field position) nor does it have small, producing property that might be of interest to energy companies. Management would like to issue stock but not at the current stock price of 4% of net asset value.
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This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
InPlay Oil is a junior oil and gas exploration and production company with operations in Alberta focused on light oil production. The company operates long-lived, low-decline properties with drilling development and enhanced oil recovery potential as well as undeveloped lands with exploration possibilities. The common shares of InPlay trade on the Toronto Stock Exchange under the symbol IPO and the OTCQX Exchange under the symbol IPOOF.
Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Production slows. Management projects 2022 production of 9,100-9,200 BOE/d versus 11/9/22 guidance of 9,150-9,400. Downtime at a third party gas facility led to a 435 BOE/d decrease in production. Cold weather also delayed getting wells on line. We have reduced our estimate to 9,162 BOE/d from 9,280. The company projects 2023 production of 9,500-10,000 BOE/d down from 9,900-10,400. We have lowered our forecast to 10,000 BOE/d from 10,400 to be within management’s guidance. We are comfortable being at the upper end of guidance given InPlay’s history of surpassing guidance (until the most recent quarter).
Expenditures rise. The company projects 2022 capital expenditures of C$76-78 million up from C$70-72 million due the acceleration of a drilling program. 2023 capital expenditure guidance increased to C$75-80 million (versus C$69-71 million) despite the drilling of 0.5 net wells less than previously assumed. Management attributes the higher capital expenditures mainly to two gas facility upgrades but also notes that it plans to drill longer wells in 2023 than in 2022.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
CALGARY, AB, Jan. 18, 2023 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) is pleased to announce it has been named to the 2023 OTCQX® Best 50, a ranking of top performing companies traded on the OTCQX Best Market last year.
The OTCQX Best 50 is an annual ranking of the top 50 U.S. and international companies traded on the OTCQX market. The ranking is calculated based on an equal weighting of one-year total return and average daily dollar volume growth in the previous calendar year. Companies in the 2023 OTCQX Best 50 were ranked based on their performance in 2022.
Doug Bartole, President and Chief Executive Officer of InPlay, commented: “We are very pleased with InPlay’s inclusion in the OTCQX Best 50 list. InPlay was the fifth best performer on the OTCQX Best Market based on 2022 total return and average daily dollar volume growth and this is the second consecutive year placing in the top five on this list. This ranking is a stong acknowledgement of the value we have created for shareholders through measured per share growth, free adjusted funds flow generation and delivering sustainable returns to shareholders. It is also evidence of the commitment of our employees and management team, strong leadership from our board of directors and the support of our lenders and shareholders. As outlined in our recently announced 2023 capital budget and guidance, InPlay finds itself in an extremely enviable financial and operational position allowing the Company to continue to forecast strong results in the upcoming year.”
The OTCQX Best Market offers transparent and efficient trading of established, investor-focused U.S. and global companies. To qualify for the OTCQX market, companies must meet high financial standards, follow best practice corporate governance, and demonstrate compliance with applicable securities laws.
About InPlay Oil Corp.
InPlay is a junior oil and gas exploration and production company with operations in Alberta focused on light oil production. The company operates long-lived, low-decline properties with drilling development and enhanced oil recovery potential as well as undeveloped lands with exploration possibilities. The common shares of InPlay trade on the Toronto Stock Exchange under the symbol IPO and the OTCQX Exchange under the symbol IPOOF. Additional information about the Company and our latest corporate presentation can be found on InPlay’s website at www.inplayoil.com.
SOURCE InPlay Oil Corp.
For further information: Doug Bartole, President and Chief Executive Officer, InPlay Oil Corp., Telephone: (587) 955-0632; Darren Dittmer, Chief Financial Officer, InPlay Oil Corp., Telephone: (587) 955-0634
Deep sea sponges and other creatures live on and among valuable manganese nodules like this one that could be mined from the seafloor. (GEOMAR)
Deep Seabed Mining Plans Pit Renewable Energy Demand Against Ocean Life in a Largely Unexplored Frontier
As companies race to expand renewable energy and the batteries to store it, finding sufficient amounts of rare earth metals to build the technology is no easy feat. That’s leading mining companies to take a closer look at a largely unexplored frontier – the deep ocean seabed.
A wealth of these metals can be found in manganese nodules that look like cobblestones scattered across wide areas of deep ocean seabed. But the fragile ecosystems deep in the oceans are little understood, and the mining codes to sustainably mine these areas are in their infancy.
A fierce debate is now playing out as a Canadian company makes plans to launch the first commercial deep sea mining operation in the Pacific Ocean.
The Metals Company completed an exploratory project in the Pacific Ocean in fall 2022. Under a treaty governing the deep sea floor, the international agency overseeing these areas could be forced to approve provisional mining there as soon as spring 2023, but several countries and companies are urging a delay until more research can be done. France and New Zealand have called for a ban on deep sea mining.
As scholars who have long focused on the economic, political and legal challenges posed by deep seabed mining, we have each studied and written on this economic frontier with concern for the regulatory and ecological challenges it poses.
Manganese nodules on the seafloor in the Clarion-Clipperton Zone, between Hawaii and Mexico, . (GEOMAR)
What’s Down There, and Why Should We Care?
A curious journey began in the summer of 1974. Sailing from Long Beach, California, a revolutionary ship funded by eccentric billionaire Howard Hughes set course for the Pacific to open a new frontier — deep seabed mining.
Widespread media coverage of the expedition helped to focus the attention of businesses and policymakers on the promise of deep seabed mining, which is notable given that the expedition was actually an elaborate cover for a CIA operation.
The real target was a Soviet ballistic missile submarine that had sunk in 1968 with all hands and what was believed to be a treasure trove of Soviet state secrets and tech onboard.
The expedition, called Project Azorian by the CIA, recovered at least part of the submarine – and it also brought up several manganese nodules from the seafloor.
Manganese nodules are roughly the size of potatoes and can be found across vast areas of seafloor in parts of the Pacific and Indian oceans and deep abyssal plains in the Atlantic. They are valuable because they are exceptionally rich in 37 metals, including nickel, cobalt and copper, which are essential for most large batteries and several renewable energy technologies.
Manganese nodules form as metals accumulate around a shell or part of another nodule. (GEOMAR)
These nodules form over millennia as metals nucleate around shells or broken nodules. The Clarion-Clipperton Zone, between Mexico and Hawaii in the Pacific Ocean, where the mining test took place, has been estimated to have over 21 billion metric tons of nodules that could provide twice as much nickel and three times more cobalt than all the reserves on land.
Mining in the Clarion-Clipperton Zone could be some 10 times richer than comparable mineral deposits on land. All told, estimates place the value of this new industry at some US$30 billion annually by 2030. It could be instrumental in feeding the surging global demand for cobalt that lies at the heart of lithium-ion batteries.
Yet, as several scientists have noted, we still know more about the surface of the moon than what lies at the bottom of the deep seabed.
Deep Seabed Ecology
Less than 10% of the deep seabed has been mapped thoroughly enough to understand even the basic features of the structure and contents of the ocean floor, let alone the life and ecosystems therein.
Even the most thoroughly studied region, the Clarion-Clipperton Zone, is still best characterized by the persistent novelty of what is found there.
Brightly colored sea cucumbers and many other unusual deep sea creatures live among the nodules in the Clarion-Clipperton Zone (GEOMAR)
Brightly colored sea cucumbers and many other unusual deep sea creatures live among the nodules in the Clarion-Clipperton Zone. (GEOMAR)
Between 70% and 90% of living things collected in the Clarion-Clipperton Zone have never been seen before, leaving scientists to speculate about what percentage of all living species in the region has never been seen or collected. Exploratory expeditions regularly return with images or samples of creatures that would richly animate science fiction stories, like a 6-foot-long bioluminescent shark.
Also unknown is the impact that deep sea mining would have on these creatures.
An experiment in 2021 in water about 3 miles (5 kilometers) deep off Mexico found that seabed mining equipment created sediment plumes of up to about 6.5 feet (2 meters) high. But the project authors stressed that they didn’t study the ecological impact. A similar earlier experiment was conducted off Peru in 1989. When scientists returned to that site in 2015, they found some species still hadn’t fully recovered.
Environmentalists have questioned whether seafloor creatures could be smothered by sediment plumes and whether the sediment in the water column could effect island communities that rely on healthy oceanic ecosystems. The Metals Company has argued that its impact is less than terrestrial mining.
Given humanity’s lack of knowledge of the ocean, it is not currently possible to set environmental baselines for oceanic health that could be used to weigh the economic benefits against the environmental harms of seabed mining.
Scarcity and the Economic Case for Mining
The economic case for deep seabed mining reflects both possibility and uncertainty.
On the positive side, it could displace some highly destructive terrestrial mining and augment the global supply of minerals used in clean energy sources such as wind turbines, photovoltaic cells and electric vehicles.
Terrestrial mining imposes significant environmental damage and costs to human health of both the miners themselves and the surrounding communities. Additionally, mines are sometimes located in politically unstable regions. The Democratic Republic of Congo produces 60% of the global supply of cobalt, for example, and China owns or finances 80% of industrial mines in that country. China also accounts for 60% of the global supply of rare earth element production and much of its processing. Having one nation able to exert such control over a critical resource has raised concerns.
Deep seabed mining comes with significant uncertainties, however, particularly given the technology’s relatively early state.
First are the risks associated with commercializing a new technology. Until deep sea mining technology is demonstrated, discoveries cannot be listed as “reserves” in firms’ asset valuations. Without that value defined, it can be difficult to line up the significant financing needed to build mining infrastructure, which lessens the first-mover advantage and incentivizes firms to wait for someone else to take the lead.
Commodity prices are also difficult to predict. Technology innovation can reduce or even eliminate the projected demand for a mineral. New mineral deposits on land can also boost supply: Sweden announced in January 2023 that it had just discovered the largest deposit of rare earth oxides in Europe.
In all, embarking on deep seabed mining involves sinking significant costs into new technology for uncertain returns, while posing risks to a natural environment that is likely to rise in value.
Who Gets to Decide the Future of Seafloor Mining?
The United Nations Convention on the Law of the Sea, which came into force in the early 1990s, provides the basic rules for ocean resources.
It allows countries to control economic activities, including any mining, within 200 miles of their coastlines, accounting for approximately 35% of the ocean. Beyond national waters, countries around the world established the International Seabed Authority, or ISA, based in Jamaica, to regulate deep seabed mining.
Critically, the ISA framework calls for some of the profits derived from commercial mining to be shared with the international community. In this way, even countries that did not have the resources to mine the deep seabed could share in its benefits. This part of the ISA’s mandate was controversial, and it was one reason that the United States did not join the Convention on the Law of the Sea.
Where large numbers of manganese nodules are found. The areas with the greatest concentrations are circled. (GEOMAR)
Where large numbers of manganese nodules are found. The areas with the greatest concentrations are circled. (GEOMAR)
With little public attention, the ISA worked slowly for several decades to develop regulations for exploration of undersea minerals, and those rules still aren’t completed. More than a dozen companies and countries have received exploration contracts, including The Metals Company’s work under the sponsorship of the island nation of Nauru.
ISA’s work has started to draw criticism as companies have sought to initiate commercial mining. A recent New York Times investigation of internal ISA documents suggested the agency’s leadership has downplayed environmental concerns and shared confidential information with some of the companies that would be involved in seabed mining. The ISA hasn’t finalized environmental rules for mining.
Much of the coverage of deep seabed mining has been framed to highlight the climate benefits. But this overlooks the dangers this activity could pose for the Earth’s largest pristine ecology – the deep sea. We believe it would be wise to better understand this existing, fragile ecosystem better before rushing to mine it.
In the future, the energy needed to run the powerful computers on board a global fleet of autonomous vehicles could generate as many greenhouse gas emissions as all the data centers in the world today.
That is one key finding of a new study from MIT researchers that explored the potential energy consumption and related carbon emissions if autonomous vehicles are widely adopted.
The data centers that house the physical computing infrastructure used for running applications are widely known for their large carbon footprint: They currently account for about 0.3 percent of global greenhouse gas emissions, or about as much carbon as the country of Argentina produces annually, according to the International Energy Agency. Realizing that less attention has been paid to the potential footprint of autonomous vehicles, MIT researchers built a statistical model to study the problem. They determined that 1 billion autonomous vehicles, each driving for one hour per day with a computer consuming 840 watts, would consume enough energy to generate about the same amount of emissions as data centers currently do.
The researchers also found that in over 90 percent of modeled scenarios, to keep autonomous vehicle emissions from zooming past current data center emissions, each vehicle must use less than 1.2 kilowatts of power for computing, which would require more efficient hardware. In one scenario — where 95 percent of the global fleet of vehicles is autonomous in 2050, computational workloads double every three years, and the world continues to decarbonize at the current rate — they found that hardware efficiency would need to double faster than every 1.1 years to keep emissions under those levels.
“If we just keep the business-as-usual trends in decarbonization and the current rate of hardware efficiency improvements, it doesn’t seem like it is going to be enough to constrain the emissions from computing onboard autonomous vehicles. This has the potential to become an enormous problem. But if we get ahead of it, we could design more efficient autonomous vehicles that have a smaller carbon footprint from the start,” says first author Soumya Sudhakar, a graduate student in aeronautics and astronautics.
Sudhakar wrote the paper with her co-advisors Vivienne Sze, associate professor in the Department of Electrical Engineering and Computer Science (EECS) and a member of the Research Laboratory of Electronics (RLE); and Sertac Karaman, associate professor of aeronautics and astronautics and director of the Laboratory for Information and Decision Systems (LIDS). The research appears today in the January-February issue of IEEE Micro.
Modeling Emissions
The researchers built a framework to explore the operational emissions from computers on board a global fleet of electric vehicles that are fully autonomous, meaning they don’t require a backup human driver.
The model is a function of the number of vehicles in the global fleet, the power of each computer on each vehicle, the hours driven by each vehicle, and the carbon intensity of the electricity powering each computer.
“On its own, that looks like a deceptively simple equation. But each of those variables contains a lot of uncertainty because we are considering an emerging application that is not here yet,” Sudhakar says.
For instance, some research suggests that the amount of time driven in autonomous vehicles might increase because people can multitask while driving, and the young and the elderly could drive more. But other research suggests that time spent driving might decrease because algorithms could find optimal routes that get people to their destinations faster.
In addition to considering these uncertainties, the researchers also needed to model advanced computing hardware and software that didn’t exist yet.
To accomplish that, they modeled the workload of a popular algorithm for autonomous vehicles, known as a multitask deep neural network, because it can perform many tasks at once. They explored how much energy this deep neural network would consume if it were processing many high-resolution inputs from many cameras with high frame rates simultaneously.
When they used the probabilistic model to explore different scenarios, Sudhakar was surprised by how quickly the algorithms’ workload added up.
For example, if an autonomous vehicle has 10 deep neural networks processing images from 10 cameras, and that vehicle drives for one hour a day, it will make 21.6 million inferences each day. One billion vehicles would make 21.6 quadrillion inferences. To put that into perspective, all of Facebook’s data centers worldwide make a few trillion inferences each day (1 quadrillion is 1,000 trillion).
“After seeing the results, this makes a lot of sense, but it is not something that is on a lot of people’s radar. These vehicles could actually be using a ton of computer power. They have a 360-degree view of the world, so while we have two eyes, they may have 20 eyes, looking all over the place and trying to understand all the things that are happening at the same time,” Karaman says.
Autonomous vehicles would be used for moving goods, as well as people, so there could be a massive amount of computing power distributed along global supply chains, he says. And their model only considers computing — it doesn’t take into account the energy consumed by vehicle sensors or the emissions generated during manufacturing.
Keeping Emissions in Check
To keep emissions from spiraling out of control, the researchers found that each autonomous vehicle needs to consume less than 1.2 kilowatts of energy for computing. For that to be possible, computing hardware must become more efficient at a significantly faster pace, doubling in efficiency about every 1.1 years.
One way to boost that efficiency could be to use more specialized hardware, which is designed to run specific driving algorithms. Because researchers know the navigation and perception tasks required for autonomous driving, it could be easier to design specialized hardware for those tasks, Sudhakar says. But vehicles tend to have 10- or 20-year lifespans, so one challenge in developing specialized hardware would be to “future-proof” it so it can run new algorithms.
In the future, researchers could also make the algorithms more efficient, so they would need less computing power. However, this is also challenging because trading off some accuracy for more efficiency could hamper vehicle safety.
Now that they have demonstrated this framework, the researchers want to continue exploring hardware efficiency and algorithm improvements. In addition, they say their model can be enhanced by characterizing embodied carbon from autonomous vehicles — the carbon emissions generated when a car is manufactured — and emissions from a vehicle’s sensors.
While there are still many scenarios to explore, the researchers hope that this work sheds light on a potential problem people may not have considered.
“We are hoping that people will think of emissions and carbon efficiency as important metrics to consider in their designs. The energy consumption of an autonomous vehicle is really critical, not just for extending the battery life, but also for sustainability,” says Sze.
CALGARY, AB, Jan. 6, 2023 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces record sales volumes in December 2022 and an operational update.
December 2022 sales volumes
December sales volumes averaged 2,785 boepd, including natural gas sales of 15.9 MMcfpd and associated natural gas liquids sales from condensate of 125 bopd, and 15 bopd of oil sales, based on field estimates, a 4% increase from our November 2022 average daily volumes. Our sales volumes averaged 2,724 boepd in the fourth quarter of 2022, an increase of 3% from the third quarter of 2022.
Operational Update
We have completed testing our 182-C2 well on our 100% owned and operated Block 182. We completed drilling the 182-C2 well in October to a total measured depth (“MD”) of 3,185 metres. As previously announced, based on open-hole wireline logs, the well encountered a 223.7-metre-thick section with 121.3 metres of sand estimated above 6% porosity in the sand-dominated interval between 2,704.1 and 2,927.8 metres total vertical depth in the Sergi Formation. The well also encountered 10.9 metres of potential net hydrocarbon pay in the Agua Grande Formation, with an average porosity of 8.9% and average water saturation of 25.1%, using a 6% porosity cut-off, 50% Vshale cut-off and 50% water saturation cut-off. During testing operations of the Sergi and Agua Grande Formations we recovered non-commercial amounts of oil and natural gas. These results indicate lower than anticipated permeability and we are evaluating alternatives to remove any near well bore formation damage and reservoir stimulations to enhance permeability in the Agua Grande and Sergi Formations in this well, and the Sergi Formation in our 183-B1 well.
Alvopetro Energy Ltd.’svision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
All amounts contained in this new release are in United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.
Abbreviations:bbls = barrelsboepd = barrels of oil equivalent (“boe”) per daybopd = barrels of oil and/or natural gas liquids (condensate) per dayMMcf = million cubic feetMMcfpd = million cubic feet per day
BOE Disclosure. The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
Testing and Well Results. Data obtained from the 182-C2 well identified in this press release, including hydrocarbon shows, open-hole logging, net pay and porosities and initial testing data, should be considered to be preliminary until detailed pressure transient and other analysis and interpretation has been completed. Hydrocarbon shows can be seen during the drilling of a well in numerous circumstances and do not necessarily indicate a commercial discovery or the presence of commercial hydrocarbons in a well. There is no representation by Alvopetro that the data relating to the 182-C2 well contained in this press release is necessarily indicative of long-term performance or ultimate recovery. The reader is cautioned not to unduly rely on such data as such data may not be indicative of future performance of the well or of expected production or operational results for Alvopetro in the future.
Forward-Looking Statements and Cautionary Language. This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward–looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning potential hydrocarbon pay in the 182-C2 well, exploration and development prospects of Alvopetro and the expected timing of certain of Alvopetro’s testing and operational activities. The forward–looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to expectations and assumptions concerning testing results of the 183-B1 well and the 182-C2 well, equipment availability, the timing of regulatory licenses and approvals, the success of future drilling, completion, testing, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of the COVID-19 pandemic, the performance of producing wells and reservoirs, well development and operating performance, foreign exchange rates, general economic and business conditions, weather and access to drilling locations, the availability and cost of labour and services, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
If you predicted that oil prices would go up last year, you were correct. If you predicted they’d go down, you were also correct. I dare say that even with insight as to what was to come, many analysts would have had the timing completely reversed from what actually happened. Why? What caused the volatility? And most importantly, what can we learn from this to help us in 2023 and beyond? After all, in 2022, oil company Exxon increased in market value more than any other company in the S&P 500. It became the eighth largest with a 74.3% increase in share price, up from the 27th largest a year ago. In contrast, WTI Crude closed near its low for the year, the dynamics involved are certainly worth investor exploration.
Background
Twelve months ago, according to the Energy Information Administration (EIA) the price of West Texas Intermediate (WTI) crude oil was considered high at $75.99/bbl. WTI closed the year less than 6% higher at $80.47/bbl. But this is not indicative of the wild surprises in between. There are two events that had a major impact during those twelve months.
Russia’s late February invasion of its neighbor helped crude prices to shoot up above $120/bbl. Oil has only visited that level once before (2008). Very few could have expected this event, so the expectations leading up to the early months of 2022 were, at worst moderate price declines to moderate increases. Those expecting some price increases pointed to the ongoing supply shortfall related to the pandemic response. This is the period that surprised traders with oil on the way up. Then as it became evident the war would be prolonged and Europe and other regions would take steps to move away from Russia’s output, expectations were for further price increases. What was not anticipated was a massive release of oil from the U.S. Strategic Petroleum Reserves. Along with releases from reserves in other parts of the world, oil prices sank. But, fear of the European winter, lack of support from OPEC+, and anticipation of price caps on Russian oil creating a loss of supply had many talking about upward pressure by year-end. It has not materialized.
The Crude World Order (OPIC?)
What’s changed the expected results related to oil prices and even producer prices? First off, there was a level of unity never-before-experienced and organization among petroleum-importing countries among consuming nations. The pushback and, to some degree taking charge, by nations that are net consumers began in late Spring 2022 when 31 members of the International Energy Agency (IEA) decided to all release oil from reserves to quench demand and impact prices.
The Paris-based IEA promotes what it believes are beneficial energy situations for consumers. It had taken the lead on emergency measures before, but never with this much unity or on this scale. The amount of reserves sold into the oil market amounts to less than 1%, but it is estimated to have shaved $20 or more off per barrel oil prices in the spring and summer. Brent crude, the international oil benchmark, hit its peak settlement value of $127.98 per barrel in March but had fallen below $100 by July. Recently it has been trading near $80.
Certainly, the drawdown on reserves which borrowed from the future will need to be replenished. Pulling from reserves is unsustainable and therefore limits bargaining power. Nations have pledged to return their reserves to a level deemed in line with national security (the U.S. has a 50-day reserve supply), but the timing is uncertain.
What is positive for consumers is the IEA has learned to stand firm and work together.
Why are Oil Company Stocks Outperformers?
Crude is roughly the same price now as it was at the beginning of last year. Yet, factors including conservation efforts and China Covid policies have caused limited demand growth. And despite favorable economics currently, energy companies have been slow to drill new wells. U.S. rig count, as reported by Baker Hughes, crept up to 779 rigs by the end of the year. This compares to a peak level of 1,600 in 2014.
So why, as mentioned earlier, are oil companies performing as tech companies did in 2021?
On the surface, one might think energy company stock prices would be weakening, but this isn’t the case there are other factors at play. Michael Heim, Senior Energy Analyst, at Noble Capital Markets, explains in his newly released Q4 2022 Energy Industry Report, “Operating cash flow has soared over the last two years, but capital expenditures have barely increased. The result has been a large increase in dividend payments, share repurchases, and debt reduction.” Heim’s report further explains that while capital expenditures lagged well behind, it is inaccurate to conclude that oil production has not increased. The Noble Capital Markets analyst explains, “…current production levels are above that during peak drilling periods in 2014. The implication is that drilling has become more productive. While drilling advances such as the use of horizontal drill and fracking in shale deposits may be old hat, it is worth noting that drillers have been refining drilling techniques for individual drilling locations.” Drillers are improving techniques, improving efficiencies and maximizing production per dollar spent. Heim also attributes some of the efficiencies to well recompletions, which he explains are less expensive to put in service.
The S&P index that tracks the Energy sector gained 53.8% last year. If you had had a crystal ball that told you about the events that would transpire, such as the European war, and oil returning to its starting place, it’s a rare investor that would expect the drillers/producers to increase over 50%. While all situations have their own circumstances, understanding why price action happened can provide greater preparedness to face the markets each year.
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Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.
Refer to the bottom of the report for important disclosures
Energy Stocks Were Strong. Energy stocks rose 21.5% in the fourth quarter far outpacing a 7.1% rise for the S&P 500 Index. For the year, energy stocks were up an impressive 57% versus a 20% decline in the overall market. The strength can largely be attributed to rising energy prices, although we would note that energy prices have largely leveled out after a strong first half of the year.
Oil prices are near $80. Near month oil future contracts are now almost $80 per barrel, below peak prices but significantly higher than historic prices. At $80 per barrel, most energy companies are very profitable and generating significant excess free cash flow. Despite the favorable economics, energy companies have been slow to drill new wells, and modest production increases have come mainly from improved efficiencies. In addition, there is a growing belief that OPEC’s spare capacity is declining questioning its ability to meet demand increases. As time passes, $80 oil is starting to feel like the new equilibrium level with $40-$60 oil prices a thing of the past.
Gas prices are rising even more than oil prices. Natural gas prices have risen steadily over the last two years even as production levels have been steady. Storage levels, which were running below historical levels, have improved in recent months.
Energy industry fundamentals remain strong. Oil and gas prices are near historical highs and above the levels assumed in our financial and valuation models. Energy company cash flow generation is high, and companies are facing the envious position of trying to decide what to do with the cash. Debt levels have been pared down and managements have been raising dividend levels and repurchasing shares. Drilling is increasing but at a controllable pace that doesn’t seem likely to put prices into a downcycle. We believe the case for smaller cap energy stocks is especially strong. If our belief that a world-wide recession is already factored into energy prices is correct, small cap energy companies will be in the best position to take advantage of any price increase.
Energy Stocks
Energy stocks, as measured by the XLE Energy Index, rose sharply in the most recent quarter after logging in a flat third quarter. In the fourth quarter, energy stocks rose 21.5% far outpacing a 7.1% rise for the S&P 500 Index. For the year, energy stocks were up an impressive 57% versus a 20% decline in the overall market. This year’s strong performance comes after last year’s 50% rise. The strength can largely be attributed to rising energy prices, although we would note that energy prices have largely leveled out after a strong first half of the year.
Oil Prices
Oil prices rose steadily over a two-year period beginning the spring of 2020. WTI prices peaked at $120 per barrel in the first week of June. Prices declined in the third quarter but seem to have leveled off in recent months. Near month oil future contracts are now almost $80 per barrel, below peak prices but significantly higher than historic prices. At $80 per barrel, most energy companies are very profitable and generating significant excess free cash flow. As time passes, $80 oil is starting to feel like the new equilibrium level with $40-$60 oil prices a thing of the past.
Figure #1
Despite the favorable economics, energy companies have been slow to drill new wells. U.S. rig count, as reported by Baker Hughes, crept up to 779 rigs by the end of the year. This compares to a peak level of 1,600 in 2014. The disparity between increased profitability and increased capital expenditures is shown in the chart below. Operating cash flow has soared over the last two years, but capital expenditures have barely increased. The result has been a large increase in dividend payments, share repurchases and debt reduction.
Figure #2
While capital expenditures have not increased in line with cash flow, it would be unfair to say that oil production has not increased. Indeed, current production levels are above that during peak drilling periods in 2014. The implication is that drilling has become more productive. While drilling advances such as the use of horizontal drill and fracking in shale deposits may be old hat, it is worth noting that drillers have been refining drilling techniques for individual drilling locations. Drillers continue to perfect the ideal number of fracking targets and the materials used to frack. In addition, as we discussed in our September quarter comments, there has been a sharp increase in the number of well recompletions, which are less expensive to complete but not a long-term solution.
Figure #3
Meanwhile, OPEC has been increasing production in recent years after making sharp reductions during the COVID years. However, there are growing concerns that OPEC’s overall capacity is declining and that its spare capacity has consequentially declined. If this is indeed true, OPEC’s ability to fulfill increased demand for oil may be limited. This would bode well, not only for oil prices, but for the role domestic producers will have in meeting demand.
Figure #4
Natural Gas Prices
The chart below shows natural gas prices against production levels. As the chart shows, natural gas prices have risen steadily over the last two years even as production levels have remained steady. To that extent, natural gas prices are acting like oil prices. Natural gas prices tend to track oil prices but with a few distinctions. Natural gas demand and supply is less global than oil. Imports (and now exports) of liquefied natural gas represent a small portion of domestic supply and demand. Secondly, natural gas is used primarily for space heating. That means demand is more seasonal. It also means demand can be affected by weather conditions. On the other hand, natural gas demand is less affected by general economic conditions than oil.
Figure #5
Storage levels, which were running below historical levels, have improved in recent months. We would note that the most recent storage numbers do not reflect the cold snap across the country during the last week of the year. Cold temperatures may send storage levels lower than is reflected in the chart below.
Figure #6
Outlook
Energy industry fundamentals remain strong. Oil and gas prices are near historical highs and above the levels assumed in our financial and valuation models. Energy company cash flow generation is high, and companies are facing the envious position of trying to decide what to do with the cash. Debt levels have been pared down and managements have been raising dividend levels and repurchasing shares. Drilling is increasing but at a controllable pace that doesn’t seem likely to put prices into a downcycle.
We believe the case for smaller cap energy stocks is strong. Major oil companies are facing increasing pressure to focus on renewable energy instead of producing more carbon-based fuel. Smaller cap energy companies are less tethered and often able to acquire and exploit properties being ignored by the majors. If our belief that a world-wide recession is already factored into energy prices is correct, small cap energy companies will be in the best position to take advantage of any price increase.
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Nuclear Fusion’s Potential to Be a Highly Disruptive Breakthrough with Investment Opportunities
Scientists at the Energy Department’s Lawrence Livermore National Laboratory (LLNL) in California announced the first-ever demonstration of fusion “ignition.” This means that more energy was generated from fusion than was needed to operate the high-powered lasers that triggered the reaction. More than 2 megajoules (MJ) of laser light were directed onto a tiny gold-plated capsule, resulting in the production of a little over 3 MJ of energy, the equivalent of three sticks of dynamite.
This important milestone is the culmination of decades’ worth of research and lots of trial and error, and it makes good on the hope that humanity will one day enjoy 100% clean and plentiful energy.
This article was republished with permission from Frank Talk, a CEO Blog by Frank Holmes of U.S. Global Investors (GROW). Find more of Frank’s articles here – Originally published December 19, 2022.
Unlike conventional nuclear fission, which produces highly radioactive waste and carries the risk of nuclear proliferation, nuclear fusion has no emissions or risk of cataclysmic disaster. That should please activists who support renewable, non-carbon-emitting energy sources such as wind and solar and yet oppose nuclear power.
75th Anniversary of Another Great American Invention, The Transistor
I think it’s only fitting that this breakthrough occurred not just in the U.S., the most innovative country on earth, but also on the 75th anniversary of the invention of the transistor.
Like fusion energy, the transistor’s importance can’t be overstated. Invented in December 1947 in New Jersey’s storied Bell Labs—also the birthplace of the photovoltaic cell, fiber optic cable, communications satellite, UNIX operating system and C programming language—the transistor made the 20th century possible. Everything we use and enjoy today, from our iPhones to our Teslas, wouldn’t exist without the seminal American invention.
In 2021, the electric vehicle maker unveiled its proprietary application-specific integrated circuit (ASIC) for artificial intelligence (AI) training. The ASIC chip, believe it or not, boasts an unbelievable 50 billion transistors.
Private Investment in Fusion Technology Has Been Increasing
Getting your electricity from a commercial fusion reactor is still years if not decades away, but that hasn’t stopped money from flowing into the sector. This year, private investment is estimated to top $1 billion, following the record $2.6 billion that went into fusion research in 2021, according to BloombergNEF.
Private Sector Investment in Nuclear Fusion May Top $1 Billion in 2022
At the moment, there aren’t any publicly traded fusion companies. However, Bloomberg has a Global Nuclear Theme Peers index that tracks listed companies with exposure to the industry, estimated by Bloomberg to one day achieve a jaw-dropping $40 trillion valuation. Some of the more recognizable names include Rolls-Royce, Toshiba, Hitachi and General Electric.
For the five-year period, the index of 64 “nuclear” stocks has advanced approximately 100%, compared to the MSCI World Index, up 38% over the same period.
The number of private firms involved in R&D continues to grow, raising the possibility that some will tap public markets in the coming years.
Among the largest is Commonwealth Fusion Systems, or CFS, which spun out of MIT’s Plasma Science and Fusion Center in 2018. The company raised $1.8 billion in December 2021, on top of the $250 million it had raised previously. Its investors include Bill Gates and Google, along with oil companies, venture capital firms and sovereign wealth funds. CFS claims to have the fastest, lowest cost solution to commercial fusion energy and is in the process of building a prototype that is set to demonstrate net energy gain by 2025.
Another major player is TAE Technologies. Located in California, the company has raised a total of $1.2 billion as of December 2022, from investors such as the late Paul Allen, Goldman Sachs, Google and the family office of Charles Schwab. TAE says it is developing a fusion reactor, scheduled to be unveiled in the early 2030s, that will generate electricity from a proton-boron reaction at an incredible temperature of 1 billion degrees.
Other contenders in the field include Washington State-based Helion Energy, Canada’s General Fusion and the United Kingdom’s Tokamak Energy. In February 2022, Tokamak broke a longstanding record by generating 59 MJ of energy, the highest sustained energy pulse ever.
As an investor, I would keep an eye on this space!
Solar Accounted For 45% Of All New Energy Capacity Growth In The U.S.
In the meantime, energy investors with an eye on the future still have renewable energy stocks to consider.
2022 has been a challenging year for the industry, with much of it facing supply constraints. According to Wood Mackenzie, total new solar installations in the U.S. were 18.6 gigawatts (GW), a 23% decrease from 2021.
Even so, solar accounted for 45% of all new electricity-generation capacity added this year through the end of the third quarter. That’s greater than any other energy source. Wind was in second place, representing a quarter of all new energy power, followed by natural gas at 21% and coal at 10%, its best year since 2013.
WoodMac expresses optimism in the next two years. Solar projects that were delayed this year due to supply issues may finally come online in 2023, and by 2024, the real effects of President Biden’s Inflation Reduction Act (IRA) should be felt. The U.K.-based research firm forecasts 21% average annual growth from 2023 through 2027, so now may be an opportune time to start participating.
One of our favorite plays right now is Canadian Solar, up more than 11% for the year. On Thursday of this week, the Ontario-based company announced that it would begin mass-producing high efficiency solar modules in the first quarter of 2023. Canadian Solar shares were up more than 1% last week, despite experiencing two down days on this week’s news of continued rate hikes into 2023.
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The BI Global Nuclear Theme Peers is an index not for use as a financial benchmark that tracks 64 companies exposed to nuclear energy research and production. The MSCI World Index is a free-float weighted equity index which includes developed world markets and does not include emerging markets.
Holdings may change daily. Holdings are reported as of the most recent quarter-end. The following securities mentioned in the article were held by one or more accounts managed by U.S. Global Investors as of (09/30/22): Tesla Inc., Canadian Solar Inc.
Energy Fuels is a leading U.S.-based uranium mining company, supplying U3O8 to major nuclear utilities. Energy Fuels also produces vanadium from certain of its projects, as market conditions warrant, and is ramping up commercial-scale production of REE carbonate. Its corporate offices are in Lakewood, Colorado, near Denver, and all its assets and employees are in the United States. Energy Fuels holds three of America’s key uranium production centers: the White Mesa Mill in Utah, the Nichols Ranch in-situ recovery (“ISR”) Project in Wyoming, and the Alta Mesa ISR Project in Texas. The White Mesa Mill is the only conventional uranium mill operating in the U.S. today, has a licensed capacity of over 8 million pounds of U3O8 per year, has the ability to produce vanadium when market conditions warrant, as well as REE carbonate from various uranium-bearing ores. The Nichols Ranch ISR Project is on standby and has a licensed capacity of 2 million pounds of U3O8 per year. The Alta Mesa ISR Project is also on standby and has a licensed capacity of 1.5 million pounds of U3O8 per year. In addition to the above production facilities, Energy Fuels also has one of the largest NI 43-101 compliant uranium resource portfolios in the U.S. and several uranium and uranium/vanadium mining projects on standby and in various stages of permitting and development. The primary trading market for Energy Fuels’ common shares is the NYSE American under the trading symbol “UUUU,” and the Company’s common shares are also listed on the Toronto Stock Exchange under the trading symbol “EFR.” Energy Fuels’ website is www.energyfuels.com.
Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
The sales, along with recently signed utility contracts, will generate cash flow as UUUU starts up operations. Congress allocated $75 million to establish a national uranium security reserve in its 2020 budget. The US Energy Secretary indicated earlier that it expects to make four individual awards of 100,000-500,000 pounds of U3O8 for a total of 1 million pounds. Energy Fuels, as the largest licensed producer of uranium, was in a good position to receive one of the rewards. The UUUU announcement did not indicate a volume level. Peninsula Energy announced that it received an award for 300,000 pounds but did not specify a sales amount.
The sales can be done right away before mining operations are restarted. The conditions of the DOE award state that the uranium must be physically located at Honeywell’s conversion facilities in Metropolis, IL. Energy Fuels currently holds about 610,000 pounds of U3O8 at Metropolis worth more than $30 million at current uranium spot prices. A volume awards similar to that for Peninsula seems reasonable implying that the DOE is paying a price near $60/lb. or slightly above current spot prices, and be well within current inventory levels.
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Owners of electric vehicles (EVs) are accustomed to plugging into charging stations at home and at work and filling up their batteries with electricity from the power grid. But someday soon, when these drivers plug in, their cars will also have the capacity to reverse the flow and send electrons back to the grid. As the number of EVs climbs, the fleet’s batteries could serve as a cost-effective, large-scale energy source, with potentially dramatic impacts on the energy transition, according to a new paper published by an MIT team in the journal Energy Advances.
“At scale, vehicle-to-grid (V2G) can boost renewable energy growth, displacing the need for stationary energy storage and decreasing reliance on firm [always-on] generators, such as natural gas, that are traditionally used to balance wind and solar intermittency,” says Jim Owens, lead author and a doctoral student in the MIT Department of Chemical Engineering. Additional authors include Emre Gençer, a principal research scientist at the MIT Energy Initiative (MITEI), and Ian Miller, a research specialist for MITEI at the time of the study.
The group’s work is the first comprehensive, systems-based analysis of future power systems, drawing on a novel mix of computational models integrating such factors as carbon emission goals, variable renewable energy (VRE) generation, and costs of building energy storage, production, and transmission infrastructure.
“We explored not just how EVs could provide service back to the grid — thinking of these vehicles almost like energy storage on wheels — but also the value of V2G applications to the entire energy system and if EVs could reduce the cost of decarbonizing the power system,” says Gençer. “The results were surprising; I personally didn’t believe we’d have so much potential here.”
Displacing New Infrastructure
As the United States and other nations pursue stringent goals to limit carbon emissions, electrification of transportation has taken off, with the rate of EV adoption rapidly accelerating. (Some projections show EVs supplanting internal combustion vehicles over the next 30 years.) With the rise of emission-free driving, though, there will be increased demand for energy. “The challenge is ensuring both that there’s enough electricity to charge the vehicles and that this electricity is coming from renewable sources,” says Gençer.
But solar and wind energy is intermittent. Without adequate backup for these sources, such as stationary energy storage facilities using lithium-ion batteries, for instance, or large-scale, natural gas- or hydrogen-fueled power plants, achieving clean energy goals will prove elusive. More vexing, costs for building the necessary new energy infrastructure runs to the hundreds of billions.
This is precisely where V2G can play a critical, and welcome, role, the researchers reported. In their case study of a theoretical New England power system meeting strict carbon constraints, for instance, the team found that participation from just 13.9 percent of the region’s 8 million light-duty (passenger) EVs displaced 14.7 gigawatts of stationary energy storage. This added up to $700 million in savings — the anticipated costs of building new storage capacity.
Their paper also described the role EV batteries could play at times of peak demand, such as hot summer days. “V2G technology has the ability to inject electricity back into the system to cover these episodes, so we don’t need to install or invest in additional natural gas turbines,” says Owens. “The way that EVs and V2G can influence the future of our power systems is one of the most exciting and novel aspects of our study.”
Modeling Power
To investigate the impacts of V2G on their hypothetical New England power system, the researchers integrated their EV travel and V2G service models with two of MITEI’s existing modeling tools: the Sustainable Energy System Analysis Modeling Environment (SESAME) to project vehicle fleet and electricity demand growth, and GenX, which models the investment and operation costs of electricity generation, storage, and transmission systems. They incorporated such inputs as different EV participation rates, costs of generation for conventional and renewable power suppliers, charging infrastructure upgrades, travel demand for vehicles, changes in electricity demand, and EV battery costs.
Their analysis found benefits from V2G applications in power systems (in terms of displacing energy storage and firm generation) at all levels of carbon emission restrictions, including one with no emissions caps at all. However, their models suggest that V2G delivers the greatest value to the power system when carbon constraints are most aggressive — at 10 grams of carbon dioxide per kilowatt hour load. Total system savings from V2G ranged from $183 million to $1,326 million, reflecting EV participation rates between 5 percent and 80 percent.
“Our study has begun to uncover the inherent value V2G has for a future power system, demonstrating that there is a lot of money we can save that would otherwise be spent on storage and firm generation,” says Owens.
Harnessing V2G
For scientists seeking ways to decarbonize the economy, the vision of millions of EVs parked in garages or in office spaces and plugged into the grid for 90 percent of their operating lives proves an irresistible provocation. “There is all this storage sitting right there, a huge available capacity that will only grow, and it is wasted unless we take full advantage of it,” says Gençer.
This is not a distant prospect. Startup companies are currently testing software that would allow two-way communication between EVs and grid operators or other entities. With the right algorithms, EVs would charge from and dispatch energy to the grid according to profiles tailored to each car owner’s needs, never depleting the battery and endangering a commute.
“We don’t assume all vehicles will be available to send energy back to the grid at the same time, at 6 p.m. for instance, when most commuters return home in the early evening,” says Gençer. He believes that the vastly varied schedules of EV drivers will make enough battery power available to cover spikes in electricity use over an average 24-hour period. And there are other potential sources of battery power down the road, such as electric school buses that are employed only for short stints during the day and then sit idle.
The MIT team acknowledges the challenges of V2G consumer buy-in. While EV owners relish a clean, green drive, they may not be as enthusiastic handing over access to their car’s battery to a utility or an aggregator working with power system operators. Policies and incentives would help.
“Since you’re providing a service to the grid, much as solar panel users do, you could be paid for your participation, and paid at a premium when electricity prices are very high,” says Gençer.
“People may not be willing to participate ’round the clock, but if we have blackout scenarios like in Texas last year, or hot-day congestion on transmission lines, maybe we can turn on these vehicles for 24 to 48 hours, sending energy back to the system,” adds Owens. “If there’s a power outage and people wave a bunch of money at you, you might be willing to talk.”
“Basically, I think this comes back to all of us being in this together, right?” says Gençer. “As you contribute to society by giving this service to the grid, you will get the full benefit of reducing system costs, and also help to decarbonize the system faster and to a greater extent.”
Actionable Insights
Owens, who is building his dissertation on V2G research, is now investigating the potential impact of heavy-duty electric vehicles in decarbonizing the power system. “The last-mile delivery trucks of companies like Amazon and FedEx are likely to be the earliest adopters of EVs,” Owen says. “They are appealing because they have regularly scheduled routes during the day and go back to the depot at night, which makes them very useful for providing electricity and balancing services in the power system.”
Owens is committed to “providing insights that are actionable by system planners, operators, and to a certain extent, investors,” he says. His work might come into play in determining what kind of charging infrastructure should be built, and where.
“Our analysis is really timely because the EV market has not yet been developed,” says Gençer. “This means we can share our insights with vehicle manufacturers and system operators — potentially influencing them to invest in V2G technologies, avoiding the costs of building utility-scale storage, and enabling the transition to a cleaner future. It’s a huge win, within our grasp.”
The research for this study was funded by MITEI’s Future Energy Systems Center.
Nuclear Power Plant Start Will be Delayed as Reliable US Fuel Production Needs to Improve
The energy and fuel shortages stemming from the Russia/Ukraine war extend beyond oil and gas. A sharp impact is also being felt in the nuclear energy world as uranium is less available for new and existing plants. In the US, TerraPower’s natrium reactor completion date is now estimated at least two years beyond the original plan. This is because of problems securing the proper fuel. TerraPower is a start-up co-founded by Bill Gates with support from Warren Buffett to revolutionize nuclear reactor design and methods. The natrium reactor being built as a test of the technology is being built in Kemmerer, Wyoming, which is considered a coal town. The original completion date was 2028.
What is Now Expected
The company expects the natrium demonstration reactor operation to be delayed by at least two years because there will not be sufficient commercial capacity to produce high-assay low-enriched uranium fuel to test come the original 2028 in-service date.
TerraPower’s CEO and President Chris Levesque said Russia’s invasion of Ukraine earlier this year caused “the only commercial source of HALEU fuel” to no longer be a viable part of the supply chain. The company is now working with the US Department of Energy (DOE), Congress, and project stakeholders to explore potential alternative sources. Levesque said, “while we are working now with Congress to urge the inclusion of $2.1 billion to support HALEU in the end-of-year government funding package, it has become clear that domestic and allied HALEU manufacturing options will not reach commercial capacity in time to meet the proposed 2028 in-service date for the Natrium demonstration plant.”
The company has not provided a new schedule but expects to in 2023, when there may be more clarity of what will be available and when. “But given the lack of fuel availability now and that there has been no construction started on new fuel enrichment facilities, TerraPower is anticipating a minimum of a two-year delay to being able to bring the Natrium reactor into operation,” Levesque warned.
About the Plant and its Fuel
Kemmerer in Wyoming was selected in 2021 as the preferred site for the Natrium demonstration project, featuring a 345 MWe sodium-cooled fast reactor with a molten salt-based energy storage system. TerraPower remains fully committed to the project and is “moving full steam ahead” on the construction of the plant, licensing applications and engineering and design work, Levesque added. Work scheduled to begin in Spring 2023 on the large sodium facility will continue as planned, and TerraPower expects “minimal disruption” to the current projected start-of-construction date.
HALEU fuel is enriched to between 5% and 20% uranium-235, and is the fuel type which will fuel most of the next-generation reactor designs. The DOE has projected a national need for more than 40 tonnes of HALEU before the end of the decade to support the current administration’s goal of 100% clean electricity by 2035.
Funding the Construction
Gates helped found TerraPower in 2006 and has been the company’s chairman. TerraPower’s goal is to provide more affordable, secure, and environmentally friendly nuclear energy globally. The plant is expected to cost $4 billion. To date, $1.6 billion has been appropriated by Congress, and private funding of $830 has been raised by TerraPower.
Wyoming US Senator John Barrasso responded to the announcement saying the US ” must reestablish itself as the global leader in nuclear energy. Instead of relying on our adversaries like Russia for uranium, the United States must produce its own supply of advanced nuclear fuel.” He said he has sent a letter to Energy and Natural Resources Chairman Joe Manchin requesting an oversight hearing early next year to ensure that DOE is “working aggressively” to make HALEU available for the USA’s first advanced reactors. He also said he has written to Secretary of Energy Jennifer Granholm today “blasting DOE for not moving fast enough to ensure a domestic supply of HALEU”.
Take Away
The Natrium project by Bill Gate’s company, with support from US tax dollars and Warren Buffett, is being constructed as a test. One thing the test bore out is that securing a reliable fuel supply needs a good deal more work.
Natrium plants are smaller and use current technology. These plants are expected to be built faster and cheaper than a traditional large-scale nuclear power plant. When first announced last year, Gates and Buffett said that once successfully demonstrated, the plant could be quickly expanded or replicated elsewhere.
DOE program supports critical domestic clean energy & national security priorities
Pending membership in DOE HALEU Consortium to support fuel for next generation advanced nuclear reactors
LAKEWOOD, Colo., Dec. 16, 2022 /CNW/ – Energy Fuels Inc. (NYSE American: UUUU) (TSX: EFR) (“Energy Fuels” or the “Company”), a leading U.S. producer of uranium and rare earth elements (“REE“), today announced that it has been awarded a contract to sell $18.5 million of natural uranium concentrates (“U3O8“) to the U.S. government for the establishment of a strategic uranium reserve (the “Uranium Reserve“). The U.S. National Nuclear Security Administration (“NNSA“), an office within the U.S. Department of Energy (“DOE“), is the agency tasked with purchasing domestic U3O8 and conversion services for the Uranium Reserve. The Uranium Reserve is intended to be a backup source of supply for domestic nuclear power plants in the event of a significant market disruption. Additionally, the Company announced its application for membership in the DOE’s newly created HALEU Consortium.
Uranium Reserve Award:
Energy Fuels expects to complete the sale of uranium for the Uranium Reserve to NNSA during Q1-2023 and realize total gross proceeds of $18.5 million. The U3O8 the Company expects to sell to the U.S. government is currently held in the Company’s inventory at the Metropolis Works Conversion Facility, located in Metropolis, Illinois. The sale does not involve the physical movement of material, so the sale and transfer can be completed quickly.
Mark S. Chalmers, President and CEO of Energy Fuels stated: “Energy Fuels is pleased to contribute to U.S. energy security by supplying U.S.-origin uranium to the U.S. uranium reserve. Russia’s invasion of Ukraine has highlighted America’s troubling dependence on Russia and its allies for our nuclear fuel and uranium supply, and the need for the U.S. to rebuild its uranium and nuclear fuel capabilities. Today, nuclear energy provides the U.S. with roughly 20% of all electricity, and 50% of our clean, carbon-free electricity. U.S. and European nuclear industries are actively working to shift away from Russian uranium supply, but the process will be difficult and lengthy. The U.S. can rely on supply from allies like Canada, Australia and others for a large proportion of our uranium and nuclear fuel supply, but we must also restore our own capabilities. For the past several years, U.S. uranium production has been near-zero and our only uranium conversion facility has been shut-down. The Uranium Reserve is a small, but important, step toward resolving this untenable situation.”
HALEU Consortium:
On December 12, 2022, Energy Fuels also applied for membership in the DOE’s newly created HALEU Consortium. The HALEU Consortium is a program managed by the DOE’s office of Nuclear Energy (“NE“) intended to help create a secure domestic supply of high-assay, low-enriched uranium (“HALEU“) used by many of the next generation of advanced nuclear reactor technologies. HALEU enables many advanced reactor designs to be smaller and more efficient than traditional reactors. The uranium used in traditional nuclear reactors is enriched to roughly 3% – 5% of the fissionable isotope, uranium-235 (“U-235“). HALEU is enriched to between 5% and 20% U-235. Today, only Russian companies are able to supply HALEU, which is causing delays in the development of advanced reactors. For example, TerraPower recently announced a delay in building its first Natrium reactor in Wyoming. TerraPower is a high-profile next generation advanced reactor developer funded by Bill Gates. TerraPower specifically attributed the delay to the lack of availability of HALEU outside of Russia.
As the leading producer of U3O8 in the U.S., and the owner and operator of the only conventional uranium mill in the U.S., Energy Fuels believes it can play an important role in advising the DOE and teaming with other companies for this critical program. Furthermore, Energy Fuels is pursuing other DOE priorities related to uranium production, including rare earth element and medical isotope production.
Mr. Chalmers continued: “Energy Fuels is increasingly recognized by the U.S. government and other market participants as indispensable to weaning the U.S. off of Russian uranium supply, and as a solid partner in other important priorities. Our White Mesa Mill is critical and unique domestic infrastructure, with licenses, expertise and capabilities found nowhere else in the U.S., that are needed to produce uranium, and many other critical minerals and materials. We stand ready to play a critical role in restoring America’s uranium, rare earths, and other critical material capabilities, while reducing our troubling dependence on Russia and China.”
About Energy Fuels: Energy Fuels is a leading U.S.-based uranium mining company, supplying U3O8 to major nuclear utilities. The Company also produces vanadium from certain of its projects, as market conditions warrant, mixed rare earth element carbonate (“RE Carbonate“) from uranium-bearing monazite ores and is ramping up to full commercial-scale production of separated rare earth oxides. Its corporate offices are in Lakewood, Colorado near Denver, and all its assets and employees are in the United States. Energy Fuels holds two of America’s key uranium production centers: the White Mesa Mill in Utah and the Nichols Ranch ISR Project in Wyoming. The White Mesa Mill is the only conventional uranium mill operating in the U.S. today, has a licensed capacity of over 8 million pounds of U3O8 per year, and has the ability to produce vanadium when market conditions warrant, as well as RE Carbonate from various uranium-bearing ores. The Nichols Ranch ISR Project is currently on standby and has a licensed capacity of 2 million pounds of U3O8 per year. In addition to the above production facilities, Energy Fuels also has one of the largest S-K 1300 and NI 43-101 compliant uranium resource portfolios in the U.S. and several uranium and uranium/vanadium mining projects on standby and in various stages of permitting and development. The primary trading market for Energy Fuels’ common shares is the NYSE American under the trading symbol “UUUU,” and the Company’s common shares are also listed on the Toronto Stock Exchange under the trading symbol “EFR.” Energy Fuels’ website is www.energyfuels.com.
Cautionary Note Regarding Forward-Looking Statements: This news release contains certain “Forward Looking Information” and “Forward Looking Statements” within the meaning of applicable United States and Canadian securities legislation, which may include, but are not limited to, statements with respect to: any expectation that the Company will complete the contemplated sale of uranium to the DOE in Q1-2023 or at all; any expectation that the Company will maintain its position as a leading uranium company in the United States; any expectation that the Company will be admitted as a member of the HALEU Consortium or that the Company can play an important role in this critical program; any expectation that the Mill will be successful in producing RE Carbonate and/or separated rare earth element oxides on a full-scale commercial basis or at all; any expectation that the Company will successfully produce radioisotopes to be used for the production of medical isotopes on a commercial basis or at all; any expectation that the Company is increasingly being recognized by the U.S. government and other market participants as an indispensable party in efforts to wean the U.S. off of Russian uranium supply, and a partner in other important priorities; and any expectation that the Company stands ready to play a critical role in restoring America’s uranium, rare earths and other critical material capabilities, while reducing America’s dependence on Russia and China. Generally, these forward-looking statements can be identified by the use of forward-looking terminology such as “plans,” “expects,” “does not expect,” “is expected,” “is likely,” “budgets,” “scheduled,” “estimates,” “forecasts,” “intends,” “anticipates,” “does not anticipate,” or “believes,” or variations of such words and phrases, or state that certain actions, events or results “may,” “could,” “would,” “might” or “will be taken,” “occur,” “be achieved” or “have the potential to.” All statements, other than statements of historical fact, herein are considered to be forward-looking statements. Forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements express or implied by the forward-looking statements. Factors that could cause actual results to differ materially from those anticipated in these forward-looking statements include risks associated with: commodity prices and price fluctuations; processing and mining difficulties, upsets and delays; permitting and licensing requirements and delays; changes to regulatory requirements; legal challenges; the availability of feed sources for the Mill; competition from other producers; public opinion; government and political actions; available supplies of monazite sands; the ability of the Mill to produce RE Carbonate to meet commercial specifications on a commercial scale at acceptable costs; the ability of the Mill to separate rare earth oxides to meet commercial specifications on a commercial scale at acceptable costs; market factors, including future demand for rare earth elements; the ability of the Mill to be able to separate radium or other radioisotopes at reasonable costs or at all; market prices and demand for medical isotopes; and the other factors described under the caption “Risk Factors” in the Company’s most recently filed Annual Report on Form 10-K, which is available for review on EDGAR at www.sec.gov/edgar.shtml, on SEDAR at www.sedar.com, and on the Company’s website at www.energyfuels.com. Forward-looking statements contained herein are made as of the date of this news release, and the Company disclaims, other than as required by law, any obligation to update any forward-looking statements whether as a result of new information, results, future events, circumstances, or if management’s estimates or opinions should change, or otherwise. There can be no assurance that forward-looking statements will prove to be accurate, as actual results and future events could differ materially from those anticipated in such statements. Accordingly, the reader is cautioned not to place undue reliance on forward-looking statements. The Company assumes no obligation to update the information in this communication, except as otherwise required by law.
SOURCE Energy Fuels Inc.
For further information: Investor Inquiries: Energy Fuels Inc., Curtis Moore, VP – Marketing and Corporate Development, (303) 974-2140 or Toll free: (888) 864-2125, investorinfo@energyfuels.com, www.energyfuels.com
