Category: Oil and Gas

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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.

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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.

 

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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.

 

The U.S. and many other countries are addicted to plastics, with consumers finding it impossible to move away from a wide variety of plastic products. This inevitably equates to huge quantities of plastic waste. As companies continue to rely heavily on plastics for the production and storage of millions of products, several major companies are assuring consumers that they can rapidly shift away from polluting plastics in favor of recyclable, compostable, and all-around more sustainable plastic products. However, many industry experts doubt the validity of these bold claims as they ask – if a transformation is possible why has it not already happened?

The Current Situation 

Around 36 million tons of plastic is thrown away annually in the U.S., a figure higher than any other country. There are 10 chemical recycling facilities across the country at present, with a total capacity of 456,000 tons of plastic when operating at full capacity – which many are not. The U.S. is falling short when it comes to plastic recycling, with no clear indication of how or when this might change. When consumers throw their waste into the recycling, they expect these products to be recycled. However, without the facilities needed to process all this waste most of it is ending up in landfills. 

A New Way to Recycle 

Several big corporations promise a major shift in the coming years to make their products more sustainable. Companies such as L’Oreal, Nestle, and Proctor & Gamble are promising to reduce the use of plastics and make plastic products that remain more sustainable. Several companies plan to do this by developing innovative “advanced” or “chemical” recycling plants that they believe will be capable of recycling a much wider variety of plastic products. 

Rather than grinding up or melting waste plastic, as is done in conventional recycling practices, new, advanced-recycling methods include breaking down plastics much further, into more basic molecular building blocks, and making them into new plastic. It promises to turn plastic polymers back into their original molecules, using methods such as dissolving with chemicals or heat, to be processed and used again and again. 

Is Advanced Recycling Viable?

Nestlé, L’Oréal, and Procter & Gamble are just some of the major players that are investing in advanced recycling methods, with all three funding PureCycle Technologies to help them achieve their plastics targets. The company runs a $500 million facility in Ironton, Ohio, with a processing capacity of 182 tons of waste polypropylene. PureCycle promises to help companies transform hard-to-recycle products, such as single-use cups, yogurt tubs, and coffee pods. The firm’s CEO, Dustin Olson, stated, “We believe in this technology. We’ve seen it work… We’re making leaps and bounds.”

However, the reality is very different. The plant was set to commence operations in 2020 but PureCycle has faced several hurdles in getting it up and running. There have been technical issues at the facility, shareholder lawsuits, and concerns over the efficacy of the technology. 

Meanwhile, an Agilyx and Americas Styrenics-managed chemical recycling facility in Tigard, Oregon, has been forced to shut down following the loss of millions of dollars. Other plants across the U.S. are underperforming as the technology has not lived up to initial expectations. One plant in Ashley, Indiana fell severely short of its aim to recycle 100,000 tons of plastic annually by 2021, having processed just 2,000 tons in total by late 2023. Fires, oil spills, and worker safety complaints were some of the issues cited at the plant. 

In 2023, a report by Beyond Plastics and the International Pollutants Elimination Network found that several chemical recycling projects have failed in previous decades and these types of operations also produce large quantities of hazardous waste, release toxic air pollution, threaten environmental justice, and contribute to climate change. Judith Enck, president of Beyond Plastics, stated, “For many of the same reasons why traditional recycling of plastics has been an abysmal failure, chemical recycling has also failed for decades. Plastic waste is expensive to collect, sort, and clean, and its variety of different chemicals, colors, and polymers makes it inherently too difficult to be made into new plastic products.” 

A Global Effort 

In June last year, negotiators met in Paris to develop a global plastics treaty. While the plastics industry is pushing for more recycling, other sectoral experts believe this will not solve the global plastics problem. A U.N. Environment Program report published prior to the talks raised concerns about the chemicals found in plastics and the potential for the chemicals to be released during the recycling process. A Greenpeace report showed that toxicity can build up in recycled plastics, either through contamination or as a result of the recycling process itself. 

Plastics manufacturers and several major corporations are optimistic about the potential for advanced recycling technology, believing that it could transform the plastics sector and make products more sustainable. However, several failures at facilities in recent years, coupled with underperformance and concerns over the chemicals used and produced at plants, suggest that advanced recycling may be a pipedream. Whether or not chemical recycling improves, the sector must be strictly regulated to ensure public safety and prevent companies from greenwashing when it comes to their plastic promises.

Always Be Aware With Shale Magazine

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

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

The fuel savings gained by installing energy storage systems on oil and gas platforms are significant, but it’s the safe-ty benefits that might overcome what has been a relatively slow uptake of late.

Industry lore has it that drilling rigs say hello to each other using the gensets onboard to make smoke signals. The reality is that the engineers are often just running the generators at low load to ensure they have spinning reserve. The soot released is a byproduct of that sub-optimal load and the need to maximize energy security.

Energy security is paramount offshore, so sub-optimal energy production can be maintained for days or weeks, for example in adverse weather conditions, due to the long time needed to stop and restart generators.

In 2019, Woodside claimed a first when it installed a 1MW battery ESS on the Goodwyn A production platform to provide spinning reserve so that three gas turbine generators can run optimally rather than four sub-optimally.

The same year, Siemens Energy claimed a first for the installation of its BlueVault ESS on the West Mira semi-sub drilling rig. Here it is used for peak shaving during topside operations as well as spinning reserve in DP operations, nearly halving the run time of the platform’s diesel engines. Siemens Energy’s subsequent installations include the jack-ups Maersk Intrepid and Maersk Integrator.

Between 2019 and 2022, Corvus Energy delivered energy storage for NOV PowerBlade installations on four Odfjell Drilling semi-subs: Deepsea Aberdeen, Deepsea Atlantic, Deepsea Stavanger and Deepsea Nordkapp. The system captures electrical braking energy from drilling or hoisting systems and provides it to the power grid to enable peak shaving.

One of the world’s most advanced offshore construction vessels, the North Sea Giant, was the first vessel where batteries (from Corvus Energy) were part of a DP3 power management system.
Corvus Energy SVP sales, Efraim Kanestrom, notes some cooling off on retrofit projects over the last couple of years due to rising oil prices and the greater geopolitical need for energy security. It’s a temporary lull that he believes could be overcome soon even if the focus on emission reduction and energy efficiency is temporarily reduced in the industry. The operators still need to focus on the safety of crew and assets.

NOV powerblade Corvus dolphin lightweight ESS scaled .
Image courtesy Corvus

In addition to the environmental and financial benefits, hybridization reduces soot and NOx emissions, a health benefit for offshore crews. Blackout prevention and better station-keeping are also beneficial to operational safety, reducing downtime and improving crew well-being.

Still, the industry has been reticent over concerns that the ESS itself could be a hazard by acting as an ignition source in an already high-risk environment. Kanestrom notes that the company’s Orca system was the first ESS to be approved for use on offshore oil and gas platforms and that its in-built safety systems include the possibility to shut down the system completely (with no risk for sparks) in case of an emergency situation with hydrocarbons on deck.

The safety features of the Siemens Energy BlueVault system include using liquid cooled modules built into a stand-ard Siemens Energy switchboard system. Each module is connected touch-free at the rear of the system to the bat-tery interface module through short-circuit-proof rails. For additional protection of the crew and the establishment of robustness against internal faults, the plant is enclosed and equipped with doors, so the design is like a distribu-tion switchboard where several racks are connected through the same internal busbar. Arcing cannot occur on either the battery or the busbar side of the battery interface module, so the design will prevent an internal electri-cal failure from igniting the battery modules, regardless of the cause of the failure.

Siemens Energy’s installations include the jack-up Maersk Intrepid.
Image Courtesy Siemens Energy

Demand is growing significantly, says George Bitar, Siemens Energy business development manager for offshore solutions.
Image Courtesy Siemens Energy

Siemens Energy business development manager for offshore solutions, George Bitar, says demand is growing signifi-cantly for the system offshore for both newbuildings and retrofit, partly as a result of the reduction in opex that BlueVault offers through its advanced digital battery monitoring system.

Battery manufacturer Echandia has entered the market too, with a 2023 order for an ESS for a jack-up drilling rig in the Middle East.

Professor Elisabetta Tedeschi of the Norwegian University of Science and Technology (NTNU) and University of Trento says that while uptake has been limited to date, lithium ion batteries have only recently experienced wide adoption in several other sectors due to a relatively steep cost decrease. As an example, according to the Interna-tional Energy Agency, the global installed capacity of grid-scale battery ESS was 28GW as of 2022, of which 11GW was added in 2022 alone. Offshore oil and gas platforms may represent the next frontier.  

Tedeschi and her team have developed a versatile seven-step technology suitability assessment for the installation of ESS on offshore platforms. Testing the assessment methodology on the operating profile of one North Sea plat-form, the required ESS capabilities were calculated based on the need to provide maximum power for six hours to reduce the 77MW load peak by 5%. The results indicated that lithium iron phosphate (LFP) was the most suitable battery chemistry for peak shaving. LFP has the safety advantage that it is thermally stable, so there is no risk of thermal runaway.

A second case study indicated LFP and lithium nickel manganese cobalt (NMC) were jointly most suited for providing spinning reserve on another platform.

In both cases, safety was an important consideration, along with factors such as high volumetric density, low mainte-nance and solid operating experience.

Using offshore renewable power offers an alternative way of reducing emissions on production platforms, but this is unlikely to eliminate the need for ESS. Tedeschi’s team have evaluated the lifecycle costs of using ESS for primary frequency control to ensure the intermittency of wind power generation does not result in sudden critical fre-quency fluctuations.

Lithium-ion capacitor technology from Beyonder in Norway was regarded as a promising technology. This combina-tion of battery cell and supercapacitor is very safe, with reduced risk of thermal runaway when compared to lithium ion battery chemistries. However, the technology is not yet mature, so it is yet to see large-scale adoption.

That is expected to change in the future, and Tedeschi co-researcher Ayotunde A. Adeyemo says ESS can play a major role in upstream decarbonization and increase the penetration of renewable energy.

“Smoke signaling” could soon be a thing of the past.
Offshore oil and gas platforms may represent the next frontier, said Professor Elisabetta Tedeschi of the Norwegian University of Science and Technology (NTNU) and University of Trento
Image courtesy NTNU

The fuel savings gained by installing energy storage systems on oil and gas platforms are significant, but it’s the safe-ty benefits that might overcome what has been a relatively slow uptake of late.

Industry lore has it that drilling rigs say hello to each other using the gensets onboard to make smoke signals. The reality is that the engineers are often just running the generators at low load to ensure they have spinning reserve. The soot released is a byproduct of that sub-optimal load and the need to maximize energy security.

Energy security is paramount offshore, so sub-optimal energy production can be maintained for days or weeks, for example in adverse weather conditions, due to the long time needed to stop and restart generators.

In 2019, Woodside claimed a first when it installed a 1MW battery ESS on the Goodwyn A production platform to provide spinning reserve so that three gas turbine generators can run optimally rather than four sub-optimally.

The same year, Siemens Energy claimed a first for the installation of its BlueVault ESS on the West Mira semi-sub drilling rig. Here it is used for peak shaving during topside operations as well as spinning reserve in DP operations, nearly halving the run time of the platform’s diesel engines. Siemens Energy’s subsequent installations include the jack-ups Maersk Intrepid and Maersk Integrator.

Between 2019 and 2022, Corvus Energy delivered energy storage for NOV PowerBlade installations on four Odfjell Drilling semi-subs: Deepsea Aberdeen, Deepsea Atlantic, Deepsea Stavanger and Deepsea Nordkapp. The system captures electrical braking energy from drilling or hoisting systems and provides it to the power grid to enable peak shaving.

One of the world’s most advanced offshore construction vessels, the North Sea Giant, was the first vessel where batteries (from Corvus Energy) were part of a DP3 power management system.
Corvus Energy SVP sales, Efraim Kanestrom, notes some cooling off on retrofit projects over the last couple of years due to rising oil prices and the greater geopolitical need for energy security. It’s a temporary lull that he believes could be overcome soon even if the focus on emission reduction and energy efficiency is temporarily reduced in the industry. The operators still need to focus on the safety of crew and assets.

NOV powerblade Corvus dolphin lightweight ESS scaled .
Image courtesy Corvus

In addition to the environmental and financial benefits, hybridization reduces soot and NOx emissions, a health benefit for offshore crews. Blackout prevention and better station-keeping are also beneficial to operational safety, reducing downtime and improving crew well-being.

Still, the industry has been reticent over concerns that the ESS itself could be a hazard by acting as an ignition source in an already high-risk environment. Kanestrom notes that the company’s Orca system was the first ESS to be approved for use on offshore oil and gas platforms and that its in-built safety systems include the possibility to shut down the system completely (with no risk for sparks) in case of an emergency situation with hydrocarbons on deck.

The safety features of the Siemens Energy BlueVault system include using liquid cooled modules built into a stand-ard Siemens Energy switchboard system. Each module is connected touch-free at the rear of the system to the bat-tery interface module through short-circuit-proof rails. For additional protection of the crew and the establishment of robustness against internal faults, the plant is enclosed and equipped with doors, so the design is like a distribu-tion switchboard where several racks are connected through the same internal busbar. Arcing cannot occur on either the battery or the busbar side of the battery interface module, so the design will prevent an internal electri-cal failure from igniting the battery modules, regardless of the cause of the failure.

Siemens Energy’s installations include the jack-up Maersk Intrepid.
Image Courtesy Siemens Energy

Demand is growing significantly, says George Bitar, Siemens Energy business development manager for offshore solutions.
Image Courtesy Siemens Energy

Siemens Energy business development manager for offshore solutions, George Bitar, says demand is growing signifi-cantly for the system offshore for both newbuildings and retrofit, partly as a result of the reduction in opex that BlueVault offers through its advanced digital battery monitoring system.

Battery manufacturer Echandia has entered the market too, with a 2023 order for an ESS for a jack-up drilling rig in the Middle East.

Professor Elisabetta Tedeschi of the Norwegian University of Science and Technology (NTNU) and University of Trento says that while uptake has been limited to date, lithium ion batteries have only recently experienced wide adoption in several other sectors due to a relatively steep cost decrease. As an example, according to the Interna-tional Energy Agency, the global installed capacity of grid-scale battery ESS was 28GW as of 2022, of which 11GW was added in 2022 alone. Offshore oil and gas platforms may represent the next frontier.  

Tedeschi and her team have developed a versatile seven-step technology suitability assessment for the installation of ESS on offshore platforms. Testing the assessment methodology on the operating profile of one North Sea plat-form, the required ESS capabilities were calculated based on the need to provide maximum power for six hours to reduce the 77MW load peak by 5%. The results indicated that lithium iron phosphate (LFP) was the most suitable battery chemistry for peak shaving. LFP has the safety advantage that it is thermally stable, so there is no risk of thermal runaway.

A second case study indicated LFP and lithium nickel manganese cobalt (NMC) were jointly most suited for providing spinning reserve on another platform.

In both cases, safety was an important consideration, along with factors such as high volumetric density, low mainte-nance and solid operating experience.

Using offshore renewable power offers an alternative way of reducing emissions on production platforms, but this is unlikely to eliminate the need for ESS. Tedeschi’s team have evaluated the lifecycle costs of using ESS for primary frequency control to ensure the intermittency of wind power generation does not result in sudden critical fre-quency fluctuations.

Lithium-ion capacitor technology from Beyonder in Norway was regarded as a promising technology. This combina-tion of battery cell and supercapacitor is very safe, with reduced risk of thermal runaway when compared to lithium ion battery chemistries. However, the technology is not yet mature, so it is yet to see large-scale adoption.

That is expected to change in the future, and Tedeschi co-researcher Ayotunde A. Adeyemo says ESS can play a major role in upstream decarbonization and increase the penetration of renewable energy.

“Smoke signaling” could soon be a thing of the past.
Offshore oil and gas platforms may represent the next frontier, said Professor Elisabetta Tedeschi of the Norwegian University of Science and Technology (NTNU) and University of Trento
Image courtesy NTNU