Suncor Stocks Surge after Pump-Up in Buyback Program

Suncor Energy Inc. shares rose to an almost 16-year high after the oil-sands producer accelerated plans to ramp up share buybacks, marking a win for activist investor Elliott Investment Management LP.   

Canada’s second-largest oil producer by market value said it boosted spending on share repurchases to 75 percent of its free funds flow this quarter. Buybacks will ramp up to essentially all of its free funds when it cuts net debt to C$8 billion ($5.9 billion), discarding its previous target of C$5 billion. Suncor has just under C$9 billion in debt currently.

The stock rose as much as 3.2 percent to hit C$56.30 in Toronto, the highest intraday price since September 2008. The shares are up about 32 percent this year, the fourth-best performance in the 41-company S&P/TSX Energy Index. 

Suncor’s gains mark a major turnaround for a company that was a laggard of the Canadian oil industry two years ago, beset by a string of worker deaths. The poor performance prompted activist investor Elliott to demand a major shakeup of the company and ultimately resulted in the appointment of former Exxon Mobil Corp. executive Rich Kruger as CEO last year.

When Elliott launched its campaign two years ago, it held a 3.4 percent economic interest in Suncor. The activist now holds a 4.1 percent direct stake that makes it the company’s fourth-largest investor, according to data compiled by Bloomberg.

Elliott has increased its stake in Suncor because of the positive results on its performance and safety and still believes the stock has the potential for significant gain, according to a person familiar with the matter.

The shares are up about 33 percent since Elliott revealed its stake. That’s in line with the performance of rival Canadian Natural Resources Ltd. over that period and tops that of Cenovus Energy Inc.

Suncor has halted worker fatalities since the appointment of Kruger, who previously led Exxon’s Imperial Oil Ltd. Canadian division and came out of retirement to take the CEO position. He also has cut jobs to trim expenses and struck a C$1.47 billion deal to buy TotalEnergies SE’s stake in an oil-sands mine to secure more bitumen supplies for the upgraders at its Base Plant.

Kruger said Tuesday that Suncor expects to reach its new debt target — which reflects the company’s confidence in its momentum — by the middle of next year, or possibly by the end of this year. The company also announced that it would add C$3.3 billion to free funds flow by 2026 and would lower its breakeven oil price level by $10 a barrel — to $43 a barrel — in the same period.   

Source link

#Suncor #Stocks #Surge #PumpUp #Buyback #Program

Trump VP prospect Doug Burgum and GOP oil baron Harold Hamm are allies in business and politics

Republican presidential candidate and former President Donald Trump shakes hands with North Dakota Gov. Doug Burgum as Vivek Ramaswamy, left, watches at a campaign rally at The Margate Resort in Laconia, New Hampshire, Jan. 22, 2024.

Jabin Botsford | The Washington Post | Getty Images

If former President Donald Trump taps North Dakota Gov. Doug Burgum to be his running mate, the biggest beneficiary of the partnership could be someone else entirely: Harold Hamm, the billionaire founder and executive chairman of shale oil drilling giant Continental Resources, who could end up with two powerful allies in a Trump White House.

Burgum’s ties to Hamm and the shale oil drilling giant he founded are complex. Continental is the largest oil and gas leaseholder in North Dakota, where oil and gas is the biggest industry by revenue.

The two men also have a friendship outside of business: Burgum recently contributed a rave review blurb to Hamm’s new memoir. And during his 2023 state of the state address, Burgum compared Hamm favorably to President Theodore Roosevelt, describing Hamm as a person “whose grit, resilience, hard work and determination has changed North Dakota and our nation.”

But Burgum has an even more personal link to Continental: Burgum’s family leases 200 acres of farmland in Williams County to the energy giant for the company to pump oil and gas, according to previously unreported business records and a federal financial disclosure report.

Burgum has made up to $50,000 in royalties since late 2022, while he’s been governor, from the deal with Continental Resources, according to his financial disclosure, details of which have not been reported.

Experts told CNBC that Burgum and his family business likely made thousands more from the agreement with Continental Resources since signing a contract with the company in 2009.

This link between Burgum and Continental highlights one of the potential risks for Trump of selecting a running mate who has lived most of his adult life in private.

Burgum has never been subjected to the kind of scrutiny that someone like Sen. Marco Rubio, R-Fla., has undergone and from which Rubio has emerged politically intact.

Burgum endorsed Trump in January, a month after he dropped out of the Republican primary for president. Since then, he has become an advisor to Trump on energy policy and joined a shortlist of contenders to be the former president’s running mate.

Hamm, meanwhile, is one of Trump’s biggest supporters in the industry. Burgum, Hamm and other industry advocates were reportedly at a meeting at Trump’s private Florida club, Mar-a-Lago, where the former president called on oil and gas executives to donate $1 billion to his campaign in exchange for his plan to roll back environmental regulations.

Hamm is co-hosting an event for Trump that’s sponsored by the former president’s political action committee, Make America Great Again Inc., on May 22, according to an invitation.

Continental Resources donated $1 million to the super PAC in April, according to Federal Election Commission records. Hamm gave $614,000 to the Trump 47 Committee in March.

Burgum’s oil deal with Continental

The original agreement between the Burgum Farm Partnership and Continental Resources was signed by Bradley Burgum, the governor’s late brother, according to a land lease reviewed by CNBC.

Burgum spokesman Mike Nowatzki told CNBC the contract was drawn up years before the governor was sworn into office in 2017.

“North Dakota is a leading energy producer, including the No. 3 oil producing state. Tens of thousands of families and mineral owners have similar arrangements,” Nowatzki said. “As the publicly available disclosures show: The cited agreement began many years before he became governor.”

Nowatzki did not answer specific questions about the deal, Burgum’s role with the family business or his relationship with Hamm.

A spokeswoman for both Continental Resources and Hamm did not respond to a request for comment. A spokesman for the Trump campaign did not respond to a request for comment.

CNBC obtained Burgum’s personal financial disclosure by a request to the Federal Election Commission. His business records were acquired through the North Dakota secretary of state’s office.

Data from North Dakota’s Minerals Department shows that the locations of the oil and gas wells matches the coordinates of Burgum’s family farm on his business records. The state’s data does not identify Burgum’s address, but the area where the farm and seven of Continental Resources wells are located is within a small township named Brooklyn.

All seven wells have been active since 2011, just two years after Burgum’s family signed an agreement with Continental Resources. The wells produced over 5,000 barrels of oil and thousands of cubic feet in natural gas in March alone, according to the latest data from Drilling Edge. It’s unclear how many of the seven wells are located directly on the Burgum property.

Burgum was elected governor in 2016 and reelected to a second term in 2020. He’s not running for reelection in 2024.

The Burgum Farm Partnership LLP, which oversees the family farm land in Williams County and Cass County, is worth between $500,001 and $1 million, according to the financial disclosure.

Doug Burgum is a managing partner of the Burgum Farm Partnership, and he signed the businesses’ latest annual report in March. Burgum’s financial disclosure says the governor is a non-managing member and the company is a “family investment” limited liability partnership.

The company’s annual report that was filed to the secretary of state’s office in April lists Burgum, his late brother’s two children, his sister, Barbara, and his own three adult children as managing partners of the family business.

The oil and gas land deal says Continental Resources provides the Burgum Farm Partnership 19% of the proceeds from the sales of oil and gas Continental sold after it is pumped from the Burgum property, according to the contract and experts who reviewed the records.

“The greater benefit is that the Burgum Farm Partnership does not have to invest any money to drill the wells, collect the hydrocarbons (no pipes, no tanks, no roads),” Edward Hirs, an energy fellow at the University of Houston, said in an email after reviewing the contract.

The royalty payments arrive in monthly and quarterly installments, according to the agreement.

The sun sets behind a pumpjack during a gusty night in Fort Stockton, Texas, March 24, 2024.

Brandon Bell | Getty Images

Experts note that landholders leasing their property to oil and gas companies can make thousands of dollars more beyond the royalties in bonuses and other payments.

“The company will usually pay the land owner a ‘bonus’ for signing the lease (usually hundreds or thousands of dollars per acre, depending on how hot the market might be),” said Jack Balagia, an adjunct professor at the University of Texas and former general counsel for Exxon Mobil. 

Ryan Kellogg, a professor at the University of Chicago who reviewed the contract, said the document does not disclose details of a bonus to the Burgum farm company, except to give a low range of how much was paid.

“The up-front bonus payment is not disclosed,” Kellogg said. “It’s just listed as ‘$10 and more’ where the ‘more’ is potentially significant. Bonuses are almost never disclosed in leases.”

The Burgum contract also says that the family business made money from Continental Resources through one initial down payment called “paid-up” on the lease, with no details provided on how much Burgum and his family saw from that part of the agreement.

“By paid-up, [we mean] a lease where all cash for the term of the lease is paid upfront, and by a rental form, we mean one with a down payment and rental payments once a year after that,” said Ted Borrego, an adjunct professor at the University of Houston Law Center.

Burgum drilling contract raises questions

North Dakota Gov. Doug Burgum encourages voters to support Republican presidential candidate and former President Donald Trump during a campaign rally in the basement ballroom of The Margate Resort in Laconia, New Hampshire, Jan. 22, 2024.

Chip Somodevilla | Getty Images

Neither of Burgum’s two financial disclosures from his successful runs for governor reveal a land deal with Continental Resources. North Dakota requires candidates for state office to disclose only the names of businesses that do not act as their principal source of income. No other details are required to be disclosed.

Since Burgum first ran for governor in 2016, he’s disclosed to the North Dakota secretary of state’s office that he and his wife, Kathryn, have a financial interest in more than a dozen companies, including Burgum Farm Partnership.

But those three-page state records do not specify how much of a financial interest they have in these companies nor any money they make from those businesses. 

A candidate for president or Congress is required to disclose many more details, including a range of income from each of their assets during the previous 12 months.

Burgum’s federal disclosure report spans 26 pages and reveals scores of closely held LLCs, partnerships and assets. With Burgum’s net worth easily in the hundreds of millions, the Continental lease forms only a small part of his income streams.

Burgum and Trump aligned on energy

Ultimately, it may not matter to Trump whether Burgum has been fully vetted if the governor is the person he wants on his ticket.

For Trump, Burgum represents a key ally in the oil and gas business, as the former president looks to raise money from the industry’s executives.

Dan Eberhart, who runs oil and gas drilling company Canary, said a Trump/Burgum ticket could help to accomplish this.

“Choosing Burgum would bring more industry donors to Trump’s orbit,” Eberhart said in a recent interview.

“Nominating Burgum as VP would send a strong signal to the industry that we would have an important voice in a potential Trump administration,” he added.

President Donald Trump greets Harold Hamm after he was introduced by Hamm at the Shale Insight 2019 Conference in Pittsburgh, Oct. 23, 2019.

Leah Millis | Reuters

Government ethics watchdogs have also started to take notice of the relationship between Trump, Hamm, Burgum and others linked to the oil and gas industry.

“The fact that Mr. Burgum has an income producing, oil and gas lease arrangement with Continental Resources itself raises its own concerns, since Continental Resources’ executive chairman, Harold Hamm, recently participated with other oil and gas executives and Mr. Burgum in the Mar-a-Lago meeting Mr. Trump held last month seeking $1 billion in fundraising from those in attendance,” said Canter.

“Under these circumstances, Mr. Burgum seems to be uniquely positioned to benefit himself both financially and politically depending on what he is able to bring to the table that would serve the respective interests of Trump and Hamm,” she said.

Hamm’s company has had extensive business in North Dakota for over a decade, and the state is ranked in the top three states to produce oil.

In 2022, Hamm announced Continental Resources was investing $250 million into a pipeline that spanned 2,000 miles to capture carbon dioxide and pump it underground for storage in North Dakota. Last year, Hamm donated $50 million to a planned library in North Dakota honoring Roosevelt.

Hamm’s alliance with Burgum preceded a donation Continental Resources made to a PAC that backed the North Dakota governor when he ran for president. The company gave $250,000 to the pro-Burgum Best of America PAC in July, according to FEC filings.

Burgum’s gubernatorial campaign has regularly been backed by other executives in the oil and gas industry, according to data from the nonpartisan OpenSecrets.

Burgum’s successful campaign for governor in 2020 received more than $35,000 from those in the oil and gas industry. That amount is second only to the more than $1 million Burgum put into his campaign.

Correction: This story has been updated to reflect the correct spelling of Make America Great Again Inc. and the correct spelling of Ryan Kellogg’s name.

Source link

#Trump #prospect #Doug #Burgum #GOP #oil #baron #Harold #Hamm #allies #business #politics

The Bird-Flu Host We Should Worry About


Of all the creatures stricken with this new and terrible H5N1 flu—the foxes, the bears, the eagles, ducks, chickens, and many other birds—dairy cattle are some of the most intimate with us. In the United States, more than 9 million milk cows live on farms, where people muck their manure, help birth their calves, tend their sick, and milk them daily. That kind of proximity is exactly what gives a virus countless opportunities to encounter humans—and then evolve from an animals-only virus into one that troubles people too.

But as unnerving as H5N1’s current spread in cows might be, “I would be a whole lot more concerned if this was an event in pigs,” Richard Webby, the director of the World Health Organization Collaborating Centre for Studies on the Ecology of Influenza in Animals and Birds, told me. Like cows, pigs share plenty of spaces with us. They also have a nasty track record with flu: Swine airways are evolutionary playgrounds where bird-loving flu viruses can convert—and have converted—into ones that prefer to infect us. A flu virus that jumped from swine to humans, for instance, catalyzed the 2009 H1N1 pandemic. If there’s a list of riskiest animals for an avian flu to infiltrate, “pigs are clearly at the top,” Webby said.

To successfully spread in a new species, a flu virus must infiltrate that creature’s cells, reproduce inside of them, and then make it to the next host. This H5N1 has managed that feat in several animals, but so far, “we’re actually still dealing with a very avian virus,” Michelle Wille, a virologist at the University of Melbourne, told me. For the virus to spread widely in humans, scientists think that it would need to pick up several new traits; so far, they’ve detected only one such modification, which has boosted the virus’s ability to replicate inside mammalian cells.

In particular, the virus does not seem to have acquired what Webby considers the most crucial modification, one that would help it more efficiently enter human-airway cells in the first place. To do that, H5N1 would need to adjust its ability to latch on to particular sugars on cell surfaces, which effectively serve as locks to the cell’s interior. For decades, though, the virus has preferred the version of those sugars that’s most commonly found in the gastrointestinal tract of birds, and still seems to. Experts would really start to worry, Webby said, if it started glomming very tightly instead onto the ones most commonly found in human airways.

That said, the difference between those sugars is architecturally quite small. And although scientists might colloquially call some bird receptors and others human receptors, mammals can produce bird receptors, and vice versa. (Humans, for instance, have bird receptors in their eyes, which likely explains why the farm worker who appears to have caught H5N1 from a dairy cow developed only conjunctivitis.) The right animal host could encourage the virus to switch its preference from birds to humans—and pigs fit that bill. They just so happen to harbor both bird receptors and human receptors in their respiratory tract, giving the flu viruses that infect them plenty of opportunity to transform.

Just by hanging out in pigs for a while, H5N1 could enhance its ability to enter our cells. Or, perhaps even more concerning, it could encounter a flu that had already evolved to infect humans, and swaps bits of its genome with that virus. Pigs catch our viruses all the time. And should one of those pathogens hybridize with this H5N1, becoming human-adapted enough to spread among people but still avian-adapted enough to elude our immune system, a large-scale outbreak could begin. In the late 1970s, after an H1N1 avian-flu virus hopped from wild waterfowl into Europe’s pig population, it took just a few years to start infecting people in Europe and Asia. Eventually, that same virus helped birth 2009’s pandemic swine flu.

Right now flu surveillance among swine needs to be dialed up, experts told me; protections for farm workers who handle the animals should ramp up too. Seema Lakdawala, a virologist at Emory University, told me that she’d also like to see cow’s milk on farms better contained and more quickly heat-treated, so that other animals in the vicinity won’t be exposed to the liquid in its raw form. (Several farm cats, for instance, appear to have caught H5N1 by drinking raw milk on farms.)

At this point, any worry about the virus evolving dramatically in pigs is still theoretical. H5N1 hasn’t yet been detected in farm pigs, and experimental infections have found that the virus, although capable of infecting and replicating in swine, doesn’t seem to transmit easily among them. Even if that were to change, pigs may not end up being the ideal venue for the many other genetic gymnastics that would help this virus adapt to us.

That said, “we don’t fully understand all of the mutations or genetic requirements” needed to convert an avian virus, Louise Moncla, a virologist at the University of Pennsylvania, told me. Viruses sometimes surprise us: 2009’s H1N1 flu, for instance, caused a pandemic without making the genetic change that seems to have helped this new H5N1 along. Which means it’s not a complete comfort that H5N1 isn’t spreading in pigs yet—especially when so many cows are getting sick now.

Scientists know relatively little about flu in cows. Although cattle have been known to catch certain kinds of flu before, the current outbreak is the first time a type-A influenza, the group that H5N1 belongs to, has been detected in their kind. Researchers are only now starting to understand the animals’ susceptibility to these pathogens, and a recent preprint study, which Webby contributed to, revealed human-esque flu receptors in several parts of the cow body, some of which have bird receptors too—a finding that suggests that the risk posed by continued spread in cows is higher than once thought. Webby, for one, isn’t panicking yet, and he told me that the results mainly help explain why cow udders, now confirmed to be full of bird receptors, have turned out to be such great homes for H5N1. And because cows are likely spreading the virus to one another via milking equipment—basically a free ride for the pathogen—there may be little pressure for the virus to change its MO.

The bigger risk is simpler. “The things that make me the most nervous are the species that we regularly interact with all the time,” Moncla told me. The more cows catch the virus, the more exposure there will be for us, giving the virus more chances to explore and potentially adapt to our respiratory tract. Commercial milking is a messy affair: The processing machinery sprays and mists the liquid all about. Lakdawala imagines that milking an infected cow without protective equipment could be “like me squirting 10,000 or 100,000 viral particles into someone’s nose.” Just one of those particles needs to carry the right set of genetic changes for this flu to become a human one.

Katherine J. Wu is a staff writer at The Atlantic.




Source link

#BirdFlu #Host #Worry

Malcy’s Blog: Oil price, Chariot, Union Jack, Serica,

WTI (June) $80.06 +83c, Brent (July) $83.98 +71c, Diff -$12c.

USNG (June) $2.63 +13c, UKNG (June) 75.15p +1.9p, TTF (June) €31.325 +€0.59.

Oil price

Oil completed a reasonable week, WTI was up $1.80 and Brent $1.19 and with the former expiring tomorrow night the market is contemplating any effects of the loss of the Iranian President and Foreign Minister in a helicopter crash at the weekend.

Elsewhere economic data in China was a bit better than expected as was the Government support, more likely the Ukraine hitting Russian refineries had more effect.


Chariot  announce the spud of the OBA-1 well on the Dartois prospect in the Loukos Onshore licence onshore Morocco (Chariot, Operator 75%, ONHYM, 25%)

·      Dartois target has Best Estimate recoverable prospective resources of 12 Bcf

·      Independent prospect targeting a different trapping style to the Gaufrette prospect drilled by the RZK-1 well

·      Success could potentially unlock a trend of prospects with combined Best Estimate recoverable prospective resources of 20 Bcf

·      Results will be announced on completion of drilling

Duncan Wallace, Technical Director of Chariot commented:

“We are pleased to be underway with our second well in this drilling campaign, having spud the OBA-1 well within short order of completing operations at Gaufrette. We are now testing an independent prospect at Dartois, which is in a different reservoir fairway and along trend from an existing gas discovery, and we look forward to providing an update on the results in due course.”

Chariot continues to offer a Moroccan experience for shareholders who should benefit from the high natural gas prices and generous fiscal terms on offer in country. They have this low cost, shallow programme which if successful will come onstream quickly and profitably, they also have the subsequent development at Anchois which should deliver a substantial prize. All in all Chariot offers a combination of upside designed to work across the board for investors.

Union Jack Oil

Union Jack has announced its audited results for the year ended 31 December 2023.

Operational Highlights

•      Flagship Wressle project continues to deliver following a workover, installation of a down hole pump and other significant site upgrades

•      Wressle Competent Person’s Report upgrades Reserves by 263%

•      Application submitted for the drilling of two back-to-back Wressle development wells and the Penistone Flags gas monetisation

•      Positive Biscathorpe planning appeal decision

•      Sale of 2.5% interest in offshore North Sea Claymore Area Royalty

•      Commencement of acquisition of United States Mineral Royalties and drilling activity in Oklahoma

•      Planned drilling and development during 2024 to encompass both sides of the Atlantic

•      Post Balance Sheet date, the Andrews 1-17 Well, in Oklahoma, USA, has been declared a commercial discovery

Financial Highlights

•      Gross profit of £3,298,844 (2022: £5,100,479)

•      Net profit of £859,089 (2022: £3,606,624)

•      Basic earnings per share 0.79 pence (2022: 3.20 pence)

•      Oil revenues £5,065,679 (2022: £8,507,050)

•      The Company continues to be debt free

•      Post Balance Sheet date, a dividend of 0.25 pence per ordinary share was declared, payable on 26 July 2024

David Bramhill, Executive Chairman, commented:

“The Board’s confidence has once again been supported by the Company’s solid 2023 financial results, confirming its resilience, both financially and operationally.

“In the UK, Union Jack will remain focused on the development of its flagship project, Wressle, where the Operator and joint venture partners have ambitious near-term appraisal and development programmes planned. The Board is of the opinion that, within the Wressle development, there remains significant material upside which will support the Company with revenues for at least another decade.

“I also look forward to progress at West Newton. Encouragingly, the results from this key project to date signal a potentially highly valuable onshore project with resources comparable to those usually reported offshore. A significant onshore domestic gas resource, as indicated at West Newton, has the potential to become an important transition fuel in helping the UK achieve its 2050 Net Zero target.

“Union Jack’s initial successes in the USA, in just a few months, highlight the ease of entry and ability to execute business in that country, justifying the Board’s decision to seek further growth opportunities internationally to bolster its flagship production and appraisal assets in the United Kingdom.

“Following the Company’s USA entry, involving both the Andrews 1-17 discovery well and the financial attractions of Union Jack’s expanding Mineral Royalties portfolio, I believe that the Board’s optimism and our further expansion in the USA, executed alongside a proactive drilling campaign, will deliver material rewards in due course.

“Our appetite for additional growth opportunities has been whetted by our recent positive experience in the USA and discussions are at an advanced stage with Reach in respect of materially expanding our activities over the coming months and beyond.

“I am confident that the significant increase in drilling, appraisal and development activity now planned in the pursuit of growth from our balanced UK and USA portfolios has the potential for significant value creation for shareholders. We believe our heightened activity and the expected additional news-flow generated, combined with effective investor engagement on both sides of the Atlantic, will continue to attract the ongoing support of our existing shareholders and the attention of new investors, broadening the appeal of the Company to a wider audience.

“Overall, Union Jack is in sound financial health with a robust Balance Sheet and continues to be debt free.

“The future of Union Jack remains bright.”

Full year numbers from Union Jack with nothing we dont know already, Wressle continues to deliver and with two wells to come and production and reserves rising the backbone of the company continues to flourish. 

The company has started a programme in the USA and its first well has already come in, more is planned and the company is planning to ‘materially increase’ its presence out there. If nothing else it proves that such an exploration move can prove mighty rewarding and UJO are succeeding ‘on both sides of the Atlantic’.

With cash being thrown off and the company being debt free it has just announced 0.25p per share in the way of a dividend and a great deal to come all across the portfolio in the next year or two. The shares are far too low and the longer they carry on like this the more attractive they become. 

Serica Energy

Serica has announced that it has received final approval from the NSTA to develop the 100% owned and operated Belinda field. The field will be tied back to the Triton FPSO following the drilling of the development well which is scheduled to take place in the first half of 2025. The Belinda well is the 5th well in Serica’s Triton area drilling campaign, which commenced in April this year using the COSLInnovator drilling rig. All these wells are designed to enhance production via the Triton FPSO.

Proven and probable reserves in the Belinda field are estimated at about 5 million barrels of oil equivalent (80% oil). Production is scheduled to commence in 1Q2026 following the tie-back work to the Triton FPSO.

David Latin, Chairman and Interim CEO of Serica commented:

We are delighted to have received approval to develop Belinda. This will build on our strong track record of delivering growth and adding value through investment in our assets. We have further potential projects in our portfolio which we continue to assess, including the possible re-development of the Kyle field, which could, like Belinda, be another low emissions tie-back candidate to the Triton FPSO. We look to the UK government to implement tax and licensing arrangements that support investments like Belinda, thereby creating UK jobs, earnings and tax receipts instead of increasing reliance on energy imports.”

Another smart move from Serica, a useful add to the production at extremely low cost and handy closeness to the Triton FPSO which makes the timescale even better. The low emissions tick another box and of course this is a sensible way of carrying on and also putting the Government on notice…

Nostra Terra Oil & Gas

Nostra Terra has announced changes to its board of directors with effect from today.

Matt Lofgran, Nostra Terra’s long-serving CEO, has stepped down from the role to concentrate on other interests. Matt has led the Company since 2009 and he will continue to provide support to the Company as an advisor for a 6 month transition period. 

Paul Welch, currently a non-executive director of the Company, will move to the role of CEO with immediate effect. Paul has extensive experience of working in the Texas oil and gas industry. Overall, he has more than 30 years of industry experience, having worked for Shell Oil Company for 15 years and for several large independents, including Hunt Oil Company and Pioneer Natural Resources. Paul was CEO of AIM-listed explorer Chariot Oil and Gas (2009-2012) and subsequently of Sea Dragon Energy and SDX Energy, the latter until 2019. He was appointed as CEO of Cosimo Holding Ltd in 2019. Paul was also appointed Chairman of Main Market ACP Energy PLC in 2022. He graduated from the Colorado School of Mines with bachelor’s and master’s degrees in petroleum engineering. He also holds an MBA in Finance from Southern Methodist University (SMU) in Dallas, Texas. 

Steve Staley, Nostra Terra’s Chairman, said: 

“On behalf of the Board I would like to thank Matt for his long service to Nostra Terra and am glad that he will continue to provide support to the Company as we move forward.

I would also like to welcome Paul to the role of CEO and look forward to working with him in that new capacity as we embark on the next phase of growth.”

I mention this story only briefly as Matt Lofgran has been a dedicated follower of the sector for many years and I wish him well.

Also readers will remember Paul Welch who has been away from our patch for a while since leaving SDX in 2019, it will be interesting to see what becomes of NTOG under his leadership and indeed of Steve Staley..

And finally…

Well whatever the Gooners did wasn’t going to be enough as the Noisy Neighbours comfortably beat the Hammers despite a wonder goal from Kudus.

And Xander Schauffele won the PGA at Valhalla.

With Lando Norris chasing him down for another GP Max had a close run thing, this time he held on…

Source link

#Malcys #Blog #Oil #price #Chariot #Union #Jack #Serica

Iraq Stops Diesel Import Deals as Refinery Upgrades Boost Output

Iraq halted contracts to import diesel after the upgrade of some refineries helped bolster local output, putting the country on track for fuel self sufficiency. 

The country wound down purchase deals at the end of last year and hasn’t bought the fuel under long-term contracts so far in 2024, according to traders involved in the market. It has bought three diesel cargoes this year, according to market data provider Vortexa, but traders said those were spot shipments.

Iraq, however, is still buying gasoline under term deals, according to the traders who asked not to be identified because the information isn’t public. It’s targeting eliminating imports of the motor fuel as early as this year. The country is refurbishing refineries that were damaged during two decades of war, with the Al-Shamal plant restarting in 2024, and others to follow, Hamid Younis, deputy oil minister for refining affairs, said in February.

A spokesman for the oil ministry couldn’t immediately be reached for comment outside normal business hours. 

Iraq imported 2.83 million barrels of diesel last year, or about 7,800 barrels a day, according to Vortexa. It also tendered to buy about 55,000 barrels a day of gasoline on average through the end of this year, according to traders. That’s up from about 43,000 barrels of seaborne gasoline supplied daily on average last year, according to Vortexa. 

Baghdad is buying gasoline from trading units of Saudi Aramco, Reliance Industries Ltd. and Oman’s state energy company OQ, among others, according to traders and data from ship tracking firm Vortexa. Those companies are supplying under long-term contracts that Iraq continued this year, the traders said.

The country has a designed refining capacity is 1.26 million barrels a day, though actual processing is lower. 

Iraq is the second-largest crude oil producer in the Organization of Petroleum Exporting Countries, behind Saudi Arabia. Iraq’s oil output has been in focus in recent months as the country struggles to meet a limit pledged to the OPEC+ group that includes allied countries like Russia. The amount of crude the country actually refines along with its exports are some of the main factors used to assess Iraq’s production.

Source link

#Iraq #Stops #Diesel #Import #Deals #Refinery #Upgrades #Boost #Output

Wind Turbine Makers Halt Race for Size to Focus on Cost, Delivery – Canadian Energy News, Top Headlines, Commentaries, Features & Events – EnergyNow


Image: REUTERS/Fabian Bimmer


  • After rapid increases in offshore wind turbine capacities, western suppliers are doubling down on existing models to drive supply chain efficiencies and reduce risks.

Another stumble for offshore wind in New York has highlighted shifting sentiment in the offshore wind turbine market.

Last month, New York State Energy Research and Development Authority (NYSERDA) chose not to sign offtake agreements with three planned offshore wind projects after designated turbine supplier GE Vernova decided to switch to a smaller turbine.

The 1.4 GW Attentive Energy One (TotalEnergies and Corio Generation), 1.3 GW Community Offshore Wind (RWE and National Grid) and 1.3 GW Excelsior Wind (Vineyard Offshore) projects were all awarded provisional contracts in a competitive auction in October 2023.

GE Vernova decided to switch from its latest 18 MW turbines to a 15.5/16.5 MW platform and this caused “technical and commercial complexities” which meant the project could not proceed under the awarded contract terms, a NYSERDA spokesperson said. Most U.S. offshore wind projects set to be built over the next few years plan to install turbines in the 11 to 15 MW range.

The developers declined to comment on their plans for the projects but they have indicated their continued interest in the New York market, NYSERDA said. Last month, New York announced plans for two more offshore wind solicitations this summer and in 2025.

After years of rapid increases in turbine capacities, GE Vernova’s decision reflects a trend by western original equipment manufacturers (OEMs) of introducing fewer new turbines and focusing on existing models for longer.

GE Vernova did not give a reason for its turbine switch, but it follows a difficult few years in which volatile costs and delivery challenges have delayed projects and severely dented the revenues of turbine suppliers.

The hunger for larger turbines led to some developers bidding projects based on turbines in early development stages, which can lead to offtake awards that are at higher risk of abandonment by awardees, a spokesperson for Danish turbine supplier Vestas told Reuters Events.

Vestas plans to focus on its 15 MW offshore wind turbine. This size is “best positioned to enable greater certainty of on-time, successful project delivery,” the spokesperson said.


Over the past decade, offshore wind developers in Europe and U.S. sought larger turbines to lower the cost of energy per kilowatt hour and win state-backed power contracts in competitive auctions.

The maximum size of new offshore wind turbines has risen from around 8 MW to around 15 MW amid an “arms race” among leading OEMs, said Signe Sorensen, Senior Research Analyst for the Americas at Aegir Insights.

CHART: Global average offshore wind turbine capacities

Global average offshore wind turbine capacities
Source: U.S. Department of Energy’s Offshore Wind Market Report, 2023 Edition (August 2023)

Intense competition squeezed the margins of turbine suppliers, while volatile global costs and logistics issues since the coronavirus pandemic have prompted offshore wind investors, developers and suppliers to reassess project risks.

On the U.S. East Coast, soaring costs and high interest rates prompted multiple cancellation of offshore wind contracts, delaying projects and curbing progress in building out new supply chain facilities.

Under financial pressure, western wind turbine suppliers are producing less turbine variants than Chinese rivals.

Since 2020, western suppliers have announced 29 new variants of onshore and offshore wind turbines, compared with over 426 from China, according to Endri Lico, principal analyst for Global Wind Technology and Supply Chain at Wood Mackenzie.

“The main reason is due to OEMs profitability pressure and their need to simplify their product portfolio,” Lico told Reuters Events.

Focusing on one model size could lead to reduced manufacturing costs thanks to standardization and industrialization, hence providing western OEMs and their component suppliers with the “clearest path to return to profitability,” Lico said.

A focus on more mature existing technology would enable the supply chain to “reap the quality and cost benefit of consistent volume and an industrialized wind turbine technology over many years,” the Vestas spokesperson said.

“Designing technology with the current supply chain in mind will result in cost predictability, shorter execution times, and industry scalability,” the spokesperson said.

Timing risk

Developers look to optimise power generation and in some cases smaller turbines can be more cost-competitive because they can produce more power at slower wind speeds, feature more mature technology, or are more readily available.

Developer Ocean Winds, a 50/50 joint venture owned by EDP Renewables and ENGIE, selects the best turbine size for a given project while also “considering time to market,” a company spokesperson said.

CHART: Global offshore wind turbine market share for operating projects (end of 2022)

Global offshore wind turbine market share for operating projects (end of 2022)
Source: U.S. Department of Energy’s Offshore Wind Market Report, 2023 Edition (August 2023)

Source: U.S. Department of Energy’s Offshore Wind Market Report, 2023 Edition (August 2023)

The pioneering 800 MW Vineyard Wind project in Massachusetts (Copenhagen Infrastructure Partners and Avangrid) is currently installing an earlier turbine model by GE Vernova designed to operate at 14.7 MW. Meanwhile, the 2.6 GW Coastal Virginia Offshore Wind project will install 14.7 MW Siemens Gamesa turbines (SGRE) in the next few years while Orsted has chosen the 11 MW Siemens Gamesa models for the 924 MW Sunrise Wind project in New York.

Vestas has received firm orders for 15 MW turbines from projects in Poland, Germany and the Netherlands and has signed conditional agreements to supply the turbine to Equinor’s Empire 1 and 2 projects in New York, the company said. Empire Wind 1 is slated to start producing power in 2026 but Empire Wind 2 has yet to secure an offtake agreement.

The standardisation of turbines at existing capacities would reduce the need for new larger vessels or significant upgrades to existing vessels.

A lack of U.S. wind turbine installation vessels remains a significant risk for project developers, exposing companies to global vessel supply markets and workarounds using barges to transport into and out of East Coast ports.

“The cost savings from the larger turbines are partially lost to increased vessel costs,” Sorensen noted.

Bidding year

A raft of U.S. offshore wind auctions this year will indicate whether developers will be happy to focus on 15 MW turbines in their mid-term growth plans.

Developers including Orsted, Avangrid, Vineyard Offshore, EDP and Engie bid to secure up to 6 GW of new offshore wind capacity in the latest power auctions by three New England states. Together, the East Coast states of New York, New Jersey, Massachusetts, Connecticut, Rhode Island, and Maryland plan to tender for around 16 GW of offshore wind power in 2024.

Lico expects GE Vernova, Vestas and Siemens Gamesa to focus on the 14 to 15 MW range until 2029-2030, when they could start launching bigger models.

“They will continue to co-exist with the next-generation turbine for some years (beginning of ‘30s) until we fully transition to 20 MW [plus],” he said.

Developers will continue to be tempted by larger turbines and lower costs, and ongoing innovations by Chinese suppliers could spur western suppliers to refocus towards larger units.

Indeed, Siemens Gamesa has announced plans to develop “the world’s largest offshore turbine generator” and has received funding from the European Union for a prototype model.

“If the competitors keep going bigger, GE Vernova and Vestas may have to as well, no matter their preferences,” Sorensen said.


Share This:

More News Articles

Source link

#Wind #Turbine #Makers #Halt #Race #Size #Focus #Cost #Delivery #Canadian #Energy #News #Top #Headlines #Commentaries #Features #Events #EnergyNow

Malcy’s Blog: Oil price, Arrow Exploration, Scirocco. And finally…

WTI (June) $78.63 +61c, Brent (July) $82.75 +37c, Diff -$4.12 -24c.

USNG (June) $2.42 -5c, UKNG (June) 71.65p -0.35p, TTF (June) €29.705 -€0.475.

Oil price

Oil is up a little today, the EIA inventory stats were better than forecast showing a crude draw of 2.508m barrels with small draws in gasoline and distillates. 

Arrow Exploration

Arrow has announced the spud of the Carrizales Norte B pad Horizontal Well 1 (“CNB HZ-1”) on the Tapir Block in the Llanos Basin of Colombia.

The CNB HZ-1 well will develop the Ubaque formation which has been successfully delineated by the CN Q1 2024 well program.  The CNB HZ-1 well is expected to be drilled to a true vertical depth of 8,400 feet and have a horizontal length of 1,800 feet.

Once CNB HZ-1 is on production in June, Arrow plans to drill a water disposal well and three more horizontal wells from the CNB pad.  Following further drilling during the second half of 2024 at Baquiano and Matteguafa, the Company expects to drill additional horizontal wells at the CNB pad towards the end of the year.

The Baquiano pad and road construction are now complete and the RCE-1 well has been successfully converted to a water disposal well.  The process of converting the CN-4 well to a water disposal well has begun, which is estimated to take up to four months.

Arrow is also in the initial planning stage for a 3D seismic program in the southern end of the Tapir block where the intent is to further develop the Icaco and Macoya Este leads.

The Company continues to have a strong balance sheet with US$12.4 million cash and no debt as of May 1, 2024.  Arrow expects to release Q1 2024 results at the end of May.

Marshall Abbott, CEO of Arrow commented: “Spudding Arrow’s first horizontal well at the CNB pad is a significant milestone in Arrow’s development plan for the hydrocarbon dense Ubaque reservoir.  After the Carrizales Norte discovery, we determined that the Ubaque reservoir could be developed most efficiently using horizontal drilling technologies and the successful spudding is a result of a year of preparation and geological, seismic, engineering and simulation work.”

“The Q1 2024 well program has helped determine the extent of the Ubaque zone, both proving that the sands are continuous, thick and permeable, and adding to reserves at the Carrizales Norte field. Arrow believes the horizontal wells at Carrizales Norte will be transformative for the Company, resulting in a step change in production, and that the technology will be effective in other prospects on the Tapir block.”

“I want to thank everyone at Arrow for their dedication and hard work over the last year which has enabled us to progress Arrow to the next level.”

This is indeed a significant milestone in Arrow’s development plan, over recent months I have watched Arrow very carefully and in the next few days I hope to comment about how well they have done and how the recent period of success has set them on their horizontal journey.

The success of drilling in the last 15 months or more has meant that Arrow has achieved a great deal of success and in particular that has opened up opportunities in this case in the Ubaque formation. There are significant advantages of the horizontal play, in this case a vertical well costing say $3-4m would expect to produce around 700 b/d whereas a horizontal well should cost say $5-7m and might deliver some 2000b/d.

These numbers, should they be confirmed next month, will be the highlight of the 2024 drilling campaign, after this the company expect to drill three more wells from this pad which was being completed when I visited Bogota recently. Finally, water disposal will be a necessary measure and such a well will be ready on the pad, further water disposal wells are planned.

I am expecting significant interest in this, the next phase of Arrow’s drilling campaign here in the CN field in the Tapir Block in the Llanos Basin. Recently the Canacol overhang has been cleared away and with such a formidable operational success rate I’m convinced that my 50 Target Price will be achieved.

Scirocco Energy

Scirocco has today provided an update with regards to the cancellation from trading on AIM following shareholder approval for the Cancellation at the Company’s General Meeting on 7 May 2024.

The Company reminds Shareholders that today, 16 May 2024, will be the last day of dealings in the Company’s ordinary shares on AIM. Admission to trading on AIM will be cancelled at 7am BST on Friday 17 May 2024.

As discussed in the circular, published on 17 April 2024, the Company stated it would update shareholders on the selection of service provider that can facilitate a secondary market trading platform. Scirocco Energy can confirm that its ordinary shares will be admitted to trade on JP Jenkins ( share dealing platform on Friday 17 May 2024.

JP Jenkins provides a share trading venue for unlisted or unquoted assets in companies, enabling shareholders and prospective investors to buy and sell equity on a matched bargain basis. JP Jenkins is a trading name of InfinitX Limited and Appointed Representative of Prosper Capital LLP (FRN453007). Shareholders wishing to trade these securities can do so through their stockbroker. Trades will be conducted at a level that JP Jenkins is able to match a willing seller and a willing buyer.

The Board is now engaged with pre-liquidation preparation and expects to notify shareholders in late June of a further (and final) GM to enter Members Voluntary Liquidation (“MVL”) with the aim of distributing cash to Shareholders over the 2024 – 2026 (and potentially 2027) period in accordance with the outcome of the 19 March 2024 GM. The matched bargain trading platform will cease if the Company enters an MVL. Shareholders are reminded that the timing of any distributions pursuant to the MVL – which are not guaranteed – will depend on a number of factors, most predominantly the development of the Ruvuma asset (in line with the expected plan of its owners which the Company has no control over), and will be under the control of the liquidator, if the Company enters an MVL.

The Company will issue notices via the JPJ platform and post them on its website site which will remain live.

The shareholders have voted and now they can wait until possibly 2027 until the wisdom of their decision finally pays out in its entirety. This is no time to get into the whys and wherefores of the decision but I have to say that I was in a number of those presentations at which management outlined the transition of the company into the renewables space and it was impressive. Yes, shareholders get some money back but one thinks of what might have been…

And finally…

Last night in the Prem the penultimate games were played, the Red Devils finished their atrocious league campaign with a win at home against the Magpies and Chelsea went to the Seagulls and won 1-2. All now rests on Sunday’s fixtures…

And the US PGA starts today at Valhalla Golf Club, interestingly the scene of Rory’s last Major victory…

Share This Story, Choose Your Platform!

Go to Top

Source link

#Malcys #Blog #Oil #price #Arrow #Exploration #Scirocco #finally

Major Plans for Geothermal Energy Development Across U.S. | Shale Magazine

The U.S. is developing its geothermal energy capacity through investment in research and development, as well as several new production projects across the country. National policies and schemes, such as the Inflation Reduction Act (IRA) and the U.S. Department of Energy’s (DOE) Geothermal Technologies Office’s (GTO) 2022-2026 Multi-Year Program Plan (MYPP), have spurred investment in the sector with more growth expected to follow. Some states are taking the lead when it comes to conventional geothermal energy development, while other regions are focusing on enhanced geothermal systems, which have the potential to offer far greater power from geothermal reserves in future years. 

National Policies Support Geothermal Development

There are a variety of geothermal energy systems, including direct use and district heating systems, geothermal power plants, and geothermal heat pumps, which use either the Earth’s high temperatures near the surface or drill miles down to access higher temperatures. Geothermal energy can be used for heating or cooling purposes, as well as to generate clean electricity by using high or medium-temperature resources in tectonically active regions of the world. 

The GTO launched its Multi-Year Program Plan in 2022 to build on the findings of the previous GeoVision analysis and better understand the geothermal potential in the U.S. It establishes three strategic goals for 2022 to 2026, which are:

  • Strategic Goal 1: Drive toward a carbon-free electricity grid by supplying 60 gigawatts (GW) of enhanced geothermal systems (EGS) and hydrothermal resource deployment by 2050.
  • Strategic Goal 2: Decarbonize building heating and cooling loads by capturing the economic potential of 17,500 geothermal district heating installations and by installing geothermal heat pumps in 28 million households nationwide by 2050.
  • Strategic Goal 3: Deliver economic, environmental, and social justice advancements through increased geothermal technology deployment.

This plan is supported by the Biden administration’s 2022 IRA, which raised the geothermal federal tax credit from 26% to 30% until 2032 and offers other financial incentives to companies developing geothermal energy projects across the country. Since the launch of the IRA, the GTO has announced several funding opportunities for geothermal projects, with a particular focus on research and development into new technologies. 

Some States are Taking the Lead

Some states are supporting the development of conventional geothermal projects, encouraged by the introduction of tax credits and other financial incentives. Minnesota is expanding its networked geothermal systems thanks to new bills introduced by state legislators to encourage greater uptake. These systems consist of ground-source heat pumps that deliver low-carbon heating and cooling to buildings. Some examples include the thermal energy network developed in Rochester’s city hall, and the geothermal systems serving Carleton College and The Heights, a development on St. Paul’s East Side where over 1,000 people will reside and another 1,000 will work. Projects such as these can help reduce both heating and cooling-related carbon emissions and cut energy costs. 

Luke Gaalswyk, the president and CEO of St. Paul-based Ever-Green Energy, stated, “There’s a lot of excitement building around networked geothermal.” Meanwhile, Joe Dammel, the managing director for buildings at policy non-profit Fresh Energy, explained, “We think that there’s tremendous potential from network geothermal… The studies being considered and the number of bills at the Legislature right now are only going to help us understand the technical and economic potential of geothermal.”

Massive Advances Being Seen in Enhanced Geothermal Systems

Other regions of the U.S. are investing in research and development into enhanced geothermal systems (EGS) with the hope of extracting even greater amounts of energy. Fervo Energy is one of the companies working to develop EGS, which is supported by government funding. In July last year, Fervo announced it had successfully operated Project Red – a geothermal well around 200 miles northeast of Reno – over a 30-day test period. During this test, it produced 3.5 MW of electricity, more than any other enhanced geothermal facility worldwide. This offered greater optimism about the future of geothermal energy production in the U.S. 

EGS works by injecting water at high pressure into deep rocks to re-open natural fractures that have closed over time, allowing hot water or steam to flow into extraction wells. The continuous injection of water helps these fractures stay open for water to be heated and extracted to generate electricity. 

The DoE is investing heavily in research into EGS, announcing plans to invest $60 million to demonstrate the efficacy and scalability of EGS in March this year. The DoE plans to award the funds to three projects – Chevron New Energies, Fervo Energy, and Mazama Energy. Currently, geothermal energy accounts for less than 1% of U.S. electricity, but that could soon change as EGS could more than double the amount of recoverable geothermal energy in the U.S. and lengthen the life of existing geothermal sites. The development of EGS technology is expected to increase the U.S. geothermal capacity by as much as 20-fold by 2050, which could contribute around 10% of the country’s electricity.

Always Be Aware With Shale Magazine

As the world turns, you can count on Shale Magazine to continuously provide trustworthy insight on energy, investment, and sustainability. We interviewed the best experts and top minds to uncover the facts other media outlets want to downplay. You can rely on our team’s keen insight into the events and news that impact your bottom line. Subscribe to Shale Magazine for up-to-date news and info. As the ESG landscape changes, we’ll be on the front lines to keep you informed.

Felicity Bradstock is a freelance writer specializing in Energy and Industry. She has a Master’s in International Development from the University of Birmingham, UK, and is now based in Mexico City.


National Innovation Day: PG&E Is Partnering in Three New and State-of-the-Art Clean Air Technologies
Texas RRC Eschews State-Mandated Production Cuts

Source link

#Major #Plans #Geothermal #Energy #Development #Shale #Magazine

Rystad Energy: Oil demand to grow in the mid-term

Oil demand will rise further in the medium term, according to Rystad Energy research and modelling, as low-carbon alternatives are not yet sufficiently developed or economically competitive to offset the growing demand for transportation and industrial services. Rystad Energy’s latest Oil Macro Scenarios report explains how the 13 sectors that rely on oil will face a more complex transition than expected just a couple of years ago. These findings underscore the notion that oil demand remains sticky and the process of substituting the capital stock associated with oil consumption will be complex and lengthy due to the competitive advantages of oil in multiple transportation sectors and industrial processes.

The research evaluates the five-year demand trajectory of oil, the technological readiness of each sector to transition and the policy frameworks supporting that shift. Rystad Energy’s analysis sheds light on the impact of crucial breakthroughs, such as the rapid electrification of buses, rail and cars, as well as the challenges faced by the remaining sectors that lack fully developed or competitive alternative technologies.

“As oil demand is likely to stay on an upward trajectory in the medium term, the probability of a fast transition away from oil decreases unless we witness breakthroughs in those low-carbon energy carriers that can technically and economically substitute oil. Our updated mid-term forecast should bring a dose of realism to the oil transition narrative, alongside a renewed sense of urgency to explore and invest even more – wherever it makes economic sense – in clean tech and renewables, to achieve those breakthroughs,” says Claudio Galimberti, global market analysis director at Rystad Energy.


About a quarter of global oil demand comes from passenger road transportation, so it is no surprise that the adoption of electric vehicles (EVs), which comprise both battery electric vehicles (BEV) and plug-in-hybrid (PHEV), is a key factor to estimate the oil demand impact. EVs have risen since 2018, making up 16% of global sales in 2022. However, last year saw an inflection point – with global EV sales landing only at 19% – due to a combination of lack of mass-market EVs outside of China, poor charging infrastructure, low consumer acceptance in some regions, charging insecurity, and the withdrawal of subsidies in some countries.

Despite these challenges, Rystad Energy still predicts that the electrification of passenger road transport will regain force in the second half of this decade and beyond. Car manufacturers have committed to producing tens of millions of EVs in the coming years, which will bring about economies of scale. Still, it is important to note that some of these plans have recently been scaled back due to poor returns on investment. In the end, one big problem will need to be solved: the ;charging insecurity; in areas where car owners do not own private parking spots. This phenomenon is particularly acute in many non-OECD countries and in quite a few OECD ones as well.

Beyond passenger road transport, the transition to alternative energy sources faces headwinds. In heavy-duty commercial road transport, oil demand is expected to grow in line with the expansion of the global economy, especially in Asia, as alternatives to oil remain limited. As an example, batteries are still too heavy and large to fit in a Class 8 truck and, even if they did, it would take too long to charge them. Battery swapping, a process where batteries with low charge get replaced with fully charged ones at specialised stations, has shown promise in China, but it is still a tiny fraction of the electric truck fleet. Catenary and induction charging – methods of charging electric vehicles while they are in motion – could be a solution, but they are currently too expensive. Granted, Volvo and Tesla have started the production and delivery of electric semitrucks, but the numbers are still small and will continue to be so in the medium term.

The maritime industry shares many of the same challenges as heavy-duty trucks. Shipping large cargo across the seas efficiently and affordably requires a fuel with high energy density, safe storage and transport and a well-established supply chain. While alternatives like ammonia and methanol may satisfy some of these requirements, they are yet to outcompete oil on key metrics like affordability and energy density. Furthermore, the fast aging of the global maritime fleet is set to slow down the fleet turnover.

Sustainable Aviation Fuel (SAF) is an environmentally friendly alternative to traditional jet fuel. Although SAF has the potential to grow significantly in the aviation industry during the 2030s and beyond, it will not significantly impact aviation in the next five years. Despite major commitments from airlines and the International Civil Aviation Organization’s (ICAO) Corsia programme, SAF’s share will be less than 5% of jet fuel demand by the end of this decade. This translates to less than 0.4% of global oil demand.

Buses and rail transportation do not have to wait for alternatives as they are already available and proving to be highly effective. The recent electrification trend in these two sectors in China, India and Europe will continue in the coming years, thanks to government policies. However, even if these two sectors were to be fully electrified in the next 15 years, the maximum reduction in oil demand by 2030 would only be around 0.5 – 0.8 million bpd since they currently represent less than 3% of oil demand.

Stationary sectors

The stationary sectors, which include petrochemical, industry, building, non-energy use, energy own use, power and agriculture, account for 42.3% of global oil demand as of 2024 and are vital components of the energy transition. In the petrochemical sector, demand for plastics is set to surge in the coming years – on the back of an expanding global middle class – and oil and natural gas liquids (NGLs) will be the feedstock used to produce plastic. To reduce demand for virgin feedstock, mechanical and chemical recycling rates must increase. However, higher investment in the recycling supply chain, as well as research and development, are needed to achieve this. It is important to recall that global plastic recycling rates are currently only 8% of total plastic consumption, with scant evidence that they could increase significantly by the end of the decade.

Oil demand in the building sector has proven more resilient than expected just a few years ago. In regions where the natural gas grid is not available and winters are long and frigid, oil – in the form of liquified petroleum gas (LPG), kerosene or gasoil – remains the most efficient energy carrier for space and water heating. Heat-pumps, which are typically very efficient for space heating in milder climates, tend to have a reduced effectiveness in very cold regions. Finally, in countries that still rely on burning biomass for cooking, such as sub-Saharan Africa, LPG could be a cleaner energy carrier, which could result in a 1.5 million bpd uptick in oil consumption.

High energy density is essential in the industry sector to achieve the high temperatures required for operations such as steelmaking, cement production, petrochemicals, and refining subsectors. Although hydrogen is considered the most viable low-carbon energy carrier alternative to oil, it is unlikely to become a strong competitor in the next five years due to high costs and lack of a developed supply chain.

Rystad Energy’s research confirms that oil demand remains sticky and it will take time and resources to switch the capital stock associated with its consumption. It also reminds us of the importance of understanding the whole energy system end-to-end, and not just the oil system. Lowering global emissions is still possible in the medium term if other energy sectors deploy clean technology and renewables at a faster pace. In this context, the rapid deployment of solar PV in power generation, displacing coal, has done just that over the past few years. As a result, a fast reduction in global emissions is still within reach, despite climbing oil demand.

Read the article online at:

Source link

#Rystad #Energy #Oil #demand #grow #midterm

Saturn Oil & Gas Inc. reports Q1 2024 financial and operating results | BOE Report

Saturn Oil & Gas Investor & Media Contacts:

John Jeffrey, MBA – Chief Executive Officer
Tel: +1 (587) 392-7900

Kevin Smith, MBA – VP Corporate Development
Tel: +1 (587) 392-7900
[email protected]

(1) See reader advisory: Non-GAAP and Other Financial Measures
(2) See reader advisory: Supplemental Information Regarding Product Types

Reader Advisory

Non-GAAP and Other Financial Measures

Throughout this news release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures provided by other issuers. Non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS. The disclosure under the section “Non-GAAP and Other Financial Measures” including non-GAAP financial measures and ratios, capital management measures and supplementary financial measures in the Company’s Condensed consolidated interim financial statements and MD&A are incorporated by reference into this news release.

This press release may use the terms “adjusted EBITDA”, “adjusted funds flow”, “free funds flow” and “net debt” which are capital management financial measures. See the disclosure under “Capital Management” in our condensed consolidated interim financial statements for the three months ended March 31, 2024, for an explanation and composition of these measures and how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.

Capital expenditures

Saturn uses capital expenditures to monitor its capital investments relative to those budgeted by the Company on an annual basis. Saturn’s capital budget excludes acquisition and disposition activities as well as the accounting impact of any accrual changes or payments under certain lease arrangements. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. The following table details the composition of capital expenditures and capital expenditures, net acquisitions and dispositions (“A&D“) to the nearest GAAP measure, to cashflow used in investing activities.

Three months ended March 31,
($000s) 2024 2023
Cash flow used in investing activities 49,692 499,563
Change in non-cash working capital (15,726 ) (10,057 )
Capital expenditures, net A&D 33,966 489,506
Acquisitions, net of cash acquired (465,223 )
Capital expenditures 33,966 24,283

Gross petroleum and natural gas sales

Gross petroleum and natural gas sales is calculated by adding oil, natural gas and NGLs revenue, before deducting certain gas processing expenses in arriving at Petroleum and natural gas revenue as required under IFRS-15. These processing expenses associated with the processing of natural gas and NGLs revenue are a result of the Company transferring custody of the product at the terminal inlet, and therefore receiving net prices. This metric is used by management to quantify and analyze the realized price received before required processing deductions, against benchmark prices. The calculation of the Company’s gross petroleum and natural gas sales is shown within the Petroleum and natural gas sales section of the MD&A for the three months ended March 31, 2024.

Net operating expenses

Net operating expense is calculated by deducting processing income primarily generated by processing third party production at processing facilities where the Company has an ownership interest, from operating expenses presented on the Statement of income (loss). Where the Company has excess capacity at one of its facilities, it will process third-party volumes to reduce the cost of ownership in the facility. The Company’s primary business activities are not that of a midstream entity whose activities are focused on earning processing and other infrastructure-based revenues, and as such third-party processing revenue is netted against operating expenses in the MD&A. This metric is used by management to evaluate the Company’s net operating expenses on a unit of production basis. Net operating expense per boe is a non-GAAP financial ratio and is calculated as net operating expense divided by total barrels of oil equivalent produced over a specific period of time. The calculation of the Company’s net operating expenses is shown within the net operating expenses section of the MD&A for the three months ended March 31, 2024.

Operating netback and Operating netback, net of derivatives

The Company’s operating netback is determined by deducting royalties, net operating expenses and transportation expenses from petroleum and natural gas sales. The Company’s operating netback, net of derivatives is calculated by adding or deducting realized financial derivative commodity contract gains or losses from the operating netback. The Company’s operating netback and operating netback, net of derivatives are used in operational and capital allocation decisions. Presenting operating netback and operating netback, net of derivatives on a per boe basis is a non-GAAP financial ratio and allows management to better analyze performance against prior periods on a per unit of production basis. The calculation of the Company’s operating netbacks and operating netback, net of derivatives are summarized as follows.

Three months ended March 31,
($000s) 2024 2023
Petroleum and natural gas sales 168,219 131,407
Royalties (21,189 ) (14,947 )
Net operating expenses (47,563 ) (33,717 )
Transportation expenses (3,155 ) (1,609 )
Operating netback 96,312 81,134
Realized loss on financial derivatives (4,601 ) (7,275 )
Operating netback, net of derivatives 91,711 73,859
($ per boe amounts)
Petroleum and natural gas sales 70.03 82.11
Royalties (8.82 ) (9.34 )
Net operating expenses (19.80 ) (21.07 )
Transportation expenses (1.31 ) (1.01 )
Operating netback 40.10 50.69
Realized loss on financial derivatives (1.92 ) (4.55 )
Operating netback, net of derivatives 38.18 46.14

Adjusted EBITDA

The Company considers adjusted EBITDA to be a key capital management measure as it is both used within certain financial covenants prescribed under the Company’s Senior Term Loan and demonstrates Saturn’s standalone profitability, operating and financial performance in terms of cash flow generation, adjusting for interest related to its capital structure. Adjusted EBITDA is defined by the Company as earnings before interest, taxes, depreciation, amortization and other noncash or extraordinary items.

Adjusted funds flow

The Company considers adjusted funds flow to be a key capital management measure as it demonstrates Saturn’s ability to generate the necessary funds to manage production levels and fund future growth through capital investment. Management believes that this measure provides an insightful assessment of Saturn’s operations on a continuing basis by eliminating certain non-cash charges, actual settlements of decommissioning obligations, of which the nature and timing of expenditures may vary based on the stage of the Company’s assets and operating areas, and transaction costs which vary based on the Company’s acquisition and disposition activity.

Free funds flow

The Company considers free funds flow to be a key capital management measure as it is used to determine the efficiency and liquidity of Saturn’s business, measuring its funds available after capital investment available for debt repayment, pursue acquisitions and gauge optionality to pay dividends and/or return capital to shareholders through share repurchases. Saturn calculates free funds flow as adjusted funds flow in the period less expenditures on property, plant and equipment and exploration and evaluation assets, together “capital expenditures”. By removing the impact of current period capital expenditures from adjusted funds flow, management monitors its free funds flow to inform its capital allocation decisions.

The following table reconciles adjusted EBITDA, adjusted funds flow and free funds flow to cash flow from operating activities:

Three months ended March 31,
($000s) 2024 2023
Cash flow from operating activities 70,222 46,794
Change in non-cash working capital (6,565 ) 3,653
Decommissioning expenditures 4,521 259
Transaction costs 3,748
Net interest(1) 19,975 15,406
Adjusted EBITDA 88,153 69,860
Net interest(1) (19,975 ) (15,406 )
Adjusted funds flow 68,178 54,454
Capital expenditures(2) (33,966 ) (24,283 )
Free funds flow 34,212 30,171

(1) Calculated as interest expense, net of interest revenue.
(2) Calculated as expenditures on PP&E and E&E assets on the consolidated statements of cash flows.

Market capitalization and net debt

Management considers net debt a key capital management measure in assessing the Company’s liquidity. Total market capitalization and net debt to annualized quarterly adjusted funds flow are used by management and the Company’s investors in analyzing the Company’s balance sheet strength and liquidity. The summary of total market capitalization, net debt, annualized quarterly adjusted funds flow and net debt to annualized quarterly adjusted funds flow is as follows:

($000s) March 31,
December 31,
Total common shares outstanding (000s) 161,206 139,313
Share price(1) 2.54 2.20
Total market capitalization 409,463 306,489
Adjusted working capital(2) 9,572 8,240
Senior Term Loan 375,742 451,153
Convertible notes 1,103 1,090
Net debt 386,417 460,483
Current quarter adjusted funds flow 68,178 80,247
Annualized factor 4 4
Annualized quarterly adjusted funds flow 272,712 320,988
Net debt to annualized quarterly adjusted funds flow 1.4x 1.4x

(1) Represents the closing share price on the TSX on the last day of trading of the period.
(2) Adjusted working capital is calculated as cash, accounts receivable, deposits and prepaids net of accounts payable.

Supplemental Information Regarding Product Types

References to gas or natural gas and NGLs in this press release refer to conventional natural gas and natural gas liquids product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101“), except where specifically noted otherwise.

The following table summarizes Saturn’s average production by business unit for the three months ended March 31, 2024 and 2023:

Three months ended March 31, 2024 Three months ended March 31, 2023
Southeast Saskatchewan 10,274 789 4,420 11,800 7,527 481 2,913 8,494
West Central Saskatchewan 3,220 37 512 3,342 5,072 12 429 5,156
Central Alberta 3,858 1,087 20,258 8,321 1,416 388 7,386 3,034
North Alberta 1,629 431 5,226 2,931 665 111 1,938 1,099
Total boe/d 18,981 2,344 30,416 26,394 14,680 992 12,666 17,783

Initial Production Rates

Any reference in this news release to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Any reference in this news release to initial production rates consist of the above noted product types, using a conversion rate of 1 bbl : 6 MCF (where applicable). Readers are cautioned not to place undue reliance on such rates in calculating aggregate production for Saturn.

Per boe or ($/boe)

Any reference in this news release to disclosures for petroleum and natural gas sales, royalties, operating expenses, transportation expenses and marketing expenses on a per boe basis are supplementary financial measures that are calculated by dividing each of these respective GAAP measures by Saturn’s total production volumes for the period.

Per Share Amounts

Per share amounts noted in this news release are based on Saturn’s weighted average issued and outstanding common shares as of March 31, 2024, unless noted otherwise.

Abbreviations and Frequently Reoccurring Terms

Saturn uses the following abbreviations and frequently recurring terms in this press release: “WTI” refers to West Texas Intermediate, a grade of light sweet crude oil used as benchmark pricing in the United States; “MSW” refers to the mixed sweet blend that is the benchmark price for conventionally produced light sweet crude oil in Western Canada; “AECO” refers to Alberta Energy Company, a grade or heating content of natural gas used as benchmark pricing in Alberta, Canada; “bbl” refers to barrel; “bbl/d” refers to barrels per day; “GJ” refers to gigajoule; “NGL” refers to Natural Gas Liquids; “Mcf” refers to thousand cubic feet.

Boe Presentation

Boe means barrel of oil equivalent. All boe conversions in this news release are derived by converting gas to oil at the ratio of six thousand cubic feet (“Mcf“) of natural gas to one barrel (“Bbl“) of oil. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 Bbl: 6 Mcf, utilizing a conversion ratio of 1 Bbl : 6 Mcf may be misleading as an indication of value.

Forward-Looking Information and Statements.

Certain information included in this press release constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project”, “scheduled”, “will” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this press release may include, but is not limited to, the drilling of development wells, the business plan, cost model and strategy of the Company.

The forward-looking statements contained in this press release are based on certain key expectations and assumptions made by Saturn, including expectations and assumptions concerning: the timing of and success of future drilling, development and completion activities, the performance of existing wells, the performance of new wells, the availability and performance of facilities and pipelines, the ability to allocate capital to pay down debt and grow or maintain production, the geological characteristics of Saturn’s properties, the application of regulatory and licensing requirements, the availability of capital, labour and services, the creditworthiness of industry partners and the ability to source and complete asset acquisitions.

Although Saturn believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Saturn can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), constraints in the availability of services, commodity price and exchange rate fluctuations, actions of OPEC and OPEC+ members, changes in legislation impacting the oil and gas industry, adverse weather or break-up conditions and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. These and other risks are set out in more detail in Saturn’s Annual Information Form for the year ended December 31, 2023.

Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may prove to be incorrect. Although Saturn believes that the expectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because Saturn can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this press release, assumptions have been made regarding and are implicit in, among other things, our capital expenditure and drilling programs, drilling inventory and booked locations, production and revenue guidance, ESG initiatives, debt repayment plans and future growth plans. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.

The forward-looking information contained in this press release is made as of the date hereof and Saturn undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking information contained in this press release is expressly qualified by this cautionary statement.

All dollar figures included herein are presented in Canadian dollars, unless otherwise noted.

To view the source version of this press release, please visit

Source link

#Saturn #Oil #Gas #reports #financial #operating #results #BOE #Report