Thursday, September 01, 2022

Permex Petroleum (OILCF)
Well Completions Demonstrate Two-Pronged Approach to Growth

Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.

Refer to the full report for the price target, fundamental analysis, and rating.

 Permex announced positive results for five well recompletions of previously shut-in wells. The wells came on line at an initial rate of 50 BOE/d and stabilized at 35 BOE/d. By comparison, the company just reported production of 8,946 BOE for the fiscal nine months ended June 30, 2022 which equates to 32.8 BBL/d. Production from these five well essentially doubles production to a reported level of 71 BOE/d. Assuming net revenues double to a level near $300,000/qtr. and G&A returns to a historical level of $250,000/qtr. (last quarter was $1 million due to one-time legal, accounting, and marketing costs) then the company should be close to cash flow neutral.

Well recompletion and stimulation provide a good balance to in-fill drilling. While we are clearly focused on new drilling in the Breedlove Field in Martin County, it is worth remembering that Permex has ample opportunity to perform lower cost, lower risk, well completions and stimulation. The company has an additional 62 shut-in oil, gas, and salt water disposal wells in each of its properties remaining to be brought online. Recompletions have a high return on investment and should help fund in-fill drilling. As a reminder, we expect the company to drill one vertical and one horizontal well before yearend. The company reported $5.4 million in cash as of June 30, 2022, which should fund one if not both of the wells….

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 Credit: Rebecca Miller (MIT)

A New Concept for Low-Cost Batteries

David L. Chandler | MIT News Office

As the world builds out ever larger installations of wind and solar power systems, the need is growing fast for economical, large-scale backup systems to provide power when the sun is down and the air is calm. Today’s lithium-ion batteries are still too expensive for most such applications, and other options such as pumped hydro require specific topography that’s not always available.

Now, researchers at MIT and elsewhere have developed a new kind of battery, made entirely from abundant and inexpensive materials, that could help to fill that gap.

The new battery architecture, which uses aluminum and sulfur as its two electrode materials, with a molten salt electrolyte in between, is described today in the journal Nature, in a paper by MIT Professor Donald Sadoway, along with 15 others at MIT and in China, Canada, Kentucky, and Tennessee.

“I wanted to invent something that was better, much better, than lithium-ion batteries for small-scale stationary storage, and ultimately for automotive [uses],” explains Sadoway, who is the John F. Elliott Professor Emeritus of Materials Chemistry.

In addition to being expensive, lithium-ion batteries contain a flammable electrolyte, making them less than ideal for transportation. So, Sadoway started studying the periodic table, looking for cheap, Earth-abundant metals that might be able to substitute for lithium. The commercially dominant metal, iron, doesn’t have the right electrochemical properties for an efficient battery, he says. But the second-most-abundant metal in the marketplace — and actually the most abundant metal on Earth — is aluminum. “So, I said, well, let’s just make that a bookend. It’s gonna be aluminum,” he says.

Then came deciding what to pair the aluminum with for the other electrode, and what kind of electrolyte to put in between to carry ions back and forth during charging and discharging. The cheapest of all the non-metals is sulfur, so that became the second electrode material. As for the electrolyte, “we were not going to use the volatile, flammable organic liquids” that have sometimes led to dangerous fires in cars and other applications of lithium-ion batteries, Sadoway says. They tried some polymers but ended up looking at a variety of molten salts that have relatively low melting points — close to the boiling point of water, as opposed to nearly 1,000 degrees Fahrenheit for many salts. “Once you get down to near body temperature, it becomes practical” to make batteries that don’t require special insulation and anticorrosion measures, he says.

The three ingredients they ended up with are cheap and readily available — aluminum, no different from the foil at the supermarket; sulfur, which is often a waste product from processes such as petroleum refining; and widely available salts. “The ingredients are cheap, and the thing is safe — it cannot burn,” Sadoway says.

In their experiments, the team
showed that the battery cells could endure hundreds of cycles at exceptionally
high charging rates, with a projected cost per cell of about one-sixth that of
comparable lithium-ion cells. They showed that the charging rate was highly dependent on the working temperature, with 110 degrees Celsius (230 degrees Fahrenheit) showing 25 times faster rates than 25 C (77 F).

Surprisingly, the molten salt the team chose as an electrolyte simply because of its low melting point turned out to have a fortuitous advantage. One of the biggest problems in battery reliability is the formation of dendrites, which are narrow spikes of metal that build up on one electrode and eventually grow across to contact the other electrode, causing a short-circuit and hampering efficiency. But this particular salt, it happens, is very good at preventing that malfunction.

The chloro-aluminate salt they chose “essentially retired these runaway dendrites, while also allowing for very rapid charging,” Sadoway says. “We did experiments at very high charging rates, charging in less than a minute, and we never lost cells due to dendrite shorting.”

“It’s funny,” he says, because the whole focus was on finding a salt with the lowest melting point, but the catenated chloro-aluminates they ended up with turned out to be resistant to the shorting problem. “If we had started off with trying to prevent dendritic shorting, I’m not sure I would’ve known how to pursue that,” Sadoway says. “I guess it was serendipity for us.”

What’s more, the battery requires no external heat source to maintain its operating temperature. The heat is naturally produced electrochemically by the charging and discharging of the battery. “As you charge, you generate heat, and that keeps the salt from freezing. And then, when you discharge, it also generates heat,” Sadoway says. In a typical installation used for load-leveling at a solar generation facility, for example, “you’d store electricity when the sun is shining, and then you’d draw electricity after dark, and you’d do this every day. And that charge-idle-discharge-idle is enough to generate enough heat to keep the thing at temperature.”

This new battery formulation, he says, would be ideal for installations of about the size needed to power a single home or small to medium business, producing on the order of a few tens of kilowatt-hours of storage capacity.

For larger installations, up to utility scale of tens to hundreds of megawatt hours, other technologies might be more effective, including the liquid metal batteries Sadoway and his students developed several years ago and which formed the basis for a spinoff company called Ambri, which hopes to deliver its first products within the next year. For that invention, Sadoway was recently awarded this year’s European Inventor Award.

The smaller scale of the aluminum-sulfur batteries would also make them practical for uses such as electric vehicle charging stations, Sadoway says. He points out that when electric vehicles become common enough on the roads that several cars want to charge up at once, as happens today with gasoline fuel pumps, “if you try to do that with batteries and you want rapid charging, the amperages are just so high that we don’t have that amount of amperage in the line that feeds the facility.” So having a battery system such as this to store power and then release it quickly when needed could eliminate the need for installing expensive new power lines to serve these chargers.

The new technology is already the basis for a new spinoff company called Avanti, which has licensed the patents to the system, co-founded by Sadoway and Luis Ortiz ’96 ScD ’00, who was also a co-founder of Ambri. “The first order of business for the company is to demonstrate that it works at scale,” Sadoway says, and then subject it to a series of stress tests, including running through hundreds of charging cycles.

Would a battery based on sulfur run the risk of producing the foul odors associated with some forms of sulfur? Not a chance, Sadoway says. “The rotten-egg smell is in the gas, hydrogen sulfide. This is elemental sulfur, and it’s going to be enclosed inside the cells.” If you were to try to open up a lithium-ion cell in your kitchen, he says (and please don’t try this at home!), “the moisture in the air would react and you’d start generating all sorts of foul gases as well. These are legitimate questions, but the battery is sealed, it’s not an open vessel. So I wouldn’t be concerned about that.”

The research team included members from Peking University, Yunnan University and the Wuhan University of Technology, in China; the University of Louisville, in Kentucky; the University of Waterloo, in Canada; Oak Ridge National Laboratory, in Tennessee; and MIT. The work was supported by the MIT Energy Initiative, the MIT Deshpande Center for Technological Innovation, and ENN Group.

Reprinted with permission from MIT News ( http://news.mit.edu/)

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Wednesday, August 31, 2022

Permex Petroleum (OILCF)
Permex reports fiscal third quarter results

Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.

Refer to the full report for the price target, fundamental analysis, and rating.

Permex reported results for the quarter ended June 30, 2022. Given limited sales at this point in the company’s development, results are largely a function of operating costs. The company reported a large jump in auditing, legal, and marketing fees as the company prepares to begin drilling on the recently-acquired Breedlove field properties. Total operating expenses were $1,278,251 for the quarter versus $177,861 for the same period last year. Net income was ($761,303) or ($0.00) per share versus ($103,541) or ($0.00) per share. We had been looking for net income of ($191,000) or ($0.00) per share.

The shares of Permex trade on company developments not financial results. We believe the company has tremendous upside as it drills out its property. Consequently, the stock price rightfully trades on operational developments instead of financial results. Along those lines, the company reported back on August 16th that it had received approval on its permit application for drilling on the Breedlove field in Martin County. We expect the company to drill one vertical and one horizontal well in Martin County before the end of the year….

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. 

Energy Sector’s Relative Strength Against The Market Is Looking Very Attractive

The University of Texas at Austin (UT), just a couple of hours up the road from our headquarters in San Antonio, may soon unseat Harvard as the wealthiest school in the U.S. How has it managed to do this? In a word: Oil.

At a time when large sovereign wealth funds are divesting from fossil fuels, and ESG (environmental, social and corporate goverance) investing has gone mainstream, the UT System has been the longtime owner and manager of 2.1 million acres of mineral-rich land, scattered across West Texas, that it leases out to as many as 250 producers, including ConocoPhillips.

Thanks to higher oil prices, the mineral rights to the land generate roughly $6 million every day, according to Bloomberg.

The UT System’s decision to continue participating in oil is in keeping with Texas’s close ties to the fossil fuels industry. The state produces more oil and gas (and wind power) than any other, a fact that policymakers are eager to protect. Last week, Texas moved to restrict state pension funds from investing in BlackRock, UBS Group, Credit Suisse and a number of other financial institutions that have been found to be “hostile” toward the energy sector.

But it’s more than just tradition. UT’s oil investments have been incredibly profitable and, by most accounts, will continue to be so as long as the energy crisis deepens and inflationary pressures keep prices elevated. The S&P 500 Energy Index is by far the top performing sector for the year, up nearly 50%, compared to the broader market, which is off by 12%.

A New Cycle Of Outperformance?

Looking ahead, energy stocks appear to be setting up for a new cycle of outperformance relative to the market. Take a look at the chart below, which shows the long-term ratio between the energy index and S&P 500. Technically, this may be the most attractive time to invest in energy since at least the beginning of the century.

Warren Buffett seems to agree. His company, Berkshire Hathaway, recently received regulatory approval to buy up to half of Houston-based Occidental Petroleum (OXY).

The disruptions of the past two years are believed to have triggered a readjustment in the energy market. In a just-released
report, Deloitte projects that oil and gas producers could report the highest-ever free cash flow (FCF), as much as $1.4 trillion, in 2022. The industry could also become debt-free by 2024.

Although oil prices in 2022 have been equivalent to those in 2013 and 2014, cash flows are currently three times higher thanks to capital expenditure discipline after years of underinvestment, Deloitte analysts say. U.S. shale producers, which generated negative cash flows in nine out of the last 10 years, are expected to report record FCF of $600 billion.

This comes as the U.S. is set to export a record amount of crude oil this year and next as the country captures market share away from Russia. Since Congress lifted the 40-year-old oil export ban in 2015, weekly exports have steadily risen above 4 million barrels a day, but earlier this month, exports exceeded 5 million barrels for the first time. According to Bloomberg, U.S. suppliers will likely be able to hold on to the increased market share since producers in other regions, including those in the North Sea and West Africa, have not been growing output as rapidly as American companies have.

California Bans Gas-Powered Vehicles By 2035. Will The
Infrastructure Be Ready By Then?

The backdrop to all of this, of course, is the expansion of ESG-minded investing and global financing of alternative fuels and renewable energy sources. Last week, California became the first state to approve a ban on the sale of new gas-powered vehicles by 2035 in favor of electric vehicles (EVs). This is a huge opportunity, as investment in the state’s notoriously spotty power grid will need to increase significantly.

New, more reliable EV charging stations will also need to be installed. Earlier this month, J.D. Power announced that Americans’ satisfaction in charging infrastructure is declining due to a growing number of “
inadequate”
and “non-functioning stations.” 

“This lack of progress points to the need for improvement as EVs gain wider consumer acceptance because the shortage of public charging availability is the number one reason vehicle shoppers reject EVs,” the report reads.

Airlines And Shipping Companies Seeking Alternative Fuels

The airlines and container shipping industries are also seeking ways to achieve net-zero carbon emissions by 2050. One method being used by airlines is sustainable aviation fuel (SAF), which reportedly reduces CO2 emissions by as much as 80%. The liquid fuel is normally produced from a number of sources, including waste oil and fats, municipal waste and non-food crops.

SAF is currently much more expensive to make than traditional jet fuel, but several companies and groups are leading the effort to scale up the technology. Boeing is establishing a facility in Japan to begin researching and developing SAF, while World Energy, a Boston-based low-carbon solutions provider, is planning to convert a refinery in Houston to an SAF plant. Earlier this month, Alaska Airlines announced it had finalized an agreement to buy 185 million gallons of SAF from biofuel company Gevo over five years starting in 2026. Alaska also has announced a collaboration between Microsoft and start-up firm Twelve to advance production of E-Jet, an even more sustainable fuel that’s made from carbon dioxide.

As for shipping, wind propulsion is being touted as the “most impactful emissions reduction technology.” Today, 21 large ocean-going vessels already have wind-assist systems installed, according to the International Windship Association (IWSA), and by the end of 2023, this number could jump to nearly 50. Some of the biggest names in maritime shipping are involved in investing millions of dollars into wind
propulsion technology, including Cargill, Maersk and Mitsui. The IWSA calls the 2020s the “Decade of Wind Propulsion.”

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Energy
Sector’s Relative Strength Against The Market Is Looking Very Attractive

US
Global Investors Disclaimer

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.

Holdings may change daily. Holdings are reported as of the most recent quarter-end. The following securities mentioned in the article were held by one or more accounts managed by U.S. Global Investors as of (06/30/22): ConocoPhillips, Occidental Petroleum Corp., The Boeing Group Co., Alaska Air Group Inc., AP Moller-Maersk A/S, Mitsui OSK Lines Ltd.

The S&P 500 Energy Index is a capitalization-weighted index. The index was developed with a base level of 10 for the 1941-43 base period. The S&P 500 Stock Index is a widely recognized capitalization-weighted index of 500 common stock prices in U.S. companies.

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Image Credit: Paul B (Flickr)

Will Drivers Continue to be Dogged by High Gas Prices as US Strategic Oil Reserve is Replenished?

The last time the US Strategic Oil Reserves was this low was January 1985. The US population was then 238 million, The Cosby Show was the top-rated on TV, the threat of the AIDS virus was just beginning to be understood, and a newly appointed NIH Director named Anthony Fauci had just been promoted. In 37 years, some things have changed, and some things have not. One that has not is the need for reliable energy.

The Reserves reached their peak in April 2011 with 726.5 million barrels; today, we sit with 453.1 million. Will it take 37 years to replenish the more than 200 million barrels, 160 million of which have been siphoned off since March of this year?

The barrels that are being used in 2022 were ordered released by the White House to offset the domestic loss of production, pipeline distribution, and less supply being compounded by global shortages resulting from a partial embargo against Russia. The order was intended to work to lower gas prices today and help reduce the impact oil prices are having on unacceptably high inflation.

President Biden said in March that the US would release one million barrels of oil a day for six months as petroleum products spiked following the start of the Russian/Ukrainian war. The White House then said, in late July, the US would release another 20 million barrels.

To some degree, it worked as intended. There has been a fall in the price at the gas pumps over the past two months. Much of this has been supply-related, helped by the reserve releases, to a lesser extent, demand has also slowed from receding economic activity. WTI crude, the US benchmark price, has dropped around 24%.

That decline has brought US gasoline prices down from above $5 a gallon in June to $3.89 on Tuesday, August 17. Globally, other countries are tapping into their own strategic reserves as well.

What Happens When we Refill It?

The US consumed about 20 million barrels of oil a day on average in 2021, according to the EIA. During the same year, it produced 11 million barrels a day. The Biden administration is proposing to refill the stockpiles under a plan that is likely to see it order 60 million barrels this fall for delivery at an unspecified time in the future. That leaves at least another 100 million barrels to bring the country back to where we were in March 2022 – over two hundred more to bring us back to the peak. It took 37 years last time for the country to stockpile the same amount.

The current infrastructure is not supporting additional oil output, otherwise, companies would be pumping more now. On July 1, President Biden made public a five-year proposal for offshore oil and gas development in areas of existing production and said the final plan might have anywhere from zero to 11 lease sales.

The range of proposed options was between two auctions a year and none at all. The plan seemed conflicted with a desire to balance the administration’s efforts to reduce the use of fossil fuels and its calls to increase needed oil and gas.

Energy Demand Moving Forward

Does restocking the Reserves point toward high petroleum demand for a much longer time period than ever expected? Does it also create opportunities for producers of biofuels, for example, GEVO?

The current fuel issues are not going to disappear overnight. Borrowing from the future with the intent, and now a plan, to pay it back, will require more production than before. Companies that produce are not inclined to make big investments in building out a platform when the political climate is one of wanting to shut production down as soon as possible.

The cost of reducing energy output and then borrowing from reserves, especially after an unexpected embargo is placed on a major global  supplier, could keep the price of all energy elevated for a much longer time than the end of a war, of installation of coastal wind farms.

Paul Hoffman

Managing Editor, Channelchek

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Sources

https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MCSSTUS1&f=M

https://www.eia.gov/petroleum/gasdiesel/gas_geographies.php#pricesbyregion

https://www.whitehouse.gov/briefing-room/statements-releases/2022/07/26/fact-sheet-department-of-energy-releases-new-notice-of-sale-as-gasoline-prices-continue-to-fall/

https://www.niaid.nih.gov/about/director

https://www.energy.gov/articles/doe-announces-additional-notice-sale-crude-oil-strategic-petroleum-reserve

https://www.reuters.com/business/energy/biden-administration-proposes-offshore-drilling-plan-focused-mainly-us-gulf-2022-07-01/

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Image Credit: Kees Torn (Flickr)

Natural Gas Prices May Continue to Explode Through Winter

Natural-gas futures jumped to nearly $10 per million BTU today (August 23), the highest since July 2008. This is an increase of 20% over the past month, up 146% from a year ago, and up 350% from three years ago. The drop-off in commodity prices that helped bring natural gas prices down has now been more than erased by what has been extreme volatility even by natural gas price standards.

The 14-year highs reached this week in U.S. natural-gas futures point to unrelenting demand pressures, especially in Europe. There are reasons to believe the increases will continue.

The latest price spike is largely fueled by Russia’s plans to shut down one of Europe’s main fuel arteries for a few days at the end of August. It’s unclear if that shutdown, announced Friday, is actual unplanned maintenance along the Nord Stream gas pipeline or related to economic warfare by Russia as retaliation for Western Europe’s support for Ukraine.

Short supply in Europe, above-average hot weather impacting utilities’ needs in the U.S, and concerns related to hurricane season, when storms often halt production on platforms in the Gulf of Mexico, may serve to increase prices higher.

Source: Koyfin

Normally in late Summer, prices ease in anticipation of low demand fall weather. Producers and traders usually squirrel away supplies in underground caverns until winter, when demand and prices typically are at their high for the year.

This year, though, export demand, electric demand related to some of the hottest weather on record, and low production growth have kept U.S. natural-gas supplies from growing ahead of the heating season.

The U.S. Energy Information Administration (EIA) reported an unseasonably paltry offload into storage facilities. Storage grew but left a projected deficit of 12.7% to the average for this point on the calendar.

The lag in storage could be leading to a global situation if winter is colder than normal – a situation where natural gas prices may spike upward.

Production vs. Usage

EIA data show that monthly domestic production reached its highest level since the pandemic in May, though it remained short of the output record set in December 2019. And output has decreased.

U.S. demand is rising. Coal prices that have risen more sharply than gas and scarce supplies of coal have limited electric producers’ options, which have been in high demand to run air conditioners this summer. Government energy forecasters expect average daily U.S. gas consumption this year to be 3% higher. They expect year-over-year production gains at roughly the same rate.

Meanwhile, exports are set to rise this fall when one of the country’s biggest liquefied-natural-gas, or LNG, terminals resume operations. Freeport LNG’s facility on a Texas barrier island has been shut down since a fire in early June. This reduced U.S. export capacity by about one-sixth, or near 2 billion cubic feet a day. It produces roughly enough energy units to power 50,000 homes for a year it went back online and became available for U.S. consumption this summer, which helped to hold prices lower in the US. The facility said it expects to resume exports in October.

Spikes in futures prices don’t immediately translate into higher natural gas prices at home, but eventually, they do increase the average paid.

Inflation and Natural Gas

In addition to electricity prices increasing via power plants, other increases, including food prices via fertilizers, and other unexpected impacts such as glass bottle production, that add to overall inflation.

The June-July plunge in natural-gas futures prices had been one of the reasons cited why inflation in the U.S. was seen as having peaked and moving lower. Utility natural gas piped to homes accounts for about 1% of total CPI. As part of the July CPI reading, utility gas piped to homes fell by 3.6% in price from June, the first month-to-month decline since January after repeated spikes., including +8.2% in June from May and +8.0% in May from April.

Spikes in futures prices don’t immediately translate into higher natural gas prices at home, but eventually, they do. Eventually, prices average up, and we will all be sharing the cost as consumers or perhaps benefitting as investors in either natural gas companies, or more directly in funds or futures.

Paul Hoffman

Managing Editor, Channelchek

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Sources

https://globallnghub.com/front-month-rallies-to-5.html

https://www.eia.gov/todayinenergy/detail.php?id=53559

https://www.eia.gov/petroleum/supply/weekly/

A Gas Shortage Could Crunch Beer Bottles Too – WSJ

https://www.cmegroup.com/trading/energy/natural-gas/lng-futures.html

https://www.energy.gov/sites/prod/files/2017/09/f36/Understanding%20Natural%20Gas%20and%20Lng%20Options_general%20no%20appendix.pdf

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Alvopetro Announces 182-C1 Well Results

Research, News, and Market Data on Alvopetro Energy

Aug 22, 2022

CALGARY, AB, Aug. 22, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces that we have suspended testing at the 182-C1 well on our 100% owned and operated Block 182 in the Recôncavo basin. During the testing operation we perforated the entire 25m of net pay section of the well on tubing conveyed perforations in an underbalanced condition. No formation flow was observed after the initial perforations. We injected 124 barrels (“bbls”) of 15% hydrochloric acid to remove possible near wellbore damage. We then removed the liquid from the wellbore with a jet lift operation using nitrogen and coil tubing. After recovering 231 bbls of the initial 303 bbls of brine and acid we discontinued operations, due to lack of progress in removing any further liquids. We have not recovered any hydrocarbons from the wellbore and will continue to monitor the wellbore pressure from surface, but expect to permanently abandon wellbore in the future.

The primary and secondary targets of the 182-C1 well were the Agua Grande and Sergi Formations, respectively. Based on open hole logs, the 182-C1 well encountered net pay in the Agua Grande Formation very close to the main bounding fault and the well crossed over the fault before encountering the secondary target in the Sergi Formation. We plan to drill a follow up well, 182-C2, to assess the Agua Grande reservoir quality and to target the Sergi Formation further east from the bounding fault. We expect to spud the 182-C2 well later in August.

Corporate Presentation

Alvopetro’s updated corporate presentation is available on our website at:http://www.alvopetro.com/corporate-presentation. 

Social MediaFollow Alvopetro on our social media channels at the following links:

Twitter – https://twitter.com/AlvopetroEnergyInstagram – 
https://www.instagram.com/alvopetro/LinkedIn – 
https://www.linkedin.com/company/alvopetro-energy-ltdYouTube: https://www.youtube.com/channel/UCgDn_igrQgdlj-maR6fWB0w

Alvopetro Energy Ltd.’s vision 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.

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 exploration and development prospects of Alvopetro and
the expected timing of certain of Alvopetro’s operational activities. The
forward?looking
statements are based on certain key expectations and assumptions made by
Alvopetro, including but not limited to expectations and assumptions concerning
testing results, equipment availability, the timing of regulatory licenses and
approvals, the success of future drilling, completion, testing, recompletion
and development activities, the outlook for commodity markets and ability to
access capital markets, the impact of the COVID-19 pandemic, the performance of
producing wells and reservoirs, well development and operating performance, foreign
exchange rates, general economic and business conditions, weather and access to
drilling locations, the availability and cost of labour and services,
environmental regulation, including regulation relating to hydraulic fracturing
and stimulation, the ability to monetize hydrocarbons discovered, 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.

SOURCE Alvopetro Energy Ltd.

Image Credit: Alberta Newsroom (Flickr)

Biden Signs Inflation Reduction Act: Its Climate Promise Relies Heavily on Carbon Capture, Meaning Thousands of Miles of Pipeline

President Joe Biden signed a sweeping climate, energy and health care bill on Aug. 16, 2022, that contains about US$370 billion to foster clean energy development and combat climate change, constituting the largest federal climate investment in history.

Several studies project that its climate and energy provisions could enable the United States to reduce its greenhouse gas emissions by around 40% below 2005 levels by 2030. That would be a significant improvement over the current projections of around 27%, and it could put the U.S. within hailing range of its pledge under the Paris Agreement to reduce emissions by at least 50% by 2030.

Notably, one linchpin of the new climate provisions is a set of incentives to substantially expand technologies that capture carbon dioxide and either store it underground or ship it for reuse.

So far, the uptake of carbon capture technologies has been slow. The costs are high, and these technologies can require miles of pipeline and vast amounts of underground storage, both of which can trigger local backlash. A recent study projected that the U.S. would have to construct 65,000 miles of carbon dioxide pipelines to achieve net-zero emissions in 2050, a whopping 13 times the current capacity.

I’m the former founding co-director of the Institute for Carbon Removal Law &  Policy at American University. While the new law, known as the Inflation Reduction Act, has many provisions designed to jump-start the carbon removal sector, it’s far from certain that the industry will be able to move quickly.

One-Sixth of all Emissions Cuts

The Inflation Reduction Act includes two primary types of carbon capture.

Carbon capture and storage entails capturing carbon dioxide generated during power generation and industrial processes, such as steel and concrete production, and transporting it for storage or use. The most common use to date has been for enhanced oil recovery – injecting the gas into oil and gas reservoirs to extract more fossil fuels.

It also seeks to drive deployment of direct air capture technologies, which can pull carbon dioxide out of the air.

A Princeton University analysis estimated that pertinent provisions of the legislation “would increase the use of carbon capture 13-fold by 2030 relative to current policy,” with only a modest amount projected to come from carbon dioxide removal. This could translate into about one-sixth to one-fifth of its projected carbon dioxide emissions reductions.

Consistent with most of its other energy and climate provisions, the Inflation Reduction Act seeks to drive widespread deployment of carbon removal technologies through incentives. Most importantly, it substantially amends a provision of the U.S. tax code
referred to as 45Q, which is designed to drive corporate investments in carbon
capture.

Under its provisions, tax credits for capturing carbon dioxide at industrial facilities and power plants would increase from $50 per ton today to up to $85 per ton if the carbon is stored. If the carbon is used instead for oil drilling, the credit would go from $30 today to $60 per ton.

Credits for capturing carbon from air via direct air capture would also dramatically jump, from $50 to $180 per ton if the carbon dioxide is stored, and from $35 currently to $130 per ton if it is used.

The new law also moves back the deadline for starting construction of carbon capture facilities that qualify from 2026 to 2033, reduce the minimum capture requirements for obtaining credits, and permit direct payments for the full value of credits for the first five years of a project’s operation in lieu of tax credits.

Missing Pieces

Currently there are only a dozen carbon capture and storage facilities in the U.S. and a couple of direct air capture facilities removing a small amount of carbon from the air.

There’s a reason the uptake of carbon capture, particularly direct air capture, has been slow. Direct air capture cost estimates vary from $250 to $600 per ton, according to one analysis, while experts have estimated that a price under $100 and closer to $50 could create a market.

Some experts believe that the Inflation Reduction Act sufficiently ratchets up 45Q credits to start driving widespread construction of carbon capture and storage facilities in the power and industrial sectors. Others believe that the direct pay provision is “the fundamental missing piece” for carbon capture and storage because project developers and sponsors can avoid the often onerous and costly process of raising tax equity to qualify to use the credits.

There’s hope that the increase in credit values for direct air capture will help to foster “synthetic economics” for this nascent market, infusing sufficient capital to develop technologies at scales that are profitable.

Pipeline Challenges Ahead

However, while the Inflation Reduction Act may appear helpful on a theoretical basis, both carbon capture and storage and direct air capture could face some serious headwinds over the course of the next decade and beyond.

One major challenge could be resistance to the construction of pipelines to transport carbon dioxide to storage sites. In recent years, counties and private landowners in Iowa have voiced opposition to such projects, particularly the idea that the state might allow pipeline builders to seize private land for their projects.

Pipeline construction is also a point of contention for environmental groups, especially environmental justice organizations, and could lead to protracted litigation. This stems in part from a carbon dioxide pipeline rupture in Satartia, Mississippi, in 2020, which hospitalized 45 people.

If public opposition delays construction, projects could be pushed past the window for the incentives, leaving developers with expensive projects. While some studies argue that enhanced oil recovery results in a net reduction in carbon dioxide emissions, this may ultimately be a hard political sell for local communities.

The Inflation Reduction Act may ultimately brighten the prospects for carbon removal in America, but this is by no means assured, especially in the optimistic time frame of the next decade.

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Monday, August 15, 2022

Alvopetro Energy (ALVOF)
No surprises in quarterly results, time to shift focus to the future

Alvopetro Energy Ltd.’s vision 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.

Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.

Refer to the full report for the price target, fundamental analysis, and rating.

Alvopetro Energy reported 2022-2Q results significantly higher than last year and in line with expectations. Production of 2,359 boe/d (versus 2,361 last year and 2,501 last quarter) reflects a 5-day suspension of production in preparation for a processing plant expansion. The average gas price was $11.90/mcf. versus $6.06/mcf last year. With higher pricing, sales rose 93%, fund flow from operations rose 127%, and net income rose 74%. Results were in line with our expectations.

Positive pricing will continue for the immediate future and beyond. Contracted gas prices were set at $11.28/mcf. effective August 1, 2022. We believe the price Alvopetro will receive over the six months of this period’s pricing to be above $11.28/mcf and closer to $11.50/mcf. based on current exchange rates. Prices would have been set at a higher level had the increase not been constrained by a ceiling. In fact, Alvopetro management showed a chart with current prices indicating prices might have been as high $20 had there not been a ceiling. The indicated price is so far above the ceiling price that pricing will most likely be at the ceiling for the foreseeable future even if energy prices or the Real pull back from current levels….

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 Credit: Victor Leshyk (MIT News)

A New Method Boosts Wind Farms’ Energy Output, Without New Equipment

David L. Chandler | MIT
News Office

Virtually all wind turbines, which produce more than 5 percent of the world’s electricity, are controlled as if they were individual, free-standing units. In fact, the vast majority are part of larger wind farm installations involving dozens or even hundreds of turbines, whose wakes can affect each other.

Now, engineers at MIT and elsewhere have found that, with no need for any new investment in equipment, the energy output of such wind farm installations can be increased by modeling the wind flow of the entire collection of turbines and optimizing the control of individual units accordingly.

The increase in energy output from a given installation may seem modest — it’s about 1.2 percent overall, and 3 percent for optimal wind speeds. But the algorithm can be deployed at any wind farm, and the number of wind farms is rapidly growing to meet accelerated climate goals. If that 1.2 percent energy increase were applied to all the world’s existing wind farms, it would be the equivalent of adding more than 3,600 new wind turbines, or enough to power about 3 million homes, and a total gain to power producers of almost a billion dollars per year, the researchers say. And all of this for essentially no cost.

The research is published today in the journal Nature Energy, in a study led by MIT Esther and Harold E. Edgerton Assistant Professor of Civil and Environmental Engineering Michael F. Howland.

“Essentially all existing utility-scale turbines are controlled ‘greedily’ and independently,” says Howland. The term “greedily,” he explains, refers to the fact that they are controlled to maximize only their own power production, as if they were isolated units with no detrimental impact on neighboring turbines.

But in the real world, turbines are deliberately spaced close together in wind farms to achieve economic benefits related to land use (on- or offshore) and to infrastructure such as access roads and transmission lines. This proximity means that turbines are often strongly affected by the turbulent wakes produced by others that are upwind from them — a factor that individual turbine-control systems do not currently take into account.

“From a flow-physics standpoint, putting wind turbines close together in wind farms is often the worst thing you could do,” Howland says. “The ideal approach to maximize total energy production would be to put them as far apart as possible,” but that would increase the associated costs.

That’s where the work of Howland and his collaborators comes in. They developed a new flow model which predicts the power production of each turbine in the farm depending on the incident winds in the atmosphere and the control strategy of each turbine. While based on flow-physics, the model learns from operational wind farm data to reduce predictive error and uncertainty. Without changing anything about the physical turbine locations and hardware systems of existing wind farms, they have used the physics-based, data-assisted modeling of the flow within the wind farm and the resulting power production of each turbine, given different wind conditions, to find the optimal orientation for each turbine at a given moment. This allows them to maximize the output from the whole farm, not just the individual turbines.

Today, each turbine constantly senses the incoming wind direction and speed and uses its internal control software to adjust its yaw (vertical axis) angle position to align as closely as possible to the wind. But in the new system, for example, the team has found that by turning one turbine just slightly away from its own maximum output position — perhaps 20 degrees away from its individual peak output angle — the resulting increase in power output from one or more downwind units will more than make up for the slight reduction in output from the first unit. By using a centralized control system that takes all of these interactions into account, the collection of turbines was operated at power output levels that were as much as 32 percent higher under some conditions.

In a months-long experiment in a real utility-scale wind farm in India, the predictive model was first validated by testing a wide range of yaw orientation strategies, most of which were intentionally suboptimal. By testing many control strategies, including suboptimal ones, in both the real farm and the model, the researchers could identify the true optimal strategy. Importantly, the model was able to predict the farm power production and the optimal control strategy for most wind conditions tested, giving confidence that the predictions of the model would track the true optimal operational strategy for the farm. This enables the use of the model to design the optimal control strategies for new wind conditions and new wind farms without needing to perform fresh calculations from scratch.

Then, a second months-long experiment at the same farm, which implemented only the optimal control predictions from the model, proved that the algorithm’s real-world effects could match the overall energy improvements seen in simulations. Averaged over the entire test period, the system achieved a 1.2 percent increase in energy output at all wind speeds, and a 3 percent increase at speeds between 6 and 8 meters per second (about 13 to 18 miles per hour).

While the test was run at one wind farm, the researchers say the model and cooperative control strategy can be implemented at any existing or future wind farm. Howland estimates that, translated to the world’s existing fleet of wind turbines, a 1.2 percent overall energy improvement would produce  more than 31 terawatt-hours of additional electricity per year, approximately equivalent to installing an extra 3,600 wind turbines at no cost. This would translate into some $950 million in extra revenue for the wind farm operators per year, he says.

The amount of energy to be gained will vary widely from one wind farm to another, depending on an array of factors including the spacing of the units, the geometry of their arrangement, and the variations in wind patterns at that location over the course of a year. But in all cases, the model developed by this team can provide a clear prediction of exactly what the potential gains are for a given site, Howland says. “The optimal control strategy and the potential gain in energy will be different at every wind farm, which motivated us to develop a predictive wind farm model which can be used widely, for optimization across the wind energy fleet,” he adds.

But the new system can potentially be adopted quickly and easily, he says. “We don’t require any additional hardware installation. We’re really just making a software change, and there’s a significant potential energy increase associated with it.” Even a 1 percent improvement, he points out, means that in a typical wind farm of about 100 units, operators could get the same output with one fewer turbine, thus saving the costs, usually millions of dollars, associated with purchasing, building, and installing that unit.

Further, he notes, by reducing wake losses the algorithm could make it possible to place turbines more closely together within future wind farms, therefore increasing the power density of wind energy, saving on land (or sea) footprints. This power density increase and footprint reduction could help to achieve pressing greenhouse gas emission reduction goals, which call for a substantial expansion of wind energy deployment, both on and offshore.

What’s more, he says, the biggest new area of wind farm development is offshore, and “the impact of wake losses is often much higher in offshore wind farms.” That means the impact of this new approach to controlling those wind farms could be significantly greater.

The Howland Lab and the international team is continuing to refine the models further and working to improve the operational instructions they derive from the model, moving toward autonomous, cooperative control and striving for the greatest possible power output from a given set of conditions, Howland says.

“This paper describes a significant step forward for wind power,” says Charles Meneveau, a professor of mechanical engineering at Johns Hopkins University, who was not involved in this work. “It includes new ideas and methodologies to effectively control wind turbines collectively under the highly variable wind energy resource. It shows that smartly implemented yaw control strategies using state-of-the-art physics-based wake models, supplemented with data-driven approaches, can increase power output in wind farms.” The fact that this was demonstrated in an operating wind farm, he says, “is of particular importance to facilitate subsequent implementation and scale-up of the proposed approach.”

Reprinted with the permission  MIT News http://news.mit.edu/

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Alvopetro Announces Record Funds Flow from Operations for the Second Quarter of 2022 & Q2 Results Webcast

Research, News, and Market Data on Alvopetro Energy

Aug 11, 2022

CALGARY, AB, Aug. 11, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces operating and financial results for the second quarter of 2022 including record funds flow from operations of $12.4 million. We will host a live webcast to discuss Q2 2022 results on Friday August 12, 2022 beginning at 8:00 am Mountain time.

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.

Financial and Operating Highlights – Second Quarter of 2022

• Daily sales averaged 2,359 boepd in Q2 2022, consistent with the Q2 2021 average of 2,361 boepd and a 6% reduction from the Q1 2022 average of 2,501 boepd as a result of a planned five-day shut-down of our gas processing facility to complete necessary work in advance of the facility expansion.
• On February 1, 2022, our contracted natural gas price under our long-term gas sales agreement increased 48% to Brazilian real (“BRL”)1.94/m3. With all natural gas sales in Q2 2022 at this higher price and an appreciation of the BRL relative to the USD compared to Q2 2021, our average realized natural gas price increased to $11.90/Mcf compared to the Q2 2021 average price of $6.06/Mcf and the Q1 2022 average price of $10.03/Mcf. Higher commodity prices resulted in a 93% increase in our natural gas, condensate and oil revenue compared to Q2 2021.
• With higher realized sales prices, our operating netback increased to $63.96 per boe in Q2 2022, an improvement of 103% from Q2 2021 and 19% from Q1 2022.
• We generated cash flows from operating activities of $13.0 million ($0.38 per basic share and $0.35 per diluted share) and funds flows from operations of $12.4 million ($0.37 per basic share and $0.34 per diluted share), increases of $7.3 million and $7.0 million, respectively compared to Q2 2021.
• We reported net income of $6.6 million, an increase of $2.8 million compared to Q2 2021.
• Capital expenditures totaled $6.3 million, focused on drilling costs for our 182-C1 and 183-B1 wells, long lead purchases, final costs for our Murucututu field production facility installation on other development costs on our Murucututu project.
• We repaid an additional $2.5 million of our credit facility, bringing the balance outstanding to $2.5 million. As at June 30, 2022, we had a net working capital surplus of $11.6 million, including $13.7 million in cash and cash equivalents. The Company’s working capital net of our credit facility balance improved to $9.1 million, compared to $7.3 million as of March 31, 2022.
• Effective August 1, 2022 our natural gas price has been set at BRL1.94/m3 or $11.28/Mcf (based on our average heat content to date of 107% and the July 31, 2022 BRL/USD foreign exchange rate of 5.19). The adjusted price is based on the ceiling price in the contract, which was adjusted to $10.22/MMBtu effective August 1, 2022. While the ceiling price increased by 6% from the February 1, 2022 ceiling price, due to the appreciation of the BRL relative to the USD in the first half of 2022 compared to the latter half of 2021, the BRL denominated contractual price remained consistent. This price will be effective for all natural gas sales from August 1, 2022 to January 31, 2023.

The following table provides a summary of Alvopetro’s financial and operating results for three and six months ended June 30, 2022 and June 30, 2021. 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.

Second Quarter 2022 Results Webcast

Alvopetro will host a live webcast to discuss Q2 2022 financial results at 8:00 am Mountain time on August 12, 2022. Details for joining the event are as follows:

Date: August 12, 2022Time: 8:00 AM Mountain/10:00 AM Eastern
Link: https://us06web.zoom.us/j/89887067576Dial-in
Numbers: https://us06web.zoom.us/u/kSVhrrkB0Webinar
ID: 898 8706 7576

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.

Corporate Presentation

Alvopetro’s updated corporate presentation is available on our website at: http://www.alvopetro.com/corporate-presentation. 

Social Media

Follow Alvopetro on our social media channels at the following links:

Twitter – https://twitter.com/AlvopetroEnergy Instagram – 
https://www.instagram.com/alvopetro/ LinkedIn – 
https://www.linkedin.com/company/alvopetro-energy-ltd

Alvopetro Energy Ltd.’s vision 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.

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 (Net 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. As of June 30, 2022, Alvopetro’s net working capital surplus exceeds the balance outstanding on the Credit Facility.

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 MD&A 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 plans relating to the Company’s operational activities, the expected natural gas price, gas sales and gas deliveries under Alvopetro’s long-term gas sales agreement, exploration and development prospects of Alvopetro, the expected timing of certain of Alvopetro’s testing and operational activities, future results from operations, and the Company’s plans for dividends in the future. The forward?looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to equipment availability, the timing of testing of the 182-C1 and the 183-B1 wells and the results from such testing, the timing of regulatory licenses and approvals, the success of future drilling, completion, testing, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of the COVID-19 pandemic and other significant worldwide events, the performance of producing wells and reservoirs, well development and operating performance, foreign exchange rates, general economic and business conditions, weather and access to drilling locations, the availability and cost of labour and services, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, 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 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 restated 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.

SOURCE Alvopetro Energy Ltd.

Friday, August 12, 2022

InPlay Oil (IPOOF)
Another solid quarter with results generally in line with expectations

InPlay Oil 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 full report for the price target, fundamental analysis, and rating.

InPlay reported sold 2022-2Q results. Production (9,063 boe/d) was a bit below our expectations due to difficulties trucking out oil due to wet weather (55 boe/d reduction). On the other hand, oil and natural gas pricing was above expectations at C$116.74 (versus our C$105 estimate) and C$7.61 per mcf. (versus our C$6.90 per mcf. estimate). Notably, lifting and operating costs were a modest $12.28/boe down from first quarter LOE of $12.96. The net effect was adjusted fund flow (C$40.9m vs. C$38.7m) and net income (C$29.0m/$0.32 vs. C$27.8m/$0.32) in line with expectations.

Accelerated drilling program is showing signs of success. InPlay drilled five wells during the quarter. Drill time has been reduced to 10-11 days. InPlay did not indicate the cost to drill the wells, but we assume original drilling cost of C$2.5 million may be coming down. The company anticipates drilling three wells in the third quarter despite delays due to wet weather. …

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.