Image Credit: Jan-Rune Smenes Reite

Who Really Owns the Oil Industry’s Future Stranded Assets?

Over the past three years, the planet has experienced both an oil glut and an oil drought. Investors, including those in pension and 401K plans, have been subject to unrivaled volatility. In this article, a Professor of Economics teams up with an Earth Science Lecturer to explore what they project will unfold going forward in climate regulation, oil production, and the investors in the industry. Paul Hoffman – Managing Editor

When an oil company invests in an expensive new drilling project today, it’s taking a gamble. Even if the new well is a success, future government policies designed to slow climate change could make the project unprofitable or force it to shut down years earlier than planned.

When that happens, the well and the oil become what’s known as stranded assets. That might sound like the oil company’s problem, but the company isn’t the only one taking that risk.

This article was republished with permission from The Conversation, a news site dedicated to sharing ideas from academic experts. It was written by and represents the research-based opinions of Gregor Semieniuk, Assistant Research Professor of Economics, UMass Amherst, and Philip Holden, Senior Lecturer in Earth System Science, The Open University

In a study published May 26, 2022, in the journal Nature Climate Change, we traced the ownership of over 43,000 oil and gas assets to reveal who ultimately loses from misguided investments that become stranded.

It turns out, private individuals own over half the assets at risk, and ordinary people with pensions and savings that are invested in managed funds shoulder a surprisingly large part, which could exceed a quarter of all losses.

More Climate Regulations are Coming

In 2015, almost every country worldwide signed the Paris climate agreement, committing to try to hold global warming to well under 2 degrees Celsius (3.6 F) compared to pre-industrial averages. Rising global temperatures were already contributing to deadly heat waves and worsening wildfires. Studies showed the hazards would increase as greenhouse gas emissions, primarily from fossil fuel use, continue to rise.

It’s clear that meeting the Paris goals will require a global energy transition away from fossil fuels. And many countries are developing climate policies designed to encourage that shift to cleaner energy.

But the oil industry is still launching new fossil fuel projects, which suggests that it doesn’t think it will be on the hook for future stranded assets. U.N. Secretary-General António Guterres called a recent wave of new oil and gas projects “moral and economic madness.”

How Risk Flows from Oil Field to Small Investor

When an asset becomes stranded, the owner’s anticipated payoff won’t materialize.

For example, say an oil company buys drilling rights, does the exploration work and builds an offshore oil platform. Then it discovers that demand for its product has declined so much because of climate change policies that it would cost more to extract the oil than the oil could be sold for.

The oil company is owned by shareholders. Some of those shareholders are individuals. Others are companies that are in turn owned by their own shareholders. The lost profits are ultimately felt by those remote owners.

In the study, we modeled how demand for fossil fuels could decline if governments make good on their recent emissions reduction pledges and what that would mean for stranded assets. We found that $1.4 trillion in oil and gas assets globally would be at risk of becoming stranded.

Stranded assets mean a wealth loss for the owners of the assets. We traced the losses from the oil and gas fields, through the extraction companies, on to those companies’ immediate shareholders and fundholders, and again their shareholders and fundholders if the immediate shareholders are companies, and all the way to people and governments that own stock in the companies in this chain of ownership.

It’s a complex network.

On their way to ultimate owners, much of the loss passes through financial firms, including pension funds. Globally, pension funds that invest their members’ savings directly into other companies own a sizable amount of those future stranded assets. In addition, many defined contribution pensions have investments through fund managers, such as BlackRock or Vanguard, that invest on their behalf.

We estimate that total global losses hitting the financial sector – including through cross-ownership of one financial firm by another – from stranded assets in oil and gas production could be as high as $681 billion. Of this, about $371 billion would be held by fund managers, $146 billion by other financial firms and $164 billion could even affect bondholders, often pension funds, whose collateral would be diminished.

U.S. owners have by far the largest exposure. Ultimately, we found that losses of up to $362 billion could be distributed through the financial system to U.S. investors.

Some of the assets and companies in an ownership chain are also overseas, which can make the exposure to risk for a fund owner even more difficult to track.

Someone Will Get Stuck with those Assets

Our estimates are based on a snapshot of recent global share ownership. At the moment, with oil and gas prices near record highs due to supply chain problems and the Russian war in Ukraine, oil and gas companies are paying splendid dividends. And in principle, every shareholder could sell off their holdings in the near future.

But that does not mean the risk disappears: Someone else buys that stock.

Ultimately, it’s like a game of
musical chairs. When the music stops, someone will be left with the stranded asset.
And since the most affluent investors have sophisticated investment teams, they
may be best placed to get out in time, leaving less sophisticated investors and
defined contribution pension plans to join the oil and gas field workers as
losers, while the managers of the oil companies unfold their golden parachutes.

Alternatively, powerful investors could successfully lobby for compensation, as has happened repeatedly in the U.S. and Germany. One argument would be that they couldn’t have anticipated the stricter climate laws when they invested or they could point to governments asking companies to produce more in the short-term, as happened recently in the U.S. to substitute for Russian supplies.

However, divesting right away or hoping for compensation aren’t the only options. Investors – the owners of the company – can also pressure companies to shift from fossil fuels to renewable energy generation or another choice with growth potential for the future.

Investors not only may have the financial risk, but also the related financial responsibility, and ethical choices may help preserve both the value of their investments and the climate.

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Has Summer Driving Season Been Cancelled by High Gas Prices?

Some products are very sensitive to price changes. When the price rises, consumption is reduced. Others, will be consumed at or near the same rate regardless of price.  Gasoline has always been considered a product where price has very little influence over demand – until now. The current rise in fuel prices has economists scratching their heads as drivers forgo trips, travel, and even commuting to work.

Destruction of Demand

In economics 101, students learn about elasticity of demand. If a product’s consumption is impacted greatly by price changes, it is considered elastic, if demand is slightly or not impacted, it is considered inelastic. Medicines, non-substitutable food products, and fuel for automobiles have been understood to be inelastic – people buy them even when prices rise. Professors may have to rewrite the eco 101 textbooks because gasoline consumption isn’t following the old rule in 2022.

As the summer driving season begins in the U.S., the pain of filling up the tank has gotten high enough for gasoline consumption to be dropping.

Seasonally, demand on a four-week rolling basis has hit its lowest level since 2013, (excluding the pandemic-forced lockdown in 2020). And compared to just one year ago, demand is down about 5%. This is according to data from the Energy Information Administration (EIA).

Where are prices headed? Some fuel stations are upgrading their pumps to double-digit readouts (exceeding $9.99) as prices at gas stations continue to rise. Across the U.S., fuel costs have hit yet another record over the past two weeks. This is running counter to the expected increase in driving post-pandemic fears.

Regular gas prices have never before hit the highs they are today in the U.S.  The average gallon of gas hit $4.59 on Tuesday (May 27), about 51% higher than a year ago. And in California, AAA data shows, that prices are exceeding $6.

Demand Destruction

In economics, demand destruction refers to a permanent or sustained decline in the demand for a product in reaction to an increase in price. The demand destruction apparently caused by the high gas prices could alter earlier forecasts for gasoline prices. The reduced demand was not built into models forecasting demand and related prices. If the trajectory of consumption continues to fall, the impact on producers may follow.  

Take-Away

In economics, nothing exists in a vacuum and its mechanisms are in constant flux. Even products with consistent demand can be impacted by substitutes. Up until recently substitutes for being in the office, meeting face to face with friends, or shopping barely existed. Today one can do all of these to one degree or another. Also, the populace has been retrained to enjoy their home surroundings. What may have once seemed like an imperative, like a drive to the park or visit with friends across town, is less critical now.

Will fuel prices come down as result? An equilibrium will be reached as demand would also pick up if prices retreat.

Paul Hoffman

Managing Editor, Channelchek

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Sources

https://www.eia.gov/petroleum/gasdiesel/

https://www.forbes.com/sites/daneberhart/2022/04/20/pandemic-demand-destruction-no-match-for-supply-shortages/?sh=516ba90d7849

https://www.forbes.com/sites/daneberhart/2022/04/20/pandemic-demand-destruction-no-match-for-supply-shortages/?sh=516ba90d7849

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Energy Fuels Announces Election of Directors

Research, News, and Market Data on Energy Fuels

LAKEWOOD, Colo., May 25, 2022 /CNW/ – Energy Fuels Inc. (NYSE: UUUU) (TSX: EFR) (“Energy Fuels” or the “Company”), the leading uranium producer in the United States, announces the results of the election of directors at its annual meeting of shareholders (the “Meeting“) held virtually on May 25, 2022.

The ten (10) nominees proposed by management for election as directors were elected by the shareholders of the Company, through a combination of votes by proxy and electronic poll, as follows:

Nominee	Votes For	% For	Votes Withheld	% Withheld
J. Birks Bovaird	28,895,258	84.00%	5,504,196	16.00%
Mark S. Chalmers	34,174,259	99.35%	225,195	0.65%
Benjamin Eshleman III	33,122,677	96.29%	1,276,777	3.71%
Ivy V. Estabrooke	34,046,339	98.97%	353,115	1.03%
Barbara A. Filas	33,578,211	97.61%	821,243	2.39%
Bruce D. Hansen	33,031,520	96.02%	1,367,934	3.98%
Jaqueline Herrera	33,885,122	98.50%	514,332	1.50%
Dennis L. Higgs	33,942,354	98.67%	457,100	1.33%
Robert W. Kirkwood	33,124,267	96.29%	1,275,187	3.71%
Alexander Morrison	33,845,484	98.39%	553,970	1.61%

About
Energy Fuels: Energy Fuels is a leading U.S.-based uranium mining company, supplying U₃O₈ to major nuclear utilities. Energy Fuels also produces vanadium from certain of its projects, as market conditions warrant, and is ramping up commercial-scale production of rare earth element (“REE“) carbonate. Its corporate offices are in Lakewood, Colorado, near Denver, and all its assets and employees are in the United States. Energy Fuels holds three of America’s key uranium production centers: the White Mesa Mill in Utah, the Nichols Ranch in-situ recovery (“ISR“) Project in Wyoming, and the Alta Mesa ISR Project in Texas. The White Mesa Mill is the only conventional uranium mill operating in the U.S. today, has a licensed capacity of over 8 million pounds of U₃O₈ per year, and has the ability to recycle alternate feed materials from third parties, to produce vanadium when market conditions warrant, and to produce REE carbonate from various uranium-bearing ores. Energy Fuels is also evaluating the potential to recover medical isotopes for use in targeted alpha therapy cancer treatments. The Nichols Ranch ISR Project is on standby and has a licensed capacity of 2 million pounds of U₃O₈ per year. The Alta Mesa ISR Project is also on standby and has a licensed capacity of 1.5 million pounds of U₃O₈ per year. In addition to the above production facilities, Energy Fuels also has one of the largest SK-1300/NI 43-101 compliant uranium resource portfolios in the U.S. and several uranium and uranium/vanadium mining projects on standby and in various stages of permitting and development. The primary trading market for Energy Fuels’ common shares is the NYSE American under the trading symbol “UUUU,” and the Company’s common shares are also listed on the Toronto Stock Exchange under the trading symbol “EFR.” Energy Fuels’ website is www.energyfuels.com.

SOURCE Energy Fuels Inc.

Dr. Patrick Gruber to Participate in a Water Tower Research Fireside Chat on Thursday, June 2 at 4:00 pm EDT

Research, News, and Market Data on Gevo

ENGLEWOOD, Colo., May 26, 2022 (GLOBE NEWSWIRE) — Gevo, Inc. (NASDAQ:GEVO), announced today that Dr. Patrick Gruber, Chief Executive Officer, will participate in a Water Tower Research Fireside Chat on Thursday, June 2, 2022 at 4:00 pm EDT.

Topic: Business Overview

Investors and other persons interested in participating in the event must register using the link below. Please note that the replay may be accessed at any time after the presentation ends on June 2, 2022, utilizing the same registration link.

Registration Link:

https://globalmeet.webcasts.com/starthere.jsp?ei=1550774&tp_key=8c41aff149

About Gevo

Gevo’s mission is to transform renewable energy and carbon into energy-dense liquid hydrocarbons. These liquid hydrocarbons can be used for drop-in transportation fuels such as gasoline, jet fuel and diesel fuel, that when burned have potential to yield net-zero greenhouse gas emissions when measured across the full life cycle of the products. Gevo uses low-carbon renewable resource-based carbohydrates as raw materials, and is in an advanced state of developing renewable electricity and renewable natural gas for use in production processes, resulting in low-carbon fuels with substantially reduced carbon intensity (the level of greenhouse gas emissions compared to standard petroleum fossil-based fuels across their life cycle). Gevo also plans to take advantage of decarbonization via geological sequestration in the future. Gevo’s products perform as well or better than traditional fossil-based fuels in infrastructure and engines, but with substantially reduced greenhouse gas emissions. In addition to addressing the problems of fuels, Gevo’s technology also enables certain plastics, such as polyester, to be made with more sustainable ingredients. Gevo’s ability to penetrate the growing low-carbon fuels market depends on the price of oil and the value of abating carbon emissions that would otherwise increase greenhouse gas emissions.

Gevo believes that its proven, patented technology enabling the use of a variety of low-carbon sustainable feedstocks to produce price-competitive low-carbon products such as gasoline components, jet fuel and diesel fuel yields the potential to generate project and corporate returns that justify the build-out of a multi-billion-dollar business.

Gevo believes that the Argonne National Laboratory GREET model is the best available standard of scientific-based measurement for life cycle inventory or LCI.

Learn more at Gevo’s website: www.gevo.com

Gevo Investor and Media Contact

Heather L. Manuel

+1 720-418-0085

[email protected]

Friday, May 20, 2022

Energy Fuels (UUUU)
UUUU locks up Rare Earth Element Supplies

Energy Fuels is a leading U.S.-based uranium mining company, supplying U3O8 to major nuclear utilities. Energy Fuels also produces vanadium from certain of its projects, as market conditions warrant, and is ramping up commercial-scale production of REE carbonate. Its corporate offices are in Lakewood, Colorado, near Denver, and all its assets and employees are in the United States. Energy Fuels holds three of America’s key uranium production centers: the White Mesa Mill in Utah, the Nichols Ranch in-situ recovery (“ISR”) Project in Wyoming, and the Alta Mesa ISR Project in Texas. The White Mesa Mill is the only conventional uranium mill operating in the U.S. today, has a licensed capacity of over 8 million pounds of U3O8 per year, has the ability to produce vanadium when market conditions warrant, as well as REE carbonate from various uranium-bearing ores. The Nichols Ranch ISR Project is on standby and has a licensed capacity of 2 million pounds of U3O8 per year. The Alta Mesa ISR Project is also on standby and has a licensed capacity of 1.5 million pounds of U3O8 per year. In addition to the above production facilities, Energy Fuels also has one of the largest NI 43-101 compliant uranium resource portfolios in the U.S. and several uranium and uranium/vanadium mining projects on standby and in various stages of permitting and development. The primary trading market for Energy Fuels’ common shares is the NYSE American under the trading symbol “UUUU,” and the Company’s common shares are also listed on the Toronto Stock Exchange under the trading symbol “EFR.” Energy Fuels’ website is www.energyfuels.com.

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

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

Energy Fuels signed purchase agreements to acquire mineral concessions in Bahia, Brazil believed to include monazite sand, which contains both rare earth elements (REE) and uranium. The project has yet to be mined, but over 3,300 holes have been drilled indicating the presence of monazite. The monazite is close to the surface and should be a low-cost source of supply. The monazite will be shipped to UUUU’s milling operations in the United States where it is developing and expanding REE extraction and separation operations. Management indicated that building a Brazil milling plant is possible, although we do not view that as a near-term project. Energy Fuels will pay $27.5 million for the concessions, an amount easily funded with its $106 million of cash and marketable securities.

Management believes the project could supply 3,000-10,000 per year of monazite containing 1,500-5,000 of total rare earth oxides (TREO). The company had previously stated a goal of eventually producing 10,000 tons of REE annually, implying processing 20,000-25,000 tons of monazite. To date, production ramp up has been hampered by an inability to secure sufficient monazite sand. If management is correct about the potential of the Brazil project, it could represent 25-50% of supply at full production (which we model to be in 2026). As such, the agreement represents a significant step in locking up supply. We expect the company to continue to look to sign additional supply agreements….

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. 

InPlay Oil Corp. Announces Annual Meeting Voting Results for Election of Directors

News and Market Data on InPlay Oil Corp

CALGARY, Alberta, May 19, 2022 (GLOBE NEWSWIRE) — InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announced today the voting results for the election of directors at its annual meeting of shareholders held on May 19, 2022 (the “Meeting”). The following five nominees were elected as directors of InPlay to serve until the next annual meeting of shareholders or until their successors are elected or appointed, with common shares represented at the Meeting voting in favour of individual nominees as follows:

Director		Percentage Approval			Percentage Withheld
Douglas J. Bartole		99.8	%		0.2	%
Joan E. Dunne		99.6	%		0.4	%
Craig Golinowski		99.5	%		0.5	%
Stephen C. Nikiforuk		99.7	%		0.3	%
Dale O. Shwed		99.4	%		0.6	%

For complete voting results, please see our Report of Voting Results which is available through SEDAR at www.sedar.com.

InPlay is based in Calgary, Alberta and the common shares of InPlay are traded on The Toronto Stock Exchange under the trading symbol “IPO”. For further information about the Corporation, please visit our website at www.inplayoil.com.

For further information please contact:

Doug Bartole President and Chief Executive Officer InPlay Oil Corp. Telephone: (587) 955-0632

Darren Dittmer Chief Financial Officer InPlay Oil Corp. Telephone: (587) 955-0634

Thursday, May 19, 2022

Energy Fuels (UUUU)
Are we seeing the first signs of ramping up?

Energy Fuels is a leading U.S.-based uranium mining company, supplying U3O8 to major nuclear utilities. Energy Fuels also produces vanadium from certain of its projects, as market conditions warrant, and is ramping up commercial-scale production of REE carbonate. Its corporate offices are in Lakewood, Colorado, near Denver, and all its assets and employees are in the United States. Energy Fuels holds three of America’s key uranium production centers: the White Mesa Mill in Utah, the Nichols Ranch in-situ recovery (“ISR”) Project in Wyoming, and the Alta Mesa ISR Project in Texas. The White Mesa Mill is the only conventional uranium mill operating in the U.S. today, has a licensed capacity of over 8 million pounds of U3O8 per year, has the ability to produce vanadium when market conditions warrant, as well as REE carbonate from various uranium-bearing ores. The Nichols Ranch ISR Project is on standby and has a licensed capacity of 2 million pounds of U3O8 per year. The Alta Mesa ISR Project is also on standby and has a licensed capacity of 1.5 million pounds of U3O8 per year. In addition to the above production facilities, Energy Fuels also has one of the largest NI 43-101 compliant uranium resource portfolios in the U.S. and several uranium and uranium/vanadium mining projects on standby and in various stages of permitting and development. The primary trading market for Energy Fuels’ common shares is the NYSE American under the trading symbol “UUUU,” and the Company’s common shares are also listed on the Toronto Stock Exchange under the trading symbol “EFR.” Energy Fuels’ website is www.energyfuels.com.

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

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

Energy Fuels reported 2022-1Q results generally in line with expectations and gave an update on operations. Production and sales remain small (modest Vanadium sales) making bottom line results largely a function of operating costs. A slight increase in operating losses ($10.2m versus $8.8m) and net losses ($14.7m versus $10.9m) reflect additional ramp up costs for UUUU’s rare earth element (REE) development and were expected.

Development discussions were largely a repeat of the April update. But wait! A uranium supply contract?!?! Management plans to separate REE elements, efforts to access new REE supplies (Monzanite), and its medical isotope recovery partnership. This is all old news. However, management also announced on a call with investors (not in the press release) that it had just signed a uranium supply contract. This is the first contract in several years and a clear sign that the uranium market has improved to a point where UUUU may ramp up production, “perhaps as early as this summer.”…

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 Fuels Secures Major Rare Earth Land Position in Brazil

Research, News, and Market Data on Energy Fuels

LAKEWOOD, Colo., May 19, 2022 /CNW/ – Energy Fuels Inc. (NYSE American: UUUU) (TSX: EFR) (“Energy Fuels” or the
“Company”) is pleased to announce that it has entered into binding agreements (the “Purchase Agreements“) to acquire seventeen (17) mineral concessions (the “Transaction“) between the towns of Prado and Caravelas in the State of Bahia, Brazil totaling 15,089.71 hectares (approximately 37,300 acres or 58.3 square miles) (the ”
Bahia Project“).

Energy Fuels Inc–Energy Fuels Secures Major Rare Earth Land Pos

Based on significant historical drilling performed to date, it is believed that the Bahia Project holds significant quantities of heavy minerals, including monazite, that will feed Energy Fuels’ quickly emerging U.S.-based rare earth element (“REE“) supply chain. The Bahia Project has seen no previous mining, but several of the concessions have valid exploration and mining permits with the Government of Brazil. Therefore, the Company believes there is a clear path to moving the Bahia Project to production.

The Bahia Project is a well-known heavy mineral sand (“HMS“) deposit with over 3,300 vertical historic exploration auger holes drilled to date, indicating significant concentrations of titanium (ilmenite and rutile), zirconium (zircon), and rare earth elements (monazite). Importantly, the mineralization is at or near the surface, meaning the material is expected to be relatively easy to recover using standard, low-cost sand mining techniques, including the use of front-end loaders, excavators and/or dredges. Due to the drilling method used historically, drilling performed to date only averages 5.86 meters deep, or the average depth of the water table in the region. There is no reason to believe that mineralization stops at the water table. Therefore, the Company believes mineralization is open at depth. Energy Fuels’ primary interest is in the monazite which contains both rare earth elements and uranium. Preliminary assay data indicates the monazite sand contained in the HMS concentrate ranges between 0.62% and 12.82%¹, and the uranium contained in the monazite is expected to be comparable to typical Colorado Plateau uranium deposits.

Energy Fuels plans to perform extensive exploration work over the next six months to further define and quantify the HMS resource at the Bahia Project. This is expected to include a comprehensive sonic drilling and geophysical mapping program to define the HMS grades and depths for the various mineral products, including the REE resources associated with the Bahia Project. The Company plans to engage industry leaders in mineral processing to complete a Preliminary Economic Assessment under NI 43-101 (Canada) and an Initial Assessment under SK-1300 (US) during late Q1 or early Q2 2023.

Based on preliminary, historical resource estimates, the Company believes the Bahia Project has the potential to supply approximately 3,000 – 10,000 tonnes per year of monazite sand concentrate to the Mill (depending on production rates), containing approximately 1,500 – 5,000 tonnes of total rare earth oxides (“TREO“) per year, potentially for decades. The Company expects to mine and produce an HMS concentrate at the site, which contains all the valuable minerals, including monazite. This HMS concentrate would then be shipped to an existing HMS facility for further refinement and separation of the monazite into a product Energy Fuels can process at the Mill. The Company is evaluating whether this further refinement and separation step could potentially be performed in Brazil. However at this time, the Company plans to ship lower concentrations of monazite sand for concentration at a U.S. facility. Preliminary internal projections indicate this latter option can be very cost-effective, despite the larger shipping quantities, as the less concentrated material will not require the more expensive Class 7 designation applicable to higher concentrated materials, and it can be shipped in bulk.

Mark S. Chalmers, President and CEO of Energy Fuels stated: “This is another very significant step in Energy Fuels’ development as a major global rare earth element producer based in the United States. We are aggressively seeking to expand our monazite sand feeds. With guidance from our heavy mineral sand experts, the Company has been evaluating the acquisition of monazite-bearing projects. The Bahia deposit is well-known throughout the HMS industry as having excellent potential to produce high-quality ilmenite, rutile, and zircon products, in addition to monazite. We are very pleased to have secured this project, as it has the potential to provide Energy Fuels with our own low-cost source of monazite feed that we fully control. The Company expects to supplement its monazite supply in the future with open market purchases, arrangements with existing monazite producers, and/or additional acquisitions. Energy Fuels is in advanced discussions with other current and future monazite producers around the world to provide creative options on how to best build upon our momentum and add further scale.

“At Energy Fuels, we have proven our ability to process natural monazite sand concentrate into a high purity mixed rare earth carbonate, containing about 32% – 34% neodymium/praseodymium (NdPr). Our clear current priorities are to continue to build our book of monazite feed to a world scale and to leverage our existing solvent extraction experience and infrastructure at the Mill to produce both separated ‘light’ and ‘heavy’ rare earth oxides, and other products, by adding commercial separation capabilities to the Mill. To achieve these ambitious goals, we have assembled a team of rare earth heavy-weights, including Neo Performance Materials, Carester SAS, and other heavy mineral sand and rare earth experts, that we believe is unmatched anywhere in the world.

“In my view, this acquisition will provide significant credibility to investors, other monazite suppliers, and clean energy manufacturers, as we will clearly demonstrate that Energy Fuels is well on its way to becoming a large-scale producer of advanced rare earth materials in the U.S. We have already proven our processing capabilities. Now, we are proving that upon successful completion of this acquisition, we will own and control ‘the elements’ to supply EV, renewable energy and other technology manufacturers.”

Under the Transaction, Energy Fuels has entered into Purchase Agreements with private mineral rights holders in Brazil to acquire seventeen (17) heavy mineral sand concessions comprising the Bahia Project, subject to a 90-day due diligence period. The total consideration for this acquisition is $27,500,000 in cash, with non-refundable deposits totaling $2,750,000 cash due on signing, and additional non-refundable deposits totaling $2,850,000 cash due at various benchmarks during the due diligence period, and the remaining $21,900,000 due at closing. Closing is expected to follow the 90-day due diligence period and is subject to Energy Fuels being satisfied with its due diligence investigations. The Purchase Agreements contain other customary terms and conditions for a transaction of this nature.

ABOUT ENERGY FUELS

Energy Fuels is a leading U.S.-based uranium mining company, supplying U₃O₈ to major nuclear utilities. Energy Fuels also produces vanadium from certain of its projects, as market conditions warrant, and is ramping up commercial-scale production of REE carbonate. Its corporate offices are in Lakewood, Colorado, near Denver, and all its assets and employees are in the United States. Energy Fuels holds three of America’s key uranium production centers: the White Mesa Mill in Utah, the Nichols Ranch in-situ recovery (“ISR“) Project in Wyoming, and the Alta Mesa ISR Project in Texas. The White Mesa Mill is the only conventional uranium mill operating in the U.S. today, has a licensed capacity of over 8 million pounds of U₃O₈ per year, has the ability to produce vanadium when market conditions warrant, as well as REE carbonate from various uranium-bearing ores. The Nichols Ranch ISR Project is on standby and has a licensed capacity of 2 million pounds of U₃O₈ per year. The Alta Mesa ISR Project is also on standby and has a licensed capacity of 1.5 million pounds of U₃O₈ per year. In addition to the above production facilities, Energy Fuels also has one of the largest NI 43-101 compliant uranium resource portfolios in the U.S. and several uranium and uranium/vanadium mining projects on standby and in various stages of permitting and development. The primary trading market for Energy Fuels’ common shares is the NYSE American under the trading symbol “UUUU,” and the Company’s common shares are also listed on the Toronto Stock Exchange under the trading symbol “EFR.” Energy Fuels’ website is www.energyfuels.com.

Daniel Kapostasy, P.G., Director of Technical Services for Energy
Fuels, is a Qualified Person as defined by Canadian National Instrument
43-101 and has reviewed and approved the technical disclosure contained in this
news release, including sampling, analytical, and test data underlying such
disclosure. 

CAUTIONARY STATEMENTS REGARDING FORWARD LOOKING STATEMENTS

This news release contains “forward-looking information”
within the meaning of applicable securities laws in the United States and Canada.
Forward-looking information may relate to future events or future performance of
Energy Fuels. All statements in this release, other than statements of
historical facts, with respect to Energy Fuels’ objectives and goals, as well
as statements with respect to its beliefs, plans, objectives, expectations,
anticipations, estimates, and intentions, are forward-looking information.
Specific forward-looking statements in this discussion include, but are not
limited to, the following:; any expectation that the Transaction will close and
that the Company will acquire the Bahia Project on the terms disclosed or at
all; any expectation as to the concentrations or quantities of heavy minerals,
including monazite contained in the Bahia Project; any expectation as to the
potential annual supply of monazite sands from the Bahia Project to the Mill,
the contained tonnes of TREO per year, or the number of years or decades of
such potential supply; any expectation that monazite sands from the Bahia
Project may be a low-cost source of monazite feed; any expectation that there
may be a clear path to moving the Bahia Project into production; any
expectation that the mineralization does not stop at the water table and is
open at depth; any expectation as to the exploration or development work the
Company plans to perform on the Bahia Project; any expectation that a
Preliminary Economic Assessment under NI 43-101 or an Initial Assessment under
SK-1300 will be performed and the timing of completion of any such assessments;
any expectation as to how the Bahia Project may be mined, or the manner or
location of any further refinement and separation of mined material; any
expectation as to the cost-effectiveness of transporting various forms of HMS
from the mine to a concentration facility; any expectation that the Company may
become a major global rare earth element producer based in the United
States; any expectation that the Company may be successful in expanding its
monazite sand feeds; any expectation that the Company will or will continue to
successfully process monazite sand concentrates into a high purity mixed rare
earth carbonate; any expectation that the Company may be successful at
developing a full scale separations facility at the Mill; and any expectation
that the Company will continue to be a leading U.S. based uranium mining
company. Often, but not always, forward-looking information can be identified
by the use of words such as “plans”, “expects”, “is
expected”, “budget”, “scheduled”,
“estimates”, “continues”, “forecasts”,
“projects”, “predicts”, “intends”,
“anticipates” or “believes”, or variations of, or the
negatives of, such words and phrases, or state that certain actions, events or
results “may”, “could”, “would”,
“should”, “might” or “will” be taken, occur or be
achieved. This information involves known and unknown risks, uncertainties and
other factors that may cause actual results or events to differ materially from
those anticipated in such forward-looking information. Factors that could
cause actual results to differ materially from those anticipated in these
forward-looking statements include risks associated with: technical
difficulties; mining or processing difficulties and upsets; licensing, permitting and regulatory delays; litigation risks;
competition from others; political actions or instability in foreign countries;
and market factors, including future demand for and prices realized from the
sale of uranium, vanadium and REEs. Forward-looking statements contained herein
are made as of the date of this news release, and Energy Fuels disclaims, other
than as required by law, any obligation to update any forward-looking
statements whether as a result of new information, results, future events,
circumstances, or if management’s estimates or opinions should change, or
otherwise. There can be no assurance that forward-looking statements will prove
to be accurate, as actual results and future events could differ materially
from those anticipated in such statements. Accordingly, the reader is cautioned
not to place undue reliance on forward-looking statements. Energy Fuels assumes
no obligation to update the information in this communication, except as
otherwise required by law.

____________________________

¹ This information comes from 16 different Exploration Reports filed with the Brazilian Government’s National Agency of Minerals (ANM) over several years (2011-2019). These grades should be considered conceptual in nature since there has been insufficient exploration to define a mineral resource and it is uncertain if further exploration will result in the target being delineated as a mineral resource. The data was obtained by sampling 1-meter intervals from a hand auger hole, separating out the heavy mineral fraction using heavy liquids, separating the heavy minerals by magnetic strength and then point counting the minerals under a microscope. Energy Fuels plans to initiate a sonic drill program to better define the exploration target and use industry best practices to determine an estimate of all the heavy minerals found within the project area. A qualified person has not done sufficient work to classify this historical estimate as current and Energy Fuels is not treating this historical estimate as current.

SOURCE Energy Fuels Inc.

For further information: ENERGY FUELS: Curtis Moore – VP of Marketing & Corporate Development, (303) 974-2154

Monday, May 16, 2022

Alvopetro Energy (ALVOF)
A strong quarter as higher prices take effect

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.

First quarter results reflect higher prices. Revenues in the 2022 first quarter were $14.0m versus $6.9m and our $13.4m projection. Higher revenues reflect a 15% increase in production and a 48% increase in prices ($10.03/mcf). As a result of higher prices, operating netbacks rose to $53.94/boe from $28.52/boe. This is one of the best netbacks in the industry. 

Cash flow is soaring. Funds from operations rose to $10.9m versus $4.8m. The company has been active with its cash flow increasing its capital expenditures, paying down debt, and raising the dividend. Working capital less debt switched over to a positive position a few quarters ago and is now $7.3 million. With debt levels soon to be eliminated, the stakeholder focus will soon shift to equity shareholders. We expect additional dividend increases in upcoming quarters and would not be surprised to see the company initiate a share repurchase program in 2023….

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: Robert Course-Baker (Flickr)

Meet the Power Plant of the Future: Solar + Battery Hybrids are Poised for Explosive Growth

America’s electric power system is undergoing radical change as it transitions from fossil fuels to renewable energy. While the first decade of the 2000s saw huge growth in natural gas generation, and the 2010s were the decade of wind and solar, early signs suggest the innovation of the 2020s may be a boom in “hybrid” power plants.

A typical hybrid power plant combines electricity generation with battery storage at the same location. That often means a solar or wind farm paired with large-scale batteries. Working together, solar panels and battery storage can generate renewable power when solar energy is at its peak during the day and then release it as needed after the sun goes down.

A look at the power and storage projects in the development pipeline offers a glimpse of hybrid power’s future.

This article was republished with permission from The Conversation, a news site dedicated to sharing ideas from academic experts. It was written by and represents the research-based opinions of Joachim Seel, Senior Scientific Engineering Associate, Lawrence Berkeley National Laboratory, Bentham Paulos, Affiliate, Electricity Markets & Policy Group, Lawrence Berkeley National Laboratory, and Will Gorman, Graduate Student Researcher in Electricity Markets and Policy, Lawrence Berkeley National Laboratory

Our team at Lawrence Berkeley National Laboratory found that a staggering 1,400 gigawatts of proposed generation and storage projects have applied to connect to the grid – more than all existing U.S. power plants combined. The largest group is now solar projects, and over a third of those projects involve hybrid solar plus battery storage.

While these power plants of the future offer many benefits, they also raise questions about how the electric grid should best be operated.

 

Why Hybrids are Hot

As wind and solar grow, they are starting to have big impacts on the grid.

Solar power already exceeds 25% of annual power generation in California and is spreading rapidly in other states such as Texas, Florida and Georgia. The “wind belt” states, from the Dakotas to Texas, have seen massive deployment of wind turbines, with Iowa now getting a majority of its power from the wind.

This high percentage of renewable power raises a question: How do we integrate renewable sources that produce large but varying amounts of power throughout the day?

That’s where storage comes in. Lithium-ion battery prices have rapidly fallen as production has scaled up for the electric vehicle market in recent years. While there are concerns about future supply chain challenges, battery design is also likely to evolve.

The combination of solar and batteries allows hybrid plant operators to provide power through the most valuable hours when demand is strongest, such as summer afternoons and evenings when air conditioners are running on high. Batteries also help smooth out production from wind and solar power, store excess power that would otherwise be curtailed, and reduce congestion on the grid.

Hybrids Dominate the Project Pipeline

At the end of 2020, there were 73 solar and 16 wind hybrid projects operating in the U.S., amounting to 2.5 gigawatts of generation and 0.45 gigawatts of storage.

Today, solar and hybrids dominate the development pipeline. By the end of 2021, more than 675 gigawatts of proposed solar plants had applied for grid connection approval, with over a third of them paired with storage. Another 247 gigawatts of wind farms were in line, with 19 gigawatts, or about 8% of those, as hybrids.

The amount of proposed solar, storage and wind power waiting to hook up to the grid has grown dramatically in recent years, while coal, gas and nuclear have faded. Lawrence Berkeley National Laboratory

Of course, applying for a connection is only one step in developing a power plant. A developer also needs land and community agreements, a sales contract, financing and permits. Only about one in four new plants proposed between 2010 and 2016 made it to commercial operation. But the depth of interest in hybrid plants portends strong growth.

In markets like California, batteries are essentially obligatory for new solar developers. Since solar often accounts for the majority of power in the daytime market, building more adds little value. Currently 95% of all proposed large-scale solar capacity in the California queue comes with batteries.

Five Lessons on Hybrids and Questions for the Future

The opportunity for growth in renewable hybrids is clearly large, but it raises some questions that our group at Berkeley Lab has been investigating.

Here are some of our top findings:

• The investment pays off in many regions. We found that while adding batteries to a solar power plant increases the price, it also increases the value of the power. Putting generation and storage in the same location can capture benefits from tax credits, construction cost savings and operational flexibility. Looking at the revenue potential over recent years, and with the help of federal tax credits, the added value appears to justify the higher price.

• Co-location also means tradeoffs. Wind and solar perform best where the wind and solar resources are strongest, but batteries provide the most value where they can deliver the greatest grid benefits, like relieving congestion. That means there are trade-offs when determining the best location with the highest value. Federal tax credits that can be earned only when batteries are co-located with solar may be encouraging suboptimal decisions in some cases.

Hybrid power has become standard in Hawaii as solar power saturates the grid. Dennis Schroeder/NREL

• There is no one best combination. The value of a hybrid plant is determined in part by the configuration of the equipment. For example, the size of the battery relative to a solar generator can determine how late into the evening the plant can deliver power. But the value of nighttime power depends on local market conditions, which change throughout the year.

• Power market rules need to evolve. Hybrids can participate in the power market as a single unit or as separate entities, with the solar and storage bidding independently. Hybrids can also be either sellers or buyers of power, or both. That can get complicated. Market participation rules for hybrids are still evolving, leaving plant operators to experiment with how they sell their services.

• Small hybrids create new opportunities: Hybrid power plants can also be small, such as solar and batteries in a home or business. Such hybrids have become standard in Hawaii as solar power saturates the grid. In California, customers who are subject to power shutoffs to prevent wildfires are increasingly adding storage to their solar systems. These “behind-the-meter” hybrids raise questions about how they should be valued, and how they can contribute to grid operations.

 

Hybrids are just beginning, but a lot more are on the way. More research is needed on the technologies, market designs and regulations to ensure the grid and grid pricing evolve with them.

While questions remain, it’s clear that hybrids are redefining power plants. And they may remake the U.S. power system in the process.

Suggested Reading

The Good News and Bad News Surrounding US Uranium Self-Reliance

Has Uranium Demand Changed with Russia Ukraine War?

The Appeal of EVs with Bidirectional Charging

Clean vs Dirty Electrons on Power Grid

 

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Thursday, May 12, 2022

InPlay Oil (IPOOF)
Results surpass expectations once again

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.

2022-1Q results surpass expectations. Production levels continue to soar as the company executes a robust drilling program. Production was 8,221 boed up 66% and above our 8,000 boed estimate. Realized prices of $97.5 per barrel and $5.18 per thousand cubic feet (mcf) were up sharply from last year but slightly below that in our models. Resulting operating income of $34.1 million and adjusted funds from operations of $29.4 million were in line with expectations.

This is just the beginning for InPlay. The company was very active in the quarter, drilling six wells.  InPlay will continue to be active in the June quarter drilling five wells, three of which should come online in the second quarter. Management indicates a payback of three months for the wells at current prices. At such a rate of return, expanding drilling efforts is an easy decision. Rising costs, including steel and crew costs, have yet to significantly impact well drilling costs but bear watching….

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. 

InPlay Oil Corp. Announces First Quarter 2022 Financial and Operating Results Highlighted by Record Quarterly Production and Financial Results

News and Market Data on InPlay Oil Corp

CALGARY, Alberta, May 11, 2022 — InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its record setting financial and operating results for the three months ended March 31, 2022, our first full quarter incorporating the acquisition of Prairie Storm Resources Corp. (“Prairie Storm”). InPlay’s condensed unaudited interim financial statements and notes, as well as Management’s Discussion and Analysis (“MD&A”) for the three months ended March 31, 2022 will be available at “www.sedar.com” and our website at “www.inplayoil.com”. Our corporate presentation will soon be available on our website.

First Quarter 2022 Financial &
Operating Highlights

• Achieved record average quarterly production of 8,221 boe/d⁽¹⁾ (59% light crude oil and NGLs), an increase of 66% from first quarter production in 2021 of 4,965 boe/d
  ⁽¹⁾ (70% light crude oil and NGLs) and an increase of 23% compared to our previous quarterly record of 6,687 boe/d⁽¹⁾ (61% light crude oil and NGLs) in the fourth quarter of 2021. Average production per weighted average basic share increased 31% compared to the first quarter of 2021 (34% on a debt adjusted⁽⁴⁾ basis) and 3% compared to the fourth quarter of 2021 (9% on a debt adjusted basis).
• Generated record quarterly adjusted funds flow (“AFF”)⁽²⁾ of $29.4 million ($0.34 per weighted average basic share⁽³⁾), an increase of 381% compared to $6.1 million ($0.09 per weighted average basic share) in the first quarter of 2021 and an increase of 71% compared to $17.1 million ($0.23 per weighted average basic share) in the fourth quarter of 2021, our prior record quarter.
• Increased operating netbacks
  ⁽⁴⁾ by 73% to $46.06/boe from $26.66/boe in the first quarter of 2021 and 17% compared to $39.43/boe in the fourth quarter of 2021, our prior record quarter.
• Realized quarterly record operating income⁽⁴⁾ and operating income profit margin⁽⁴⁾ of $34.1 million and 65% respectively compared to $11.9 million and 60% in the first quarter of 2021; $24.3 million and 65% in the fourth quarter of 2021, our prior record quarter.
• Reduced operating expenses by 10% to $12.96/boe compared to $14.37/boe in the first quarter of 2021, despite rising costs of services in the industry.
• Generated free adjusted funds flow (“FAFF”)⁽⁴⁾ of $7.8 million, a quarterly record for the Company.
• Achieved a record quarterly annualized net debt⁽²⁾ to earnings before interest, taxes and depletion (“EBITDA”)⁽⁴⁾ ratio of 0.6, compared to 2.6 in the first quarter of 2021 and 1.1 in fourth quarter of 2021.
• Realized net income of $18.8 million ($0.22 per basic share; $0.21 per diluted share) compared to a net loss of $7.5 million ($0.11 per basic and diluted share) in the first quarter of 2021.

Notes:
1.	See “Reader Advisories – Production Breakdown by Product Type”
2.	Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
3.	Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
4.	Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release.

Financial and Operating Results:

(CDN) ($000’s)	Three months ended March 31
	2022		2021
Financial
Oil and natural gas sales	52,156		20,001
Adjusted funds flow(1)	29,379		6,105
Per share – basic (1)	0.34		0.09
Per share –diluted(1)	0.32		0.09
Per boe(1)	39.71		13.66
Comprehensive income (loss)	18,774		(7,536	)
Per share – basic	0.22		(0.11	)
Per share – diluted	0.21		(0.11	)
Capital expenditures – PP&E and E&E	21,562		12,209
Property acquisitions (dispositions)	(1	)	19
Corporate acquisitions	432		–
Net debt(1)	(73,392	)	(79,780	)
Shares outstanding	86,537,351		68,256,616
Basic weighted-average shares	86,449,636		68,256,616
Diluted weighted-average shares	90,964,311		68,256,616
Operational
Daily production volumes
Light and medium crude oil (bbls/d)	3,571		2,665
Natural gas liquids (bbls/d)	1,307		802
Conventional natural gas (Mcf/d)	20,054		8,994
Total (boe/d)	8,221		4,965
Realized prices(2)
Light and medium crude oil & NGLs ($/bbls)	97.50		55.75
Conventional natural gas ($/Mcf)	5.18		3.22
Total ($/boe)	70.50		44.76
Operating netbacks ($/boe)(3)
Oil and natural gas sales	70.50		44.76
Royalties	(10.27	)	(2.79	)
Transportation expense	(1.21	)	(0.94	)
Operating costs	(12.96	)	(14.37	)
Operating netback	46.06		26.66
Realized (loss) on derivative contracts	(0.81	)	(6.81	)
Operating netback (including realized derivative contracts)	45.25		19.85

 

(1)	Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
(2)	Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
(3)	Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release.

First Quarter 2022 Financial &
Operations Overview:

Production averaged 8,221 boe/d (59% light crude oil & NGLs)⁽¹⁾ in the first quarter of 2022 which includes the impact of a force majeure of a third party facility that affected March production by approximately 200 boe/d. Production increased by 66% compared to 4,965 boe/d (70% light crude oil & NGLs)
⁽¹⁾ in the first quarter of 2021 and 23% compared to 6,687 boe/d (61% light crude oil & NGLs)⁽¹⁾ in the fourth quarter of 2021. This resulted in a quarterly record $29.4 million of Adjusted Funds Flow (“AFF”) generated during the first quarter of 2022 and $7.8 million in Free Adjusted Funds Flow (“FAFF”) which reduced debt levels.

InPlay’s capital program for the first quarter of 2022 consisted of $21.6 million of capital expenditures. The Company drilled, completed and brought on production three (3.0 net) Extended Reach Horizontal (“ERH”) wells in Pembina, and two (1.7 net) Willesden Green wells on our newly acquired Prairie Storm assets, and participated in one (0.2 net) non-operated Willesden Green ERH well. The Company also completed the two (1.6 net) wells that were drilled in December on Prairie Storm Willesden Green assets and these wells were brought on production in the second half of January. A total of six (4.9 net) wells were drilled during the quarter, the most active quarter in the Company’s history. The first quarter capital program also included lease construction to expedite the second quarter drilling program and the construction of a small modular multi-well battery in Willesden Green to accommodate future drilling. Given the strong economics tied to the current pricing environment, InPlay also increased its well servicing expenditures in the quarter to optimize wells, activate wellbores that had been down and to reduce operating expenses on certain wells.

The average well results from the first quarter capital program are above our forecasted type curves with average payouts of wells (with over two months of production data) expected to be approximately three months in the current pricing environment. The initial production (“IP”) rates for the two (1.6 net) wells drilled in Willesden Green in December and brought on production in the second half of January, which are stabilizing ahead of forecast, were as follows:

	IP 30	IP 60	IP 90
	(% light crude oil and NGLs)	(% light crude oil and NGLs)	(% light crude oil and NGLs)
1.5 mile well	593 boe/d (80%)	433 boe/d (79%)	355 boe/d (78%)
1.0 mile well	203 boe/d (83%)	169 boe/d (77%)	161 boe/d (72%)

The combined IP rates for the three (3.0 net) ERH wells drilled in Pembina and brought on production ahead of schedule in late February continue to clean up as follows:

IP 30	IP 60	Current(1)
(% light crude oil and NGLs)	(% light crude oil and NGLs)	(% light crude oil and NGLs)
1,063 boe/d (73%)	1,122 boe/d (67%)	1,292 boe/d (55%)

The IP rates for the two (1.7 net) wells drilled in Willesden Green and brought on production in mid-March continue to clean up as follows:

	IP 30	Current(1)
	(% light crude oil and NGLs)	(% light crude oil and NGLs)
1.5 mile well	296 boe/d (88%)	415 boe/d (82%)
1.0 mile well*	126 boe/d (85%)	197 boe/d (80%)

* The 1.0 mile well had initially experienced wax and pumping issues.

(1)   Based on field
estimates.

Efficient field operations and increased production levels resulted in the Company achieving a 10% reduction to operating expenses to $12.96/boe compared to $14.37/boe in the first quarter of 2021. This was a significant achievement given the cold winter, inflationary pressures in the industry and ongoing supply chain disruptions. The resulting operating income⁽²⁾ and operating income profit margin⁽²⁾ for the first quarter of 2022 were quarterly records for the Company at $34.1 million and 65% respectively. Net income of $18.8 million ($0.22 per basic share; $0.21 per diluted share) was realized in the first quarter compared to a net loss of $7.5 million ($0.11 per basic and diluted share) in the first quarter of 2021.

Notes:
1.	See “Reader Advisories – Production Breakdown by Product Type”
2.	Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures”.

Operations Update

InPlay’s capital program for the second quarter of 2022 is ahead of schedule which will benefit the Company as production is anticipated to be brought on earlier than forecasted into a very strong price environment. Drilling operations for three (3.0 net) wells in Pembina have just finished and these wells are expected to come on production by the end of May. An additional two (1.9 net) two-mile wells are planned to be drilled in Willesden Green during the second quarter and are expected to come on production in mid-July. The Company plans to utilize the same drilling rig for the remainder of our 2022 capital program allowing for continued drilling efficiencies and cost savings associated with a consistent and experienced crew, materially reducing our inflation risk in the current environment.

Environmental, Social and Governance
(“ESG”) Update

InPlay is committed to environmental stewardship while safely and efficiently developing our assets that contribute to the local, provincial and Canadian economies. The Company will further outline our ESG initiatives with the release of our inaugural sustainability report this summer. We place a high importance on managing emissions, water conservation, spill mitigation and abandonment and reclamation activities. Our goal is to ensure all stakeholders benefit from our business operations both in the short-term and long into the future.

The Company continues to reduce our inactive well liability. During the first quarter of 2022, InPlay spent $1.4 million on the abandonment of 14 wellbores and the reclamation of 4 well sites. To further evidence our commitment to ESG initiatives, the Company has added approximately $1 million to our budget for emission related projects during 2022. Specifically, the Company will be accelerating projects to convert high-bleed pneumatic devices to low-bleed pneumatics and install vapor recovery units at certain facilities. These projects will have the benefit of materially reducing our emissions while also providing the Company with economic benefit through more efficient operations and gas conservation.

Outlook⁽⁴⁾

InPlay’s successful first quarter capital program has led to a strong start to the year and establishes a solid foundation to generate significant FAFF throughout the remainder of the year while providing strong returns to shareholders. InPlay’s production in April averaged approximately 9,000 boe/d⁽¹⁾ based on field estimates and is currently tracking at the mid-point of our average annual production guidance of 8,900 to 9,400 boe/d⁽¹⁾. The Company’s drilling program is ahead of schedule, and with approximately 70% of our planned 2022 wells remaining to be drilled and expected to be on production by the middle of the fourth quarter, InPlay is well positioned to deliver strong production and FAFF growth to its shareholders.

Strong commodity pricing, increased fuel prices, supply chain disruptions and increased activity levels have heightened inflationary pressures across the industry. One of the biggest issues has been the supply of steel casing and tubular products required to drill wells. InPlay has been able to mitigate these supply issues through strong industry relationships and proactive decision making. The Company proactively acquired an inventory of these products at favorable pricing in the summer and fall of 2021 to accommodate our H1 2022 drilling program. The Company has acquired all pipe products to accommodate our drilling program for the second half of the year, albeit at higher pricing levels. InPlay will also incur additional costs associated with drilling two (1.9 net) two mile wells (versus 1.5 mile wells in our original budget), and approximately $1 million for various emission reduction initiatives. In aggregate, these additional activities combined with inflationary pressures has our 2022 capital budget increased to $64 million (previously $58 million). The Company will continue to monitor industry wide cost pressures and efforts will be taken to minimize their impact on our operations.

With the further strengthening of commodity prices and our updated capital budget, InPlay now forecasts 2022 AFF⁽²⁾ of $147 to $156 million (versus prior guidance of $141 to $150 million) with FAFF⁽³⁾ at $83 to $92 million (in line with prior guidance), which would result in InPlay being in a positive working capital position, in excess of debt, by year end. The Company’s leverage metrics are forecasted to remain at historically low levels, with net debt to quarterly annualized earnings before interest, taxes and depletion (“EBITDA”)
⁽³⁾ forecasted to be 0.3x for the second quarter of 2022.

InPlay is executing its strategy to provide disciplined, top-tier light oil weighted production and FAFF per share growth, reducing debt and leverage ratios, while seeking to capitalize on strategic and accretive acquisition opportunities with our pristine balance sheet. Execution of InPlay’s disciplined strategy is significantly ahead of schedule on debt and leverage reduction which places the Company in a solid position to sustainably generate long-term per share growth and deliver top-tier returns to shareholders in a prudent and fiscally responsible manner. Management would like to thank our employees, board members, lenders and shareholders for their support and we look forward to continuing our journey of deleveraging and maximizing shareholder returns.

 

Notes:
1.	See “Production Breakdown by Product Type” at the end of this press release.
2.	Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
3.	Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release.
4.	See “Reader Advisories – Forward Looking Information and Statements” for key budget and underlying assumptions related to our 2022 capital program and associated guidance.

 

Reader Advisories

Non-GAAP and Other Financial Measures

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

Non-GAAP
Financial Measures and Ratios

Included in this document are references to the terms “free adjusted funds flow”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA” and “Debt adjusted production per share”. Management believes these measures are helpful supplementary measures of financial and operating performance and provide users with similar, but potentially not comparable, information that is commonly used by other oil and natural gas companies. These terms do not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than “profit (loss) before taxes”, “profit (loss) and comprehensive income (loss)”, “adjusted funds flow”, “capital expenditures”, “corporate acquisitions, net of cash acquired”, “net debt”, “weighted average number of common shares (basic)” or assets and liabilities as determined in accordance with GAAP as a measure of the Company’s performance and financial position.

Free Adjusted Funds Flow

Management considers free adjusted funds flow and free adjusted funds flow per share important measures to identify the Company’s ability to improve its financial condition through debt repayment, which has become more important recently with the introduction of second lien lenders, on an absolute and weighted average per share basis. Free adjusted funds flow should not be considered as an alternative to or more meaningful than adjusted funds flow as determined in accordance with GAAP as an indicator of the Company’s performance. Free adjusted funds flow is calculated by the Company as adjusted funds flow less exploration and development capital expenditures and property dispositions (acquisitions) and is a measure of the cashflow remaining after capital expenditures before corporate acquisitions that can be used for additional capital activity, corporate acquisitions, repayment of debt or decommissioning expenditures. Free adjusted funds flow per share is calculated by the Company as free adjusted funds flow divided by weighted average outstanding shares. Refer below for a calculation of historical Free adjusted fund flow and to the “Forward Looking Information and Statements” section for a calculation of forecast Free adjusted funds flow.

(thousands of dollars)	Three Months Ended March 31
	2022		2021
Adjusted funds flow	29,379		6,105
Exploration and dev. capital expenditures	(21,562	)	(12,209	)
Property dispositions (acquisitions)	1		(19	)
Free adjusted funds flow	7,818		(6,123	)

Operating Income/Operating Netback per
boe/Operating Income Profit Margin

InPlay uses “operating income”, “operating netback per boe” and “operating income profit margin” as key performance indicators. Operating income is calculated by the Company as oil and natural gas sales less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative, share-based compensation, financing and other non-cash items. Management considers operating income an important measure to evaluate its operational performance as it demonstrates its field level profitability. Operating income should not be considered as an alternative to or more meaningful than net income as determined in accordance with GAAP as an indicator of the Company’s performance. Operating netback per boe is calculated by the Company as operating income divided by average production for the respective period. Management considers operating netback per boe an important measure to evaluate its operational performance as it demonstrates its field level profitability per unit of production. Operating income profit margin is calculated by the Company as operating income as a percentage of oil and natural gas sales. Management considers operating income profit margin an important measure to evaluate its operational performance as it demonstrates how efficiently the Company generates field level profits from its sales revenue. Refer below for a calculation of operating income, operating netback per boe and operating income profit margin.

(thousands of dollars)	Three Months Ended March 31
	2022		2021
Revenue	52,156		20,001
Royalties	(7,599	)	(1,245	)
Operating expenses	(9,588	)	(6,422	)
Transportation expenses	(893	)	(418	)
Operating income (2)	34,076		11,916
Sales volume (Mboe)	739.9		446.9
Per boe
Revenue	70.50		44.76
Royalties	(10.27	)	(2.79	)
Operating expenses	(12.96	)	(14.37	)
Transportation expenses	(1.21	)	(0.94	)
Operating netback per boe	46.06		26.66
Operating income profit margin	65	%	60	%

Net Debt to EBITDA

Management considers Net Debt to EBITDA an important measure as it is a key metric to identify the Company’s ability to fund financing expenses, net debt reductions and other obligations. EBITDA is calculated by the Company as adjusted funds flow before interest expense. When this measure is presented quarterly, EBITDA is annualized by multiplying by four. This measure is consistent with the EBITDA formula prescribed under the Company’s Senior Credit Facility. Net Debt to EBITDA is calculated as Net Debt divided by EBITDA. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast Net Debt to EBITDA.

Production per Debt Adjusted Share

InPlay uses “Production per debt adjusted share” as a key performance indicator. Debt adjusted shares should not be considered as an alternative to or more meaningful than common shares as determined in accordance with GAAP as an indicator of the Company’s performance. Debt adjusted shares is a non-GAAP measure used in the calculation of Production per debt adjusted share and is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. Debt adjusted shares should not be considered as an alternative to or more meaningful than weighted average number of common shares (basic) as determined in accordance with GAAP as an indicator of the Company’s performance. Management considers Debt adjusted share is a key performance indicator as it adjusts for the effects of capital structure in relation to the Company’s peers. Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Management considers Production per debt adjusted share is a key performance indicator as it adjusts for the effects of changes in annual production in relation to the Company’s capital structure. Refer below for a calculation of Production per debt adjusted share.

		Three months ended March 31
		2022	2021
Production	Boe/d	8,221	4,965
Net Debt	$ millions	$73.4	$79.8
Weighted average outstanding shares	# millions	86.4	68.3
Assumed Share price(2)	$	3.20	N/A
Production per debt adjusted share growth(2)		34%	N/A

 

		Three months ended
		March 31, 2022	Dec. 31, 2021
Production	Boe/d	8,221	6,687
Net Debt	$ millions	$73.4	$80.2
Weighted average outstanding shares	# millions	86.4	74.3
Assumed Share price(2)	$	3.20	N/A
Production per debt adjusted share growth(2)		9%	N/A

 

	(1)	Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Debt adjusted shares is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. Share price at December 31, 2022 is assumed to be consistent with the share price at December 31, 2021.
	(2)	Weighted average share price throughout the first quarter of 2022.

Capital
Management Measures

Adjusted Funds Flow

Management considers adjusted funds flow to be an important measure of InPlay’s ability to generate the funds necessary to finance capital expenditures. Adjusted funds flow is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2021. All references to adjusted funds flow throughout this document are calculated as funds flow adjusting for decommissioning expenditures and transaction and integration costs. This item is adjusted from funds flow as decommissioning expenditures are incurred on a discretionary and irregular basis and are primarily incurred on previous operating assets and transaction costs are non-recurring costs for the purposes of an acquisition, making the exclusion of these items relevant in Management’s view to the reader in the evaluation of InPlay’s operating performance. The Company also presents adjusted funds flow per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of profit (loss) per common share.

Net Debt

Net debt is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2021. The Company closely monitors its capital structure with a goal of maintaining a strong balance sheet to fund the future growth of the Company. The Company monitors net debt as part of its capital structure. The Company uses net debt (bank debt plus accounts payable and accrued liabilities less accounts receivables and accrued receivables, prepaid expenses and deposits and inventory) as an alternative measure of outstanding debt. Management considers net debt an important measure to assist in assessing the liquidity of the Company.

Supplementary
Measures

“Average realized crude oil
price” is comprised of crude oil commodity sales from production, as determined in accordance with IFRS, divided by the Company’s crude oil production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

“Average realized NGL price” is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company’s NGL production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

“Average realized natural gas
price” is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company’s natural gas production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

“Average realized commodity
price” is comprised of commodity sales from production, as determined in accordance with IFRS, divided by the Company’s production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

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

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

“Adjusted funds flow per
boe” is comprised of adjusted funds flow divided by total production.

Forward-Looking Information and
Statements

This news release contains certain forward–looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following; the Company’s planned 2022 capital program including wells to be drilled and completed and the timing of the same; 2022 guidance based on the planned capital program including forecasts of 2022 annual average production levels, debt adjusted production levels, adjusted funds flow, free adjusted funds flow, Net Debt/EBITDA ratio, operating income profit margin, and Management’s belief that the Company can grow some or all of these attributes and specified measures; light crude oil and NGLs weighting estimates; expectations regarding future commodity prices; future oil and natural gas prices; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition, development and infrastructure activities and related capital expenditures, including our planned 2022 capital program; the amount and timing of capital projects; forecasted spending on decommissioning and emission reduction projects in 2022; the expectation that InPlay will be in a positive working capital position by 2022 year end; the expectation that the Company will experience inflationary cost pressures in the second half of 2022; the Company’s planned 2022 abandonment and reclamation program, including the abandonments and reclamations to be completed, forecasted spending on these activities, reduction to our ARO and forecasted LMR rating; the planned release of InPlay’s inaugural sustainability report in the summer of 2022; and methods of funding our capital program.

Forward-looking statements or information are based on a number of material factors, expectations or assumptions of InPlay which have been used to develop such statements and information but which may prove to be incorrect. Although InPlay believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because InPlay can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which InPlay operates; the timely receipt of any required regulatory approvals; the ability of InPlay to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which InPlay has an interest in to operate the field in a safe, efficient and effective manner; the ability of InPlay to obtain debt and/or equity financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and the ability of InPlay to secure adequate product transportation; future commodity prices; that various conditions to a shareholder return strategy can be satisfied; expectations regarding the potential impact of COVID-19 and the Russia/Ukraine conflict; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which InPlay operates; and the ability of InPlay to successfully market its oil and natural gas products.   

The forward-looking information and statements included herein are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: the continuing impact of the COVID-19 pandemic and the Russia/Ukraine conflict; changes in our planned 2022 capital program; changes in commodity prices and other assumptions outlined herein; the potential for variation in the quality of the reservoirs in which we operate; changes in the demand for or supply of our products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans or strategies of InPlay or by third party operators of our properties; changes in our credit structure, increased debt levels or debt service requirements; inaccurate estimation of our light crude oil and natural gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in InPlay’s continuous disclosure documents filed on SEDAR including our Annual Information Form and our MD&A.

The internal projections, expectations or beliefs underlying the Company’s 2022 capital budget, associated guidance and corporate outlook for 2022 and beyond are subject to change in light of ongoing results, prevailing economic circumstances, commodity prices and industry conditions and regulations. InPlay’s outlook for 2022 and beyond provides shareholders with relevant information on management’s expectations for results of operations, excluding any potential acquisitions, dispositions or strategic transactions that may be completed in 2022 and beyond including, without limitation, the potential impact of any shareholder return strategy that may be implemented in the future. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted and InPlay’s 2022 guidance and outlook may not be appropriate for other purposes.

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

The forward-looking information and statements contained in this news release speak only as of the date hereof and InPlay does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

The key budget and underlying material assumptions used by the Company in the development of its 2022 guidance including forecasted production, operating income, capital expenditures, adjusted funds flow, free adjusted funds flow, FAFF yield, Net Debt, Net Debt/EBITDA, EV/DAAFF, production per debt adjusted share growth are as follows:

		Actuals FY 2021	Previous Guidance FY 2022(1)	Updated Guidance FY 2022
WTI	US$/bbl	$67.91	$90.00	$95.40
NGL Price	$/boe	$37.79	$52.35	$47.80
AECO	$/GJ	$3.44	$4.30	$6.00
Foreign Exchange Rate	CDN$/US$	0.80	0.80	0.79
MSW Differential	US$/bbl	$3.88	$3.00	$2.70
Production	Boe/d	5,768	8,900 – 9,400	8,900 – 9,400
Royalties	$/boe	5.51	9.80 – 10.60	11.50 – 13.00
Operating Expenses	$/boe	12.83	10.00 – 13.00	11.00 – 14.00
Transportation	$/boe	1.11	0.85 – 1.10	1.05 – 1.30
Interest	$/boe	2.67	0.75 – 1.15	0.85 – 1.25
General and Administrative	$/boe	2.83	2.00 – 2.60	2.40 – 2.95
Hedging loss	$/boe	6.20	0.35 – 0.65	1.85 – 2.15
Decommissioning Expenditures	$ millions	$1.4	$2.0 – $2.5	$2.0 – $2.5
Adjusted Funds Flow	$ millions	$47.0	$141 – $150	$147 – $156
Weighted average outstanding shares	# millions	69.8	86.2	86.5
Adjusted Funds Flow per share	$/share	0.67	1.64 – 1.75	1.70 – 1.80

 

		Actuals FY 2021	Previous Guidance FY 2022(1)	Updated Guidance FY 2022
Adjusted Funds Flow	$ millions	$47.0	$141 – $150	$147 – $156
Capital Expenditures	$ millions	$33.3	$58.0	$64.0
Free Adjusted Funds Flow	$ millions	$13.6	$83 – $92	$83 – $92
Shares outstanding, end of year	# millions	86.2	86.2	86.5
Assumed Share Price	$	2.18(4)	3.06	3.66
Market capitalization	$ millions	$188	$264	$317
FAFF Yield	%	7%	31% – 35%	26% – 29%

 

		Actuals FY 2021	Previous Guidance FY 2022(1)	Updated Guidance FY 2022
Adjusted Funds Flow	$ millions	$47.0	$141 – $150	$147 – $156
Interest	$/boe	2.67	0.75 – 1.15	0.85 – 1.25
EBITDA	$ millions	$52.6	$144 – $153	$150 – $159
Net Debt/(Positive working capital, in excess of debt)	$ millions	$80.2	($1) – ($10)	($1) – ($10)
Net Debt/EBITDA		1.5	0.0 – 0.1	0.0 – 0.1

 

		Actuals Q2 2021	Previous Guidance FY 2022(1)	Updated Guidance Q2 2022
Adjusted Funds Flow	$ millions	$8.2		$37 – $40
Interest	$/boe	3.27		1.00 – 1.25
EBITDA	$ millions	$9.8		$38 – $41
Annualized EBITDA	$ millions	$39.2		$154 – $162
Net Debt/(Positive working capital, in excess of debt)	$ millions	$76.1		$50 – $53
Net Debt/EBITDA		1.9	N/A(3)	0.3

 

		Actuals FY 2021	Previous Guidance FY 2022(1)	Updated Guidance FY 2022
Production	Boe/d	5,768	8,900 – 9,400	8,900 – 9,400
Opening Net Debt	$ millions	$73.7	$80.2	$80.2
Ending Net Debt/(Pos. working capital, in excess of debt)	$ millions	$80.2	($1) – ($10)	($1) – ($10)
Weighted average outstanding shares	# millions	69.8	86.2	86.5
Assumed Share price	$	1.16(5)	3.06	3.66
Production per debt adjusted share growth(2)		31%	85% – 95%	70% – 80%

 

		Actuals FY 2021	Previous Guidance FY 2022(1)	Updated Guidance FY 2022
Share outstanding, end of year	# millions	86.2	86.2	86.5
Assumed Share price	$	2.18(3)	3.06	3.66
Market capitalization	$ millions	$188	$264	$317
Net Debt/(Positive working capital, in excess of debt)	$ millions	$80.2	($1) – ($10)	($1) – ($10)
Enterprise value	$millions	$268.2	$253 – $261	$307 – $316
Adjusted Funds Flow	$ millions	$44.1	$141 – $150	$147 – $156
Interest	$/boe	2.67	0.75 – 1.15	0.85 – 1.25
Debt Adjusted AFF	$ millions	$49.7	$144 – $153	$151 – $160
EV/DAAFF		5.4	1.6 – 1.8	1.9 – 2.1

 

	(1)	As previously released March 16, 2022.
	(2)	Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Debt adjusted shares is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. Share price at December 31, 2022 is assumed to be consistent with the current share price.
	(3)	Guidance had not been previously released for this measure.
	(4)	Ending share price at December 31, 2021.
	(5)	Weighted average share price throughout 2021.
	•	See “Production Breakdown by Product Type” below
	•	Quality and pipeline transmission adjustments may impact realized oil prices in addition to the MSW Differential provided above
	•	Changes in working capital are not assumed to have a material impact between Dec 31, 2021 and Dec 31, 2022.

Test Results and Initial Production
(“IP”) Rates
Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long term performance or of ultimate recovery. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed.

Production Breakdown by Product Type
Disclosure of production on a per boe basis in this press release consists of the constituent product types as defined in NI 51-101 and their respective quantities disclosed in the table below:

	Light and Medium Crude oil (bbls/d)		NGLS (boe/d)		Conventional Natural gas (Mcf/d)		Total (boe/d)
Q1 2021 Average Production	2,665		802		8,994		4,965
Q4 2021 Average Production	3,156		932		15,589		6,687
2021 Average Production	2,981		782		12,030		5,768
Q1 2022 Average Production	3,571		1,307		20,054		8,221
2022 Annual Guidance	4,320		1,311		21,114		9,150(1)
April 2022 Average Production	3,971		1,447		21,492		9,000

 

Note:
	1.	This reflects the mid-point of the Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.
	2.	With respect to forward-looking production guidance, product type breakdown is based upon management’s expectations based on reasonable assumptions but are subject to variability based on actual well results.

References to crude oil, NGLs or natural gas production in this press release refer to the light and medium crude oil, natural gas liquids and conventional natural gas product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“Nl 51-101”).

BOE Equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.  

Oil and Gas Metrics
This presentation may contain metrics commonly used in the oil and natural gas industry, such as “payout”. This term does not have standardized meaning or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare InPlay’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation, should not be unduly relied upon.

“Payout” refers to the time required to pay back the capital expenditures (on a before tax basis) of a project.