Category: Oil and Gas

CALGARY, Alberta, April 29, 2024 (GLOBE NEWSWIRE) — Gibson Energy Inc. (TSX:GEI) (“Gibson” or the “Company”) announced today its financial and operating results for the three months ended March 31, 2024.

“We are pleased to announce a strong start to the year, driven by stable, high-quality cash flows from our Infrastructure segment, which includes both our Canadian assets and our now fully integrated Gateway Terminal, which achieved record volumes in March,” said Steve Spaulding, President and Chief Executive Officer. “These positive financial results further enhance our conservative financial profile, with our payout and leverage ratios at or below our target ranges. As we look forward, we are focused on execution, including contract discussions at our Gateway Terminal and continued construction of the two new TMX tanks at our Edmonton Terminal.”

Financial Highlights:

• Revenue of $3,289 million in the first quarter, a $923 million or 39% increase relative to the first quarter of 2023, primarily due to higher sales volumes within the Marketing segment and revenue contribution from the Gateway Terminal
• Infrastructure adjusted EBITDA⁽¹⁾ of $151 million in the first quarter, a $43 million or 40% increase from the first quarter of 2023, primarily driven by the contribution from the Gateway Terminal
• Marketing adjusted EBITDA⁽¹⁾ of $34 million in the first quarter, a $25 million or 43% decrease from the first quarter of 2023, due to weaker contributions from both Refined Products and Crude Marketing
• Adjusted EBITDA⁽¹⁾ on a consolidated basis of $170 million in the first quarter, a $15 million or 10% increase over the first quarter of 2023, as a result of the factors described above
• Net income of $40 million in the first quarter, a $48 million or 54% decrease over the first quarter of 2023, due to the impact of unrealized gains and losses on financial instruments, higher finance and executive transition costs, as well as depreciation and amortization expenses, partially offset by lower income tax expense and higher adjusted EBITDA⁽¹⁾, as noted above
• Distributable cash flow⁽¹⁾ of $114 million in the first quarter, a $7 million or 7% increase from the first quarter of 2023, as a result of the factors described above
• Dividend payout ratio⁽²⁾ on a trailing twelve-month basis of 63%, below the Company’s 70% – 80% target
• Net debt to adjusted EBITDA ratio⁽²⁾ at March 31, 2024 of 3.5x, which is within the Company’s 3.0x – 3.5x target range, notwithstanding adjusted EBITDA⁽¹⁾ only including eight months of contribution from the Gateway Terminal; the net debt to adjusted EBITDA ratio⁽²⁾ is expected to be temporarily elevated until twelve months of adjusted EBITDA⁽¹⁾ from the Gateway Terminal is reflected in the Company’s net debt to adjusted EBITDA ratio⁽²⁾

Strategic Developments and Highlights:

• Fully integrated the operations and maintenance functions of the Gateway Terminal from Buckeye to Gibson effective January 1, 2024
• Announced Steve Spaulding’s intention to retire as President and Chief Executive Officer. Gibson’s Board has engaged a search firm to evaluate internal and external candidates; to ensure a smooth transition, Mr. Spaulding will continue to serve in his current role and remain on the Board until a successor has been identified and appointed
• Appointed Craig V. Richardson to Gibson’s Board; Mr. Richardson brings extensive U.S. commercial and regulatory experience, and serves on the Audit Committee and Health and Safety Committee
• Announced that Gibson achieved top quartile safety performance among peers for the third consecutive year, including record low Total Recordable Injury Frequency of 0.22 in 2023

Management’s Discussion and Analysis and Financial Statements
The 2024 first quarter and year-end Management’s Discussion and Analysis and unaudited Condensed Consolidated Financial Statements provide a detailed explanation of Gibson’s financial and operating results for the three months ended March 31, 2024, as compared to the three months ended March 31, 2023. These documents are available at www.gibsonenergy.com and on SEDAR+ at www.sedarplus.ca.

Earnings Conference Call & Webcast Details
A conference call and webcast will be held to discuss the 2024 first quarter financial and operating results at 7:00am Mountain Time (9:00am Eastern Time) on Tuesday, April 30, 2024.

To register for the call, view dial-in numbers, and obtain a dial-in PIN, please access the following URL:

Registration at least five minutes prior to the conference call is recommended.

This call will also be broadcast live on the Internet and may be accessed directly at the following URL:

The webcast will remain accessible for a 12-month period at the above URL.

Annual General Meeting & Webcast Details
Gibson is holding its Annual Meeting of Shareholders on Tuesday, April 30, 2024 at 10:00am Mountain Time (12:00 noon Eastern Time). This meeting will be held in a hybrid format (virtual and in-person). Applying technology to the meeting by allowing virtual participation will make the meeting more relevant, accessible and engaging for all involved, permitting a broader base of shareholders to participate in the meeting, regardless of their geographic location.

Attending In-Person:

• Lumi Experience Studio
• Suite 1410, 225 6 Ave SW, Calgary, Alberta

Attending virtually can be accessed using the following URL:

The webcast will remain accessible for a 12-month period at the above URL.

Additionally, information and materials related to the annual general meeting of shareholders can be accessed using the following URL:

Supplementary Information
Gibson has also made available certain supplementary information regarding the 2024 first quarter financial and operating results, available at www.gibsonenergy.com.

About Gibson
Gibson is a leading liquids infrastructure company with its principal businesses consisting of the storage, optimization, processing, and gathering of liquids and refined products. Headquartered in Calgary, Alberta, the Company’s operations are located across North America, with core terminal assets in Hardisty and Edmonton, Alberta, Ingleside, Texas, and a facility in Moose Jaw, Saskatchewan.

Gibson shares trade under the symbol GEI and are listed on the Toronto Stock Exchange. For more information, visit www.gibsonenergy.com.

Forward-Looking Statements
Certain statements contained in this press release constitute forward-looking information and statements (collectively, forward-looking statements) including, but not limited to, statements concerning Gibson’s ability to enter into contracts for the Gateway Terminal, the construction and completion of additional tankage and the retirement of Gibson’s President and Chief Executive Officer and the replacement and transition of this role. All statements other than statements of historical fact are forward-looking statements. The use of any of the words ‘‘anticipate’’, ‘‘plan’’, ‘‘contemplate’’, ‘‘continue’’, ‘‘estimate’’, ‘‘expect’’, ‘‘intend’’, ‘‘propose’’, ‘‘might’’, ‘‘may’’, ‘‘will’’, ‘‘shall’’, ‘‘project’’, ‘‘should’’, ‘‘could’’, ‘‘would’’, ‘‘believe’’, ‘‘predict’’, ‘‘forecast’’, ‘‘pursue’’, ‘‘potential’’ and ‘‘capable’’ and similar expressions are intended to identify forward looking statements. The forward-looking statements reflect Gibson’s beliefs and assumptions with respect to, among other things, Gibson’s ability to enter into contracts for the Gateway Terminal, the construction and completion of additional tankage and the retirement of Gibson’s President and Chief Executive Officer and the replacement and transition of this role. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this press release should not be unduly relied upon. These statements speak only as of the date of this press release. The Company does not undertake any obligations to publicly update or revise any forward-looking statements except as required by securities law. Actual results could differ materially from those anticipated in these forward-looking statements as a result of numerous risks and uncertainties including, but not limited to, the risks and uncertainties described in “Forward-Looking Information” and “Risk Factors” included in the Company’s Annual Information Form and Management’s Discussion and Analysis, each dated February 20, 2024, as filed on SEDAR+ and available on the Gibson website at www.gibsonenergy.com.

For further information, please contact:

Investor Relations:
(403) 776-3077
[email protected]

Media Relations:
(403) 476-6334
[email protected]

Specified Financial Measures

This press release refers to certain financial measures that are not determined in accordance with GAAP, including non-GAAP financial measures and non-GAAP financial ratios. Readers are cautioned that non-GAAP financial measures and non-GAAP financial ratios do not have standardized meanings prescribed by GAAP and, therefore, may not be comparable to similar measures presented by other entities. Management considers these to be important supplemental measures of the Company’s performance and believes these measures are frequently used by securities analysts, investors and other interested parties in the evaluation of companies in industries with similar capital structures.

For further details on these specified financial measures, including relevant reconciliations, see the “Specified Financial Measures” section of the Company’s MD&A for the three months ended March 31, 2024 and 2023, which is incorporated by reference herein and is available on Gibson’s SEDAR+ profile at www.sedarplus.ca and Gibson’s website at www.gibsonenergy.com.

a)   Adjusted EBITDA

Noted below is the reconciliation to the most directly comparable GAAP measures of the Company’s segmented and consolidated adjusted EBITDA for the three months ended March 31, 2024, and 2023:

b)   Distributable Cash Flow

The following is a reconciliation of distributable cash flow from operations to its most directly comparable GAAP measure, cash flow from operating activities:

c)   Dividend Payout Ratio

d)   Net Debt To Adjusted EBITDA Ratio

An analyst has described how North Sea oil field redevelopments are “on the rise”, however, some are going more smoothly than others.

Like a person who kept their 1970s flared jeans, operators are cracking out some old favourites as they plunge money into these projects to breathe new life into them.

Vice president of operations for Europe at Welligence Energy Analytics, David Moseley, noted this trend.

He told Energy Voice: “The number of redevelopment projects in the UK is on the rise. The logic is clear – material greenfield developments in the UK are in decline, driven by the basin’s maturity and diminishing discovery sizes, making revisiting large, older fields increasingly viable as a way of adding new reserves.

“The wealth of subsurface well and production data makes the case more compelling. “

That being said, redevelopments may not always be the right fit for a company’s portfolio.

Mr Moseley added: “There is a need to balance this with individual project-specific risks, especially where those that led to original early production cessation could resurface – production performance being one obvious example.”

As redeveloping old fields becomes fashionable, Energy Voice runs through the hottest prospects in UK waters.

UK North Sea redevelopment rundown

Penguins

Shell’s Penguins project is a redevelopment of a hub that once served the giant Brent Charlie platform.

Penguins has historically been oil-producing with associated gas reinjected to boost production.

Shell now intends to take associated gas and export it through a new pipeline to the St Fergus terminal in Aberdeenshire.

The London-listed supermajor’s project has encountered several setbacks, namely due to delays in the construction and transport of the field’s name-sake floating production, storage and offloading vessel.

The Penguins FPSO is Shell’s first new manned vessel for the UK in three decades.

© Supplied by Greenpeace

Set to work on a field 150 miles north-east of Shetland, the vessel is expected to unlock 80 million barrels of oil, Shell said at the time of the investment decision in 2018, which would have otherwise been left stranded as Brent Charlie shut down.

The vessel is currently at Aibel’s yard in Haugesund, Norway where it has been for more than a year. The FPSO is set to come to the UK between April – September this year.

Murlach

Late last year the UK government approved BP’s Murlach project, a redevelopment of part of the Skua field.

Sitting around 126 miles east of Aberdeen, the field produced through the early 2000s and was previously operated by Shell.

Its redevelopment is expected to recover around 26 million barrels of oil and 602 million cubic metres of gas.

BP acquired the licence along with joint venture partner NEO Energy – which holds a 20% stake in the project – as part of the 30th Licensing Round following its relinquishment by the rival supermajor.

The project itself will consist of two production wells and a subsea tieback to the Eastern Trough Area Project (ETAP) installation.

© Supplied by BP

Peak production would be in the region of 20,000 barrels of oil per day and around 17 million cubic feet of associated gas per day.

The Murlach project will share existing infrastructure already present around the Murlach Field, including the Heron A production pipeline to transport production fluids, the Heron wash water pipeline and the Seagull control umbilical.

In January Wood announced a multi-million dollar contract to deliver topside modifications at ETAP.

The Aberdeen-based engineering firm said the “major” two-year contract’s key focus was to enable the platform’s connection to Murlach.

Mr Moseley described Murlach and Penguins as “fairly advanced,” compared to others in this list.

Cheviot

While the two UK supermajor’s redevelopments are progressing well, Waldorf Production’s Cheviot project seems less certain.

After discussing Penguins and Murlach, Mr Moseley added: “Others still have a fair way to go and have a relatively high degree of uncertainty in terms of likelihood of happening,” for example Cheviot.

The Cheviot project is a redevelopment of the Emerald which was owned by Midland and Scottish Resources and ceased production in 1996.

Waldorf currently owns a 100% stake in the Cheviot redevelopment project.

Aberdeen’s Waldorf Production is being faced with liquidity shortfalls, recent reports suggest, however, the firm has remained tight-lipped on the issue.

Waldorf Production was asked for comment on the future of its Cheviot development.

Affleck

NEO Energy’s Affleck development is set to be a tie-back to Harbour Energy’s Judy platform via the Talbot pipeline.

NEO intends to reconnect to existing Affleck wells A1 and A2 via a pre-existing manifold, with new pipelines and umbilicals that will link it to both Talbot and Judy.

The project that sits 178 miles south-east of Aberdeen received the green light from UK regulators in 2023.

The field will serve as a boost to the Judy hub, which saw its Talbot field receive a regulatory green light in 2023.

© Supplied by Harbour Energy

Talbot, which will co-mingle its production with Affleck, is estimated to hold around 18.1 million barrels of oil equivalent (boe) of light oil with associated gas.

According to NEO’s environmental statement, Affleck will produce mostly oil, reaching a peak of 5,218 barrels per day, tailing to 1,244 barrels per day in 2037 with some associated gas.

Harbour earlier this year set out plans for subsea construction and pipelay works between March and August this year.

Buchan

Another NEO Energy fronted redevelopment, Buchan was signed off by the UK regulator last year.

NEO will hold a 50% stake as the operator of Buchan, alongside partners Jersey Oil and Gas (20%) and Serica Energy (30%).

Located 93 miles off the coast of Aberdeen in the Moray Firth, the redevelopment of the former Repsol Sinopec field is the third-largest upcoming project for the UK North Sea.

Under the plans, NEO will establish a new production hub at the renamed Buchan Horst field using the Western Isles FPSO.

© Supplied by Ross Creative Commun

NEO Energy acquired the Western Isles FPSO on behalf of the Buchan joint venture in November 2023.

According to documents submitted to OPRED, NEO will commission modification work to enable the vessel to be electrification-ready from 2030.

NEO will aim to power production from a nearby INTOG offshore wind farm, with the Green Volt and Cerulean Winds projects mentioned as possible candidates.

Meanwhile, the Aberdeen firm expects drilling to commence in mid-Q2 2025, with first oil expected from Q4 2026.

The Buchan operator estimates the total capital expenditure forecast for the Buchan redevelopment to be approximately £850-950 million.

Anning, Somerville and Hodgkin

In January, Hartshead Resource announced a ‘financing backstop’ worth A$800 million (£415m) to progress the first phase of the Anning and Somerville developments.

Viaro Energy agreed to buy the majority stake in Anning and Somerville fields in January as part of a £105 million deal.

Anning and Sommerville are expected to reach first gas in the fourth quarter of this year and are redevelopments of the projects that shut down in 2015.

Phase one of the redevelopment project will focus on Anning and Sommerville while the second stage will focus on the Hodgkin and Lovelace fields.

As part of its deal earlier in the year, Viaro Energy also picked up a stake in the fields that will be developed under phase two.

The Viaro Energy and Heartshead Resource Southern North Sea development is breathing new life into the Viking E, Victoria and Audrey fields.

Galapagos

© Supplied by DCTMedia

Bridge Petroleum’s Galapagos is currently in the approval stage and is set to begin production next year, according to GlobalData.

The redevelopment of this project will require a subsea tree and around 17 wells to be drilled.

Galapagos started up production as North West Hutton in 1975 and ceased in 2002.

The field is expected to reach peak production the year after operations begin.

Bridge Petroleum hopes to extract reserves of 81 million barrels in the first phase of Galapagos.

Ad

---

A few months ago, my doctor uttered a phrase I’d long dreaded: Your blood sugar is too high. With my family history of diabetes, and occasional powerful cravings for chocolate, I knew this was coming and what it would mean: To satisfy my sweet fix, I’d have to turn to sugar substitutes. Ughhhh.

Dupes such as aspartame, stevia, and sucralose (the main ingredient in Splenda) are sweet and have few or zero calories, so they typically don’t spike your blood sugar like the real thing. But while there are now more sugar alternatives than ever, many people find that they taste terrible. The aspartame in Diet Coke leaves the taste of pennies in my mouth. And in large amounts, substitutes are bad for you: Last year, the World Health Organization warned that artificial sweeteners could raise the risk of certain diseases, singling out aspartame as “possibly carcinogenic.”

But last week, I sipped a can of Arnold Palmer with a brand-new sweetener that promised to be unlike all the rest. The drink’s strong lemon flavor was mellowed by a light, unremarkable sweetness that came from brazzein, a sugar substitute green-lighted by the FDA last month. Oobli, a California-based company that sells the lemonade-iced tea and manufactures brazzein (which occurs naturally in West Africa’s oubli fruit), has billed it as a “revolution in sweetness.” Yet like everything that came before it, brazzein is far from perfect: To help mask its off taste, the can had some real sugar in it too. For now, Eric Walters, a sweetener expert at Rosalind Franklin University, told me, brazzein is just “an alternative” to the many options that already exist. None has come even close to the real deal.

The ideal sugar alternative is more than just sweet. It must also be safe, taste good, and replicate the distinct way sugar’s sweetness develops on the tongue. In addition to aspartame and other synthetic sugar alternatives that have existed for more than a century, the past two decades have brought “natural” ones that are plant-derived: sweeteners made with stevia or monk fruit, which the FDA first approved in 2008 and 2010, respectively, can now be readily found in beverages such as Truly hard seltzer and Fairlife protein shakes. Stevia and monk fruit have been used “for hundreds of years by the people who live in the regions where they grow, so I don’t have huge worries about their safety,” Walters told me.

All of these sweeteners work in basically the same way. Chemically, molecules other than just sugar can bind to the tongue’s sweet receptors, signaling to the brain that something sweet has landed. But the brain can tell when that something is not sugar. So far, no sweetener has accomplished that trick; off flavors that sometimes linger always give away the ruse.

The problem is that sugar alternatives are like celebrity impersonators: aesthetically similar, reasonably satisfying, but consistently disappointing. Take stevia and monk fruit: By weight, they’re intensely sweet relative to table sugar—monk fruit by a factor of up to 250 and stevia by a factor of up to 400. Because only a tiny amount is needed to impart a sweet taste, those sweeteners must be bulked up with another substance so they more closely resemble sugar granules. Manufacturers used to add carbohydrates such as corn starch—which are eventually broken down into sugars—but they now use erythritol, a calorie-free sugar alcohol, which “doesn’t count as sugar at all,” Walters said.

The end products look and feel similar to sugar, but not without downsides. Erythritol has been linked to an increased risk of heart attack and stroke. And stevia and monk-fruit sweeteners come with an aftertaste that has been described as “bitter,” “unpleasant,” and “disastrous.” When Walters first helped produce stevia 35 years ago, “the taste quality was so awful that we thought no one would buy it,” he said. “But we underestimated how much people would put up with it because it was ‘natural.’”

Brazzein is yet another natural option. Unlike other sugar substitutes, brazzein is a protein, but it is still intensely sweet and low in calories. It is so sweet—about 1,000 times sweeter than sugar—that some gorillas in the wild have learned not to waste their time eating it. That protein has become a health buzzword certainly won’t hurt Oubli’s sales, but its products won’t bolster any biceps: Its teas contain very little—about 1 percent—because brazzein’s sweetness is so potent.

Last month, Oobli received a “no questions asked” letter from the FDA, which means that the agency isn’t concerned about the product’s safety. Oobli’s iced teas and chocolates are the first brazzein-sweetened products to be sold in the U.S., although the sweet protein was identified three decades ago. Thaumatin, another member of the sweet-protein family, has been in use since the 1970s, though mostly as a flavor enhancer. One reason it took brazzein so long to be marketable is that it occurs at such low levels in the oubli fruit that mass-producing it was inefficient. Instead of harvesting brazzein from fruit, Oubli grows the protein in yeast cells, which is more scalable and affordable, Jason Ryder, Oobli’s co-founder and chief technology officer, told me.

One distinction between brazzein and other sweeteners is its chemical size. Compared with sugar, stevia, and monk fruit, brazzein molecules are relatively large because they are proteins, which means they aren’t metabolized in the same way, Ryder said. The effects of existing sweeteners on the body are still being investigated; although they are generally thought to not hike blood sugar or insulin, recent research suggests that they may in fact do so. That may never be a concern with brazzein, Grant DuBois, a sweetener expert and the chief science officer at Almendra, a stevia manufacturer, told me.

The most compelling upside of brazzein may be that it tastes pretty good. My palate, which is extra sensitive to artificial sweeteners, wasn’t offended by the taste. Would drink again, I thought. But the glaring caveat with Oobli’s teas is that they do contain some actual sugar—just less than you’d expect from a regular drink. The sugar helps mitigate a feature of brazzein’s sweetness, Ryder said.

One of the enduring problems with brazzein and many other popular sugar alternatives is that their sweetness takes more time than usual to develop, then lingers longer than expected. Indeed, although I liked the Arnold Palmer as it went down, I felt a peculiar sensation afterward: a trace of sweetness at the back of my throat that intensified, and felt oddly cool, as I exhaled. It was not unpleasant, but it was also reminiscent of having accidentally swallowed minty gum. If Diet Coke were made with brazzein instead of aspartame, Walters explained, you’d taste caffeine’s bitterness and the tartness of phosphoric acid before any sweetness, and when all of those flavors dissipated, the sweetness would hang around. “It’s just not what you want your beverage to be,” he said.

Balancing brazzein with a touch of sugar achieves the goal of reducing sugar intake. But most of the time, people who seek out products sweetened with sugar alternatives want “zero sugar,” DuBois said, “so that’s not really a great solution to the problem.” The perfect sweetener would wholly replace all of the sugar in a food, but brazzein probably won’t get there unless the peculiarities of its sweetness can be fully addressed. “If I knew how, I could probably make millions of dollars,” Walters said.

The future of sugar substitutes may soon offer improvements rather than alternatives. Last year, DuBois and his colleagues at Almendra published a peer-reviewed paper describing a method to speed up slow-moving sweetness by adding a pinch of mineral salts to sweeteners, which helps them quickly travel through the thick mucus of the tongue, resulting in a vastly improved experience of sweetness. “It works with stevia, but also aspartame, sucralose, monk fruit—it works very well with everything we’ve tried,” Dubois said, noting that it would probably also work with brazzein. With the right technology, sweeteners, he said, can become “remarkably sugarlike.”

Yet searching for the perfect sugar alternative is a fool’s errand. No matter how good they get, a single substance is unlikely to satisfy all tastes and expectations about health. As my colleague Amanda Mull wrote when aspartame was deemed carcinogenic over the summer, there’s always something. Much is left to be learned about the health effects of natural sweeteners, which may not be as natural as they seem; some stevia products, for example, are chemically modified to taste better, Walters told me

More than anything, sweeteners exist so that people can indulge in sweet treats without needing to worry about the consequences. They can address most of sugar’s problems—but they can’t do everything. “If you pick one sweetener and put it in everything, and drink and eat it all day long, that’s probably not a good thing for you,” Walters said. A sugar-free, flawlessly sweet chocolate may someday come to exist, but I’ll probably never be able to gorge on it without dreading my next blood test.

Yasmin Tayag is a staff writer at The Atlantic.

---

Ad

 

CALGARY, AB, April 25, 2024 /CNW/ – Clearview Resources Ltd. (“Clearview” or the “Company”) is pleased to announce its reserves report and financial and operational results for the year ended December 31, 2023.

2023 HIGHLIGHTS

• Disposed of two non-core non-operated assets in 2023 for gross proceeds of $2.1 million at $20,000 per flowing barrel of oil equivalent per day (“boe/d”) reducing corporate asset retirement obligations by $2.4 million;
• Paid a $1.5 million return of capital distribution (approx. $0.1279 per common share), to Clearview’s shareholders with a record date of September 23, 2023;
• Reconfirmed the Company’s credit facility with its lender at $10.0 million with the next scheduled review set for June 30, 2024;
• Achieved a proved developed producing finding and development cost of $11.82/boe in 2023 and $5.39/boe over the last 3 years; and
• Generated $0.3 million in carbon credits, more than offsetting the Company’s carbon tax obligations.

FINANCIAL and OPERATIONAL RESULTS

Production for the year ended December 31, 2023 was down 16% to average 1,671 boe/d versus the comparative year of 2022 at 1,981 boe/d.  The decrease was primarily due to the disposition of 108 boe/d in the first quarter of 2023 and natural declines of approximately 12% being partially offset by the successful drilling of one gross (0.67 net) light oil Cardium well in Wilson Creek in the third quarter of 2023. Natural gas liquids production decreased 15% compared to the prior year and consistent with an 18% decrease in natural gas production.

Adjusted funds flow⁽¹⁾ for the year ended December 31, 2023 was $3.7 million (approx. $0.32 per share⁽³⁾), a decrease of 61% compared to 2022, primarily due to lower realized sales prices for all of the Company’s production and lower production volumes, resulting in a decrease in revenue of $16.4 million.  The decrease in revenue for 2023 was offset by lower royalties due to the sliding scale nature of Crown royalties, lower operating costs due to dispositions undertaken in 2022 and in the first quarter of 2023 as well as reduced spending on workovers and spending efficiencies on repairs and maintenance.  Capital expenditures⁽²⁾ for 2023 were $5.3 million, which included the drilling of a light oil well for $3.9 million.  Clearview incurred decommissioning expenditures of $0.8 million during 2023.

Upon approval from the Company’s shareholders in September 2023, the Company funded a distribution to Clearview’s shareholders in the form of a return of capital of $0.1279 per common share in December 2023.

Clearview had net debt⁽¹⁾ outstanding of $3.7 million at December 31, 2023, which included bank debt of $1.7 million, a working capital deficit of $0.8 million and the Company’s convertible debentures of $1.2 million.

FINANCIAL and OPERATING HIGHLIGHTS

Financial

Production

Realized sales prices ⁽¹⁾

Netback analysis ⁽¹⁾

YEAR END 2023 RESERVE INFORMATION

McDaniel & Associates Consultants Ltd. (“McDaniel”), the Company’s independent petroleum engineering firm, has evaluated 100% of Clearview’s crude oil, natural gas and natural gas liquids reserves (all located in Canada) as at December 31, 2023 and prepared a reserves report dated March 21, 2024 (the “McDaniel Report”) in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”). Consistent with the prior year’s reserve report, the Company used a three consultant (McDaniel, GLJ Petroleum Consultants Ltd. and Sproule) average commodity price forecast dated January 1, 2024 (“Price Forecast”) in the evaluation.  Full reserves data disclosure as required under NI 51-101 will be included in Clearview’s Annual Information Form to be filed on SEDAR+ by April 29, 2024.

RESERVES

The following table is a breakdown of the Company’s reserves information, estimated using the Price Forecast and forecast costs, as detailed in the McDaniel Report at December 31, 2023.

NET PRESENT VALUE OF FUTURE NET REVENUE

The estimated future net revenues associated with Clearview’s reserves at December 31, 2023, based on the Price Forecast, are summarized in the following table.

RESERVES RECONCILIATION

Changes between the Company gross reserve estimates made as at December 31, 2023 and the prior-year estimates, made as at December 31, 2022, using the three consultant average forecast prices and costs at the respective dates are summarized in the table below.  Negative technical revisions in the reconciliation were primarily attributable to undeveloped locations at Clearview’s Windfall property.  Eight, 100% working interest, proved undeveloped locations and two additional, 100% working interest, probable undeveloped locations were assigned reserves based on a well drilled on the property in 2018 that utilized a higher completion intensity technique compared to the legacy wells in the pool. This enhanced completion technique resulted in higher initial production rates compared to the legacy wells. A recent decline in oil production resulted in a negative revision to this well’s reserve assignment and a corresponding negative revision to the reserve assignments to the above-mentioned ten undeveloped locations in the reserve report. All ten of these undeveloped locations remain in the report as economic under the price forecast, with reduced reserve assignments compared to the previous year. Excluding the Windfall property, technical revisions for the Company’s remaining properties were a positive 217 Mboe in the total proved category and a negative 17 Mboe in the total proved plus probable category.

TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2023

The table below summarizes the elements of future net revenue estimated using the Price Forecast and forecast costs without discount.

PRICING ASSUMPTIONS

The following table summarizes the Price Forecast used in the McDaniel Report.  First year forecasted pricing used in this year’s report compared to last year’s report decreased by 10% and 48% for Edmonton Light Crude Oil and Alberta AECO spot natural gas prices respectively.

FUTURE DEVELOPMENT COSTS

The following table summarizes the escalated future development costs (“FDC”) deducted in the estimation of future net revenue.  The change in FDC compared to the prior year was principally attributable to a lower estimate for drill and completion costs for the undeveloped wells at Clearview’s Windfall property.

FINDING, DEVELOPMENT AND ACQUISITION COSTS

Finding and Development (“F&D”) costs⁽¹⁾ and Finding, Development, Acquisition and Disposition (“F,D&A”) costs⁽¹⁾ calculations for the year ended 2023 and for the most recent three years in aggregate are reported below.  For 2023, total proved and total proved plus probable calculations are not meaningful as total reserve additions were negative due to negative revisions and total capital invested was negative due to a revision in future development costs in the McDaniel Report.  F&D and F,D&A costs are indicators of the Company’s efficiency in deploying capital to develop reserves.

RESERVE LIFE INDEX

Reserve Life Index is calculated as Company Gross reserves divided by annual production for the year indicated.  Proved developed producing reserve life index increased 10% compared to the prior year.

OPERATIONS

During the first quarter of 2023, Clearview disposed of its last two non-core, non-operated properties. The disposition of the Company’s interest in the Lindale Cardium Unit closed on January 31, 2023 and the disposition of Clearview’s interest in the Bantry property closed on March 31, 2023.  Gross proceeds from the dispositions totalled $2.1 million and corporate ARO was reduced by $2.8 million (undiscounted, uninflated).

Clearview drilled its first well in five years in the third quarter of 2023. The Wilson Creek 15-25-043-05W5 Cardium horizontal well (67% working interest) came on production late in the third quarter and over the first 7 months, gross production averaged approximately 139 barrels per day (“bbl/d”) of oil and 147 thousand cubic feet per day (“mcf/d”) of natural gas for a total of 200 boe/d (including estimated natural gas liquid recoveries of 37 bbl/d). Following a recent workover to lower the down hole pump, the well is currently producing approximately 86 bbl/d of oil and 103 mcf/d of natural gas for a total of 129 boe/d (including estimated natural gas liquid recoveries of 26 bbl/d).

During the fourth quarter of 2023 and the first quarter of 2024, Clearview completed an expansion of the waterflood at its Windfall oil property.  The initial waterflood, started in 2012, showed positive results by arresting oil declines and reducing gas/oil production ratios.  The Company is currently injecting approximately 1,600 bbl/d of water into the expanded waterflood scheme.

Clearview currently has two carbon credit generating programs. Through these programs, the Company has reduced the amount of methane being vented in the field.  The measured reduction in methane venting generates carbon credits which can be used to partially offset Clearview’s carbon tax obligations and the remainder can be sold.  Total credits generated in 2023 were $0.3 million, more than offsetting the Company’s carbon tax obligation.

The Company continued abandonment and reclamation activities through to the end of 2023. During the year, Clearview incurred $0.5 million of net operated expenditures abandoning 8 gross (5.6 net) wells and 3 gross (3.0 net) pipelines and conducting numerous environmental site assessments. Expenditures on decommissioning projects in 2024 are expected to be approximately $0.8 million.

CYBERSECURITY INCIDENT UPDATE

Further to its December 6, 2023 and January 12, 2024 press releases, Clearview has not recovered any funds that were lost as a result of the cybersecurity incident.  The Company continues its efforts to recover these funds and law enforcement continues an active investigation. Due to the nature of the cybersecurity incident, these efforts may not result in the return of all or any of the stolen funds. Clearview will update if attempts to recover any funds are successful.

OUTLOOK

Clearview’s strategy remains to provide liquidity for its shareholders. The Company is actively evaluating strategic acquisition opportunities, both marketed and unsolicited, and views these as potential paths to liquidity.  Clearview submitted numerous bids to acquire various assets and companies in 2023 totaling more than $180 million. These efforts have continued into 2024. Although the Company has not yet closed on an opportunity, Clearview continues to explore strategic growth opportunities, both internally and externally. Additionally, management and the Board of Directors continue to monitor the outlook for commodity prices and forecast adjusted funds flow to determine the appropriate timing for providing additional returns to shareholders.  At the current time, the forward strip price for AECO gas indicates $1.78/mcf for the balance of 2024, 33% lower than realized gas prices in 2023. While the current natural gas price remains depressed, negatively impacting Clearview’s adjusted funds flow expectations, the outlook for 2025 is positive with current strip indications at $3.33/mcf, 25% higher than realized prices in 2023.

Clearview would like to thank its shareholders for their continued support as we evaluate our internal development plans and external opportunities to grow production volumes and adjusted funds flow towards providing liquidity for shareholders.

Clearview’s December 31, 2023 year-end audited financial statements and management’s discussion and analysis are available on the Company’s website at www.clearviewres.com and SEDAR+ at www.sedarplus.ca.

Note Regarding Forward-Looking Statements

This press release contains forward-looking statements and forward-looking information (collectively “forward-looking information”) within the meaning of applicable securities laws relating to the Company’s plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results, industry conditions, commodity prices and business opportunities. Specifically, this press release has forward looking information with respect to: expected cash provided by continuing operations, including future net revenue; future asset retirement obligations and decommissioning costs; liquidity events, including the cost, timing and intention to implement same; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas industry; the ongoing investigation and attempt to recover the stolen funds; and overall growth strategy.  Forward-looking information typically uses words such as “anticipate”, “believe”, “project”, “expect”, “goal”, “plan”, “intend” or similar words suggesting future outcomes, statements that actions, events or conditions “may”, “would”, “could” or “will” be taken or occur in the future. Statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

The forward-looking information is based on certain key expectations and assumptions made by our management, including expectations and assumptions concerning prevailing commodity prices and differentials, exchange rates, applicable royalty rates and tax laws; the impact government assistance programs will have on the Company; the impact on energy demands going forward and the inability of certain entities, including OPEC to agree on crude oil production output constraints; the impact on commodity prices, production and cash flow due to production shut-ins; the impact of regional and/or global health related events on energy demand; global energy policies going forward; our ability to execute our plans as described herein; global energy policies going forward; future exchange rates; future debt levels; the availability and cost of financing, labour and services; the impact of increasing competition and the ability to market oil and natural gas successfully and our ability to access capital. Although Clearview believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Clearview can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature such information involves inherent risks and uncertainties which could include the possibility that Clearview will not be able to execute some or all of its ongoing programs; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; further fluctuations in the price of crude oil, natural gas liquids and natural gas; fluctuations in foreign exchange or interest rates; adverse changes to differentials for crude oil and natural gas produced in Canada as compared to other markets and worsened transportation restrictions. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits that we will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide securityholders with a more complete perspective on our future operations and such information may not be appropriate for other purposes.

Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this press release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

This press release contained future-oriented financial information (“FOFI”) about Clearview’s projected 2023 adjusted funds flow, which is subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. The actual results of Clearview and the resulting financial results will likely vary from the amounts set forth herein and such variation may be material. Clearview and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Clearview undertakes no obligation to update such FOFI. FOFI contained in this press release was made as of the date of this press release and was provided for purposes of providing further information about Clearview’s anticipated future business operations. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein.

Non-IFRS Measures

Throughout this press release and other materials disclosed by the Company, Clearview uses certain measures to analyze financial performance, financial position and cash flow. These non-IFRS and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-IFRS and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with IFRS as indicators of Clearview’s performance. Management believes that the presentation of these non-IFRS and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company’s ongoing operating performance, and the measures provide increased transparency and the ability to better analyze Clearview’s business performance.

Capital Management Measures

Adjusted Funds Flow

Adjusted funds flow represents cash provided by operating activities before changes in operating non-cash working capital and decommissioning expenditures. The Company considers this metric as a key measure that demonstrate the ability of the Company’s continuing operations to generate the cash flow necessary to maintain production at current levels and fund future growth through capital investment, to repay debt and return capital to shareholders. Management believes that this measure provides an insightful assessment of the Company’s operations on a continuing basis by eliminating the actual settlements of decommissioning obligations, the timing of which is discretionary. Adjusted funds flow should not be considered as an alternative to or more meaningful than cash provided by operating activities as determined in accordance with IFRS as an indicator of the Company’s performance. Clearview’s determination of adjusted funds flow may not be comparable to that reported by other companies. Clearview also presents adjusted funds flow per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of earnings per share.  Please refer to Note 15(e) “Capital Management” in Clearview’s December 31, 2023 audited financial statements for additional disclosure on Adjusted Funds Flow.

Net Debt

Clearview closely monitors its capital structure with a goal of maintaining a strong balance sheet to fund the future growth of the Company. The Company monitors net debt as part of its capital structure. The Company uses net debt (current assets, excluding financial derivatives, less current liabilities, excluding financial derivatives, less convertible debentures) to assess financial strength, capacity to finance future development and to assist in assessing the liquidity of the Company. Please refer to Note 15(e) “Capital Management” in Clearview’s December 31, 2023 audited financial statements for additional disclosure on Net Debt.

Non-IFRS Measures and Ratios

Capital Expenditures

Capital expenditures equals additions to property, plant & equipment and additions to exploration & evaluation assets.  Clearview considers capital expenditures to be a useful measure of adjusted funds flow used for capital reinvestment.  The most directly comparable IFRS measure to capital expenditures is additions to property, plant & equipment and additions to exploration & evaluation assets.

Cash Finance Costs

Cash finance costs is calculated as finance costs less accretion of decommission obligations and accretion of convertible debenture discount.  The most directly comparable IFRS measure to cash finance costs is finance costs. A reconciliation of cash finance costs to finance costs is set out below:

Cash Finance Costs per boe

Cash finance costs per boe is calculated by dividing cash finance costs by total production volumes sold in the period.  Management considers cash finance costs per boe an important measure to evaluate the Company’s cost of debt financing relative to the Company’s corporate netback per boe.

Operating Netback per boe

Operating netback per boe is calculated by dividing operating netback by total production volumes sold in the period.  Operating netback equals oil and natural gas sales plus processing income, less royalties, transportation expenses and operating expenses. Management considers operating netback per boe an important measure to evaluate its operational performance as it demonstrates its field level profitability relative to current commodity prices.

Corporate Netback per boe

Corporate netback per boe is calculated as operating netback less general and administrative expenses and finance costs, plus/(minus) realized gains (losses) on financial instruments, minus(plus) other costs (income), plus accretion of decommissioning obligations and convertible debentures divided by total production volumes sold in the period.   Management considers corporate netback per boe an important measure to assist management and investors in assessing Clearview’s overall cash profitability.

Supplementary Financial Measures

Adjusted funds flow per share is comprised of adjusted funds flow divided by the basic weighted average common shares.

Adjusted funds flow per diluted share is comprised of adjusted funds flow divided by the diluted weighted average common shares.

Realized sales price – oil is comprised of light crude oil commodity sales from production, as determined in accordance with IFRS, before deduction of transportation costs and excluding gains and losses on financial instruments, divided by the Company’s oil production.

Realized sales price – ngl is comprised of natural gas liquids commodity sales from production, as determined in accordance with IFRS, before deduction of transportation costs and excluding gains and losses on financial instruments, divided by the Company’s ngl production.

Realized sales price – natural gas is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, before deduction of transportation costs and excluding gains and losses on financial instruments, divided by the Company’s natural gas production.

Realized sales price – total is comprised of oil and natural gas sales from production, as determined in accordance with IFRS, before deduction of transportation costs and excluding gains and losses on financial instruments, divided by the Company’s total production on a boe basis.

Oil and Gas Advisories

This press release contains certain oil and gas metrics which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons.  Such metrics have been included in this document to provide readers with additional measures to evaluate our performance however, such measures are not reliable indicators of our future performance and future performance may not compare to our performance in previous periods and therefore such metrics should not be unduly relied upon. Specifically, this press release contains the following metrics:

• Boe means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. The term “boe” may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6: 1, using a conversion on a 6: 1 basis may be misleading as an indication of value.

Abbreviations

SOURCE Clearview Resources Ltd.

 

View original content to download multimedia: http://www.newswire.ca/en/releases/archive/April2024/25/c5531.html

WTI (June) $82.21 -55c, Brent (June) $88.02 -40c, Diff -$5.21 +15c.

USNG (May) $1.65 -16c, UKNG (May) 74.0p +1.51p, TTF (May) €29.52 +€0.30. 

Oil price

It was a right old mixed bag yesterday, US data was poor as business activity fell but maybe thats good for interest rates you never know. But the inventory data saw a big draw of 6.368m barrels rescued what might have been a bad day. 

I have been going on a bit about Namibia lately, it’s the Namibian International Energy Conference in Windhoek where everybody who is anybody is on parade. And that includes, by video I admit, the Opec Secretary General who welcomed the country as a ‘significant crude producer’ and they, Opec will do all they can… 

I mentioned Sintana who have participated in the big find by GALP at Mopane and which is all the buzz and Eco Atlantic who are on trend just down the road. Today it is announced that Sintana has acquired one of the last blocks in Namibia, PEL 79 through Giraffe and with QXL, a smart move methinks.

Zephyr Energy

Zephyr has announced the spud and start of the main drilling operation on the State 36-2 LNW-CC-R well at Zephyr’s flagship project in the Paradox Basin, Utah, U.S. 

Further to the Company’s announcement on 17 April 2024, the rig-up operation for the Helmerich & Payne Rig 257 was completed yesterday, 24 April, and shortly thereafter the surface section of the well was spud.

 

Figure 1: Helmerich & Payne Rig 257 in situ at the Paradox project

The well, for which the Company expects to recover substantially all the drilling costs incurred through the well control insurance policy that it had in place for the State 36-2 LNW-CC well will target the Cane Creek reservoir and the highly productive natural fracture system encountered by the original well. Drilling is planned to a total depth of 10,362 feet measured depth (9,600 feet true vertical depth) and will incorporate a short, 270-foot horizontal reservoir section. The well has been designed and permitted such that the horizontal section can be extended to a further 10,000 feet in the Cane Creek reservoir, should that be required in the future. 

Drilling operations are expected to take approximately 30 days.  After reaching TD and setting a production liner, the Rig will be demobilised and the well will be prepared for production testing.  

Colin Harrington, Zephyr’s CEO commented:

“After months of meticulous planning we are delighted to have commenced full drilling operations with the prime objectives of delivering a safe and timely drilling operation followed by a successful well test.

“We look forward to providing regular updates as drilling progresses.”

Just what the Zephyr shareholders wanted today with news that the Paradox well has been spudded and the company are back to where they left off last year. A lot of water has passed under the bridge since then but the class of this management has meant that they developed the non-operated portfolio without which many wouldn’t have survived and had good enough insurance to pay for this well. 

So high hopes then for the voyage to TD of 10, 362 feet including a short look at the horizontal reservoir section, this should take around 30 days with flow testing after that. The market will be watching with considerable interest, any success that opens up the Paradox will indeed be a company maker…

Afentra

Afentra has provided the following update regarding the previously announced Angolan acquisition.

Government Approval of Azule Acquisition

Afentra is pleased to announce that it has received approval from the Government of Angola for the previously announced acquisition of a 12% non-operating interest in Block 3/05 and a 16% non-operating interest in Block 3/05A from Azule Energy Angola Production B.V. (‘Azule’), pursuant to a sale and purchase agreement between Azule and Afentra’s wholly-owned subsidiary, Afentra (Angola) Ltd, dated 19 July 2023.

The Company is now working with Azule to finalise the formal completion of the Azule Acquisition which is anticipated to occur within Q2 2024 as previously announced. At that time, we will provide an update on the deal completion including the asset cashflow from the 1 October 2022 effective date.

Punja Discovery Block 3/05A – Enhanced Fiscal Terms

Following a request by the Block 3/05A partnership the Government of Angola have declared the Punja Development Area located in Block 3/05A, as a marginal discovery. As a result, the applicable fiscal incentives will be applied to this discovery, significantly enhancing the commercial value of this potential development.

Commenting on the update, CEO Paul McDade said:

“The Angolan government’s approval of the Azule Acquisition allows us to proceed with the completion of our third transaction in Angola providing Afentra a material equity position in these world-class assets. The improved fiscal terms for the Punja Discovery is another clear indication of the support given by the Government of Angola to parties willing to invest in their oil and gas sector. This further encourages us to continue to work with Sonangol and our joint venture partners to grow production and reserves as we develop the vast potential of both the producing fields in Block 3/05 and the significant discoveries within Block 3/05A.”

Approval for this addition in Angola that we already knew about is fantastic news and takes the stakes in blocks 3/05 and 3/05 to 30% and 21.33% on completion if my memory is correct. In addition the news about the Punja discovery means that the Government want to make it work and shows further assistance to oil and gas industry.

Theres a very good reason that the shares are in the bucket list and why they have doubled in the last year, with a target price of 100p they remain amongst the winners in the selection box, and what’s more, there’s more to come…

Petro Matad

Petro Matad has provided the following operational update.

Key Company Updates

·    The Company is working with the local government agencies to secure the remaining approvals necessary from Matad District to allow the 2024 operational programme to commence. Preparations are being made to complete the Heron 1 well for production once approvals are in hand and when contractor crews return to Mongolia.

·    Petro Matad continues to push the central government to complete the certification process and confirm Block XX as State Special Purpose land to streamline the permitting process in future years and reduce the risk of interference or obstruction.

·    SunSteppe Renewable Energy (SRE), the Company’s renewable energy Joint Venture, continues to make good progress. An exclusive MoU with Oyu Tolgoi mine to develop a Green Hydrogen project has been signed and grant funding from the Japanese government has been secured. SRE’s 50MW Battery Energy Storage System project has now received technical approval.

Operational Update

Block XX land access and Heron 1 completion

Following the approval of land access from the Matad Citizens’ Representatives Committee, the Company has been liaising with the local authorities to secure the Matad Governor’s resolution and the land use agreement. Petro Matad has been working to correct misinformation about the Company from local activists and protesters that have been critical of oil production operations in the area for some time, protesting online and in person against the committee’s decision. The execution of the aforementioned documents will allow work in the areas chosen for 2024 operations to go ahead irrespective of the slow progress of the central government process to complete the certification of the Block XX Exploitation Area as State Special Purpose Land.

Petro Matad is also standing-by to pay compensation to the herders whose registered pastures were impacted by the award of the 214km² Block XX Exploitation Area. These payments, set out in law, should be paid from the State budget but recognising that the process could be very slow, Petro Matad had proposed paying the herders directly itself. Payments of c.$5,000 per family were due to the 10 families affected. Petro Matad had previously proposed making payment via industry regulator, the Mineral Resources and Petroleum Authority of Mongolia (MRPAM), but this was ultimately not accepted by the Ministry of Finance. Changes in the procedures to allow non-State entities to pay are now working through the Mongolian government’s system but, having requested and received a letter supporting direct payment by the Company from MRPAM, Petro Matad is ready to pay as soon as the 2024 land use agreement is signed with the Matad authorities.

With local land use approvals progressing for 2024, Petro Matad is making preparations to complete the Heron 1 well. Contracts are in place with service providers and timing of mobilisation is under discussion. Talks with PetroChina Mongolia are continuing in order to have offtake arrangements including transport, processing, export and sale of oil in place once the well is ready to produce.

Certification of Block XX as State Special Purpose Land

This process is still being held up by the Provincial Governor’s refusal to sign off on the government’s key Tripartite Agreement and whilst completion of the District level approvals will allow 2024 operations to go ahead, the Company is still pushing for the long-delayed certification process to be completed. Certification will simplify future permitting and reduce the chances of interference. The Ministry for Economic Development, which is in charge of stimulating foreign investment in Mongolia has been very active on this issue and is preparing a submission to Cabinet to attempt to remove the obstacles to completing the process. The Company continues to cooperate with all relevant agencies to make sure this process is completed but, at the same time, is looking at any legal recourse it may have if the central government fails to rectify the situation and so delays operational activities in future years.

Renewable Energy Projects

Our renewable energy Joint Venture has had a very active period at the start of 2024, with its two high-graded projects having taken important steps forward.

The first project involves the provision of Green Hydrogen to Mongolia’s major Oyu Tolgoi copper and gold mine in which Rio Tinto is the major investor. An exclusive Memorandum of Understanding has been signed with Oyu Tolgoi and the Japanese Overseas Environmental Cooperation Centre (OECC) to develop the project and supply Green Hydrogen (which is hydrogen produced from renewable energy) which will be used to provide heat to facilities at the mine. Through the involvement in the venture of OECC, the partnership has already secured some Japanese Government grant funding to support this ground-breaking green energy initiative. An application for further grant funding is expected to be made in due course. The total grant funding for a project such as this could be up to 40% of the capital expenditure requirement. Oyu Tolgoi, in the South Gobi region of Mongolia, is one of the largest known copper and gold deposits in the world and Oyu Tolgoi LLC is a Mongolian company, jointly owned by Erdenes Oyu Tolgoi LLC on behalf of the Government of Mongolia (34 per cent) and Rio Tinto (66 per cent). Rio Tinto also manages Oyu Tolgoi on behalf of the partnership. Petro Matad is delighted to see SRE cooperating on this exciting project which is designed to demonstrate the potential for Green Hydrogen to be used as a fuel in large scale mining and so to contribute to the decarbonisation of such operations.

SRE’s second high graded project is the Choir 50MW Battery Energy Storage System (BESS). Choir is a town in central Mongolia and the site of the largest electricity substation in the central portion of the Mongolian national grid. The government has identified the need for a substantial BESS at Choir to help stabilise the grid and reduce high-cost import of power from China and Russia at peak hours, when Mongolia cannot meet domestic demand, and the economically wasteful export of power during off peak periods when the country’s base load exceeds domestic demand.

SRE has secured approval of the feasibility study from the Ministry of Energy for a 50MW BESS project at Choir and is now preparing the application for the licence to construct. This project could be online as early as 2025 and will help to stabilise the Mongolian electricity grid, reduce the amount of coal used in power generation and increase the dispatch of existing renewable energy producers. SRE is keen to move this project ahead as quickly as possible. Mongolia has recently commissioned its first BESS, an 80MW project funded by the Asian Development Bank, and this has had a positive impact through what was a very hard winter in Mongolia. The Ministry of Energy has identified a significant need for BESS projects around the country and SRE is well positioned as an early entrant to be a major player in this sector.   

Mike Buck, CEO of Petro Matad, said:

“We are pushing to secure approval from Matad Soum for the land access required to execute our 2024 work programme and we are gearing up for operations during the summer. The negative reactions to the committee’s decision and misinformation spread by activists were not unexpected and underline why the central government certification process is so important for the long term and is our preferred solution.

However, with 2024 parliamentary elections looming and central government moving slowly, we are pursuing the local solution as a priority. We are also pushing the central government hard to resolve its internal issues which have created the frustrating obstruction of the state special purpose certification process for Block XX. We will buy ourselves a long-delayed operating window with the local approval for 2024 if we can get it, but we do not want to go through such a process every year.

Separately, the progress made by our renewable energy joint venture is very pleasing and to see it so quickly in partnership with Japan’s OECC and involved with the decarbonisation of the globally significant Oyu Tolgoi mine is testament to the credibility, professionalism and motivation of the team.”

For Mike Buck and his team, who must have the patience of Job by the way, they are doing anything at all possible to get get underway at the Heron field. I’d like to say that it might change anytime soon but I don’t see that and can’t hold up any hope that the authorities are doing anything to develop Heron, at least in the short term.

i3 Energy

i3 Energy has announced the Company’s 2024 capital budget and production guidance. The Company will hold an investor webinar on Thursday 2 May 2024 at 12:00 pm BST including a Q&A session (details of which can be found below).

Highlights:

·    2024 Capital Budget

2024 Capital Budget of USD 50.9 million, forecasted to deliver 15 gross wells (10.5 net, 95% net i3-operated) to be drilled across the Company’s diversified portfolio in Central Alberta, Simonette, and its northern Clearwater acreage.

·    Production Growth

Forecast exit 2024 production of 20,250 – 21,250 barrels of oil equivalent per day (“boepd”), representing a year-over-year increase of approximately 3% from the prior year average exit rate (December 2023), or approximately 8% from current levels, as the Company expects to recommence drilling in June 2024 and positions for accelerated Montney development in 2025.

·    Cash Flow

USD 70 – 75 million of 2024 Net Operating Income (“NOI”) and USD 55 – 60 million of EBITDA before hedging gains and losses, based on budget price assumptions of USD 82/barrel (“bbl”) for WTI and CAD 2.25/Gigajoules (“GJ”) for AECO natural gas.

·    Shareholder Returns

      As part of i3’s commitment to its total return model, subject to Board approval, the Company is expected to return forecasted dividends of £12.3 million (USD 15.7 million) in 2024, representing 0.2565 pence per share per quarter or 1.0260 pence per share for the year, which translates to a forward yield of 8.1% based on the closing price of i3’s ordinary shares of 12.66 pence on 23 April 2024.

Majid Shafiq, CEO of i3 Energy plc, commented:

“Following very successful initiatives in the first half of the year to increase our balance sheet strength and liquidity, i3 is extremely pleased to announce a substantial USD 51 million capital programme for the remainder of the year, which will drill a diverse group of oil and gas wells across our portfolio in Canada. The majority of wells will be drilled in the second half of the year, with the high-volume Central Alberta gas wells producing into a forecast strong winter pricing environment and pad drilling of our exciting Montney acreage expected to commence early in Q1 2025. The programme is designed to deliver production growth and support our dividend programme, whilst maintaining liquidity and a conservative leverage position to maximise flexibility to deal with volatile market conditions and opportunities as they arise.”

i3 is on the up, at least for the time being with a very positive 2024 outlook with strong production and capex guidance, 20,250-21,250 boe/d is slightly ahead of last year on capex of $50.9m. And at $82 WTI EBITDA is $55-60m giving scope for a divvi of £12.3m making a forward yield of some 8%. If it makes all the numbers, and apart from history it should and is therefore positive news. 

Coro Energy

Coro yesterday advised that it held its Annual General Meeting earlier.

The Company also announces that, as a result of the outturn of the AGM, the Company has requested that trading in the Company’s ordinary shares on AIM be suspended with immediate effect.

The resolutions put to the AGM were voted on by way of a poll and the results are as follows:

Resolutions	For	%	Against	%	Withheld
1	451,946,229	96.53%	16,260,452	3.47%	77,279,082
2	146,216,513	27.07%	393,994,930	72.93%	5,274,320
3	417,323,458	76.57%	127,726,243	23.43%	436,062
4	417,322,658	76.54%	127,888,785	23.46%	274,320

A “Vote withheld” is not a vote in law and is not counted in the calculation of the percentage of shares voted “For” or “Against” any resolution.

The Company is pleased to announce that shareholders have supported Resolutions 1, 3 and 4, enabling flexibility for further fundraising in the forthcoming period. The Company has  today also received verbal confirmation from its key Noteholders in respect of their ongoing support with regards to the near term funding needs of the business. As at 23 April 2024, the Company had unaudited cash balances of approximately US$0.5 million.

However, Resolution 2, concerning the re-election of James Parsons as a Director of the Company, was not passed at the AGM. Accordingly Mr Parsons is no longer a director of the Company.

Whilst the Company has commenced the process of recruiting at least one additional director with immediate effect, the Company’s Board currently comprises a single director.

Following the AGM, the Company’s Board is not therefore quorate under the Company’s Articles of Association (the “Articles”) or s154 of the Companies Act 2006 (the “Act”) and the Company is not therefore able to effectively operate under the Articles or the Act.

Accordingly, the Company has requested that trading in the Company’s ordinary shares on AIM be suspended with immediate effect pending, inter alia, the appointment of at least one additional director. Notwithstanding the suspension of trading in the Company’s ordinary shares, the Company will continue to make notifications as and when there are matters requiring disclosure in accordance with the Company’s obligations under the AIM Rules for Companies and/or the UK Market Abuse Regulation.

Further announcements will be made, as appropriate, in due course.

Not much to add here, shareholders vote off the Chairman and without enough directors are now suspended from trading…

And finally…

Last night in the Prem Liverpool lost away at Everton for the first time since 2010 in the league, 2-0 and maybe they are letting the title slip away…The Eagles beat the Magpies, Wolves lost to the Cherries and the Red Devils came back from behind to beat the Blades 4-2.

TotalEnergies y Vanguard Renewables han firmado un acuerdo para desarrollar 10 proyectos de gas natural renovable en Estados Unidos, potenciando la sostenibilidad y la descarbonización industrial.

TotalEnergies, una empresa global de energía integrada, y Vanguard Renewables, un líder estadounidense en producción de gas natural renovable desde orgánicos a partir de granjas y una empresa de cartera de un fondo administrado por el negocio de Infraestructura Diversificada de BlackRock, han firmado un acuerdo para crear una empresa conjunta de propiedad equitativa para desarrollar, construir y operar proyectos de gas natural renovable (RNG) Farm Powered® en los Estados Unidos. La firma tuvo lugar en Nueva York el 12 de abril de 2024 en presencia de Patrick Pouyanné, presidente y director ejecutivo de TotalEnergies y Larry Fink, presidente y director ejecutivo de BlackRock.

TotalEnergies y Vanguard Renewables avanzarán en la construcción de 10 proyectos de RNG durante los próximos 12 meses, con una capacidad total anual de RNG de 0.8 TWh (2.5 Bcf). Los tres proyectos iniciales de este acuerdo están actualmente en construcción en Wisconsin y Virginia, cada uno con una capacidad unitaria de casi 75 GWh (0.25 Bcf) de GNR por año.

Más allá de estos primeros 10 proyectos, los socios considerarán invertir juntos en una cartera potencial de alrededor de 60 proyectos en todo el país para una capacidad total de 5 TWh (15 Bcf) por año.

“TotalEnergies se complace en asociarse con BlackRock y su empresa de cartera Vanguard Renewables, para acelerar el desarrollo del procesamiento de residuos biológicos de alimentos en gas natural renovable en los Estados Unidos. Al expandirse a este mercado de rápido crecimiento, nuestra empresa conjunta creará valor para ambas compañías. Beneficiando al mismo tiempo a los sectores alimentario y agrícola, además de proporcionar una solución lista para usar a las empresas industriales que deseen descarbonizar su suministro de energía. Esta empresa conjunta es un nuevo paso para TotalEnergies en el logro de su objetivo de producir 10 TWh de gas natural renovable. 2030”, dijo Olivier Guerrini, vicepresidente de Biogás de TotalEnergies.

Vanguard Renewables, un jugador clave de RNG en Estados Unidos

Con sede cerca de Boston, Massachusetts, Vanguard Renewables se fundó en 2014 y cuenta con una plantilla de aproximadamente 260 personas. Actualmente, la empresa opera 17 instalaciones de energía orgánica a energía renovable con una capacidad anual de más de 440 GWh (1.5 Bcf) de GNR. Mirando más allá de 2024, Vanguard Renewables planea poner en marcha más de 100 proyectos de RNG para fines de 2028.

En julio de 2022, Vanguard Renewables fue adquirida por BlackRock, a través de un fondo administrado por su negocio de Infraestructura Diversificada. BlackRock se ha asociado con el equipo directivo de Vanguard Renewables para aprovechar la trayectoria líder en el mercado de la compañía e impulsar la siguiente fase de su crecimiento para respaldar la expansión nacional de sus proyectos de digestores anaeróbicos de costa a costa. BlackRock seguirá siendo el accionista mayoritario de Vanguard Renewables.

“Estamos encantados de dar la bienvenida a TotalEnergies como socio estratégico, aprovechando nuestra misión de desarrollar proyectos de producción de gas natural orgánico y renovable en todo Estados Unidos. Esta colaboración valida la posición de liderazgo de Vanguard en el espacio de RNG en los EE. UU. y reúne nuestra experiencia con la amplia experiencia de TotalEnergies en desarrollo energético a gran escala, procedimientos de seguridad y asociaciones globales. Estos 10 proyectos de RNG, emprendidos conjuntamente por TotalEnergies y Vanguard Renewables como socios de coinversión, refuerzan aún más nuestro compromiso y capacidad para cumplir nuestra misión de aprovechar el poder de los residuos para descarbonizar nuestro planeta”, afirmó Neil H. Smith, director ejecutivo en Vanguard Renovables.

La empresa conjunta se beneficiará de la experiencia de ambas empresas:

• Gracias a sus equipos experimentados y su plataforma de desarrollo, Vanguard Renewables contribuirá a la empresa conjunta con sus proyectos listos para construir a escala. También gestionará el suministro de materia prima, los activos, las operaciones y las ventas de gas natural renovable.
• Aprovechando su fuerte posición en el mercado europeo, especialmente en Francia y Polonia, TotalEnergies aportará a la JV su experiencia industrial, proporcionando soporte técnico en el diseño e ingeniería de las instalaciones, y en el rendimiento operativo de la planta.

TotalEnergies y Vanguard Renewables comercializarán el GNR a través de acuerdos de compra a largo plazo con compradores que participan activamente en la descarbonización de sus procesos industriales.

“Esta emocionante asociación reúne la experiencia global de TotalEnergies en la ampliación y operación de activos de gas renovable con la posición líder en el mercado de Vanguard Renewables en los Estados Unidos, su amplio historial operativo y relaciones con los clientes, y una sólida cartera de proyectos. Con TotalEnergies como socio estratégico, Vanguard Renewables estará posicionada para lograr un crecimiento aún más fuerte y un éxito continuo”, dijo Doug Vaccari, Director General de Infraestructura Diversificada de BlackRock .

Los primeros 10 proyectos se basan en un modelo de recuperación de materiales de desecho de las industrias de alimentos y bebidas, complementado con estiércol de granjas lecheras. Los digestores anaeróbicos se construirán en las propias granjas lecheras, que luego recuperarán y gestionarán el digestato (un subproducto del proceso de digestión anaeróbica) como un fertilizante bajo en carbono y rico en nutrientes.

Para alimentar sus digestores, Vanguard Renewables ha establecido una importante red de marcas líderes de la industria alimentaria en los Estados Unidos y la innovadora Farm Powered Strategic Alliance, que brinda a los miembros de la Alianza acceso preferencial para reciclar sus desechos orgánicos generados en actividades de fabricación o venta minorista y la oportunidad potencial de comprar la energía renovable generada en una instalación de Vanguard Renewables. Los miembros de la Alianza incluyen corporaciones multinacionales de varios sectores verticales, incluidos fabricantes líderes de alimentos, bebidas y productos farmacéuticos.

Anticipándose a la creciente cartera de digestores anaeróbicos de la Compañía, Vanguard Renewables ha ampliado sus servicios de desvío de alimentos y bebidas y su equipo de soluciones orgánicas para brindar servicio en todo los Estados Unidos contiguos.

La finalización de la transacción está sujeta a las condiciones precedentes habituales.

Last week, five Northern European countries announced a series of bilateral agreements on cross-border transport of CO2. Notably absent from the list was the UK.

The governments of Norway, Denmark, Belgium, the Netherlands and Sweden said the agreements will remove “some of the obstacles on the way to a well-functioning carbon capture and storage-market in the wide North Sea region”.

The agreements are centred transporting captured CO2 from major industrial emitters in Belgium, the Netherlands and Sweden to abundant offshore storage sites off the coast of Norway and Denmark.

With Norway positioning itself as the leading storage hub for European CO2 volumes, one analyst told Energy Voice the UK risks “wasting a naturally advantageous position” by not securing similar deals.

The ability to import CO2 shipments is an integral part of many UK carbon capture, utilisation and storage (CCUS) projects in maximising their economic potential.

Without imports, CCS projects like Acorn and Viking and others focused on the North Sea are unlikely to source enough CO2 emissions from domestic emitters to be cost-effective or make full use of the UK’s storage potential.

Norway has ‘enormous capacity’

Norway’s minister of energy Terje Aasland welcomed European neighbours progressing plans to store CO2 in Norwegian storage sites which have “enormous” capacity.

“The climate challenge transcends borders, and it is crucial that we put in place solutions for transport of CO2 across national borders,” he said.

© Supplied by Norwegian Ministry o

“This is an important day for the climate, for our industries and for the first full-scale European CCS project.”

Netherlands minister for climate and energy Rob Jetten said he hoped the declaration would soon lead to a “concrete project” with Norway.

Meanwhile, Belgian minister of the North Sea Paul Van Tigchelt said its deal with Norway will build on previous ones agreed with the Netherlands and Denmark.

“Today, we are taking another important step with Norway to store captured CO2 in their depleted oil and gas fields,” Mr Van Tigchelt said.

With Germany, Europe’s largest economy, also in the process of allowing its industrial emitters to make use of Norway’s Northern Lights CCS project, is the UK falling behind its North Sea neighbour in establishing an international carbon storage model?

UK CCUS ‘vision’

In December last year, the UK government set out its ‘vision’ for what the country’s carbon capture utilisation and storage (CCUS) market would look like in the 2030s.

The 63-page document identifies three phases of development for the CCUS sector: a ‘market creation’ phase until 2030; a transition phase between then and 2035; and ‘self-sustaining market’ from 2035 onwards.

The document also states the government will work towards supporting international CO2 imports and removing regulatory barriers to cross-border CO2 transport.

It also says the government will explore bilateral agreements with countries interested in exporting CO2 to the UK for permanent storage. “work with stakeholders to explore what actions may be required to enable a new commercial framework to support international imports”.

© Supplied by INEOS

The need for bilateral agreements on cross-border CO2 transport and storage is due to the London Protocol, an international agreement which governs the dumping of waste at sea.

Countries which have both applied a 2009 amendment to the protocol can enter into deals to allow for CO2 to be transported and stored across borders.

But unlike Norway and Denmark, the UK has so far not secured any international bilateral agreements since applying the amendment in September 2022.

The UK government’s slow progress on aligning with EU CCS policies has even led to one Scottish firm to look at storing CO2 in Denmark rather than in the UK.

Earlier this year, Carbon Capture Scotland Limited signed a deal to store CO2 emissions in Denmark, with firm’s founders calling it “ludicrous” that UK options were not available.

Norway ‘off to a head start’

Wood Mackenzie senior research analyst for CCUS Dr John Ferrier said Norway is “off to a head start” in positioning itself as the “leading storage hub for European CO2 volumes” thanks to its Northern Lights project.

“Northern Lights will soon begin receiving CO2 from the Netherlands and we expect its list of international customers to grow quickly,” Dr Ferrier said.

© Supplied by Northern Lights

“In contrast, the UK Government has focused on developing a full domestic CCUS value chain to prioritise tackling the UK emissions.

“A perceived lack of need and a lack of political drive may therefore be the reason we have not seen the UK establish bilateral agreements with other countries.

“However, we are seeing the emergence of an international CO2 storage market and, given it hosts almost half of North Sea storage capacity, the UK risks wasting a naturally advantageous position.”

Dr Ferrier said the sale of excess storage could also help support emerging UK CCUS projects, with the Acorn and Viking projects both hoping to receive CO2 from Europe.

“However, this will not be possible without bilateral agreements, which could take years to negotiate from a standing start,” he said.

UK has ‘enormous natural advantage’ on CCS

Like Norway, the UK has ample sites for CO2 storage across its depleted oil and gas fields in the North Sea.

Carbon Capture and Storage Association (CCSA) chief executive Ruth Herbert said the UK is home to around one third of Europe’s geological carbon storage, far more than it needs for its own storage requirements.

The CCSA estimates that around 20 M t p a C O₂ could be safely imported to the U K and stored in subsea geological reservoirs from neighbouring countries by 2035.

© Supplied by Storegga

But despite its “enormous natural advantage”, Ms Herbert said the UK cannot be complacent.

“The UK has made great progress in our CO2 transport and storage models and has 27 licensed CO2 stores, however, as increasing numbers of European countries are negotiating cross-border agreements it is essential that the UK moves quickly to maximise the potential and opportunities that it has available in both geology and offshore skills and experience,” she said.

“This will also provide greater competition in the CO2 storage market and lower costs for emitters across Europe.”

UK ‘playing an active role’ in CO2 networks

To achieve this, as well as putting in place bilateral agreements under the London Protocol, Ms Herbert said the UK government needs to work towards mutual recognition of equivalent storage standards.

This would mean that CO2 stored in the UK will not count as emitted under the EU emissions trading scheme, she said.

The UK government has said it is continuing to collaborate with the EU on carbon capture and storage, as well as participating as an independent observer of the EU’s Zero Emissions Platform.

In response to questions from Energy Voice, a Department for Energy Security and Net Zero spokesperson said: “The UK has one of the greatest CO2 storage potentials of any country in the world, with the North Sea having the potential to hold an estimated 78 billion tonnes.

“We are tapping into this potential by investing up to £20 billion in carbon capture and storage, driving economic growth and supporting up to 50,000 jobs.

“We welcome interest from European nations in using the UK’s vast stores and are playing an active role in developing regional transport and storage networks, including through our membership of the North Sea Basin Taskforce.”

First Quarter 2024 Operating Results:

• First quarter revenue decreased by $17.2 million (or 22%), to $62.0 million in 2024, as compared to $79.2 million in the first quarter of 2023. Contract drilling revenue totalled $39.6 million in the first quarter of 2024, which was $18.5 million (or 32%), lower than $58.1 million in the first quarter of 2023. Production services revenue was $22.4 million for the three months ended March 31, 2024, an increase of $1.1 million (or 5%) as compared to $21.3 million in the same period of the prior year. In the first quarter of 2024, revenue was negatively impacted by lower activity in contract drilling in Canada and the US due to lower commodity prices in the first part of 2024, specifically natural gas prices, compared to the first quarter of 2023 as described below:
  • In Canada, Operating Days of 952 days in the first quarter of 2024 were 331 days (or 26%) lower compared to 1,283 days in the first quarter of 2023. Drilling rig utilization in Canada was 31% in the first quarter of 2024, compared to 42% in the same period of the prior year mainly due to customers cancelling or deferring their programs into the second half of 2024, as a result of lower natural gas prices in 2023 that continued into 2024. The Canadian Association of Energy Contractors (“CAOEC”) industry Operating Days decreased 1% in the first quarter of 2024, compared to the first quarter of 2023, while the CAOEC industry average utilization increased five percentage points to 50%¹ for the first quarter of 2024, compared to the CAOEC industry average utilization of 45% in the first quarter of 2023. The increase in the CAOEC industry average utilization is attributable to a 13% decrease in the average number of drilling rigs registered with the CAOEC in the first quarter of 2024 compared to the first quarter of 2023.  If the number of registered drilling rigs with the CAOEC had not decreased, the CAOEC industry average utilization in the first quarter of 2024 would have been 45%, consistent with the first quarter of 2023.  Revenue per Operating Day averaged $34,233 in the first quarter of 2024, an increase of 3% compared to the same period of the prior year, mainly due to higher pricing;
  • In the United States (“US”), drilling rig utilization averaged 26% in the first quarter of 2024, compared to 45% in the first quarter of 2023, with Operating Days decreasing from 327 days in the first quarter of 2023 to 164 days in the first quarter of 2024 due to lower industry activity. Average active industry rigs of 623² in the first quarter of 2024 were 18% lower compared to the first quarter of 2023. Revenue per Operating Day for the first quarter of 2024 averaged US$31,858, a 4% decrease compared to US$33,021 in the same period of the prior year, mainly due to higher standby revenue in 2023; and
  • In Canada, service rig utilization of 44% in the first quarter of 2024 was consistent with the same period of the prior year. Revenue per Service Hour averaged $1,058 in the first quarter of 2024 and was 3% higher than the first quarter of 2023, due to improved pricing and inflationary pressures on operating costs, including higher wages that are passed through to the customer, which were partially offset by lower fuel surcharges as more customers provided their own fuel.
• The Company generated net income of $1.5 million in the first quarter of 2024 ($0.04 net income per basic common share) as compared to net income of $4.4 million in the same period in 2023 ($0.13 net income per basic common share). The change can mainly be attributed to a $0.7 million decrease in income tax expense, a $0.5 million decrease in stock based compensation expense, and a $0.3 million decrease in finance costs, which were partially offset by a $4.0 million decrease in Adjusted EBITDA, $0.2 million increase in depreciation expense due to property and equipment additions and a $0.2 million increase in other items. Administrative expenses in the first quarter of 2024 were $0.6 million higher than the first quarter of 2023, due to higher employee related costs including severance.
• Adjusted EBITDA of $15.2 million in the first quarter of 2024 was $4.0 million (or 21%) lower compared to $19.2 million in the first quarter of 2023. Adjusted EBITDA in 2024 was lower due to lower drilling revenue in Canada and the US, as well as lower pricing in the US, and inflationary pressures on all costs.
• First quarter additions to property and equipment of $1.9 million in 2024 compared to $5.2 million in the first quarter of 2023, consisting of $0.6 million of expansion capital related to rig upgrades and $1.3 million of maintenance capital.
• On March 22, 2024, the Company extended the maturity of its $35.0 million syndicated revolving credit facility (the “Revolving Facility”) and its $10.0 million committed operating facility (the “Operating Facility” and together the “Credit Facilities”) from May 18, 2025 to the earlier of (i) six months prior to the maturity date of the Second Lien Facility (as defined below) which is currently November 18, 2025, or (ii) March 21, 2027 if the Second Lien Facility is extended. The total commitments under the Credit Facilities are unchanged and there were no changes to the Company’s financial covenants, where are described on page 8 of the Company’s first quarter 2024 MD&A under “Liquidity and Capital Resources”.

Business Overview

Western is an energy services company that provides contract drilling services in Canada and in the US and production services in Canada through its various divisions, its subsidiary, and its first nations relationships.

Contract Drilling

Western markets a fleet of 41 drilling rigs specifically suited for drilling complex horizontal wells across Canada and the US.  Western is currently the fourth largest drilling contractor in Canada, based on the CAOEC registered drilling rigs³.

Western’s marketed and owned contract drilling rig fleets are comprised of the following:

Production Services

Production services provides well servicing and oilfield equipment rentals in Canada. Western operates 63 well servicing rigs and is the second largest well servicing company in Canada based on CAOEC registered well servicing rigs⁴.

Western’s well servicing rig fleet is comprised of the following:

Business Environment

Crude oil and natural gas prices impact the cash flow of Western’s customers, which in turn impacts the demand for Western’s services.  The following table summarizes average crude oil and natural gas prices, as well as average foreign exchange rates, for the three months ended March 31, 2024 and 2023.

West Texas Intermediate on average increased by 1% for the three months ended March 31, 2024, compared to the same period in the prior year.  Pricing on Western Canadian Select crude oil increased by 4% for the three months ended March 31, 2024, compared to the same period in the prior year.  In 2024, crude oil prices improved slightly due to tighter crude oil supplies resulting from OPEC production cuts and ongoing geopolitical conflicts in Ukraine and the Middle East.  However, natural gas prices in Canada declined in 2024 due to lower demand, as the 30-day spot AECO price decreased by 33% for the three months ended March 31, 2024, compared to the same period of the prior year.  Additionally, the US dollar to the Canadian dollar foreign exchange rate for the three months ended March 31, 2024 was consistent with the same period in the prior year.

Despite similar commodity prices in the first quarter of 2024 in both the US and Canada, industry drilling activity weakened in the US.  As reported by Baker Hughes Company⁵, the number of active drilling rigs in the US decreased by approximately 18% to 621 rigs as at March 31, 2024, as compared to 755 rigs at March 31, 2023 and averaged 623 rigs during the first quarter of 2024, compared to 760 rigs in the first quarter of 2023.  In Canada there were 146 active rigs in the Western Canadian Sedimentary Basin (“WSCB”) at March 31, 2024, compared to 140 active rigs as at March 31, 2023, representing an increase of approximately 4%, however the CAOEC⁶ reported that for drilling in Canada, the total number of Operating Days in the WCSB for the three months ended March 31, 2024, were 1% lower than the same period in the prior year.

Outlook

In 2024, commodity prices are being impacted in the short term by concerns surrounding demand from continued uncertainty concerning the ongoing war in Ukraine and by the conflict in the Middle East.  Events such as these contribute to the volatility of commodity prices.  The precise duration and extent of the adverse impacts of the current macroeconomic environment and global economic activity on Western’s customers and operations remains uncertain at this time.  Additionally, the threatened shutdown and relocation of a portion of the Enbridge Line 5 pipeline and the recent challenge of the Blueberry River First Nations agreement in British Columbia by the Treaty 8 nations have contributed to continued uncertainty regarding takeaway capacity and resource development.  However, the Trans Mountain pipeline expansion, as of the date of this press release, is complete with an anticipated in-service date of May 2024.  The Trans Mountain pipeline project, the Coastal GasLink pipeline project, which is mechanically complete and expected to be online in 2025, and the LNG Canada liquefied natural gas project in British Columbia, now more than 85% complete and expected to be online in 2025, may contribute to increased industry activity.  Controlling fixed costs, maintaining balance sheet strength and flexibility, repaying debt and managing through a volatile market are priorities for the Company, as prices and demand for Western’s services are expected to continue to improve.

As previously announced, Western’s board of directors has approved a capital budget for 2024 of $23 million, comprised of $8 million of expansion capital and $15 million of maintenance capital.  Western will continue to manage its costs in a disciplined manner and make required adjustments to its capital program as customer demand changes.  Currently, 12 of Western’s drilling rigs and 9 of Western’s well servicing rigs are operating.

As at March 31, 2024, Western had $3.6 million drawn on its Credit Facilities and $5.6 million outstanding on its committed term non revolving facility (the “HSBC Facility”), which matures on December 31, 2026.  As at March 31, 2024, Western had $99.1 million outstanding on its second lien secured term loan with Alberta Investment Management Corporation (the “Second Lien Facility”), which matures on May 18, 2026.  Western will continue to focus its efforts on debt reduction in 2024.

Energy service activity in Canada will be affected by volatile commodity prices, the continued development of resource plays in Alberta and northeast British Columbia, ongoing pipeline completions that will increase takeaway capacity, environmental regulations, and the level of investment in Canada.  With Western’s upgraded drilling rigs, the Company is well positioned to be the contractor of choice to supply drilling rigs in a tightening market.  Western is also active with three fit for purpose drilling rigs in the Clearwater formation in northern Alberta.  In the short term, the largest challenges facing the energy service industry are volatile commodity prices and the restrained growth in customer drilling activity due to their continuing preference to return cash to shareholders through share buybacks, increased dividends and repayment of debt, rather than grow production.  If commodity prices stabilize for an extended period, then as customers strengthen their balance sheets by reducing debt levels, we expect that drilling activity will increase.  In the medium term, Western’s rig fleet is well positioned to benefit from the increased drilling and production services activity generated by the LNG Canada liquefied natural gas project and the Trans Mountain pipeline expansion.  The total rig fleet in the WCSB has decreased from 440 drilling rigs at March 31, 2023 to 384 drilling rigs as of April 23, 2024, representing a decrease of 56 drilling rigs, or 13%, which reduces the supply of drilling rigs for such projects.  Western is an experienced deep horizontal driller in Canada, with an average well length of 7,897 meters drilled per well and an average of 13.5 operating days to drill per well for the three months ended March 31, 2024.  It remains Western’s view that its upgraded drilling rigs and modern well servicing rigs, reputation for quality and capacity of the Company’s rig fleet, and disciplined cash management provides Western with a competitive advantage.

Non-IFRS Measures and Ratios

Western uses certain financial measures in this press release which do not have any standardized meaning as prescribed by International Financial Reporting Standards (“IFRS”).  These measures and ratios, which are derived from information reported in the condensed consolidated financial statements, may not be comparable to similar measures presented by other reporting issuers.  These measures and ratios have been described and presented in this press release to provide shareholders and potential investors with additional information regarding the Company.  The non-IFRS measures and ratios used in this press release are identified and defined as follows:

Adjusted EBITDA and Adjusted EBITDA as a Percentage of Revenue

Adjusted earnings before interest and finance costs, taxes, depreciation and amortization, other non-cash items and one-time gains and losses (“Adjusted EBITDA”) is a useful non-GAAP financial measure as it is used by management and other stakeholders, including current and potential investors, to analyze the Company’s principal business activities prior to consideration of how Western’s activities are financed and the impact of foreign exchange, income taxes and depreciation.  Adjusted EBITDA provides an indication of the results generated by the Company’s principal operating segments, which assists management in monitoring current and forecasting future operations, as certain non-core items such as interest and finance costs, taxes, depreciation and amortization, and other non-cash items and one-time gains and losses are removed.  The closest IFRS measure would be net income for consolidated results.

Adjusted EBITDA as a percentage of revenue is a non-IFRS financial ratio which is calculated by dividing Adjusted EBITDA by revenue for the relevant period.  Adjusted EBITDA as a percentage of revenue is a useful financial measure as it is used by management and other stakeholders, including current and potential investors, to analyze the profitability of the Company’s principal operating segments.

The following table provides a reconciliation of net income, as disclosed in the condensed consolidated statements of operations and comprehensive income, to Adjusted EBITDA:

Revenue per Operating Day

This non-IFRS measure is calculated as drilling revenue for both Canada and the US respectively, divided by Operating Days in Canada and the US respectively. This calculation represents the average day rate by country, charged to Western’s customers.

Revenue per Service Hour

This non-IFRS measure is calculated as well servicing revenue divided by Service Hours.  This calculation represents the average hourly rate charged to Western’s customers.

Working Capital

This non-IFRS measure is calculated as current assets less current liabilities as disclosed in the Company’s consolidated financial statements.

Defined Terms

Average active rig count (contract drilling): Calculated as drilling rig utilization multiplied by the average number of drilling rigs in the Company’s fleet for the period.

Average active rig count (production services): Calculated as service rig utilization multiplied by the average number of service rigs in the Company’s fleet for the period.

Average meters drilled per well: Defined as total meters drilled divided by the number of wells completed in the period.

Average Operating Days per well: Defined as total Operating Days divided by the number of wells completed in the period.

Drilling rig utilization:  Calculated based on Operating Days divided by total available days.

Operating Days:  Defined as contract drilling days, calculated on a spud to rig release basis.

Service Hours:  Defined as well servicing hours completed.

Service rig utilization:  Calculated as total Service Hours divided by 217 hours per month per rig multiplied by the average rig count for the period as defined by the CAOEC industry standard.

Contract Drilling Rig Classifications

Cardium class rig: Defined as any contract drilling rig which has a total hookload less than or equal to 399,999 lbs (or 177,999 daN).

Montney class rig: Defined as any contract drilling rig which has a total hookload between 400,000 lbs (or 178,000 daN) and 499,999 lbs (or 221,999 daN).

Duvernay class rig: Defined as any contract drilling rig which has a total hookload equal to or greater than 500,000 lbs (or 222,000 daN).

Abbreviations

• Barrel (“bbl”);
• Canadian Association of Energy Contractors (“CAOEC”);
• DecaNewton (“daN”);
• International Financial Reporting Standards (“IFRS”);
• Pounds (“lbs”);
• Thousand cubic feet (“mcf”); and
• Western Canadian Sedimentary Basin (“WCSB”).

Forward-Looking Statements and Information

This press release contains certain forward-looking statements and forward-looking information (collectively, “forward-looking information”) within the meaning of applicable Canadian securities laws, as well as other information based on Western’s current expectations, estimates, projections and assumptions based on information available as of the date hereof.  All information and statements contained herein that are not clearly historical in nature constitute forward-looking information, and words and phrases such as “may”, “will”, “should”, “could”, “expect”, “intend”, “anticipate”, “believe”, “estimate”, “plan”, “predict”, “potential”, “continue”, or the negative of these terms or other comparable terminology are generally intended to identify forward-looking information.  Such information represents the Company’s internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of additions to property and equipment, anticipated future debt levels and revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance.  This forward-looking information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information.

In particular, forward-looking information in this press release includes, but is not limited to, statements relating to: the business of Western; industry, market and economic conditions and any anticipated effects on Western; commodity pricing; the future demand for the Company’s services and equipment; the effect of inflation and commodity prices on energy service activity; expectations with respect to customer spending; the completion and success of Western’s drilling rig upgrade program; the potential continued impact of the current conflicts in Ukraine and the Middle East on crude oil prices; the Company’s capital budget for 2024, including the allocation of such budget; Western’s plans for managing its capital program; the energy service industry and global economic activity; expectations with respect to the Trans Mountain pipeline expansion, including the impact of construction delays and other challenges; the potential shutdown and relocation of the Enbridge Line 5 pipeline; expectations with respect to the Coastal GasLink pipeline project and LNG Canada facility; the impact of the recent challenge to the Blueberry River First Nations decision by the Treaty 8 nations; the development of Alberta and British Columbia resource plays; expectations relating to the increase in takeaway capacity resulting from ongoing pipeline completions; challenges facing the energy service industry; the Company’s focus on debt reduction; expectations with respect to increased drilling activity; and the Company’s ability to maintain a competitive advantage, including the factors and practices anticipated to produce and sustain such advantage.

The material assumptions that could cause results or events to differ from current expectations reflected in the forward-looking information in this press release include, but are not limited to: demand levels and pricing for oilfield services; demand for crude oil and natural gas and the price and volatility of crude oil and natural gas; pressures on commodity pricing; the impact of inflation; the continued business relationships between the Company and its significant customers; crude oil transport, pipeline and LNG export facility approval and development; that all required regulatory and environmental approvals can be obtained on the necessary terms and in a timely manner, as required by the Company; liquidity and the Company’s ability to finance its operations; the effectiveness of the Company’s cost structure and capital budget; the effects of seasonal and weather conditions on operations and facilities; the competitive environment to which the various business segments are, or may be, exposed in all aspects of their business and the Company’s competitive position therein; the ability of the Company’s various business segments to access equipment (including spare parts and new technologies); global economic conditions and the accuracy of the Company’s market outlook expectations for 2024 and in the future; the impact, direct and indirect, of epidemics, pandemics, other public health crisis and geopolitical events, including the conflicts in Ukraine and the Middle East on Western’s business, customers, business partners, employees, supply chain, other stakeholders and the overall economy; changes in laws or regulations; currency exchange fluctuations; the ability of the Company to attract and retain skilled labour and qualified management; the ability to retain and attract significant customers; the ability to maintain a satisfactory safety record; that any required commercial agreements can be reached; that there are no unforeseen events preventing the performance of contracts and general business, economic and market conditions.

Although Western believes that the expectations and assumptions on which such forward-looking information is based on are reasonable, undue reliance should not be placed on the forward-looking information as Western cannot give any assurance that such will prove to be correct.  By its nature, forward-looking information is subject to 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, volatility in market prices for crude oil and natural gas and the effect of this volatility on the demand for oilfield services generally; reduced exploration and development activities by customers and the effect of such reduced activities on Western’s services and products; political, industry, market, economic, and environmental conditions in Canada, the US and globally; supply and demand for oilfield services relating to contract drilling, well servicing and oilfield rental equipment services; the proximity, capacity and accessibility of crude oil and natural gas pipelines and processing facilities; liabilities and risks inherent in oil and natural gas operations, including environmental liabilities and risks; changes to laws, regulations and policies; the ongoing geopolitical events in Eastern Europe and the Middle East and the duration and impact thereof; fluctuations in foreign exchange or interest rates; failure of counterparties to perform or comply with their obligations under contracts; regional competition and the increase in new or upgraded rigs; the Company’s ability to attract and retain skilled labour; Western’s ability to obtain debt or equity financing and to fund capital operating and other expenditures and obligations; the potential need to issue additional debt or equity and the potential resulting dilution of shareholders; uncertainties in weather and temperature affecting the duration of the service periods and the activities that can be completed; the Company’s ability to comply with the covenants under the Credit Facilities, HSBC Facility and the Second Lien Facility and the restrictions on its operations and activities if it is not compliant with such covenants; Western’s ability to protect itself from “cyber-attacks” which could compromise its information systems and critical infrastructure; disruptions to global supply chains; and other general industry, economic, market and business conditions.  Readers are cautioned that the foregoing list of risks, uncertainties and assumptions are not exhaustive.  Additional information on these and other risk factors that could affect Western’s operations and financial results are discussed under the headings “Risk Factors” in Western’s annual information form for the year ended December 31, 2023, which is available under the Company’s SEDAR+ profile at www.sedarplus.ca.

The forward-looking statements and information contained in this press release are made as of the date hereof and Western does not undertake any obligation to update publicly or revise any forward-looking statements and information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.  Any forward-looking statements contained herein are expressly qualified by this cautionary statement.

SOURCE Western Energy Services Corp.

 

Since our last market update in the subsea space about a year ago both our current market view and forecasts have strengthened significantly.

---

While the demand picture is looking solid and arguing for a strong multi-year upcycle, the supply side has also started to wake from its slumber albeit ever so slightly at the time of writing. Moreover, we register an interesting dynamic on the shipowner side, where everyone is trying to position themselves for the impeding market boom.

Please note that vessel definitions and abbreviations in this part of our industry can vary, but for the purposes of this article, we will focus on what we at Fearnley Offshore Supply define as subsea construction vessels (CON), anchor handling construction vessels (AHCON), light construction vessels (LCV), and multi-purpose supply vessels (MPSV) above 68m length overall.

We have previously highlighted the severe tightness of vessel supply in the offshore construction space as project development in both oil and gas as well as offshore renewables are pulling on the same asset pool for a large range of work scopes. With that same combined demand firmly on a rising trajectory with forecasts pointing to a multi-year plateau of high vessel activity the market, we argue, will soon find itself in dire need for more tonnage.

Combine that with the fact of very limited fleet growth, and even a larger number of units exiting the industry in recent years, it is almost ironic that the largest number of construction support vessels is not the present fleet, but was recorded back in 2021.

Coincidently, the market has vastly improved since 2021, especially from the shipowners’ perspective. Dayrates for construction support assets, as displayed on the graphs below, have improved by more than 100, 95, and almost 90% for construction vessels, light construction vessels, and multi-purpose units respectively. Other metrics as well, such as utilization for example, has also improved significantly in that same span of time, and while the aforementioned vessel exits has had some degree of positive impact herein, the most significant driver has undoubtedly been the demand development.

Construction Vessels, Rate level (USD)
Chart Courtesy Fearnley Offshore Supply

Light Construction Vessels, Rate level (USD)
Chart Courtesy Fearnley Offshore Supply

Multipurpose Vessels, Rate level (USD)
Chart Courtesy Fearnley Offshore Supply

Another insightful method to measure the health of the subsea market is to analyze the order backlog of the Tier 1 offshore construction contractors: Subsea 7, TechnipFMC, and Saipem. When doing so, we find that as per the end of 2023, these companies’ combined backlog stood at almost the same value as the previous peak 10 years prior. With more than $40 billion of work in their books, the Tier 1 players have just around 2% less orderbook value than in 2013. As such we argue quite firmly that the market, in a lot of respects, have fully recovered.

Furthermore, back in the previous market upcycle the major subsea contractors significantly increased their controlled fleet, that is the owned and long-term chartered construction support vessels, through large newbuild programs, acquisitions, and long-term chartering. This made a lot of sense given the amount of work they were lining up and threading new water in terms of project complexity at the time.

As the market crashed in the following years, investments in offshore developments all but dried up and the Tier 1’s orderbooks were brought down with it. Unsurprisingly, these companies reduced their controlled fleet significantly by shedding older and non-core tonnage as well as letting charters roll off their engagement without replacements or renewal.

What is rather surprising, however, is that the controlled fleet of these same companies at the time of writing, when their orderbook stands almost at its previous record, is at its lowest in well over a decade. In fact, what we had previously assumed would be the through fleet figure for the Tier 1’s, at 78 controlled vessels during 2020, reached a new low at 74 units during as of the end of last year.

Tier 1 Subsea Contractors Backlog and Controlled Fleet
Chart Courtesy Fearnley Offshore Supply

Therefore, we see no other alternative than that something has got to give, and in light of the vessel demand forecast for these assets, we are of the firm belief that the major subsea contractors sooner rather than later will make some strategic and significant investments. We are not alone in that belief by any means, and as a matter of fact we have seen several positioning moves on the supply side of the market.

Firstly, on an otherwise rather ordinary Thursday in March, not one, nor two, but three subsea construction newbuilds were announced all on the same day!

Rem Offshore confirmed the placement of a construction vessel at Myklebust Verft in Norway. The vessel will have a 250-ton crane and methanol power, enabling their first net zero emissions vessel of this type.

With an expected delivery in 2026, we see the announcement as the first major construction vessel newbuild in the current cycle. Furthermore, two SALT-designed light construction vessels were placed by an undisclosed owner the same day, which will be built at Wuchang Shipbuilding in China. The vessels will be prepared for alternative fuels, including a large battery package with expected delivery in 2026. The vessels are a further development of the successful SALT 305 design, which will be suitable towards both traditional oil and gas clients and core offshore wind scopes.

As we head into a stage of the cycle where vessel shortages could very well soon be reality, we see these newbuilds as a natural development. Other traditional owners have opted for the rearrangement of existing assets, with high corporate activity in recent weeks. Following the battle for Solstad Offshore between Aker and Kistefos, Siem Offshore announced the split of assets between the company founder and remaining shareholders.

Kristian Siem will exit the company he founded with nine vessels in exchange for 35% of the outstanding shares, which include three AHTS, four PSVs, and two subsea construction vessels. Kristian Siem’s Siem Sustainable Energy will become the new owner of the vessels, leaving Siem Offshore a fleet of 17 vessels. Following completion of the transaction, Siem Offshore will continue to manage the vessels on behalf of Kristian Siem for a minimum of one year.

Kistefos, owned by Christen Sveaas, will now be the largest owner of Siem Offshore, combined with being the major owner of Stockholm-listed Viking Supply Ships, which controls a fleet of six AHTS. The rationale for owning two OSV operators with separate organizations, in the same city now less, might be challenged in the near term, yet we have noted that there are no plans for consolidation as of now.

Havila Holding also made moves with the full acquisition of Volstad Maritime, where they have held 52.5% of the shares since 2017. The fleet consists of five subsea construction vessels and one diving support vessel, which is considered high specification and include three 250-tone crane DP-3 units. Havila Holding is now the controlling shareholder in Havila Shipping with a fleet of 14 vessels, joint owner of Skansi Offshore with five vessels and full owner of Volstad Maritime with five vessels.

Subsequently, we can say that the puzzle for securing high quality steel has started and multiple interesting developments have occurred on the corporate side in recent weeks. Investors with strong competence in the space are positioning themselves for a prolonged period of strong earnings, and we can expect further M&A activity going forwards as newbuilding is still limited owning cash generating steel is a top priority.  Nonetheless it still bodes well for the future prospects of the subsea construction segment as these market movements all point to even brighter days ahead.