I see Vision Marine (VMAR-NASD; $4.90) as the TESLA of electric boating.
Boat engines around the world WILL go electric.  They must, and they are. This is the bottom edge of what I see as a very thick wedge.  Where Tesla was 12 years ago, Vision Marine is now.  Except that VMAR only has 9.5 million shares out, and management/board own just over 30%!
The world needs this product. Marine ICE engines pollute almost 2.5X more than cars. Progressive US states and European countries are already starting to legislate the end of ICE engines on the water–and setting a huge growth curve for marine engines.
Investors DREAM of these kinds of scenarios–a proprietary technology at the forefront of a global sector about to get electrified.  They have millions in the bank and the industry is already rallying around them.
VMAR’s 180 hp electric powertrain boats are selling NOW–into the sweet spot of the US$17 billion boating market–the 16-26 foot powerboat. 
These engines are SO quiet—almost silent.  They’re zero-emission. You can fill them up for $5 of electricity–with standard marine electrical hook up–and boat for hours. 
No competitor is even the power and fun VMAR gives boaters.  That’s why everyone in the North America boating industry–engine AND boat manufacturers–are talking to Vision Marine CEO/Founder Alex Mongeon. 
The first one to sign on last year was Beneteau, a billion-dollar-boat-company out of France. They are already ordering engines from Vision Marine for one of their models–out of many that they have. Beneteau has committed to have ALL their boats be electric by 2030.
I think the timing is perfect for this company.  Mongeon and CTO ll the R&D and certification is done.

They have solid relationships with the big boat makers–effectively docking the competition. They have mass manufacturing facilities–ready to go–in North America with US$3 billion market cap Linamar (LNR-TSX;$60)They can make 18,000 VMAR powertrains a year.  Everything is in place for HUGE growth.
This US$45 million market cap company has multi-billion dollar partners–a huge competitive moat–in a US$17 billion market–growing at 13% CAGR for the last decade.  The industry wants the product, and doesn’t see anyone else who can provide it.
These relationships with boat makers are crucial, and shows that Vision Marine is NOT a boating company–they see their electric powertrain driving all kinds of boats from many manufacturers.


Understand that Mongeon and his team have spent THOUSANDS of hours of collaborating with the engineers of these boating companies, providing version after version for testing.  They are in active discussions with FIVE of the big boat companies–only Beneteau has signed so far–but no names can be released until those contracts are signed.
This collaboration is NOT something any new group can duplicate easily.  You must have all the battery storage technology set, control the engine temperature, use high voltage power–so many specialized marine functions that cars don’t have to worry about. Nobody else is at the table with all these boat makers because nobody else has the technology.
With a proven product and established relationships with all the big guys–Vision Marine is now in a GREAT spot.
I asked Mongeon when these big boat company executives turn from skepticism into enthusiastic:
“Right after the first prototype. We work with them all, building a 3D model together.  Then once they feel confident, they give us the boat to outfit, and test for a couple months.
“Then they come play with their boat under our watch. This is where they believe it. Not they are part of it, they’re driving it, and they’re smiling.
“I tell them–next time, you’re building it, we’ll be looking after you, we’ll be supporting you in your factory.

That’s what we do now with Beneteau.”
This is quite different–and easier–than Tesla ever had it.  They had to fight tooth and nail against everyone for every bit of market share they ever got. 
At a US$45 million market cap with only 9.5 million shares out, VMAR gives investors HUGE upside.

They don’t need to get to Tesla’s $1 trillion market cap to make investors a lot of money.
Sales of 1,000 engines/powertrains gets Vision Marine to $100 million revenue and US$3 in EPS.  That is not a huge leap, given the number of multi-billion dollar boat makers they’re dealing with.

Not to mention–I haven’t talked about any government incentives that are bound to follow suit to be akin to the automotive industry.
One more thing before I move on from OEMs–VMAR is also in advanced stage talks–going on for 18 months–with pontoon boat makers–the big party boats that go out on inland waters. 
Their E-Motion powertrain is perfect for this market. They’re three versions in and are nearing a commercial product here. It could provide a big catalyst to the future–60,000 pontoon boats are sold annually!  Again–they will all go electric.  They have to. They will.  And there’s no one else to get them there.


In the coming months and quarters, the tsunami of revenue will be from OEM deals with pontoon and big boat companies like Beneteau as the global marine industry goes 100% electric. 
But the VERY low cost of maintaining an electric boat makes for another compelling revenue model, that Vision Marine has already proved out.
Bloomberg estimates that it costs ~10% of the cost of the boat every year just to maintain the average boat.

The beauty of electric motors is there are WAY less moving parts–no alternator, fuel injectors, transmission, filters, belts, hoses.  Maintenance costs for electric motors are estimated to be 1/3rd than ICE engines.
That low-cost simplicity makes a rental model highly profitable.  Vision Marine bought an electric boat rental company in 2021, and stocked it with 35 Vision Marine boats.
It’s a simple lease model, allowing resorts and marinas to rent these electric boats (which is great test driving/exposure to hundreds of thousands of boaters), and after two years, Vision Marine gets to sell them to the open market and replace the old leases with new ones.
Revenue runs at roughly US$4 million per year with 35% margins.  There are 8000 marinas and 2000 waterfront resorts who are potential customers.
The first location proved to be such a money-maker, they’re opening a 2nd this year and are also looking into launching a franchise model in 2024.
Vision Marine obviously makes money off the franchise itself, but for the franchisees, the pull is that they can make their money back in just one year. Meanwhile, Vision Marine gets a substantial revenue share in perpetuity for licensing, merchandising and leasing.


Look folks, the more I dug into this the more convinced I was.  All the heavy lifting has been done here–years of building relationships with parts suppliers and large OEM customers, having all the manufacturing ready to go NOW, in North America…this company and its stock is now turn-key.  It’s ready to go.
They are in advanced discussions with SEVERAL global boat makers.  Everybody is talking to them. Here’s a simplified view of where they’re at in their business model:


If they had $100 million revenue today, the stock would be trading a lot higher than the $3.50 it is now. 
And it’s already being adopted by the biggest boat companies.
With all these relationships now set, shareholders won’t have to wait for a decade for VMAR to build their name and brand in order to sell to customers en masse.
They have already won the race.  VMAR doesn’t have to set electric speed records of 109 mph anymore.  The Market knows who the winner will be here. 
The path for Vision Marine will be much easier than it was for Tesla. 
I’m a growth investor.  I see a proprietary technology at the forefront of a global sector about to get electrified–don’t we dream of these kinds scenarios?

Vision Marine has reviewed and sponsored this article. The information in this newsletter does not constitute an offer to sell or a solicitation of an offer to buy any securities of a corporation or entity, including U.S. Traded Securities or U.S. Quoted Securities, in the United States or to U.S. Persons. Securities may not be offered or sold in the United States except in compliance with the registration requirements of the Securities Act and applicable U.S. state securities laws or pursuant to an exemption therefrom. Any public offering of securities in the United States may only be made by means of a prospectus containing detailed information about the corporation or entity and its management as well as financial statements. No securities regulatory authority in the United States has either approved or disapproved of the contents of any newsletter.

Keith Schaefer is not registered with the United States Securities and Exchange Commission (the “SEC”): as a “broker-dealer” under the Exchange Act, as an “investment adviser” under the Investment Advisers Act of 1940, or in any other capacity. He is also not registered with any state securities commission or authority as a broker-dealer or investment advisor or in any other capacity.

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Orbital Methane Monitoring Satellites Show Canada is a Leader in Reducing Emissions – Energy News for the Canadian Oil & Gas Industry |

For Jean-Francois Gauthier, space is the next frontier in the quest to reduce global emissions, and the view from 6,000-kilometres above Earth is that Canada is a leader in curbing the most polluting of greenhouse gases.

In April, Quebec-based GHGSat launched three more methane-sniffing satellites into Earth’s orbit – Mey-Lin, Gaspard and Océane – bringing its high-tech constellation of celestial emissions monitors to nine.

Gauthier, GHGSat’s vice-president of measurements and strategic initiatives, said after eight years of having eyes in the sky, one thing has become crystal clear – Canada is a world leader when it comes to taming methane emissions, a greenhouse gas many times more polluting than CO2.

“Canada’s performance from what we see anyway, with our satellites, is much better than the rest of the world,” he said.

“It’s shedding a light on the fact that Canada continues to be a leader on [methane emissions]. There’s always work to do – that said, if you don’t see as much with satellites, it’s encouraging because those are the biggest leaks that need addressing right away.”

The launch of GHGSat C6, C7 and C8 (Mey-Lin, Gaspard and Océane) on the Transporter-7 Mission with SpaceX in April 2023. Photo courtesy GHGSat


Canada’s oil and gas industry has been working hard to tackle methane emissions over the last two decades.

Even as Canadian oil production grew 91 per cent between 2000 and 2018, Canada’s methane emissions declined by 16 per cent. Over the same period, worldwide methane emissions increased by 27 per cent while oil production only grew by 38 per cent.

In Alberta, the heart of Canada’s oil and gas sector, efforts to reduce methane emissions are well ahead of schedule, dropping by 44 per cent between 2014 and 2021, including a 10 per cent drop from 2020. That puts the sector within a stone’s throw of reaching (and likely surpassing) its target of reducing methane emissions by 45 per cent by 2025.

Gauthier said GHGSat is looking to launch three more satellites by year’s end and has sky-high ambitions to provide a true daily snapshot of global emissions. And it’s that data, viewable by industry, policy makers and the public, that can help determine the world’s heaviest emitters and act as a catalyst for action.

“Now we’re turning our attention already to the next batches because we have ambitions to get to 100 … ideally by the end of 2026, mid-2027,” he said, noting that would include a suite of satellites and airplanes to spot any major changes in emissions.

“The ambition really is to be able to look at all emitting sites worldwide on a daily basis. So now you can really decide where to take action and start eliminating some of those biggest sources.”


Seen as a world leader in orbital emissions monitoring, GHGSat started in 2016 with a small, microwave-sized prototype satellite called Claire, in collaboration with Canada’s Oil Sands Innovation Alliance (COSIA) and other industrial partners.

She was joined in 2020 by her stellar sibling Iris, following a successful launch onboard an 11.7-metre tall Vega rocket from the Kourou International Spaceport in French Guiana. From there the company has launched a steady stream of increasingly refined satellites into orbit, each one bearing the name of one of the team members’ children.

Methane tracking satellites Luka, Penny and Diako are prepared ahead of launch with SpaceX. Photo courtesy GHGSat

The company contracts out its monitoring services to oil and gas companies, government and increasingly mining, waste management, agriculture and other emissions-intensive industries. While private sector data is owned by clients, GHGSat also offers searchable real-time emissions data available to the general public at a lower level of resolution.

Gauthier said GHGSat continues to work with the European Space Agency to provide ongoing climate data, and is in talks with NASA, which is currently assessing the company’s platform to be part of its commercial small satellite data acquisition program.

Last year, GHGSat’s six operational satellites observed over 500,000 sites in 69 countries, measuring some 179 megatonnes of CO2 equivalent methane emissions, which equates to the same annual emissions of 38.6 million cars.

Gauthier said GHGSat targeted methane not only due to its heavier environmental footprint, but due to the fact that its easier to measure from space.


However, he adds with improvements in technology the one of the next trio of satellites set for launch will key in on CO2 in an effort to provide a more complete picture of the planet’s greenhouse gas hotspots.

“We’re confident that using the same techniques that we’ve been using for methane we can use for CO2, and then be able to zero in directly to the sources,” Gauthier said.

“Industrial sites like cement plants, power plants, steel mills, aluminum smelters – these kinds of large CO2 emitters, we should be able to measure quite readily.”

Gauthier said getting a true picture of the problem is the first step. The next step is to find solutions to heavy emitters.

Rendering of GHGSat-C7 “Gaspard” monitoring for methane emissions from orbit. Photo courtesy GHGSat

Coal use is expected to reach record levels this year as the global energy crisis continues. Liquefied natural gas from Canada can make an immediate difference in reducing emissions, with a report from Wood Mackenzie showing that if Canada increased its LNG export capacity to Asia, net emissions could decline by 188 million tonnes of CO2 equivalent per year – about the annual impact of taking 41 million cars off the road.

Canada is also a world leader in developing carbon capture and storage technology, accounting for 15 per cent of global capacity despite producing less than 2 per cent of global emissions.

“The bottom line is that technologies are here, not just to measure, but to fix leaks and take care of these greenhouse gas emissions,”

“It’s really time to take action. That is, I think, is probably the most exciting thing is that the tools are there, and now it’s time to use them.”

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Data Science is the Future of Oil and Gas

Data science is the future of oil and gas.

That’s according to Andy Wang, the Founder and Chief Executive Officer of data solutions company Prescient, who made the statement during an interview with Rigzone.

“Data science will increase the capability of oil and gas operations dramatically to improve efficiency, reduce cost, enhance safety, and empower employees from the IT team to the field team,” Wang told Rigzone.

In the interview, Wang highlighted that data sciences includes many data tools, including machine learning, which he noted will be an important part of the future of oil and gas. When asked if he thought more and more oil companies would adopt data science, and machine learning, Wang responded positively on both counts.

Asked to list some drawbacks of data science in the oil and gas world, Wang told Rigzone that data science requires a shift to a data driven culture and requires the understanding of how to apply the right data science to solve the right problems.

When Rigzone enquired if data science professionals are in high demand in the oil and gas sector right now, Wang said “we see that the demand is growing”.

When Rigzone took the same question to Gladney B. Darroh, the founder and president of Houston based Piper-Morgan Search, Darroh told Rigzone that “interest is increasing”.

“I expect this interest will translate into an ever-increasing demand for data science professionals both on a direct hire and contract basis,” Darroh added.

“At the moment I haven’t seen a spike in demand, but I’ve been fielding more queries from companies. It’s definitely a wave that is building,” he continued.

Offering his view, Dave Mount, the President of Louisiana based OneSource Professional Search, told Rigzone that the demand, at least from the company’s client base of oil and gas operating companies, for dedicated data scientists “has been somewhat slow in the last two to three years”.

“The peak demand, at least from what we saw, was prior to the oil price crash/Covid,” Mount said.

“The demand seemed to emanate mostly from onshore unconventional shale players that were in high growth mode with hundreds of wells under their operating umbrella, where they had a lot of data points to sample and statistically, vs. geologically, analyze production operations and mineral royalty companies,” he added.

“We’re not sure if the drop in demand for dedicated data scientists is across the energy supply chain or just in the segments we serve,” Mount continued.

“What we have seen is more demand for employees that can integrate higher end statistical and data analysis in their more traditional roles, i.e., production analysts, production engineers, and reservoir engineers,” Mount went on to state.

Wang took part in the Society of Petroleum Engineers (SPE) International Gulf Coast Section’s recent Data Science Convention event in Houston, Texas, which was attended by Rigzone’s President. The event, which is described as the annual flagship event of the SPE-GCS Data Analytics Study Group, hosted representatives from the energy and technology sectors.

Wang is described on Prescient’s website as a technologist and entrepreneur with more than 20 years of experience. He helped grow his previous startup, GTI IoT Technology, from a two-person founding team to over 150 employees, and deployed over 500K IoT devices for industrial applications, the site highlights, adding that he received a Ph.D. from Massachusetts Institute of Technology.

According to Prescient’s website, the Massachusetts based company’s mission is to empower businesses with the tools they need to make informed decisions based on data driven insights.

To contact the author, email [email protected]

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Well Slot: Who’s drilling in the UK North Sea and Norway?

Well Slot is a monthly feature from Energy Voice and Westwood Global looking at drilling activity and rig moves in the UK North Sea and Norway.


As of 30 May, Westwood Global Energy reports that there is one appraisal well and two exploration wells active on the UKCS.

The appraisal well is in the SNS at Crosgan and the exploration wells are in the NNS at Alwyn East and WoS at Benriach. Since the previous report, the Ben Lawers well has completed in the WoS and the appraisal well at Golden Eagle North Punt Channel in the CNS is completing as a producer.

West of Shetland

© Supplied by Diamond Offshore
The Ocean GreatWhite rig.

The BP-operated 204/23a-3 Ben Lawers exploration well was completed c. 17 May, having spudded on 28 March with the Ocean GreatWhite semi-sub. The target was Paleocene T31 Vaila Formation sandstones in an amplitude driven play, in a combination trap. Pre-drill resources were c. 70 mmboe. On 12 April, an NSTA update showed Shell had farmed into the licence for a 33.33% interest. BP said the well completed with no discovery.

The TotalEnergies-operated 206/5c-4 Benriach exploration well spudded on 21 March with the Transocean Barents semi-sub. The well is targeting amplitude supported, Lower Cretaceous Royal Sovereign Formation sandstones in a combination trap, with three-way dip closure and pinchout onto a rafted Jurassic – Triassic block. Kistos has quoted pre-drill P50 resources of 638 bcf (106.3 mmboe).

Northern North Sea

The 3/9a-N59 Alwyn East well, operated by TotalEnergies, was spudded on 16 January 2023 as an extended reach well from the Alwyn North platform. The reservoir target is Middle Jurassic Brent Group sandstones in a rotated fault terrace. The well is classed as high temperature (HT) not high pressure (HP). Pre-drill P10 resources are c. 26 mmboe.

Central North Sea

well slot drilling north sea
The COSL Innovator rig.

The CNOOC-operated 14/26a-N4, Z, Y, X well was completed on 8 May 2023, after being spudded on 8 September 2022 from the Golden Eagle Northern Drill Centre with the COSLInnovator semi-sub. The wells were appraising the Punt Sandstone Member. The initial 14/26a-N4 appraisal well, targeting the northern part of the Golden Eagle Punt Member Channel, is understood to have failed to find reservoir. The 14/26a-N4Z and 14/26a-N4Y sidetracked appraisal wells, kicked off on 1 November 2022 and 8 January 2023, respectively, were J&A. The 14/26a-N4X appraisal sidetrack, kicked off on 26 February, successfully encountered hydrocarbons. The well is currently completing as a producer to be brought online soon.

Southern North Sea

The ONE-Dyas-operated 42/15a-4 Crosgan appraisal well spudded on 24 March with the Valaris 123 rig. It is a firm licence commitment well appraising the Zechstein discovery made by well 42/15a-2 in 1990 which tested the Hauptdolomit Z2 sequence at 7.6 mmscfpd post-acidisation. The well will also target the Carboniferous, Whitby Sandstone Member.

Norway Well Slot

well slot drilling north sea © Supplied by Odjfell Drilling
The Deepsea Stavanger has been hitting the mark in Norway

As of 30 May, Westwood Global Energy reports that there is one appraisal and three exploration wells active on the NCS.

The appraisal well is in the Northern North Sea at Øst Frigg Beta/Epsilon was announced as an oil discovery and is completing. Three exploration wells are drilling in the Northern North Sea at Carmen, Litago and Oseberg Lambda. Since the last report, two exploration well programs completed, with Tott West in the Norwegian Sea as a gas condensate discovery and Eggen in the Northern North Sea, with no results announced to date. Three exploration well programs spudded at Litago, Eggen and Oseberg Lambda.

North Sea

Neptune Energy Calypso © Supplied by Odfjell Drilling
The Deepsea Yantai.

The 30/6-C-2 A Oseberg Lambda well, operated by Equinor, was spudded on 19 May from the existing Oseberg C platform. The deviated well will test Statfjord Formation reservoir in the Lambda tilted fault block.

The Equinor-operated 31/2-23 Eggen well was completed on 22 May, after being spudded on 9 May with the Deepsea Stavanger semi-sub. The well targeted the Upper and Middle Jurassic in a downthrown fault block. JV partner DNO holds pre-drill resources of 15 – 100 mmboe. No results have been announced.

The 31/2-24 Litago well, operated by Equinor, was spudded on 7 May with the Deepsea Stavanger semi-sub. The well is targeting the Upper and Middle Jurassic in a downthrown fault block. JV partner DNO holds pre-drill mean resources of 25 – 195 mmboe.

The Wellesley-operated 35/10-10 S Carmen well was spudded on 4 April with the Deepsea Yantai semi-sub. The well is targeting a high impact, HPHT play in the Middle and Lower Jurassic. The operator quoted pre-drill mean resources of 109 mmboe.

The 25/2-24 S, A, C, B, Øst Frigg Beta/Epsilon well, operated by Aker BP, is in the process of completing as an oil discovery, after being spudded on 1 March with the Scarabeo 8. Three horizontal sidetracks tested the Beta West, Alfa South and Epsilon Eocene injectite targets. Aker BP announced the well as an oil discovery with gross recoverable volumes of 40 – 90 mmboe. The discoveries will be tied back to the Yggdrasil development.

Norwegian Sea

The Equinor-operated 6406/5-2 S Tott West well was completed on 1 May, after being spudded on 10 March with the Deepsea Stavanger semi-sub. The well was targeting the Middle and Lower Jurassic in a tilted fault block structure. A 24m (79ft) gas condensate column was encountered within a 60m (197ft) thick Middle Jurassic Garn Formation.

Water bearing sandstones, 102m (335ft) and 140m (459ft) thick, were encountered in the Middle Jurassic Ile Formation and Lower Jurassic Tofte Formations respectively. Westwood currently hold the well as non-commercial.

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OPEC+ prepares for weekend meeting after Saudi warns speculators to ‘watch out’

Led by Saudi Arabia and Russia, OPEC+ agreed in early October to reduce production by 2 million barrels per day from November.

Vladimir Simicek | Afp | Getty Images

The OPEC+ alliance of oil producers will decide further production policy steps over the weekend, as crude prices reflect an ongoing struggle between supply-demand fundamentals and broader macro-economic concerns.

After convening remotely throughout the Covid-19 pandemic, OPEC+ has returned to in-person meetings and will gather in Vienna on June 4. The OPEC ministers gather for a separate meeting unlikely to address output on June 3.

Ministers face an oil market rattled by supply volatility, demand uncertainty, and a prospective recession, which could throttle transport fuel consumption. Since October, OPEC+ — a 23-member alliance including heavyweights Russia and Saudi Arabia — has lowered output by 2 million barrels per day in an effort to combat lower demand. Some members have also announced additional voluntary cuts totaling 1.6 million barrels per day in April.

Group members are expected to coagulate their individual positions and proposals in the 24-48 hours before the meeting, some OPEC+ delegates told CNBC, speaking on condition of anonymity — while public comments so far have been conflicting.

On May 23, Saudi energy minister Prince Abdulaziz bin Salman warned oil market speculators they could face further pain ahead, in comments some have read as hinting further supply cuts could be in the cards.

“I keep advising [speculators] that they will be ouching. They did ouch in April. I don’t have to show my cards, I’m not [a] poker player … but I would just tell them, watch out,” he said at the time.

Russia’s Deputy Prime Minister Alexander Novak later indicated that he expected no further steps from the OPEC+ meeting, but then said his comments were misinterpreted as downplaying an output cut, according to Russian state news agency Tass.

Russia and Saudi Arabia have been united in their public OPEC+ stance since a March 2020 dispute that led to the one-month dissolution of their oil partnership and an ensuing price war.

Moscow and Riyadh later mended ties through a new OPEC+ agreement to respond to a demand plunge driven by the Covid-19 pandemic — and have remained like-minded on OPEC+ matters since. Voiding the perception of a public rift, Saudi Foreign Minister Prince Faisal bin Farhan al-Saud and his Russian counterpart Sergey Lavrov on Thursday met on the sidelines of a BRICS summit in Cape Town.

The two reviewed the cooperation between their countries and “ways to strengthen & develop them in all fields, in addition to discussing the consolidation of bilateral & multilateral action,” according to the Saudi foreign ministry.

Two OPEC+ delegates, who did not want to be named due to the market sensitivity of the meeting, told CNBC that further output cuts were unlikely this weekend. One noted that this will remain the case unless demand stays low in China — where recovery has fallen short of expectations, in the wake of shedding strict Covid-19 restrictions.

A third source said that OPEC+, which prioritizes the state of global inventories over outright prices, would be comfortable with futures above $75 per barrel, while a fourth estimated near $70-80 per barrel.

Brent futures with August expiry were trading at $75.70 per barrel at 10:24 a.m. in London, up $1.42 per barrel from the Thursday settlement.

The OPEC+ group isn’t “after spikes” and seeks a “balanced market,” the fourth delegate told CNBC, stressing that the alliance must continue to strike a “precautionary” production strategy. Deep cuts also risk re-attracting U.S. ire, as Washington has historically criticized supply reductions that pile strain on consuming households.

‘Wait and see’?

Goldman Sachs’ analysts expect OPEC+ to keep production unchanged this weekend. However, they said in a note Wednesday that they see a “sizeable 35% subjective probability” of further OPEC cuts, as oil prices are “clearly below our $80-85/bbl estimate of the OPEC put. Very low positioning, the Saudi determination not to give speculators free rein, and the decision to meet in person also suggest that deeper cuts will likely be discussed.”

OPEC+ has waded stormy waters for the better part of the year. Oil markets have historically been steered by physical supply and demand fundamentals — which have been increasingly overshadowed by broader macro-economic concerns over the fuel consumption impact of high inflation, bolstering interest rates and the spring collapse of several U.S. and European banks.

OPEC+ delegates also said the group had been following U.S. debt ceiling negotiations, as the proposal of President Joe Biden and House Speaker Kevin McCarthy transited several debate and vote stages in a bid for the world’s largest economy to avoid defaulting on its bills.

“The impact of higher oil prices on the global economy will weigh heavily on the ministers’ minds,” Jorge Leon, senior vice president of oil market research at Rystad Energy, said in a Thursday note, adding that OPEC+ could maintain production as a precaution. “The ministers might therefore take a ‘wait and see’ approach and hold off taking any action. Demand forecasts remain lukewarm at best, so maintaining current output could be the most prudent course. “

Supply is also under question, given involuntary declines.

Roughly 450,000 barrels per day of northern Iraqi exports were frozen by a legal dispute between Baghdad, Ankara, and the Kurdistan Regional Government. Nigeria, typically West Africa’s largest oil producer, self-reported its April crude production at just 999,000 barrels per day following disruptions, according to OPEC’s Monthly Oil Market Report for May.

Meanwhile, the true extent of Russian output losses remains unclear, as vessels carrying Moscow’s crude turn off their satellite tracking and Russia looks to further shift its clientele east.

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Underwhelming June Heat Crushes Natural Gas Forwards as Storage Levels Rise – Natural Gas Intelligence

As natural gas markets restlessly awaited the arrival of more impressive cooling demand, regional forwards tumbled from coast to coast during the May 25-31 trading period, NGI’s Forward Look data show.

July fixed prices at benchmark Henry Hub shed 30.6 cents for the period to end at $2.267/MMBtu. Discounts of around 25-35 cents were common throughout the Lower 48.

In the Midwest, Chicago Citygate July prices dropped 28.7 cents to average $2.107, while in the Mid-Atlantic, Transco Zone 5 shed 25.7 cents to $2.843. Farther south, Florida Gas Zone 3 gave up 37.3 cents to $2.882.

[How much more U.S. natural gas storage capacity is needed — and is it on the way? Join NGI’s Director of Strategy & Research Patrick Rau, as he dives into what’s around the corner in terms of natural gas storage and the market fundamentals driving it. Listen now.]

A few West Coast hubs posted steeper fixed price discounts. PG&E Citygate July prices plunged 81.0 cents to end the period at $4.162.

Summer On Hold?

Memorial Day serves as the unofficial start of summer. The pools open. Grills are fired. Jackets are increasingly swapped out for t-shirts and shorts. But from a natural gas demand standpoint, bulls spent the holiday waiting for the season to start in earnest, disappointed by June forecasts that lacked the heat needed to impress traders.

That absence of heat further prevented the market from building on the bullish momentum created by a surprisingly steep drop in natural gas-directed drilling last month.

Updated forecasts as of Thursday advertised comfortable conditions for much of the country to start June, flashing the potential for more intimidating heat to develop as the month progresses, according to NatGasWeather.

Midday data from the American model Thursday showed increasing demand for June 11-15 as high temperatures in the 90s were expected to increase in coverage across Texas, the South and the Southeast, the firm said.

“Longer-range weather maps maintain a rather hot U.S. pattern gaining ground during the second half of June as highs of 90s increase over the southern half of the U.S.,” NatGasWeather said. 

With markets “getting more impatient by the day waiting on widespread heat to arrive,” a lot could hinge on how June weather patterns develop in the coming weeks, according to the firm.

“If hotter patterns don’t come through for mid and late June, and if U.S. production doesn’t show any signs of declining, bears could have eyes for $2 sooner than later,” NatGasWeather said. “Conversely, if hotter patterns were to come through for the second half of June, and if power burns prove more impressive than market expectations, we must expect a short-covering rally.”

Storage Levels Swell

Nymex futures lost ground throughout the May 25-31 trading period, weighed down by the prospect of continued production strength and lackluster early June heat further padding the current inventory surplus.

The June Nymex contract posted a double-digit decline in its last day of trading, rolling off the board at $2.181 ahead of Memorial Day weekend. July, trading at a more than 20-cent premium to June heading into the weekend, sold off sharply in post-holiday trading.

Following a sizable triple-digit injection from the latest Energy Information Administration (EIA) storage report, July settled at $2.158 Thursday, off 10.8 cents on the day.

EIA reported a 110 Bcf injection for the week ended May 26, exactly on target with NGI’s modeling for the print. The build outpaced the 101 Bcf five-year average injection. Inventories exited the period at 2,446 Bcf, a 349 Bcf (plus 16.6%) surplus to the five-year average, according to EIA.

“Elevated production, subdued LNG and cooling demand reverting lower may enable the storage surplus to approach 400 Bcf above five-year norms into late June,” EBW Analytics Group analyst Eli Rubin told clients in a recent note. “While our long-term storage trajectory is sharply lower and the medium- to long-term fundamental outlook points to upside price potential, natural gas may have to muddle through a near-term soft patch in coming weeks first.”

In the near term, forecasts showing cooler-than-normal temperatures blanketing the southern half of the Lower 48 have undermined the anticipated seasonal rise in power burns, as have gains in wind and nuclear generation, according to Rubin.

“Near-term cooling demand is expected to languish below 30-year normals through mid-June as a cool southern tier of the country crushes early-season cooling demand,” the analyst said. “…Power sector demand may still rise 10 Bcf/d over the next five weeks — but meaningful increases” were not expected to materialize in the nearer term.

Congress To Rescue MVP?

Meanwhile, new developments in Washington, DC, could reshape the natural gas supply outlook longer term. 

The Biden Administration and House Republicans reached an agreement over the Memorial Day weekend to raise the debt ceiling. 

The proposed House bill included provisions to authorize the Mountain Valley Pipeline’s (MVP) permits and shield the embattled natural gas pipeline from further setbacks in court.

The bill also included permitting reforms aimed at streamlining federal environmental reviews.

According to analysts at Tudor, Pickering, Holt & Co. (TPH), a less obstructed permitting process could impact the outlook for natural gas prices in the event new infrastructure reduces Northeast supply constraints.

“Early indications from industry are that a more streamlined process could see previously tabled projects come back to the drawing board, though we will likely need to see successful test cases before large-scale, interstate projects make it into the mix,” the TPH analysts said in a recent note. “Ultimately, a significant improvement in permitting ability would have meaningful implications for the natural gas cost curve if Northeast supply constraints were mitigated in coming years.”

As for the MVP provisions in the debt bill, EBW’s Rubin said the firm was penciling in additional production in its 2024 outlook based on the news.

“While the debt ceiling bill itself would need to be passed in its current form…we have increased our 2024 production target by 1.0 Bcf/d,” Rubin said. “If the project can be placed in-service before the end of 2023, elevated Appalachian pipeline takeaway capacity could help head off shortage risks into next year.”

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Source Rock Royalties closes S.E. Saskatchewan light oil fee title & royalty acquisition with drill commitments | BOE Report

CALGARY, AB, June 1, 2023 /CNW/ – Source Rock Royalties Ltd. (“Source Rock”) (TSXV: SRR) (TSXV: SRR.WT), a pure-play oil and gas royalty company with an established portfolio of light oil focused royalties, announces that it has closed the acquisition of fee title mineral interests in two quarter sections of land (the “Fee Title”) and a 2% gross overriding royalty (the “GORR”) in approximately 5,800 gross acres (9 sections) of land in S.E. Saskatchewan (the “GORR Lands”). The combined purchase price for the transactions was $3.3 million and they have an effective date of May 1, 2023.

The Fee Title

The Fee Title is comprised of the following perpetual mineral interests:

  • 20% interest in 160 gross acres that is leased at a 20% royalty rate; and
  • 16.67% interest in 160 gross acres that is leased at a 20% royalty rate.

Both Fee Title interests recently had initial drilling completed by the respective operators. The purchase of the 20% Fee Title interest includes a commitment to drill two additional horizontal wells on or before October 31, 2023, however it is anticipated that both wells will be drilled in June 2023. Each Fee Title commitment well not satisfied will result in $200,000 in damages being due to Source Rock.

The GORR Lands

A portion of the GORR Lands are contiguous to or directly offsetting Source Rock’s existing royalty lands that are actively and successfully being developed. The majority of the GORR Lands are 100% working interest lands owned and operated by Anova Resources Inc., which provide Source Rock with exposure to multiple new areas that are highly prospective for future development of the Frobisher formation. The Frobisher is a shallow, conventional light oil play that does not require hydraulic fracturing; it is one of the most economic light oil plays in Canada. Portions of the GORR Lands are also prospective for future development of the Midale and Bakken formations.

Significant Drill Commitment

As part of the purchase of the GORR, Source Rock has received a drill commitment for 12 additional horizontal wells (each a “Drill Commitment Well”) to be drilled on Source Rock’s royalty lands prior to May 31, 2025 (the “Drill Commitment Deadline”). Source Rock is entitled to $125,000 in damages for each Drill Commitment Well not drilled before the Drill Commitment Deadline.

The Drill Commitment Deadline may be automatically extended as follows:

  • Upon the first time that the price of the NYMEX West Texas Intermediate (“WTI”) Light Sweet Crude Oil Futures Contract (in U.S. Dollars) settles below $60.00 for 30 consecutive days, it shall be extended by 90 days; and
  • Every time thereafter that the price of WTI settles below $60.00 for 30 consecutive days, it shall be extended by an additional 30 days.

President’s Message

We are excited for the near-term drilling activity that is planned on a portion of the Fee Title lands and to receive an additional drill commitment on our royalty lands. We are also very pleased to add acreage to our portfolio of light oil royalty lands in S.E. Saskatchewan. Our royalty acquisition strategy continues to be focused on a balanced approach to increasing our base of oil focused royalty production and expanding and diversifying exposure to drilling activity on highly prospective undeveloped lands.

Following completion of these acquisitions Source Rock has approximately $8.5 million of working capital ($0.19 per share) to pursue additional oil focused royalty acquisitions and partnerships with operators.

Brad Docherty, President & CEO

About Source Rock Royalties Ltd.

Source Rock is a pure-play oil and gas royalty company with an existing, light oil focused portfolio of royalty interests concentrated in southeast Saskatchewan, east-central Alberta, west-central Alberta and west-central Saskatchewan. Source Rock targets a balanced growth and yield business model, using funds from operations to pursue accretive royalty acquisitions and to pay dividends. By leveraging its niche industry relationships, Source Rock identifies and acquires both existing royalty interests and newly created royalties through collaboration with industry partners. Source Rock’s strategy is premised on maintaining a low-cost corporate structure and achieving a sustainable and scalable business, measured by growing funds from operations per share and maintaining a strong netback on its royalty production.

Forward-Looking Statements

This news release includes forward-looking statements and forward-looking information within the meaning of Canadian securities laws. Often, but not always, forward-looking information can be identified by the use of words such as “plans”, “is expected”, “expects”, “scheduled”, “intends”, “contemplates”, “anticipates”, “believes”, “proposes” or variations (including negative and grammatical variations) of such words and phrases, or state that certain actions, events or results “may”, “could”, “would”, “might” or “will” be taken, occur or be achieved. Forward-looking statements in this news release include statements regarding Source Rock’s dividend strategy and the amount and timing of future dividends (and the sustainability thereof), the potential for future drilling on Source Rock’s royalty lands (and in particular the Drill Commitment Wells being drilled prior to the Drill Commitment Deadline, if at all), expectations for results from the drilling on Source Rock’s royalty lands, expectations regarding commodity prices, Source Rock’s growth strategy and expectations with respect to future royalty acquisition and partnership opportunities, and the ability to complete such acquisitions and establish such partnerships. Such statements and information are based on the current expectations of Source Rock’s management and are based on assumptions and subject to risks and uncertainties. Although Source Rock’s management believes that the assumptions underlying these statements and information are reasonable, they may prove to be incorrect. The forward-looking events and circumstances discussed in this news release may not occur by certain dates or at all and could differ materially as a result of known and unknown risk factors and uncertainties affecting Source Rock. Although Source Rock has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking statements and information, there may be other factors that cause actions, events or results to differ from those anticipated, estimated or intended. No forward-looking statement or information can be guaranteed. Except as required by applicable securities laws, forward-looking statements and information speak only as of the date on which they are made and Source Rock undertakes no obligation to publicly update or revise any forward-looking statement or information, whether as a result of new information, future events or otherwise.

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 of this release.


SOURCE Source Rock Royalties Ltd.

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Malcy’s Blog: Oil price, UOG, Gran Tierra, Trinity, CEG/Predator, i3. And finally…

WTI (July) $68.09 -$1.37, Brent (July) $72.60 -$1.11, Diff -$4.51 +43c.

USNG (July)* $2.26 -6c, UKNG (July) 61.0p +2.74p, TTF (July) €24.265 -€0.93.

*June contract expiry

Oil price

We still have a mish-mash of factors influencing the oil price but at least the debt ceiling Bill passed the House. The view on the US economy continues to be mixed although the jobs numbers were positive, unless of course you want inflation down which the Fed do…So as for rates who knows but the dollar is still strong.

United Oil & Gas

United Oil & Gas has announced an update on the testing of the ASD-3 development well in the Abu Sennan licence, onshore Egypt. United holds a 22% non-operating interest in the Abu Sennan licence, which is operated by Kuwait Energy Egypt.


–       12.5 metres of net oil pay interpreted across the primary Abu Roash reservoir targets

–       730 bopd gross achieved on test from the Abu Roash E reservoir (“AR-E”)

–       684 bopd gross achieved on test from the Abu Roash C reservoir (“AR-C”)

–       This result has positive implications for the in-place volumes and future potential of the ASD Field

ASD-3 Well Results

The ASD-3 development well, reached total depth of 3,683 metres on 8 May, in line with the schedule and under budget. This well was drilled approx.1.2 kilometres to the north-west of the successful ASD-2 well which was drilled in March 2022.

The well has now been logged and is interpreted to have encountered 3 metres of net pay in the Abu Roash C reservoir (“AR-C”) and 9.5 metres of net pay in the Abu Roash E (“AR-E”), in line with pre-drill expectations.

The well has been completed, and has been tested from both the AR-C and AR-E at a number of different choke sizes, as summarised in the table below.


Choke Size

Duration of test

Average gross oil rate




8 hours

449 bopd


6 hours

565 bopd


8 hours

684 bopd




4 hours

439 bopd


4 hours

556 bopd


4 hours

730 bopd

The flow rates achieved during testing are in line with pre-drill expectations. The well has been completed with a single selective completion allowing production to first commence from one reservoir and then, once depletion has occurred, to be recompleted to produce from the other. A decision on which reservoir to initially bring onstream will be made in the coming days, after gauges have been recovered from the well, however United expect the well to come on production with an initial gross rate of between 500 and 600 bopd.

In addition to immediately adding several hundred barrels of oil per day to production, the ASD-3 well has also proven up the connectivity of the AR-E reservoir across the ASD Field which has positive implications for the in-place oil volumes in the AR-E reservoir and ultimate potential recovery from the field. The outcome from the well is consistent with the performance we have seen to date from the ASD-2 well, which came onstream in March 2022, and which has so far produced over 400,000 barrels of oil. This result also supports the JV view that there is long-term production potential in both the AR-C and AR-E reservoirs of the ASD field and there will now be a focus on evaluating future drilling options with the JV partners to ensure that we maximise the recovery from the field.

Drilling plans for the remainder of 2023 will be announced following the completion of the evaluation of the H1 drilling activity and following agreement with the JV partners.

United Chief Executive Officer, Brian Larkin commented:

“ASD-3 is the second successful well in our 2023 drilling programme, delivering additional production and revenue to United as the well is brought into production through existing facilities. Discussions are underway with our JV partners on plans to maximise the economic return from the potentially large in-place volume on ASD that this result has indicated.  Alongside this our workover programme continues on the licence, aiming to deliver optimum production from all of our existing wells. We will update the market on our future Abu Sennan drilling plans once the JV partners have fully evaluated the drilling results from the first two wells drilled this year.”

It is good to see UOG back in the saddle with a decent well result at Abu Sennan and as Brian Larkin pointed out to me this morning, none of the value from the prospect has gone, it is just as when they bought into it some 4 years ago. 

UOG remains a well managed company which I am sure will strengthen up with some specific M&A activity and of course Jamaican excitement is looming larger…

Gran Tierra

Gran Tierra announced an operational update. All dollar amounts are in United States dollars, and production amounts are on an average working interest before royalties basis unless otherwise indicated. Per barrel and bbl of oil per day amounts are based on WI sales before royalties.

Message to Shareholders

Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented:

“During 2023 year-to-date, Gran Tierra has completed most of its development program for 2023 with the drilling of 19 development wells, consisting of 12 new production wells and 7 new water injection wells. We remain on track and on budget with our development and exploration drilling programs for 2023. We are also very pleased with the exciting oil production results that we are seeing from our Acordionero, Costayaco and Moqueta infill development well drilling programs.

The success of our 2023 development program has been an important factor in our ongoing ramp up in oil production during 2023 and continues to demonstrate the excellent production capabilities of our major assets. We expect the ongoing positive results from our waterflood projects in the Acordionero, Costayaco, Moqueta and Suroriente fields to continue adding oil production from existing and new wells for the remainder of 2023. We are also beginning to see positive results in our polymer flood project in Acordionero.

By completing the majority of our development program in the first 5 months of 2023, we expect to realize higher oil production for the rest of 2023. With most of our development capital behind us, this should allow us to maximize cash flow. We believe the Company is well positioned to optimize value and grow production from our assets through continued enhanced oil recovery activities as demonstrated by our total current average production(1) of approximately 36,800 BOPD.”

Having said that Gran Tierra was a company and management that I had a great deal of time for but had not seen for a while I was rewarded by a one to one with a senior team on their recent visit to London. Although at a market cap of over £1.5bn it is larger than most I follow I love to operating area, ie Colombia and know the CEO from his previous history and we have shared industry contacts. 

This update indicates just how well the current drilling campaign is going and of the 19 development wells 12 have been producers and 7 water-injection with all results ‘encouraging’. As a result production is up, 36,800 b/d right now leading to strong cash flow. 

The share price performance has been terrible, maybe the tip is to avoid being sucked into a share consolidation which can’t have helped recent performance. But the shares, like a number of others do look very cheap, it is a great portfolio of assets in a great post code and as mentioned high quality management. Worth putting on the radar screen for investors. 

Operations Update:


  • Gran Tierra has begun to ramp up production in the latter half of second quarter 2023, as newly drilled Acordionero, Costayaco and Moqueta oil wells have been steadily brought online. Gran Tierra’s total current average production(1) is approximately 36,800 BOPD.
  • During second quarter-to-date 2023, The Company has achieved total average production(2) of approximately 33,600 BOPD.
  • During 2023 year-to-date, Gran Tierra has achieved total average production(3) of approximately 32,400 BOPD, which is within the Company’s previous forecast range for 2023 of 32,000-34,000 BOPD.


  • During 2023 year-to-date, Gran Tierra has drilled a total 19 development wells in Colombia, consisting of 12 new production wells and 7 new water injection wells:
    • Acordionero:
      • Development drilling resumed in January 2023 with a 10-well program that was completed in April 2023.
      • 6 wells are on production and 4 wells are on water injection.
      • As a result of the development program and continued good performance of the field’s enhanced oil recovery via waterflood, Acordionero has achieved average production(2) of approximately 18,600 BOPD during second quarter-to-date 2023, which is the highest level since May 2019.
      • During second quarter 2023, Gran Tierra achieved a new water injection record of approximately 72,000 bbl of water injected per day.
      • The polymer flood pilot was expanded with the start up of a third polymer injection well during second quarter 2023. Acordionero’s polymer flood pilot is expected to increase the field’s ultimate oil recovery.
    • Costayaco:
      • Gran Tierra has finished drilling all 7 wells in the Company’s 2023 Costayaco development campaign. The program consisted of 4 production wells and 3 water injection wells.
      • 2 production wells are currently on long-term production test and 2 water injection wells started up during second quarter 2023.
      • A summary of the recent production tests for the 2 new Costayaco production wells is provided below:
Average Production Test Rates over Period
Well NameDate Range of
Production Test
Oil (bbl/day)Watercut (%)Gas-Oil Ratio
Producing Zones
CYC-51May 22-26/202397617150Villeta & Caballos
CYC-52May 19-28/20233,34045312Villeta & Caballos

*scf = standard cubic feet

The remaining 2 new production wells and 1 new water injection well are expected to be completed and tied-in during June 2023.
The completion and stimulation of the remaining production wells and waterflood optimization through additional water injection are expected to continue to grow Costayaco’s oil production throughout the year.
2 production wells that were drilled during first quarter 2023 have both been stimulated and placed on production.
A summary of the recent production tests for the 3 newest Moqueta production wells is provided below:
Average Production Test Rates over Period
Well NameDate Range of
Production Test
Oil (bbl/day)Watercut (%)Gas-Oil Ratio
Producing Zones
MQT-24May 18-27/20231,02117554Villeta & Caballos
MQT-25May 20-26/202365039418Villeta & Caballos
MQT-26May 18-25/20234745239Caballos

*scf = standard cubic feet

1 production well is currently being drilled, with one additional production well expected to be drilled during late June – early July 2023.
The 2 additional production wells, along with 2 planned conversions of existing wells into water injection wells, are expected to grow Moqueta’s oil production and optimize its waterflood.

1 Total current average production is for the 15-day period of May 14, 2023 to May 28, 2023.
2 Total average production during second quarter-to-date 2023 is for the period of April 1, 2023 to May 28, 2023.
3 Total average production during 2023 year-to-date is for the period of January 1, 2023 to May 28, 2023.

Trinity Exploration & Production

Trinity announces its final results for the year ended 31 December 2022.

During 2022 Trinity put in place the foundations for an ambitious growth programme, developing a series of catalysts to drive shareholder value that we are now starting to execute in 2023.  These include:

·    drilling the Jacobin well targeting the deeper Miocene-age turbidite play in our onshore blocks;

·    the application for the highly prospective Buenos Ayres block in the 2022 Onshore Bid Round, the outcome of which is expected shortly; and

·    revised planning to further exploit the Galeota offshore block, focused on greater capital efficiency and shorter development and payback times.

Underlining the resilience of the base business, the Company is committing to a new Capital Allocation Policy which will include a modest but sustainable dividend commencing in Q3 2023 with an intent for that to form part of a broader distribution of operating cash flow to shareholders, depending on realised oil prices.


·    Group net sales for 2022 were 2,975 bopd (2021: 3,006 bopd)

·    Revenues of USD 92.2 million (2021: USD 66.3 million)

·    Profit before tax of USD 2.5 million (2021: USD 3.0 million)

·    Average price per barrel received was USD 84.9/bbl (2021: USD 60.4/bbl)

·    Adjusted EBITDA (before hedge costs) of USD 35.1 million (2021: USD 21.1 million)

·    Adjusted EBITDA of USD 24.7 million (2021: USD 19.8 million)

·    Operating Profit* of USD 19.0 million (2021: USD 9.3 million)

·    Cash generated from continuing operations USD 12.0 million (2021: USD 12.6 million)

·    Cash flow used in investing activities USD 15.6 million (2021: USD 13.9 million)

·    Year-end cash USD 12.1 million (2020: USD 18.3 million)

* Before SPT, Impairments and Exceptional Items

New Capital Allocation Policy

·    The Company aims to distribute 15% of operating cash flow to shareholders, for each calendar year when the realised oil price is greater than $50/bbl, and at least 20% of operating cash flow for periods when the realised price is above $80/bbl

·    Payment of a modest but sustainable dividend and the scope for additional distributions in the form of share buybacks or special dividends

·    Expected to include a total dividend (split 1/3 interim, 2/3 final) of 1.5p per share, provided the realised price is at least $50/bbl

·    It is expected that the maiden interim dividend will be declared following publication of the 2023 interim results, in Q3 2023, followed by a final dividend declared following publication of the 2023 preliminary results in Q2 2024

Positioned for Next Growth Phase and progressing catalysts

·    Dynamic strategy for growth is underpinned by a strong balance sheet and resilient and dependable cash flow

·    Clearly defined, risk-mitigated strategy to drive returns for shareholders – focus on maximising value from existing assets and through acquisitions and partnerships

·    Strengthened Management Team

·    Additions of Julian Kennedy, Mark Kingsley and Alistair Green further strengthening financial/commercial, operational and wider industry skill sets

·    Creation of Technical Committee

·    Focused on risk-mitigation and assurance of opportunities which can increase scale and optimise returns

Post Period Highlights

·    Continued momentum into Q1 2023

·    Q1 production levels resilient with sales volumes averaging 2,899 bopd (Q4 2022: 2,961 bopd).  Average production in 2023 will be influenced by the timing and outcome of the drilling campaign and continued workover and recompletion programme.

·    Average realisation of USD 67.9/bbl for Q1 2023 (Q4 2022: USD 75.4/bbl, Q1 2022: USD 83.1/bbl)

·    Cash balance of USD 11.4 million (unaudited) as at 31 March 2023 versus USD 12.1 million as at 31 December 2022 and USD 17.5 million as at 31 March 2022.

·    The Group had drawn borrowings (overdraft) of USD 2.3 million as at 31 March 2023 (USD 2.7 million as at 31 December 2022 and USD 2.7 million as at 31 March 2022).

·    On 9 January 2023, the Company submitted a bid for the Buenos Ayres block in the 2022 Onshore and Nearshore Competitive Bid Round.  The results of the Bid Round are expected shortly.

·    On 3 May 2023, the Government of Trinidad and Tobago Ministry of Energy and Energy Industries (“MEEI”) provided confirmation of the renewal of the PGB Licence for an additional 25 years from the Effective Date of 18 December 2012.  Consequently, the PGB Licence expires on 17 December 2037.  There were no additional liabilities and commitments arising from the renewed Licence.

·    The Company commenced drilling the Jacobin prospect on 15 May 2023, the first of the nine ‘Hummingbird’ deeper prospects our 3D seismic has identified across our Palo Seco acreage.

Jeremy Bridglalsingh, Chief Executive Officer of Trinity, commented:

“During 2022 Trinity initiated an ambitious growth programme, seeking to develop a series of catalysts to drive shareholder value that we are now starting to execute in 2023.  We have actioned three key growth initiatives which we believe have the potential to deliver meaningful value for shareholders.

Our core business has continued to perform consistently, forming the basis upon which the capital allocation policy has been designed.  The spudding of Jacobin is an important milestone for the Company and will help determine our further activities throughout 2023 as we look to harness the potential of the extensive Palo Seco play which extends into the Buenos Ayres block to the west, which Trinity applied for in the 2022 Onshore Bid Round.  On Galeota we initiated a revised development plan, including the existing Trintes producing field as well as appraisal and exploration opportunities, which we are aiming to finalise by Q4 this year.

2022 was a significant year for Trinity and 2023 has begun to bear the fruits of this work. I believe we have the right focus to deliver further progress and I look forward to updating our key stakeholders as we move through the year.”

Trinity is in an interesting situation, production actually fell last year despite working on the estate and Jacobin is the only realistic sight of an increase of any meaningful increase in the absence of funding for Galeota. According to my report yesterday from a Reuters article Trinity have indeed been awarded the Buenos Ayres block which is a tick in the box.

What I find difficult is that there is going to be a strange combination of raising money for Galeota shortly after paying out the initial capital allocation policy by way of a dividend. I look forward to hearing the company presentation in a couple of weeks time but whilst paying out a dividend is a popular amongst E&P companies at the moment it rarely happens at the same time as going to the market for equity…

Challenger Energy Group/Predator Oil & Gas

Challenger Energy and Predator have provided the following update in relation to the sale of the Cory Moruga licence, onshore Trinidad.

On 8 March 2023, the Company announced that it had entered into an agreement with Predator Oil and Gas Limited pertaining to the sale of the Cory Moruga asset in Trinidad. In that announcement, it was noted that completion of the transaction was conditional on consent of the Trinidadian Ministry of Energy and Energy Industries to a revised work programme for the Cory Moruga licence proposed by the Company, as well as agreement of MEEI to a revision of future fees for the Cory Moruga licence and a settlement / cancellation of past claimed dues pertaining to the Cory Moruga licence. It was further noted that the parties had agreed to work together to secure the required consents, and thus achieve completion, as soon as reasonably practicable on or before 30 May 2023, with a long stop date of 31 August 2023.

Since March 2023, the parties have worked together as required, and are engaged in a dialogue with MEEI. This is proceeding well, but the conditions for completion of the transaction have not been satisfied as at 30 May 2023. The parties remain confident, however, that appropriate consents and agreement with MEEI will be forthcoming based on dialogue with MEEI. Accordingly, the parties have mutually agreed to an extension of the 30 May 2023 target date for completion of the intended transaction, to coincide with the long-stop date of 31 August 2023.

Nothing to add here, I can just imagine the scene in Trinidad….

i3 Energy

i3 Energy has announced that the time limit for shareholders in Toscana Energy Income Corporation to claim their ordinary shares in the Company from Odyssey Trust Company pursuant to the Company’s acquisition of Toscana by way of a plan of arrangement involving, among others, the Company and Toscana, has now expired.  At the time of expiry, Odyssey held 25,503 ordinary shares in the Company and the Trust Shares on the expiry of the time limit reverted to the Company to be held in treasury in accordance with the terms of the Arrangement.

On 29 May 2023, the Company cancelled the Trust Shares that were held in treasury.  The ordinary shares cancelled represented approximately 0.002% of the issued share capital of the Company.

Following the above cancellation, as at the date of this announcement, the Company has 1,201,874,464 ordinary shares with a nominal value of £0.0001 each in issue.  Shareholders may use this figure of ordinary shares as the denominator by which they are required to notify their interest in, or change their interest in, the Company under the Disclosure Guidance and Transparency Rules.

And finally…

The first test of the summer started at Lords today with England taking on Ireland. As I write England won the toss and Ireland batting first are

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Key research shared today by the Offshore Energy Digital Strategy Group (OEDSG) at an OEUK- hosted webinar reveals digitalisation across the oil and gas and renewable energy sectors is gathering momentum.

The 2023 Offshore Energy Digital & Data Maturity Survey report aims to deepen understanding of how organisations are applying data and digital technologies to help transform the UK energy system to achieve net zero targets. More than 30 oil, gas and renewable operator companies contributed to the survey with input also provided by technology developers and supply chain companies supporting diverse offshore energies.

The OEDSG comprises Offshore Energies UK (OEUK), Opportunity North East (ONE), Net Zero Technology Centre (NZTC), Technology Leadership Board (TLB), North Sea Transition Authority (NSTA), The Crown Estate and Crown Estate Scotland, who with support from Deloitte, developed the survey, building on the findings of a baseline study conducted in 2020.

Findings from 2023 data reveal progress in the pace and integration of digitalisation with organisations recording an 8 per cent improvement across key metrics relating to strategy, leadership, training and capabilities. In comparison, the survey identifies a lag in data maturity which suggests more companies need to focus attention on developing data strategies if they are to capitalise on the opportunities ahead. There are, however, signs that companies are increasingly adopting a wider range of digital technology and data indicating this situation will improve in the future.

Feedback highlighted how increasing collaboration and coordination could enable organisations to unlock the full potential of data and digital technologies, enabling them to play a key role in accelerating the shift to cleaner energy production. It cites evidence of progress with organisations adopting data-related technologies including cloud platforms, data mesh, and data visualisation tools that are enabling greater levels of collaboration.

With people and skills playing an integral role in the energy transition, the survey highlighted the lack of access to digital and data skills as a key risk to the delivery of digital and data strategies. Challenges relate to both the upskilling of the existing workforce and recruiting new personnel into key roles across the sectors, with calls for organisations to step up initiatives to equip their staff with the necessary knowledge and training.

Using the survey to share insights on trends and challenges, the OEDSG recommends actions for individual organisations and industry and government bodies that will help drive forward the energy transition and these include:

  • Increasing efforts to improve digital maturity, with a focus on smaller organisations, equally across wind, oil, and gas.
  • Strengthening collaboration between parties including between operators in every energy sector, between operators and the supply chain and between energy sectors to drive effective cross-industry digitalisation.
  • Fostering a culture in which leaders encourage staff to adopt data-driven work practices and equip employees with the necessary skills and knowledge.

Daniel Brown, OEUK’s Head of Data & Digital said:
“Data and digital technologies play a key role in driving greater collaboration and efficiency across the UK energy sector. This survey provides invaluable insight of how and where we can work together to shape and accelerate our digital efforts in support of delivering net zero’.

Karen O’Hanlon, Director Digital Tech at Opportunity North East (ONE) said:
“The role of digital and data technologies in achieving the transition to net zero cannot be overstated. They provide essential tools for monitoring, optimising, and managing energy systems, enabling more efficient resource utilisation and facilitating the integration of renewable energy sources. However, the success of these technologies relies heavily on having access to technical talent. Upskilling the workforce and attracting new tech talent to the sector are priorities for ONE and our partners in the North East of Scotland.

Carlo Procaccini, Technology Leadership Board Co-chair, said:
“I am pleased with the publication of this important report looking at data and digital maturity across the offshore energy sectors.  Data are crucial for the optimal use of the UKCS to provide energy security and accelerate the energy transition.  The report highlights industry progress with data access and digital technologies to extract value from the data, but highlights the urgent need for greater investment in data management and digital skills development.  Regulators and industry bodies have an important role in catalysing this. “

Karen O’Hanlon, Director Digital Tech at Opportunity North East said:
“Digital and data technologies are vital to achieving the transition to net zero. They provide essential tools for monitoring, optimising, and managing energy systems. They enable more efficient resource utilisation and facilitate the integration of renewable energy sources. We also need people and skills to achieve this. Upskilling the existing workforce and attracting new tech talent to the sector and region are priorities for ONE and partners.”

Nic Granger, Chair of the OEDSG and NSTA Director of Corporate, said:
 “It is hugely encouraging to learn that offshore energy companies are increasingly using digital tools to transform the way they work. However, as the recommendations in our report show, there are still plenty of opportunities for businesses to improve. The OEDSG will play its part in coordinating efforts to realise the full potential of data and digitalisation, accelerating the transition to net zero.”

Olivia Thomas, Head of Marine Planning at The Crown Estate, said:
“The exciting potential of the offshore environment to support nature recovery, unlock renewable energy opportunities, and support energy security means it’s becoming increasingly busy, with more demands on it than ever before. As manager of the seabed around England, Wales and Northern Ireland, we’re committed to collaborating with a wide range of organisations to grow data and digital capabilities to build a joined-up picture of the diverse demands on this space and manage it so that these priorities can be realised for the benefit of the nation and the natural world. Quality data, as well as quality platforms to share, analyse and interrogate data, are key to understanding and addressing these challenges.  Today’s report shows promising progress, but also reveals more needs to be done to ensure digitalisation can fulfil its potential to help deliver, and accelerate, positive impacts for all.”

Marc Gellatly, Energy & Infrastructure Data Technical Lead for Crown Estate Scotland, said: “Investing in this survey has allowed us to better understand our offshore renewables stakeholders’ data and digital needs. The results have provided Crown Estate Scotland with a solid evidence base to inform how we further support data and digital contributing to the offshore energy sector’s progress to net-zero.”

Graeme Booth, Head of Digital Technology, Net Zero Technology Centre (NZTC), said: “By harnessing the power of data and implementing both data and digital strategies, organisations can gain unparalleled insights, optimise operations, and accelerate their progress towards a net-zero future. Embracing these advancements is not to be feared, but rather an opportunity to unlock immense value. We’re seeing evidence of this in some organisations. However, it is crucial for all organisations to develop their internal digital skills to foster innovation and facilitate the adoption of technology.”

The report can be downloaded here

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Energy Groups React to Debt Ceiling Deal

Energy Workforce & Technology Council (EWTC) President Tim Tarpley said the organization “applauds the bipartisan agreement to lift the debt ceiling”, which he highlighted includes “important reforms to the National Environmental Policy Act to help speed up projects” and “an agreement to finish the Mountain Valley Pipeline”.

“This is a positive step forward by Congress, but more must be done,” Tarpley noted in a statement sent to Rigzone.

“Global energy demand is increasing, including demand for oil and gas. Without changes to the status quo, we will not have the infrastructure, the resources or grid capacity to provide energy services to American consumers and our allies in an affordable, reliable manner,” he added.

“It is unacceptable that the average time to permit a new energy infrastructure project in the United States is now exceeding that of many western countries. This gridlock is a direct threat to American energy security,” he continued.

In the statement, Tarpley said the EWTC encourages passage of the bipartisan agreement “and a commitment from lawmakers to work together for more robust permitting reforms”.

Also commenting on the debt ceiling deal, American Petroleum Institute (API) President and CEO Mike Sommers said the API “applaud[s] Congress and the Biden administration for reaching a bipartisan agreement that includes important progress on permitting reform”.

“Our current system for reviewing the infrastructure projects that fuel our economy and support our way of life did not become an endless gauntlet of bureaucratic hurdles overnight, and it will take more than one step to develop a workable process,” he added.

“This is a positive start, and we look forward to continuing to work with policymakers on both sides of the aisle to pass this agreement and build on this progress,” Sommers went on to state.

The Congress website shows that H.R.3746 – the Fiscal Responsibility Act of 2023 – passed the House on May 30, with 225 yeas to 204 nays, after being introduced on May 29. The bill still needs to pass the Senate and go to the President before becoming law, the site outlines.

According to a summary of the bill posted on the site, H.R.3746 increases the federal debt limit, establishes new discretionary spending limits, rescinds unobligated funds, and expands work requirements for federal programs.

Specifically, the bill suspends the federal debt limit through January 1, 2025, and increases the limit on January 2, 2025, to accommodate the obligations issued during the suspension period, the summary notes. In addition, the bill establishes new discretionary spending limits for FY2024 and FY2025 that are enforced with sequestration, it adds.

The bill also includes provisions that “expedite the permitting process for certain energy projects”, the summary states.

Rigzone has contacted the U.S. Department of Energy (DOE) and the U.S. Department of the Interior (DOI) for comment on Tarpley and Sommers’ statements, and comment on H.R.3746. At the time of writing, the DOE and DOI have not yet responded to Rigzone’s requests.

The EWTC describes itself as the national trade association for the global energy technology and services sector. It represents more than 660,000 U.S. jobs in the technology-driven energy value chain, according to the organization, which notes that it works to advance member policy priorities and empower the energy workforce of the future.

The API represents all segments of America’s natural gas and oil industry, which supports nearly 11 million U.S. jobs, the organization notes on its site. The API has approximately 600 members which produce, process, and distribute the majority of the nation’s energy, its site highlights. The organization was formed back in 1919 as a standards-setting organization and has since developed more than 800 standards to enhance operational and environmental safety, efficiency, and sustainability, according to its site.

To contact the author, email [email protected]

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