Michael Heim, Senior Energy & Transportation Analyst, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Results demonstrate strong production growth and a sharp increase in cash flow and earnings. Production rates (preannounced) increased 55%. Increased production was partially offset by a drop in energy prices. Lower-than-expected prices were partially offset by a decrease in royalty rates. Production costs (excluding transportation costs) remain somewhat elevated as they were in the September quarter. We look for production costs per barrel to decrease modestly as new production comes on line in 2023.
As netbacks rose, so did the company’s Adjusted Fund Flow (AFF). The margin between prices and costs is high. Operating netbacks (realized prices less royalties and operating costs) is leading to strong cash flow which management is turning their focus toward returning to shareholders now that debt is virtually eliminated and drilling programs have been accelerated.
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This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
Largo has a long and successful history as one of the world’s preferred vanadium companies through the supply of its VPURE™ and VPURE+™ products, which are sourced from one of the world’s highest-grade vanadium deposits at the Company’s Maracás Menchen Mine in Brazil. Aiming to enhance value creation at Largo, the Company is in the process of implementing a titanium dioxide pigment plant using feedstock sourced from its existing operations in addition to advancing its U.S.-based clean energy division with its VCHARGE vanadium batteries. Largo’s VCHARGE vanadium batteries contain a variety of innovations, enabling an efficient, safe and ESG-aligned long duration solution that is fully recyclable at the end of its 25+ year lifespan. Producing some of the world’s highest quality vanadium, Largo’s strategic business plan is based on two pillars: 1.) leading vanadium supplier with an outlined growth plan and 2.) U.S.-based energy storage business support a low carbon future.
Michael Heim, Senior Vice President – Equity Research Analyst, Natural Resources, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Largo announced reduced production but increased sales. Largo announced 2023-1Q V2O5 production of 2,111 tonnes (23 tonnes/day) near the upper end of guidance, albeit slightly below that in used our models. The 14% decrease in production versus the same period last year come due to heavy rain in the early part of the quarter, planned maintenance, and the transition of a mining contractor. These factors were known and reflected in our estimates. Production levels also reflect a decline in effective grade to 0.81% from 1.27% as less vanadium was produced despite a 13% increase in mined ore.
Sales rose despite lower production as the company sold inventory and purchased material. V2O5 equivalent sales were 2,849 tonnes in the quarter, up 28% over last year sales of 2,232 tonnes and well above guidance of 2,300-2,500 tonnes and our projections that assumed sales near production levels. Sales include 245 tonnes of purchased material versus only 79 tonnes last year.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
Image: Deuterium ionized into fusion plasma lets off a fuchsia glow (Helion)
A Hybrid Regulatory Approach by the NRC on Fusion
A fusion energy system is a power plant that harnesses energy released from the fusion of atomic nuclei to generate electricity. New commercial fusion designs intended to assist in the future of mass power, are being engineered with very little regulatory framework for them to design toward. The US Nuclear Regulatory Commission (NRC) Chairman Christopher Hanson wants the regulatory framework for fusion energy systems based on its existing process for licensing the use of byproduct materials. A new framework may add to the number of companies designing and developing pilot reactors.
The process of fusion involves bringing together atomic nuclei under high temperatures and pressures to create a plasma state, where the positively charged nuclei fuse to form heavier elements, releasing a large amount of energy in the process. Unlike traditional nuclear power plants, which rely on nuclear fission, fusion power plants do not produce long-lived radioactive waste and have a virtually limitless supply of fuel in the form of hydrogen isotopes found abundantly in seawater. Fusion energy, holds great promise as a clean and sustainable source of energy as fossil fuels fall from favor.
“Dozens” of companies are developing pilot-scale commercial fusion designs, according to NRC Chair Christopher Hanson. In a press release by the NRC last Friday Hanson said the “precise future” for fusion in the USA is uncertain, the agency should provide “as much regulatory certainty as possible given what we know today.” The reason provided in the release said,”Licensing near-term fusion energy systems under a byproduct material framework will protect public health and safety with a technology-neutral, scalable regulatory approach.”
Is this overstepping on the part of the NRC? The Commission describes a fusion system as a device that contains nuclear fusion reactions as well as associated radioactive materials and supporting structures, systems and components – would generate electricity from the energy released when hydrogen atoms are combined to form helium, rather than the splitting, or fission, of uranium atoms. This very definition causes the systems to fall outside the requirements to be regulated by NRC as nuclear reactors, because they do not involve special nuclear material (plutonium, uranium-233 or enriched uranium) and cannot produce the self-sustained neutron chain reaction that defines nuclear fission reactors under NRC regulations.
The NRC staff outlined suggested options earlier in 2023 for the licensing and regulation of fusion systems. It categorized them as “utilization facilities”, with a novel regulatory framework developed to address associated specific hazards. These include a byproduct material approach, which adds to the existing regulations for byproduct material licenses. It also included a hybrid framework where the decision on whether a byproduct material or a utilization facility approach would be most appropriate for a particular system based on the potential dangers and hazards inherent to it – it would need to define what would be most applicable for that system. The NRC staff supported the use of a hybrid system in its submission.
Tritium and other radioactive materials which occur or are used in fusion systems have been categorized by the NRC as byproduct material. The NRC has now directed its staff to create a regulatory framework for fusion systems built on the agency’s existing process for licensing the use of such materials.
Image: @Helion_Energy (Twitter)
The Commission will move forward with a “limited revision” to materials licensing regulations, including consideration of whether the revision should include a new category specifically for fusion energy systems. The rule, according to the NRC, take into account fusion systems “that already have been licensed and are being regulated by the Agreement States, as well as those that may be licensed prior to the completion of the rulemaking”. The commission staff is also exected to expand materials license guidance to cover fusion systems across the US.
The US Department of Energy (DOE) announced in 2022 up to $50 million of federal funding to support experimental research in fusion energy science as part of the Biden administration’s vision to accelerate fusion energy. New designs are speeding along as a few fusion systems are likely reach design proof-of-concept, and even net power production later this decade, with deployment projected to follow in the 2030s, according to the NRC.
One US fusion system developer, Helion Energy, expressed support for the NRC’s announcement. “This approach provides a clear and effective regulatory path for our team to deploy clean, safe fusion energy,” the company said on Twitter.
Will the CPI Number or Fed Minutes Change the Market Direction this Week?
Market-moving economic reports are likely this week. Those with the highest chance to move markets are March CPI data on Wednesday, then FOMC minutes from the meeting just after last month’s bank failures, and the Producer Price Index on Thursday.
The minutes of the March 21-22 FOMC meeting will be released at 2:00 PM Wednesday, this highly watched information coincides with the half-fiscal year Budget Report from the U.S. Treasury. The FOMC minutes will get a lot of attention, but the U.S. Budget Deficit is likely to receive renewed focus as we approach summer and begin to bump up against the Treasury’s borrowing ceiling.
Monday 4/10
10:00 AM ET, Wholesale Inventories’ second estimate for February is expected to show a 0.2 percent build up; this would be unchanged from the first estimate.
Tuesday 4/11
6:00 AM ET, Small Business Optimism Index has been below the historical average of 98 for 14 months in a row. March’s consensus is 89.0 versus 90.9 in February. The direction of the health of small businesses can foreshadow changes in the stock market.
1:30 PM ET, Austan Goolsbee, President of the Federal Reserve Bank of Chicago will be speaking at a luncheon at the Economic Club of Chicago.
Wednesday 4/12
8:30 AM ET, The Consumer Price Index (CPI) core prices for March are expected to have risen by 0.4 percent versus February’s sharp and higher-than-expected increase of 0.5 percent. Overall, headline inflation prices are expected to have increased 0.3 percent after February’s 0.4 percent rise. Annual rates, which in February were 6.0 percent overall and 5.5 percent for the core, are expected to show 5.2 and 5.6 percent.
9:10 AM ET, Thomas Barkin, President of the Federal Reserve Bank of Richmond will be speaking. He spoke on April 3, indicating his expectations are that low unemployment rates will continue to support the belief that the economy is not at risk of a recession. Inflation, however, is not going away anytime soon, according to Barkin.
10:30 AM ET, The Energy Information Administration (EIA) will provide its weekly information on petroleum inventories in the U.S., whether produced here or abroad. The level of inventories helps determine prices for petroleum products. Markets will be paying close attention after OPEC+ cut production one week ago.
2:00 PM ET, FOMC minutes from the March 21-22 meeting will be released. This report will have two areas that investors will focus on. These are conversations surrounding U.S. bank health, and those discussions related to inflation and interest rates.
2:00 PM ET, the Treasury Statement related to the budget deficit are expected to report a $253.0 billion deficit in March. This would compare with a $192.7 billion deficit in March a year-ago and a deficit in February this year of $262.4 billion. March is the halfway point into the U.S government’s fiscal year.
Thursday 4/13
8:30 AM ET, Producer Price Index (PPI), After dropping 0.1 percent lower on the month in February, this inflation index on the producer level in March is expected to be unchanged. March’s ex-food ex-energy rate is seen up 0.3 percent versus February’s no change.
4:30 PM ET, the Federal Reserve’s Balance Sheet has been receiving heightened attention. After the Silicon Valley Bank collapse the Fed institutes a new method for banks to get assistance, markets will watch to see if this has grown. Also, as interest rates have risen, the fixed income securities held by the Fed have repriced billions lower, Fed watchers are beginning to comment on how dramatic this drop in value has been. The last line investors will focus on is quantitative easing. Specifically, investors will look to see if the Fed is on track with its letting securities mature off its books without reinvestment – this reduces U.S. dollars in circulation.
Friday 4/14
8:30 PM ET, March Retail Sales are expected to have fallen 0.4 percent for a second month in a row. Excluding autos, a 0.4 percent decline is also expected.
9:15 AM ET, Industrial Production is expected to rise 0.3 percent in March after being unchanged in February.
10:00 AM ET, Business Inventories for February are expected to have risen 0.3 percent following a 0.1 percent draw in January.
10:00 AM ET, Consumer Sentiment, which sank five full points in March to 62.0, is expected to improve to 62.7 in the first reading for April.
What Else
Taxes are due April 18 this year. This typically creates a wave of new IRA deposits. On April 13, in NYC there will be a luncheon roadshow with PDS Biotechnology. Noble Capital Markets organize the event, more details are available on Channelchek by clicking here.
CALGARY, AB, April 5, 2023 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces March 2023 average sales volumes of 2,690 boepd, including natural gas sales of 15.4 MMcfpd, associated natural gas liquids sales from condensate of 120 bopd and 8 bopd of oil sales, based on field estimates. Overall, our sales volumes averaged 2,767 boepd in the first quarter of 2023, an increase of 2% from the fourth quarter of 2022 and a new quarterly record for Alvopetro.
Alvopetro Energy Ltd.’svision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
All amounts contained in this new release are in United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.
Abbreviations:bbls = barrelsboepd = barrels of oil equivalent (“boe”) per daybopd = barrels of oil and/or natural gas liquids (condensate) per dayMMcf = million cubic feetMMcfpd = million cubic feet per day
BOE Disclosure. The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
Forward-Looking Statements and Cautionary Language. This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward–looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the expected natural gas sales and gas deliveries under the Company’s long-term gas sales agreement. The forward–looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to expectations and assumptions concerning the performance of producing wells and reservoirs, foreign exchange rates, well development and operating performance, the timing of regulatory licenses and approvals, equipment availability, the success of future drilling, completion, testing, recompletion and development activities, expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the outlook for commodity markets and ability to access capital markets, general economic and business conditions, the impact of the COVID-19 pandemic, weather and access to drilling locations, the availability and cost of labour and services, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Could Small Oil Companies Perform Especially Well With OPEC’s Reduced Output
Earlier this week, OPEC+ announced the cartel’s plans for production cuts. Saudi Arabia and other oil-producing members of OPEC+ defied expectations by announcing they would implement production cuts of around 1.1 million barrels a day. Prices of WTI and Brent crude quickly moved higher in the futures market – energy stocks followed. The increased cost of petroleum directly impacts the price of fuel and plastics and indirectly impacts goods that involve transportation – which is mostly all goods.
The decision by OPEC+ is highly likely to put upward pressure on CPI and PPI inflation measures as early as April. The CPI report for April will be released on May 10, and PPI on May 11. Id there good news for investors in the OPEC decision? What stocks might investors look at as potentially benefiting, assuming the OPEC countries adhere to the new production levels?
Background
U.S. markets were not open when the Organization of Petroleum Exporting Countries announced the large cut of over one million barrels per day. When regular trading resumed in the U.S. on Monday, oil prices jumped up 6.3%, and crude oil prices breached $80. Energy stocks, as measured by the Energy Sector SPDR (XLE) rose 4.5%. The price of crude based on futures contracts and the XLE have remained near these levels.
With change comes opportunity. Investors and traders are now trying to determine if this is the start of a new upward trend for the energy sector and, if so, what specific moves may benefit investors most.
One consideration they may have is that, although OPEC is cutting production, the members aren’t the only producers. Historically, domestic production was increased in N. America when prices climbed. This has been less so in recent years as the number of U.S. rigs operating hasn’t increased as might have been expected.
Will this dramatic price spike now prompt action from domestic producers? In his Energy Industry Report published on April 4, titled Why Domestic Producers Cannot Offset OPEC Production Cuts, Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, says that oil is produced in the U.S. at around $30-$40 per barrel. Heim says in his report, “If producers had the ability to ramp up drilling, we would have thought they would have done so even at $60/bbl. prices.”
Possible Beneficiaries
According to the Noble Analyst, large producers have been constrained from growing their oil operations which stems from political and even shareholder pressures to move away from carbon-based energy products. However, Heim says in his report, “Smaller producers face less pressure. Companies with ample acreage and drilling prospects are best positioned to take advantage of a prolonged oil price upcycle.”
In a conversation with the analyst, he shared that when oil prices spiked during the second half of the pandemic and later had added upward movement with the start of the Russia/Ukraine war, many small oil companies took in enough additional revenue to strengthen their finances. Some even began paying dividends for the first time, while others increased their regular dividend to shareholders.
These smaller oil producers not in the political spotlight that may reap additional benefits from OPEC’s cut could include Hemisphere Energy (HMENF). This company increased production by 55% in 2022. According to a research report by Noble Capital Markets initiating coverage on Hemisphere (dated April 3, 2023), “proven reserve findings and development costs are less than C$12/barrel, providing an extremely attractive return on investment for drilling.” It continued, “Hemisphere’s finding and development costs are among the lowest of western Canadian producers and reflect its favorable drilling locations and the company’s experience drilling in the area.” The increase in price per barrel could enhance cash flow for this North American producer, allowing it to expand production.
Permex Petroleum (OILCD, OIL.CN) is a junior oil and gas company that already had a significant upside potential before the jump in per-barrel prices. This boost in cash from higher oil prices and a possible uplisting to the NYSE, could work to benefit shareholders.
InPlay Oil (IPOOF) increased annual production last year by 58%. InPlay is an example of a smaller producer that has been able to increase drilling when prices rise. It has used increased cash flow to lower debt levels by 59% and pay shareholders with its first dividend payment.
Indonesia Energy Corporation Ltd. (INDO) is an oil and gas exploration and production company operating in Indonesia. The company plans on drilling 18 wells in the Kruh Block (four have been completed). Covid19 steps in the region where Indo Energy operates have pushed back drilling that was expected in 2023-2024 one year.
Take Away
With change comes opportunity. Higher oil prices will impact all of us that must still occasionally stop our internal combustion engine vehicles at gas stations. But the oil price increase may lead to a melting up of some stocks.
There are arguments that can be made that smaller, more nimble producers, not burdened by the political spotlight and perhaps enjoying a better financial position from the last run-up in oil, are worth looking into. A Channelchek search returned over 200 companies that may fall into this category. This search result is available here.
CALGARY, AB, April 3, 2023 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) is pleased to confirm that its Board of Directors has declared a monthly cash dividend of $0.015 per common share payable on April 28, 2023, to shareholders of record at the close of business on April 17, 2023. The monthly cash dividend is expected to be designated as an “eligible dividend” for Canadian federal and provincial income tax purposes.
About InPlay Oil Corp.
InPlay is a junior oil and gas exploration and production company with operations in Alberta focused on light oil production. The company operates long-lived, low-decline properties with drilling development and enhanced oil recovery potential as well as undeveloped lands with exploration possibilities. The common shares of InPlay trade on the Toronto Stock Exchange under the symbol IPO and the OTCQX Exchange under the symbol IPOOF.
Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.
Refer to the bottom of the report for important disclosures
OPEC cut boosts oil prices and energy stocks, offsetting last quarter’s underperformance in one day. OPEC announced a 1 million bbls./day voluntary production cut causing oil prices to rise 6.3% to a level near $80/bbl. and the XLE Energy Index to rise 4.5% the day after the announcement.
If domestic producers had the ability to expand production, they would have already. In the past, domestic production has risen in response to higher oil prices. In recent years, however, rig count has not increase as much as one would expect given the rise in oil prices. We believe the low rig count reflects a decrease in the number of economically feasible drilling locations. We would note that producers are generally able to produce oil at a cost of $30-$40/bbl. well below oil prices. If producers had the ability to ramp up drilling, we would have thought they would have done so even at $60/bbl. prices.
Horizontal drilling and fracking have increased production decline curves putting companies on a treadmill just to maintain production. More than half of domestic production comes from wells drilled in the last 24 months. The implication is that domestic oil producers are hard pressed to drill enough wells to offset production declines, let alone increase overall production to counter production declines by OPEC. As a result, we believe oil prices could remain high for many years.
Small producers and companies with a large drilling portfolio are best positioned. Larger producers continue to be constrained from expanding oil operations given political and shareholder pressures to move away from carbon-based energy. Smaller producers face less pressure. Companies with ample acreage and drilling prospects are best positioned to take advantage of a prolonged oil price upcycle.
Look for an increased focus on returning capital to shareholders. After several years of high energy prices, many companies have paid down debt and invested in infrastructure. With drilling prospects limited, we believe management will increasing look to raise dividends or repurchase shares.
Energy Stocks
Energy stocks, as measured by the XLE Energy Index, declined 5.3% in the 2023 first quarter. The decline was a sharp contrast to the 7.0% increase in the S&P 500 Index. The decline comes after several years of strong performances for energy stocks and reflects a 5.7% decrease in oil prices and a 50.5% decrease in natural gas prices. Worthy of note, as we are writing this report on April 3rd, oil prices have risen 6.3% and the XLE Energy Index is up 4.5% in response to an announcement by OPEC+ to reduce production by more than 1 million barrels per day. Following the announcement, oil prices settled above $80/bbl. almost reaching the price at the end of 2022.
Figure #1
If the cuts are adhered to, it will represent a significant increase in the excess production capacity of OPEC+. The surplus has grown steadily since the pandemic surpassing 5 million bbls./day according to the U.S. Energy Information Administration. That surplus had begun to decrease as the pandemic eased and global oil demand returned to normal levels. A reduction in production levels would return surplus capacity to pandemic levels.
Figure #2
With OPEC+ reducing production and oil prices rising, it will be interesting to see if producers in North America will respond by increasing production. In the past, when oil prices rose sharply, producers responded by drilling more wells. The advent of horizontal drilling and fracking over the last 15 years has greatly improved the economics of drilling in the basin by increasing the initial flow rates of oil and gas wells. As the chart below indicates, almost all wells drilled in North America are horizontal wells.
Figure #3
Unfortunately, one of the impacts of increased oil and gas flow is that production will decline at a higher rate after the initial production. That means more and more wells need to be drilled just to offset the drop in production. The chart below, while somewhat dated, shows Permian Basin oil production separated by the year wells came on-line. The chart shows that in 2022, more than half of all oil production came from wells drilled in 2021 or 2022. The implication is that domestic oil producers are hard pressed to drill enough wells to offset production declines, let alone increase overall production to counter production declines by OPEC+.
Figure #4
Source: Novi Labs
Without a rise in domestic production, it is likely that oil prices will remain at elevated levels. This is good news for producers who can produce oil at $30-$40 per barrel. The high netbacks (prices less royalties and operating costs) mean increased profits and cash flow for energy companies. And, if an energy company is fortunate enough to have a large acreage position with an abundance of potential drilling sites, growth rates will accelerate.
Natural Gas Prices
The outlook for natural gas, however, is not as rosy. Natural gas prices fell sharply this winter in response to warm weather and weak economic conditions.
Figure #5
Source: Natural Gas Intelligence
Storage levels, which were running below historical levels, are now at five-year highs for this time of year. With the winter heating season now coming to an end, storage levels are unlikely to reverse. As a result, natural gas prices could remain depressed until the fall heating season.
Figure #6
Outlook
A dismal quarter for the energy sector got a shot in the arm on the first day of the new quarter with a surprise OPEC+ production cut announcement. The announcement was welcomed news for producers that were already seeing profitable production margins and high returns on drilling investments. Cash flow levels are high and companies have been expanding operations and returning capital to shareholders. As investment opportunities become sparse and debt levels become low (or completely eliminated), we believe management will increase the focus on raising dividend levels and repurchasing shares. Share repurchases should support energy stock prices increases and an increased dividend yield should protect against any potential share price weakness.
We believe the case for smaller cap energy stocks is especially strong. Major oil companies are facing increasing pressure to focus on renewable energy instead of producing more carbon-based fuel. Smaller cap energy companies are less tethered and often able to acquire and exploit properties being ignored by the majors. If our belief that a world-wide recession is already factored into energy prices is correct, small cap energy companies will be in the best position to take advantage of any energy price increase resulting from OPEC+ production cuts.
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ANALYST CREDENTIALS, PROFESSIONAL DESIGNATIONS, AND EXPERIENCE
Senior Equity Analyst focusing on Basic Materials & Mining. 20 years of experience in equity research. BA in Business Administration from Westminster College. MBA with a Finance concentration from the University of Missouri. MA in International Affairs from Washington University in St. Louis. Named WSJ ‘Best on the Street’ Analyst and Forbes/StarMine’s “Best Brokerage Analyst.” FINRA licenses 7, 24, 63, 87
WARNING
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RESEARCH ANALYST CERTIFICATION
Independence Of View All views expressed in this report accurately reflect my personal views about the subject securities or issuers.
Receipt of Compensation No part of my compensation was, is, or will be directly or indirectly related to any specific recommendations or views expressed in the public appearance and/or research report.
Ownership and Material Conflicts of Interest Neither I nor anybody in my household has a financial interest in the securities of the subject company or any other company mentioned in this report.
Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
We believe the market is undervaluing Hemisphere Energy’s asset base cash flow generation. We believe the stock price will move towards our price target as the company generates operating cash flow that is used to expand operations and return capital to shareholders. We view the investment as fairly low risk because it is expanding operations is an area that is well known and already providing high returns on investment.
Strong production growth. Production increased 55% in 2022 and management expects production to grow another 10-15% in 2023 in response to the addition of new wells. Unless there is a dramatic drop in oil prices, we believe the company will be able to maintain a double-digit production growth rate for the foreseeable future. Longer-term growth may be dependent upon completing a step-out acquisition to increase the company’s drilling locations.
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*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
Petrodollar Dusk, Petroyuan Dawn: What Investors Need To Know
While most investors were trying to gauge the Federal Reserve’s next moves in light of recent bank failures last week, something interesting happened in Moscow.
During a three-day state visit, Chinese President Xi Jinping held friendly talks with Russian President Vladimir Putin in a show of unity, as both countries increasingly seek to position themselves as leaders of what they call a “multipolar world order,” one that challenges U.S.-centric alliances and agreements.
Among those agreements is the petrodollar, which has been in place for over 50 years.
In case you’re wondering, “petrodollars” are not a real currency. They’re simply dollars being used to trade oil. Early in the 1970s, the U.S. government provided economic aid to Saudi Arabia, its chief oil-producing rival, in exchange for assurances that Riyadh would price its crude exports exclusively in the U.S. dollar. In 1975, other members of the Organization of Petroleum Exporting Countries (OPEC) followed suit, and the petrodollar was born.
This had the immediate effect of strengthening the U.S. dollar. Since countries around the world had to have dollars on hand in order to buy oil (and other key commodities such as gold, also priced in dollars), the greenback became the world’s reserve currency, a status formerly enjoyed by the British pound, French franc and Dutch guilder.
All things must come to an end, however. We may be witnessing the end of the petrodollar as more and more countries, including China and Russia, are agreeing to make settlements in currencies other than the U.S. dollar. This could have wide-ranging implications on not just a macro scale but also investment portfolios.
This article was republished with permission from Frank Talk, a CEO Blog by Frank Holmes of U.S. Global Investors (GROW). Find more of Frank’s articles here – Originally published March 27, 2023
Dawn For The Petroyuan?
Putin couldn’t have been more explicit. During Xi’s state visit, he named the Chinese yuan as his favored currency to conduct trade in. Ever since Western sanctions were levied on the Eastern European country for its invasion of Ukraine early last year, Russia has increasingly depended on its southern neighbor to buy the oil other countries won’t touch.
In just the first two months of 2023, China’s imports from Russia totaled $9.3 billion, exceeding full-year 2022 imports in dollar terms. In February alone, China imported over 2 million barrels of Russian crude, a new record high.
Except that now, the yuan is presumably being used to make these settlements.
As Zoltar Pozsar, New York-based economist and investment research director at Credit Suisse, put it recently: “That’s dusk for the petrodollar… and dawn for the petroyuan.”
U.S. Dollar Still The World’s Reserve Currency, But Its Dominance Is Slipping
Before you dismiss Pozsar’s comment as an exaggeration, consider that other major OPEC nations and BRICS members (Brazil, Russia, India, China and South Africa) are either accepting yuan already or strongly considering it. Russia, Iran and Venezuela account for about 40% of the world’s proven oilfields, and the three sell their oil in exchange for yuan. Turkey, Argentina, Indonesia and heavyweight oil producer Saudi Arabia have all applied for admittance into BRICS, while Egypt became a new member this week.
What this suggests is that the yuan’s role as a reserve currency will continue to strengthen, signifying a broader shift in the global power balance and potentially giving China a bigger hand with which to shape economic policies that affect us all.
To be clear, the U.S. dollar remains the world’s top reserve currency for now, though its share of global central banks’ official holdings has slipped in the past 20 years, from 72% in 2001 to just under 60% today. By contrast, the yuan’s share of official holdings has more than doubled since 2016. The Chinese currency accounted for about 2.8% of reserves as of September 2022.
Russia Diversifying Away From The Dollar By Loading Up On Gold
It’s not all about the yuan, of course. Gold has also increased as a foreign reserve, especially among emerging economies that seek to diversify away from the dollar.
Last week, Russia announced that its bullion holdings jumped by approximately 1 million ounces over the past 12 months as its central bank loaded up on gold in the face of Western sanctions. The bank reported having nearly 75 million ounces at the end of February 2023, up from about 74 million a year earlier.
Long-Term Implications For Investors
The implications of the dollar potentially losing its status as the global reserve are numerous. Obviously, there may be currency risks, and a decrease in demand for U.S. Treasury bonds could result in rising interest rates. I would expect to see massive swings in commodity prices, especially oil prices, which could be an opportunity if you can stomach the volatility.
Gold would look exceptionally attractive, I think. A significant decrease in the relative value of the dollar would be supportive of the gold price, and I would be surprised not to see new highs. It’s for reasons like these that I always recommend a 10% weighting in gold, with 5% in physical bullion and the other 5% in high-quality gold mining equities. Be sure to rebalance at least on an annual basis.
All opinions expressed and data provided are subject to change without notice. Some of these opinions may not be appropriate to every investor. By clicking the link(s) above, you will be directed to a third-party website(s). U.S. Global Investors does not endorse all information supplied by this/these website(s) and is not responsible for its/their content.
The building wave of M&A deals in at least two of the mining sectors, is difficult to ignore. This week, lithium miner Albemarle (ALB) disclosed it had submitted a proposal to acquire Liontown Resources (LTR.Australia). Last month Newmont Mining’s proposed acquisition of Newcrest Mining, highlighted the rising interest in M&A in the gold sector. To date, both proposals have been shunned, but as companies look to increase production, inflation increases producers capital outlays, plus long permitting processes, a case could be made that growth by acquisition, friendly or not, is becoming more appealing in the sector.
Typically growing demand to buy smaller companies in a sector puts upward pressure on valuations.
The gold and lithium sectors have mostly lead over the past six months in terms of deal-making. For gold, the largest driver is these miners remain undervalued by historical levels. The trend for lithium producers in the years ahead, as battery production ramps up to meet surging demand for electric storage and green technology, is expected to continue to accelerate.
The Price of lithium, key to batteries found in most EVs, over the years has risen. This created a situation where car manufacturers themselves have realized that the best way to ensure a key ingredient to their product is to own all or part of a large enough producer. Lithium producers are looking for ways to increase yield and own more production facilities. These factors could unfold into a situation where the stock prices of companies producing either of these two metals, and even other mined minerals with growing demand, could outperform other sectors.
Five Reasons to Explore Small Mining Companies
While the real heat is on producers of minerals used to make batteries and gold miners, the below supply/demand concepts may apply to an increased need for other miners to involve themselves in M&A as well.
New List of Acquirers – The big car companies, energy companies, and other additional industrial consumers are in need of reliable supply.
Cheaper to Buy than Find – M&A is a solution to the increased costs of growing organically. It also helps circumvent what could be permitting delays and supply chain problems that prevent headway.
Scale – Gold companies normally try to extract synergies when seeking to size up, while lithium producers seek pure scale.
Big Picture Economics – The economic environment favors miners if inflation remains elevated; the companies’ production is more likely to sell for more. The cost of money, on an opportunity cost basis, especially net of inflation (real interest) favors mining.
Finding Value – Informed stock selection is key to discover and invest in companies best positioned to benefit from swelling M&A in the sector.
The fifth on this list is less of a reason to explore mining companies and more a common sense reminder. Last week the Channelchek Take Away Series brought to viewers a live in-depth presentation of 12 mining companies that were just coming off the huge PDAC mining conference in Canada. These presentations are being replayed and may be just the place to begin to hear from company executives, and a highly respected senior natural resources analyst. Audience questions and answers follow.
The information on these on-demand replay videos is current, and as you’ll see by clicking here, the list of video presentations includes a diversified mix of producers and explorers.
CALGARY, AB, March 21, 2023 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) is pleased to announce a 17% increase in our quarterly dividend, to US$0.14 per common share, our financial results for the year ended December 31, 2022, filing of our annual information form, an automatic share repurchase plan, and an operational update.
All references herein to $ refer to United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.
President & CEO, Corey C. Ruttan commented:
“We are very pleased with our 2022 results, from revenues of $63.5 million we generated $49.9 million of funds flow from operations and net income of $31.7 million, increases of 82%, 102% and 467% respectively, year over year. This represents industry leading operating netback margins underpinning our disciplined capital allocation model that balances organic growth and stakeholder returns. Since commencing production from our Caburé project in 2020, we have repaid all outstanding debt and today’s announcement represents the third increase in our quarterly dividend since Q1 2022. With this, we will have already returned $22 million ($0.62/share) to shareholders in the form of dividends. We are also firmly focused on our next phase of growth and are looking forward to an exciting 2023 capital program.”
Quarterly Dividend Increased 17% to $0.14 per Share
Alvopetro is pleased to announce that our Board of Directors has approved a 17% increase in our quarterly dividend, to $0.14 per common share, payable in cash on April 14, 2023, to shareholders of record on March 31, 2023. This dividend is designated as an “eligible dividend” for Canadian income tax purposes.
Dividend payments to non-residents of Canada will be subject to withholding taxes at the Canadian statutory rate of 25%. Shareholders may be entitled to a reduced withholding tax rate under a tax treaty between their country of residence and Canada. For further information, see Alvopetro’s website at https://alvopetro.com/Dividends-Non-resident-Shareholders.
Operational Update
Our average daily sales have continued at strong rates in 2023, averaging 2,754 boepd in January and a new daily record of 2,866 boepd in February. Effective February 1, 2023, our natural gas price increased to BRL2.00/m3 and is effective for all natural gas sales from February 1 to July 31, 2023. Including recently approved and enhanced sales tax credits, our realized gas price, net of sales taxes, for the month of February was approximately $12.23/Mcf (based on our average heat content to date and the average February 2023 BRL/USD foreign exchange rate of 5.17).
On February 6, 2023, we announced our 2023 capital program, focused on lower risk development opportunities on our Murucututu natural gas project and our Bom Lugar oil field. We have commenced stimulation operations at our 197(1) well on Murucututu. The 197(1) well location has already been tied in to our 183(1) facility and we expect to commence production from the well in the second quarter. Following this stimulation, we plan to drill two follow-up wells at Murucututu, with one well having additional uphole exploration potential. We have budgeted total capital expenditures of $16 million for our Murucututu project in 2023.
On our Bom Lugar field, we plan to drill up to two development wells in 2023, targeting the Caruaçu Formation with additional potential in the deeper Gomo and Agua Grande Formations, the first of which is planned for the second quarter. Total capital expenditures of up to $11 million are budgeted at Bom Lugar.
Additional capital spending budgeted for 2023 includes $3 million on our Caburé field for the expansion of unit facilities and drilling two additional wells, $0.5 million at our Mãe-da-lua field for stimulation of the existing well and $0.4 million in capital expenditures at our 182-C2 and 183-B2 wells.
Automatic Share Repurchase Plan
In January 2023, we received approval from the TSX Venture Exchange (“TSXV”) for a normal course issuer bid (the “NCIB”) as more particularly described in our news release dated January 3, 2023. The terms of the NCIB permit Alvopetro to repurchase up to 2,876,414 common shares from January 6, 2023 to the earlier of January 5, 2024 or when the NCIB is completed or terminated by Alvopetro. No repurchases have been made under the NCIB to date.
Alvopetro intends to enter into an automatic share purchase plan (“ASPP”) with our designated broker, subject to the approval of the TSXV. The ASPP is intended to allow for the purchase of common shares under the NCIB at times when the Corporation may not ordinarily be permitted to purchase common shares due to regulatory restrictions and customary self-imposed blackout periods.
The ASPP is to be implemented upon TSXV approval and would allow the designated broker to purchase common shares pursuant to the proposed ASPP until the expiry of the NCIB on January 5, 2024. Such purchases will be determined by the broker at its sole discretion based on the purchasing parameters set out by the Corporation in accordance with the rules of the TSXV, applicable securities laws and the terms of the ASPP. The ASPP will terminate on the earlier of the date on which: (i) the NCIB expires; (ii) the maximum number of common shares have been purchased under the ASPP; and (iii) the Corporation terminates the ASPP in accordance with its terms.
Outside of the ASPP and outside of pre-determined blackout periods, common shares may continue to be purchased under the NCIB based on management’s discretion, in compliance with the rules of the TSXV and applicable securities laws. All purchases made under the ASPP will be included in the number of common shares available for purchase under the NCIB.
December 31, 2022 Reserves and Net Asset Value
On February 28, 2023, Alvopetro announced its December 31, 2022 reserves based upon the independent reserve assessment and evaluation prepared by GLJ Ltd. (“GLJ”) dated February 27, 2023 with an effective date of December 31, 2022 (the “GLJ Reserves and Resources Report”).
Key highlights from the GLJ Reserves and Resources Report1:
2P net present value before tax discounted at 10% (“NPV10”) increased 17% to $348.2 million.
Proved reserves (“1P”) decreased 12% to 3.9 MMboe and 2P reserves increased 3% to 9.0 MMboe after 0.9 MMboe of production in 2022.
2P production replacement ratio of 132%.
2P F&D costs of $28.66/boe.
2P recycle ratio of 2.1 times.
2P Net Asset Value of CAD$13.70/share ($9.99/share) before any potential from contingent or prospective resources.
Risked best estimate contingent resource of 2.9 MMboe (NPV10 $62.2 million) and risked best estimate prospective resource of 12.5 MMboe (NPV10 $259.1 million).
1 Refer to the section entitled “Oil and Natural Gas Advisories” for additional disclosures regarding oil and natural gas reserves, contingent resources and prospective resources. In addition refer to “Oil and – Natural Gas Advisories – Other Metrics” and “Non-GAAP and Other Financial Measures” for additional disclosures and assumptions used in calculating production replacement ratio, F&D costs, recycle ratio, net asset value and net asset value per share.
Financial and Operating Highlights – Fourth Quarter of 2022
Our average daily sales increased to a new quarterly record of 2,724 boepd (+3% from Q3 2022 and +12% from Q4 2021).
With natural gas sales in Q4 2022 continuing at the ceiling price in our contract, our average realized natural gas price was $11.18/Mcf (+58% from Q4 2021) and our average realized price per boe was $68.13 (+54% from Q4 2021). Higher realized prices and record daily sales volumes resulted in a 73% increase in our natural gas, condensate and oil revenue compared to Q4 2021.
Our operating netback was $60.08 per boe in Q4 2022, an improvement of $23.70 per boe from Q4 2021 (+65%) and $0.25 per boe from Q3 2022.
We generated funds flows from operations of $13.2 million ($0.36 per basic share and $0.35 per diluted share), an increase of $6.7 million compared to Q4 2021 and a decrease of $0.2 million compared to Q3 2022.
We reported net income of $5.2 million in Q4 2022, an increase of $2.4 million (+87%) compared to Q4 2021. Net income was impacted by impairment expense of $6.3 million recognized on exploration assets.
Capital expenditures totaled $5.9 million, including drilling and testing costs for our 182-C2 well, testing of the Unit-C well and facilities expenditures at the Caburé unit, testing costs for our 183-B1 well, development costs on our Murucututu project and long-lead purchases.
Our Q4 2022 dividend increased 50% to $0.12 per share. The Q4 2022 dividend was paid on January 13, 2023 to shareholders of record on December 30, 2022.
Our cash and working capital increased to $14.7 million, an improvement of $2.5 million compared to September 30, 2022 and an increase of $12.1 million compared to December 31, 2021 working capital net of debt of $2.6 million.
Financial and Operating Highlights – Year Ended December 31, 2022
Our annual sales averaged 2,557 boepd (95% natural gas, 4% NGLs from condensate and marginal crude oil production), an increase of 8% compared to 2021.
We reported net income of $31.7 million, compared to $5.6 million in 2021 (+467%).
We generated funds flow from operations of $49.9 million ($1.44 per basic share on $1.35 per diluted share) compared to $24.6 million in 2021 ($0.74 per basic share and $0.71 per diluted share).
Capital expenditures totaled $24.8 million in 2022.
In the third quarter of 2022, all outstanding warrants were exercised. Alvopetro received cash proceeds of $2.4 million and issued a total of 2,081,616 common shares on the exercise.
The credit facility was fully repaid in September 2022 and has been cancelled.
Dividends totaled $0.36 per share in 2022 compared to $0.12 per share in 2021 (+200%).
The following table provides a summary of Alvopetro’s financial and operating results for periods noted. The consolidated financial statements with the Management’s Discussion and Analysis (“MD&A”) are available on our website at www.alvopetro.com and will be available on the System for Electronic Document Analysis and Retrieval (SEDAR) website at www.sedar.com.
2022 Results Webcast
Alvopetro will host a live webcast to discuss 2022 financial results at 9:00 am Mountain time on Wednesday March 22, 2023. Details for joining the event are as follows:
The webcast will include a question and answer period. Online participants will be able to ask questions through the Zoom portal. Dial-in participants can email questions directly to socialmedia@alvopetro.com.
Annual Information Form
Alvopetro has filed its annual information form (“AIF”) with the Canadian securities regulators on SEDAR. The AIF includes the disclosure and reports relating to oil and gas reserves data and other oil and gas information required pursuant to National Instrument 51-101 of the Canadian Securities Administrators. The AIF may be accessed electronically at www.sedar.com.
Corporate Presentation
Alvopetro’s updated corporate presentation is available on our website at:
Alvopetro Energy Ltd.’svision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
Oil and Natural Gas Advisories
Oil and Natural Gas Reserves
The disclosure in this news release summarizes certain information contained in the GLJ Reserves and Resources Report but represents only a portion of the disclosure required under National Instrument 51-101 (“NI 51-101”). For additional details, see our news release dated February 28, 2023. Full disclosure with respect to the Company’s reserves as at December 31, 2022 is contained in the Company’s annual information form for the year ended December 31, 2022 which has been filed on SEDAR (www.sedar.com). All net present values in this press release are based on estimates of future operating and capital costs and GLJ’s forecast prices as of December 31, 2022. The reserves definitions used in this evaluation are the standards defined by the Canadian Oil and Gas Evaluation Handbook (COGEH) reserve definitions, are consistent with NI 51-101 and are used by GLJ. The net present values of future net revenue attributable to the Alvopetro’s reserves estimated by GLJ do not represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
Contingent Resources
This news release discloses estimates of Alvopetro’s contingent resources and the net present value associated with net revenues associated with the production of such contingent resources as included in the GLJ Reserves and Resources Report. There is no certainty that it will be commercially viable to produce any portion of such contingent resources and the estimated future net revenues do not necessarily represent the fair market value of such contingent resources. Estimates of contingent resources involve additional risks over estimates of reserves. For additional details with respect to Alvopetro’s contingent resources evaluated as at December 31, 2022, see our news release dated February 28, 2023 and additional details contained in the Company’s annual information form for the year ended December 31, 2022 which has been filed on SEDAR (www.sedar.com).
Prospective Resources
This news release discloses estimates of Alvopetro’s prospective resources included in the GLJ Reserves and Resources Report. There is no certainty that any portion of the prospective resources will be discovered and even if discovered, there is no certainty that it will be commercially viable to produce any portion. Estimates of prospective resources involve additional risks over estimates of reserves. The accuracy of any resources estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While resources presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. For additional details with respect to Alvopetro’s prospective resources evaluated as at December 31, 2022, see our news release dated February 28, 2023 and additional details contained in the Company’s annual information form for the year ended December 31, 2022 which has been filed on SEDAR (www.sedar.com).
Other Metrics
This press release contains metrics commonly used in the oil and natural gas industry, which have been prepared by management, including “F&D costs”, “net asset value”, “net asset value per share”, “production replacement ratio” and “recycle ratio”. These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.
“F&D costs” are reflected on a per barrel of oil equivalent and are calculated as the sum of capital expenditures in the current year plus the change in FDC for the period, divided by the change in reserves in the period, before current year production. The 2022 F&D costs are computed as follows:
“Net asset value” is based on the before tax net present value of the Company’s reserves as at December 31, 2022, discounted at 10% plus the Company’s net working capital balance as of December 31, 2022. Net working capital is a capital management measure. See “Non-GAAP and Other Financial Measures” below for further details.
“Net asset value per share” is based on the computation of net asset value divided by basic shares outstanding of 36,311,579 adjusted to Canadian dollars based on the foreign exchange rate on March 21, 2023.
“Production replacement ratio” is calculated as total reserve additions divided by current year production. Alvopetro’s 2P production replacement ratio in 2022 is calculated as:
“Recycle ratio” is calculated by dividing the 2022 operating netback by F&D costs per boe for the year. The Company’s 2022 recycle ratio is calculated as follows:
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare our operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.
Non-GAAP and Other Financial Measures
This news release contains references to various non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as such terms are defined in National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. Such measures are not recognized measures under GAAP and do not have a standardized meaning prescribed by IFRS and might not be comparable to similar financial measures disclosed by other issuers. While these measures may be common in the oil and gas industry, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. The non-GAAP and other financial measures referred to in this report should not be considered an alternative to, or more meaningful than measures prescribed by IFRS and they are not meant to enhance the Company’s reported financial performance or position. These are complementary measures that are used by management in assessing the Company’s financial performance, efficiency and liquidity and they may be used by investors or other users of this document for the same purpose. Below is a description of the non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures used in this news release. For more information with respect to financial measures which have not been defined by GAAP, including reconciliations to the closest comparable GAAP measure, see the “Non-GAAP Measures and Other Financial Measures” section of the Company’s MD&A which may be accessed through the SEDAR website at www.sedar.com.
Non-GAAP Financial Measures
Operating netback
Operating netback is calculated as natural gas, oil and condensate revenues less royalties and production expenses. This calculation is provided in the “Operating Netback” section of the Company’s MD&A using our IFRS measures. The Company’s MD&A may be accessed through the SEDAR website at www.sedar.com. Operating netback is a common metric used in the oil and gas industry used to demonstrate profitability from operations.
Non-GAAP Financial Ratios
Operating netback per boe
Operating netback is calculated on a per unit basis, which is per barrel of oil equivalent (“boe”). It is a common non-GAAP measure used in the oil and gas industry and management believes this measurement assists in evaluating the operating performance of the Company. It is a measure of the economic quality of the Company’s producing assets and is useful for evaluating variable costs as it provides a reliable measure regardless of fluctuations in production. Alvopetro calculated operating netback per boe as operating netback divided by total sales volumes (barrels of oil equivalent). This calculation is provided in the “Operating Netback” section of the Company’s MD&A using our IFRS measures. The Company’s MD&A may be accessed through the SEDAR website at www.sedar.com. Operating netback is a common metric used in the oil and gas industry used to demonstrate profitability from operations on a per unit basis (boe).
Operating netback margin
Operating netback margin is calculated as operating netback per boe divided by the realized sales price per boe. Operating netback margin is a measure of the profitability per boe relative to natural gas, oil and condensate sales revenues per boe and is calculated as follows:
Funds Flow from Operations Per Share
Funds flow from operations per share is a non-GAAP ratio that includes all cash generated from operating activities and is calculated before changes in non-cash working capital, divided by the weighted the weighted average shares outstanding for the respective period. For the periods reported in this news release the cash flows from operating activities per share and funds flow from operations per share is as follows:
Capital Management Measures
Funds Flow from Operations
Funds flow from operations is a non-GAAP capital management measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. The most comparable GAAP measure to funds flow from operations is cash flows from operating activities. Management considers funds flow from operations important as it helps evaluate financial performance and demonstrates the Company’s ability to generate sufficient cash to fund future growth opportunities. Funds flow from operations should not be considered an alternative to, or more meaningful than, cash flows from operating activities however management finds that the impact of working capital items on the cash flows reduces the comparability of the metric from period to period. A reconciliation of funds flow from operations to cash flows from operating activities is as follows:
Net Working Capital
Net working capital is computed as current assets less current liabilities. Net working capital is a measure of liquidity, is used to evaluate financial resources, and is calculated as follows:
Working Capital Net of Debt
Working capital net of debt is computed as net working capital surplus decreased by the carrying amount of the Credit Facility. Working capital net of debt is used by management to assess the Company’s overall financial position.
Supplementary Financial Measures
“Average realized natural gas price – $/Mcf” is comprised of natural gas sales as determined in accordance with IFRS, divided by the Company’s natural gas sales volumes.
“Average realized NGL – condensate price – $/bbl” is comprised of condensate sales as determined in accordance with IFRS, divided by the Company’s NGL sales volumes from condensate.
“Average realized oil price – $/bbl” is comprised of oil sales as determined in accordance with IFRS, divided by the Company’s oil sales volumes.
“Average realized price – $/boe” is comprised of natural gas, condensate and oil sales as determined in accordance with IFRS, divided by the Company’s total natural gas, condensate and oil sales volumes (barrels of oil equivalent).
“Royalties per boe” is comprised of royalties, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).
“Production expenses per boe” is comprised of production expenses, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).
BOE Disclosure
The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6 Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
Forward-Looking Statements and Cautionary Language
This news release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward–looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking statements concerning plans relating to the Company’s operational activities, proposed exploration development activities and the timing for such activities, exploration and development prospects of Alvopetro, capital spending levels, future capital and operating costs, timing and taxation of dividends and plans for dividends in the future, plans for share repurchases under the NCIB and the duration of the NCIB, future production and sales volumes, the expected natural gas price, gas sales and gas deliveries under Alvopetro’s long-term gas sales agreement, the expected timing of production commencement from the 197(1) well, the proposed automatic share purchase plan, and projected financial results. Forward-looking statements are necessarily based upon assumptions and judgments with respect to the future including, but not limited to, expectations and assumptions concerning the timing of regulatory licenses and approvals, equipment availability, the success of future drilling, completion, testing, recompletion and development activities and the timing of such activities, the performance of producing wells and reservoirs, well development and operating performance, expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the outlook for commodity markets and ability to access capital markets, foreign exchange rates, general economic and business conditions, forecasted demand for oil and natural gas, the impact of the COVID-19 pandemic, weather and access to drilling locations, the availability and cost of labour and services, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. In addition, the declaration, timing, amount and payment of future dividends remain at the discretion of the Board of Directors. Although we believe that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because we can give no assurance that they will prove to be correct. Since forward looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, reliance on industry partners, availability of equipment and personnel, uncertainty surrounding timing for drilling and completion activities resulting from weather and other factors, changes in applicable regulatory regimes and health, safety and environmental risks), commodity price and foreign exchange rate fluctuations, market uncertainty associated with financial institution instability, and general economic conditions. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Three Reasons the Willow Arctic Oil Drilling Project Was Approved
For more than six decades, Alaska’s North Slope has been a focus of intense controversy over oil development and wilderness protection, with no end in sight. Willow field, a 600-million-barrel, US$8 billion oil project recently approved by the Biden administration – to the outrage of environmental and climate activists – is the latest chapter in that long saga.
To understand why President Joe Biden allowed the project, despite vowing “no more drilling on federal lands, period” during his campaign for president, some historical background is necessary, along with a closer look at the ways domestic and international fears are complicating any decision for or against future oil development on the North Slope.
More Than Just Willow
The Willow project lies within a vast, 23 million-acre area known as the National Petroleum Reserve-Alaska, or NPR-A. This was one of four such reserves set aside in the early 1900s to guarantee a supply of oil for the U.S. military. Though no production existed at the time in NPR-A, geologic information and surface seeps of oil suggested large resources across the North Slope.
This article was republished with permission from The Conversation, a news site dedicated to sharing ideas from academic experts. It represents the research-based findings and thoughts of, Scott L. Montgomery, Lecturer, Jackson School of International Studies, University of Washington.
Proof came with the 1968 discovery of the supergiant Prudhoe Bay field, which began producing oil in 1977. Exploratory programs in the NPR-A, however, found only small oil accumulations worthy of local uses.
Then, in the 2000s, new geologic understanding and advanced exploration technology led companies to lease portions of the reserve, and they soon made large fossil fuel discoveries. Because NPR-A is federal land, government approval is required for any development. To date, most have been approved. Willow is the latest.
Caribou in the National Petroleum Reserve-Alaska are important for Native groups. However, Native communities have also been split over support for drilling, which can bring income. Bob Wick/Bureau of Land Management
Caribou in the National Petroleum Reserve-Alaska are important for Native groups. However, Native communities have also been split over support for drilling, which can bring income. Bob Wick/Bureau of Land Management
Opposition to North Slope drilling from conservationists, environmental organizations and some Native communities, mainly in support of wilderness preservation, has been fierce since the opening of Prudhoe Bay and the construction of the Trans-Alaska Pipeline in the 1970s. In the wake of 1970s oil crises, opponents failed to stop development.
During the next four decades, controversy shifted east to the Arctic National Wildlife Refuge. Republican presidents and congressional leaders repeatedly attempted to open the refuge to drilling but were consistently stifled – until 2017. That year, the Trump administration opened it to leasing. Ironically, no companies were interested. Oil prices had fallen, risk was high and the reputational cost was large.
To the west of the refuge, however, a series of new discoveries in NPR-A and adjacent state lands were drawing attention as a major new oil play with multibillion-barrel potential. Oil prices had risen, and though they fell again in 2020, they have been mostly above $70 per barrel – high enough to encourage significant new development.
ConocoPhillips’ Willow project is in the northeast corner of the National Petroleum Reserve-Alaska. USGS, Department of Interior
Opposition, with Little Success
Opposition to the new Willow project has been driven by concerns about the effects of drilling on wildlife and of increasing fossil fuel use on the climate. Willow’s oil is estimated to be capable of releasing 287 million metric tons of carbon dioxide if refined into fuels and consumed.
In particular, opponents have focused on a planned pipeline that will extend the existing infrastructure further westward, deeper into NPR-A, and likely encourage further exploratory drilling.
So far, that resistance has had little success.
Twenty miles to the south of Willow is the Peregrine discovery area, estimated to hold around 1.6 billion barrels of oil. Its development was approved by the Biden administration in late 2022. To the east lies the Pikka-Horseshoe discovery area, with around 2 billion barrels. It’s also likely to gain approval. Still other NPR-A drilling has occurred to the southwest (Harpoon prospect), northeast (Cassin), and southeast (Stirrup).
One reason the Biden administration approved the Willow project involves legality: ConocoPhillips holds the leases and has a legal right to drill. Canceling its leases would bring a court case that, if lost, would set a precedent, cost the government millions of dollars in fees and do nothing to stop oil drilling.
Instead, the government made a deal with ConocoPhillips that shrank the total surface area to be developed at Willow by 60%, including removing a sensitive wildlife area known as Teshekpuk Lake. The Biden administration also announced that it was putting 13 million acres of the NPR-A and all federal waters of the Arctic Ocean off limits to new leases.
That has done little to stem anger over approval of the project, however. Two groups have already sued over the approval.
Taking Future Risks into Account
To further understand Biden’s approval of the Willow project, one has to look into the future, too.
Discoveries in the northeastern NPR-A suggest this will become a major new oil production area for the U.S. While actual oil production is not expected there for several years, its timing will coincide with a forecast plateau or decline in total U.S. production later this decade, because of what one shale company CEO described as the end of shale oil’s aggressive growth.
Historically, declines in domestic supply have brought higher fuel prices and imports. High gasoline and diesel prices, with their inflationary impacts, can weaken the political party in power. While current prices and inflation haven’t damaged Biden and the Democrats too much, nothing guarantees this will remain the case.
Geopolitical Concerns, Particularly Europe
The Biden administration also faces geopolitical pressure right now due to Russia’s war on Ukraine.
U.S. companies ramped up exports of oil and natural gas over the past year to become a lifeline for Europe as the European Union uses sanctions and bans on Russian fossil fuel imports to try to weaken the Kremlin’s ability to finance its war on Ukraine. U.S. imports have been able to replace a major portion of Russian supply that Europe once counted on.
Europe’s energy crisis has also led to the return of energy security as a top concern of national leaders worldwide. Without a doubt, the crisis has clarified that oil and gas are still critical to the global economy. The Biden administration is taking the position that reducing the supply by a significant amount – necessary as it is to avoid damaging climate change – cannot be done by prohibition alone. Halting new drilling worldwide would drive fuel prices sky high, weakening economies and the ability to deal with the climate problem.
Energy transitions depend on changes in demand, not just supply. As an energy scholar, I believe advancing the affordability of electric vehicles and the infrastructure they need would do much more for reducing oil use than drilling bans. Though it may seem counterintuitive, by aiding European economic stability, U.S. exports of fossil fuels may also help the EU plan to accelerate noncarbon energy use in the years ahead.
