The Case for More US Produced Uranium

Posted on March 22, 2022 by Admin




  Image: Fronteras desk (Flickr)

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

Is the Russia/Ukraine war providing cause to become more self-reliant producing reactor-grade uranium? Uranium can be mined in many parts of the world, but the processing that allows the reactive mineral to be used as fuel is done in just a few spots on the globe. Currently, a full 20% of electricity in the US is generated from nuclear fuel. Russia has a hand in the production of a lot of it.

Background

Enriched uranium is mined, milled, converted into a gas, then enriched to increase the percentage of the isotope to 3%-5% before rods for fuel can be created.

Each of the steps takes place at specialized facilities. Up until recently, with the reliance on nuclear power diminishing and decades of the power source largely being written out of the power production future, there was no incentive for companies along the U308 supply chain to grow their operations. And mining slowed as raw uranium prices were seen as too low to compete with cheaper imports.

Russian uranium enrichment accounts for around 35% of the global market. In fact, the only commercial plants for uranium conversion into gas are in Russia, France, and Canada. There was a plant operating in Illinois that was mothballed but is scheduled to rejoin this part of the uranium supply chain in 2023.

Price Increase

Russia enriches more uranium for use in nuclear plants than any other country. Russia’s invasion of neighboring Ukraine has shaken the global market, as sanctions, and potential sanctions have increased the scarcity of many resources, including uranium. The risk to US energy generation of relying on all or part of the production to be outside North America has suddenly become apparent. Talk of ramping up domestic production has increased, but it can’t occur overnight.

Using $URA as price proxy, Price increase since January 27, 2022

Uranium prices have risen more than 30% since the start of the war, and 40% since the beginning of the threat. Each part of the refining process, from mining the raw material to the enriching processes have experienced price increases.

While further sanctions cause utilities to lock in future needs, a trade agreement has been in place that limits US dependence on Russian uranium to no more than around 20% of domestic reactors demand. That is certainly better than a much higher percentage as the US isn’t fully reliant. But no other country could quickly fill Russia’s role in the supply chain for US usage. Another positive is US plants generally refuel every 18 to 24 months and plan for this at least two to three years in advance. So there is little concern in the short run for existing plants running out. There is time to prepare.

Opportunity

Does this create an opportunity in the stock market? Many of the forces that are weighing on some sectors of the stock market are having a positive impact on North American uranium mining stocks.

There are a number of companies that are involved in uranium production that were becoming interesting before the recent supply chain problems related to the Russian invasion. The segment was getting much attention as a result of the plans of companies to build modern, smaller nuclear reactors. The sudden change in the market landscape has now caused some of these companies’ stocks to experience price increases well in excess of that of physical uranium or uranium futures contracts.

One such company is Energy Fuels (UUUU). Energy Fuels is the largest uranium producer in the US and holds more production capacity and uranium resources than any other US producer. The current market cap is $1.6 billion. The movement on UUUU for the same period that Uranium ran up near 40%, has pushed the stock price of this producer up near 80% since late January.

On March 17, Noble Capital Markets Senior Energy Analyst Michael Heim released a report on $UUUU titled Ramp Up is Coming Slowly but
Higher Prices Could Spur Activity. The report profiles the analyst’s view on the company and prospects in light of the changing market.

Take-Away

Uranium investments, whether a trust, a producer, or an ETF that tracks uranium prices have all been seeing an upsurge in interest. Part of this has been the move toward non-carbon-based energy and new generation modular plants being built.

The current understanding of how vulnerable the US is as a result of its offshoring much of the acquisition and processes to produce nuclear fuel, is likely to reshuffle where US plants fulfill most of their need in years to come. And those needs are expected to be increasing.

Channelchek is a great resource to analyze companies involved in this mining and energy segment. No cost sign-up provides full access to the website and research, including videos specific to uranium producers.

Suggested Reading

Has Uranium Demand Changed with Russia Ukraine War?

Is it Too Late to Benefit from Higher Oil?

Uranium and Natural Gas Investments Turn Green in 2023

Investor Information on Three Segments of the Uranium Energy Sector

Sources

https://www.uxc.com/p/products/spl_cesa.aspx

https://www.wsj.com/articles/u-s-rethinks-uranium-supply-for-nuclear-plants-after-russias-invasion-of-ukraine-11647941401

https://www.eia.gov/energyexplained/nuclear/where-our-uranium-comes-from.php

https://tradingeconomics.com/commodity/uranium

Stay up to date. Follow us:

Delta Air Lines Signs 75 Million Gallon Per Year Agreement with Gevo

Posted on March 22, 2022 by Admin

Delta Air Lines Signs 75 Million Gallon Per Year Agreement with Gevo

Research, News, and Market Data on Gevo

ENGLEWOOD, Colo., March 22, 2022 (GLOBE NEWSWIRE) — Gevo, Inc. (NASDAQ: GEVO) has signed a “take-or-pay” agreement with Delta Air Lines, Inc. (NYSE: DAL) to supply 75 million gallons of sustainable aviation fuel (SAF) per year for seven years (the “Agreement”). Based on current assumptions, including those around future pricing of commodities and the future values of certain environmental benefits, Gevo estimates that the Agreement should generate approximately $2.8 billion of revenue, inclusive of the value from environmental benefits, for Gevo over the seven-year term of the Agreement.

The Agreement replaces the existing agreement signed with Delta in 2019 to purchase 10 million gallons per year and bolsters Delta’s commitment to incorporating SAF into its operations.

“On behalf of the entire team at Gevo, I want to congratulate our partners at Delta for their leadership in continuously pushing the aviation industry towards net-zero emissions. Delta makes for a great customer, recognizing that big change is needed. I also appreciate their faith in what we are doing at Gevo. Net-zero jet fuels matter. We expect production from our first Net-Zero plant to begin in 2025. To meet the demand that we now have under contract, we need to develop and build more than one Net-Zero plant. This is a happy problem to have,” said Patrick R. Gruber, Ph.D., Gevo’s Chief Executive Officer.

“Net-Zero Fuels are made by using low-carbon feedstocks produced with climate-smart agricultural practices and by eliminating fossil-based energy from the business system as much as possible. In addition, our customers depend on us to count carbon at every step of the process,” said Paul D. Bloom, Ph.D., Gevo’s Chief Carbon Officer, and Chief Innovation Officer. Dr. Bloom continued, “By accurately accounting for carbon emissions using Argonne National Laboratories GREET model along with our Verity Tracking platform we will provide confidence to our customers like Delta that scientifically robust and transparent methods are used to meet and measure their sustainability goals. We want to create a win-win value proposition for every participant in the SAF supply chain by tracking all carbon intensity benefits in our SAF.”

“SAF is a critically important lever we have available today to help our industry reduce the lifecycle carbon emissions from aviation fuel,” said Kelly Nodzak, Delta’s Director of Global Jet Fuel Procurement. “That’s why we are working to develop the market and a broader understanding of the effectiveness of SAF, which can reduce lifecycle emissions up to 80 percent when used in pure form compared to fossil jet fuels.”

“With the right policies and incentives in place, we can unlock a future where sustainable aviation fuel is a viable climate solution that benefits air travel and beyond,” said Amelia DeLuca, Delta’s Vice President of Sustainability. “SAF production creates good-paying jobs in manufacturing, improves the environmental quality for all, and fosters rural economic opportunity for feedstocks and pathways. It will help us protect the planet we share and the places we call home.”

Gevo has remained focused on sustainability at every stage of production. Gevo has developed two alcohol-to-jet pathways that can utilize various low-carbon feedstocks grown using sustainable agriculture. These feedstocks can then be converted, in some cases, to high-value nutritional products and energy-dense liquid hydrocarbons, including SAF. Gevo’s production processes will incorporate renewable energy, including wind turbines, biogas, and combined heat and power systems (CHP) to increase efficiency and reduce carbon intensity to net-zero levels, which the customer can then pass on through the fuel.

The Agreement is subject to certain conditions precedent, including Gevo developing, financing and constructing one or more production facilities to produce the SAF contemplated by the Agreement. A copy of the Agreement between Delta and Gevo has been filed with the U.S. Securities and Exchange Commission on Form 8-K.

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 the 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’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.

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

About Delta Air Lines

Delta’s commitment to sustainability is about joining arms to create a better world. The airline’s ambitious commitment to carbon neutrality from March 2020 onward is coming to fruition with swift impact through immediate actions, coupled with long-term investments to combat climate change. These investments will drive innovation, advance clean air travel technologies, accelerate the reduction of carbon emissions and waste, and establish a path to a more sustainable future. As a company driven by purpose, we hold ourselves to a high standard of producing sustainable, responsible financial results while investing in healthy communities, maintaining a diverse and inclusive workforce, and protecting natural environments. These values drive our overall approach to Environmental, Social, and Governance (ESG) sustainability and responsibility.

Learn more at the Delta Air Lines website: www.delta.com/

Forward-Looking Statements

Certain statements in this press release may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to a variety of matters, without limitation, including the Agreement, Delta’s purchase of SAF from Gevo, Gevo’s ability to produce SAF, Gevo’s estimate of the revenue that might be generated from the Agreement, Gevo’s ability to produce SAF and other fuels with a net-zero carbon intensity, Gevo’s technology, Gevo’s development, financing and construction of production facilities to produce SAF, the attributes of Gevo’s products, and other statements that are not purely statements of historical fact. These forward-looking statements are made on the basis of the current beliefs, expectations, and assumptions of the management of Gevo and are subject to significant risks and uncertainty. Investors are cautioned not to place undue reliance on any such forward-looking statements. All such forward-looking statements speak only as of the date they are made, and Gevo undertakes no obligation to update or revise these statements, whether as a result of new information, future events or otherwise. Although Gevo believes that the expectations reflected in these forward-looking statements are reasonable, these statements involve many risks and uncertainties that may cause actual results to differ materially from what may be expressed or implied in these forward-looking statements. For a further discussion of risks and uncertainties that could cause actual results to differ from those expressed in these forward-looking statements, as well as risks relating to the business of Gevo in general, see the risk disclosures in the Annual Report on Form 10-K of Gevo for the year ended December 31, 2021, and in subsequent reports on Forms 10-Q and 8-K and other filings made with the U.S. Securities and Exchange Commission by Gevo.

Gevo Investor and Media Contact

Heather L. Manuel

+1 720-418-0085

IR@gevo.com

Release – Alvopetro Announces 33 Increase In Quarterly Dividend To US$0.08 Per Share Year-End 2021 Financial Results

Posted on March 18, 2022 by Admin

Alvopetro Announces 33% Increase In Quarterly Dividend To US$0.08 Per Share, Year-End 2021 Financial Results, Filing Of Annual Information Form And An Operational Update

Research, News, and Market Data on Alvopetro Energy

CALGARY, AB, March 17, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV:ALV) (OTCQX: ALVOF) announces a US$0.08 per common share dividend, our year-end 2021 financial results, filing of our annual information form and an operational update.

All references herein to $ refer to United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.

President and CEO, Corey Ruttan commented:

“With ongoing strong performance from our Caburé project, along with the recent increase in our realized natural gas pricing to US$11.28/Mcf, we are pleased to announce a 33% increase in our quarterly dividend. We continue to target a balanced and disciplined stakeholder return and organic growth model and on March 2, 2022, we commenced our 2022 drilling campaign targeting the first of two, high-impact, conventional natural gas exploration prospects.”

Dividend

Alvopetro announces that our Board of Directors has declared a quarterly dividend of $0.08 per common share, payable in cash on April 14, 2022, to shareholders of record at the close of business on March 31, 2022. This dividend is designated as an “eligible dividend” for Canadian income tax purposes. Alvopetro’s cash flows are linked to US dollars and as such, dividends are being paid in US dollars.

Dividend payments to non-residents of Canada will be subject to withholding taxes at the Canadian statutory rate of 25%. Shareholders may be entitled to a reduced withholding tax rate under a tax treaty between their country of residence and Canada. For further information, see Alvopetro’s website at https://alvopetro.com/Dividends-Non-resident-Shareholders.

Operational Update

Our average daily sales have continued at consistent rates following our fourth quarter 2021 average of 2,432 boepd, averaging 2,509 boepd in January 2022 and 2,479 boepd in February 2022. Effective February 1, 2022, our natural gas price increased 48% to BRL1.94/m³ ($11.28/Mcf based on our average heat content and the average February 2022 BRL/USD foreign exchange rate of 5.1966). Our new contracted price is effective for all natural gas sales from February 1 to July 31, 2022.

On March 2, 2022, we spud our 182-C1 well on Block 182, the first of two conventional natural gas exploration wells planned for 2022. We anticipate the well will take approximately 42 days to drill and thereafter the rig will move to the 183-B1 well on the adjacent Block 183. Following these two wells, we plan to drill our first fit-for-purpose Murucututu development well.

We have now completed construction of our Murucututu pipeline and are currently installing field production facilities. We expect our 183(1) well to be tied-in and on production in the second quarter.

December 31, 2021 Reserves and Net Asset Value

On March 8, 2022, Alvopetro announced its December 31, 2021 reserves based upon the independent reserve assessment and evaluation prepared by GLJ Ltd. (“GLJ”) dated March 7, 2022 with an effective date of December 31, 2021 (the “GLJ Reserves and Resources Report”). The GLJ Report assigned total proved plus probable (“2P”) reserves of 8.7 MMboe and a before tax value discounted at 10% of $297.0 million. Following this evaluation and based on updated year-end 2021 financial results, the Company’s net asset value based on its 2P reserves is $299.6 million, reflecting CAD$11.18 per common share. The GLJ Reserves and Resources Report also included an assessment of the Murucututu natural gas resource which has not been reflected in the table below, with risked best estimate contingent resource of 3.5 MMboe and risked best estimate prospective resource of 12.1 MMboe (before tax net present value, discounted at 10% of $60.7 million and $208.7 million, respectively).

Base Net Asset Value (in $000s, other than per share amounts)	Total Proved	Total Proved plus Probable	Total Proved plus Probable plus Possible
Before Tax Net Present Value^(a), discounted at 10%	173,759	297,000	416,723
Working capital, net of debt – as of December 31, 2021^(b)	2,552	2,552	2,552
Total Base Net Asset Value^(b)(c)(d)	176,311	299,552	419,275
CAD$ per basic share^(e)	6.58	11.18	15.65

(a)	See “Oil and Natural Gas Reserves” section within this new release
(b)	See “Non-GAAP and Other Financial Measures” section within this new release
(c)	Alvopetro has reflected the contractual obligations pursuant to our September 2018 Gas Treatment Agreement with Enerflex, including the equipment rental component of the agreement which is treated as a right of use asset and reflected as a capital lease obligation on our financial statements. As the future capital lease payments reduce the forecasted future net revenue in all reserves categories, the capital lease obligation as reflected on the Company’s financial statements has not been included in the table above.
(d)	The net asset value reflected above includes the present value of before tax cash flows from the Company’s reserves only. No amounts have been included with respect to contingent or prospective resource volumes.
(e)	Converted to CAD$ based on the exchange rate on March 17, 2022. The per share calculation is computed based on 33.9 million common shares outstanding as of March 17, 2022.

Financial and Operating Highlights – Fourth Quarter of 2021

Our daily sales averaged 2,432 boepd in Q4 2021, a 25% increase from the Q4 2020 average of 1,950 boepd and a 1% decrease from the Q3 2021 average of 2,459 boepd. In Q4 2021, 95.7% of our sales volumes were from natural gas with 4.2% from NGLs from condensate and the remainder from crude oil sales.
Our operating netback of $36.38 per boe in Q4 2021 improved 30% from Q4 2020 due to an increase in our realized natural gas price and improved commodity prices overall, offset by increased royalties. The current quarter’s netback was consistent with Q3 2021.
We reported net income of $2.6 million, compared to $2.8 million in Q4 2020 and $1.5 million in Q3 2021.
We generated funds flow from operations in Q4 2021 of $6.5 million ($0.19 per basic share and $0.18 per diluted share) and cash flows from operating activities of $7.1 million ($0.21 per basic share and $0.20 per diluted share).
Capital expenditures totaled $1.5 million, focused on our Murucututu/Gomo pipeline extension.
We declared our second dividend of $0.06 per share to shareholders of record on December 30, 2021. Total dividends of $2.0 million were paid on January 14, 2022.
As at December 31, 2021, we had a net working capital surplus of $9.1 million, including $11.5 million in cash and cash equivalents. The Company’s working capital net of our credit facility balance of $6.5 million improved to $2.6 million, compared to $0.3 million as of September 30, 2021. In February 2022, we repaid an additional $1.5 million of our Credit Facility, bringing the outstanding balance to $5.0 million.

Financial and Operating Highlights – Year-End 2021

Our annual sales averaged 2,358 boepd (95.5% natural gas, 4.4% NGLs from condensate and marginal crude oil production).
We recognized net income of $6.6 million, compared to $5.7 million in 2020.
We generated funds flow from operations of $24.6 million ($0.74 per basic share on $0.71 per diluted share) compared to $6.2 million in 2020 ($0.19 per basic share and $0.18 per diluted share).
Capital expenditures totaled $4.5 million, focused on our Murucututu pipeline extension and our initial costs for our planned 2022 exploration program.
We completed a share restructuring in September 2021, involving a share repurchase and a consolidation resulting in a reduction in our common shares outstanding from 99.8 million to 32.9 million immediately following the restructuring.
We commenced quarterly dividend payments of $0.06/share, with dividends declared to shareholders of record on September 29, 2021 and December 30, 2021.

The following table provides a summary of Alvopetro’s financial and operating results for periods noted. The consolidated financial statements with the Management’s Discussion and Analysis (“MD&A”) are available on our website at www.alvopetro.com and will be available on the System for Electronic Document Analysis and Retrieval (SEDAR) website at www.sedar.com.

	As at and Three MonthsEnded December 31,			Year EndedDecember 31,
	2021	2020	Change (%)	2021	2020
Financial
*($000s, except where noted)*
Natural gas, oil and condensate sales	9,896	5,887	68	34,980	11,308
Net income	2,575	2,754	(6)	6,614	5,706
Per share – basic ($)	0.08	0.08	–	0.20	0.17
Per share – diluted ($)⁽¹⁾	0.07	0.08	(13)	0.19	0.16
Cash flow from operating activities	7,088	3,124	127	24,291	3,061
Per share – basic ($)	0.21	0.09	133	0.73	0.09
Per share – diluted ($)⁽¹⁾	0.20	0.09	122	0.70	0.09
Funds flow from operations ⁽²⁾	6,480	4,252	52	24,637	6,216
Per share – basic ($)	0.19	0.13	46	0.74	0.19
Per share – diluted ($)⁽¹⁾	0.18	0.13	38	0.71	0.18
Capital expenditures⁽³⁾	1,470	452	225	4,513	3,814
Total assets	81,231	80,388	1	81,231	80,388
Cash and cash equivalents	11,469	5,159	122	11,469	5,159
Net working capital surplus ⁽²⁾	9,097	5,539	64	9,097	5,539
Working capital, net of debt (net debt)⁽²⁾	2,552	(9,884)	126	2,552	(9,884)
Weighted average shares outstanding (000s)
Basic	33,824	33,086	2	33,103	32,871
Diluted ⁽¹⁾	35,986	33,557	7	34,928	35,145
Operations
Natural gas, crude oil and natural gas liquids sales:
Natural gas (Mcfpd)	13,966	11,163	25	13,517	5,346
NGLs – condensate (bopd)	103	89	16	103	44
Oil (bopd)	2	–	–	2	5
Total (boepd)	2,432	1,950	25	2,358	940

Average realized prices⁽²⁾:
Natural gas ($/Mcf)	7.07	5.36	32	6.50	5.36
NGL – condensate ($/bbl)	84.36	46.97	80	75.89	46.57
Oil ($/bbl)	76.47	–	–	63.61	36.81
Company total ($/boe)	44.22	32.82	35	40.64	32.88

Operating netback ($/boe) ⁽²⁾
Realized sales price	44.22	32.82	35	40.64	32.88
Royalties	(4.22)	(1.51)	179	(3.61)	(2.15)
Production expenses	(3.62)	(3.39)	7	(3.64)	(3.88)
Operating netback	36.38	27.92	30	33.39	26.85

Notes:
(1)	The weighted average number of diluted common shares outstanding in the computation of funds flow from operations and cash flows from operating activities per share is the same as for net income per share.
(2)	See “Non-GAAP and Other Financial Measures” section within this news release.
(3)	Includes non-cash capital expenditures of $0.4 million for the year-ended December 31, 2020.

2021 Results Webcast

Alvopetro will host a live webcast to discuss the 2021 financial results at 8:00 am Mountain time on March 18, 2022. Details for joining the event are as follows:

DATE: March 18, 2022TIME: 8:00 AM Mountain/10:00 AM EasternLINK: https://zoom.us/j/99386897923 DIAL-IN NUMBERS: https://zoom.us/u/aixrWbAbO WEBINAR ID: 993 8689 7923

The webcast will include a question and answer period. Online participants will be able to ask questions through the Zoom portal. Dial-in participants can email questions directly to socialmedia@alvopetro.com.

Corporate Presentation

Alvopetro’s updated corporate presentation is available on our website at:

http://www.alvopetro.com/corporate-presentation.

Social Media

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

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

Alvopetro Energy Ltd.’s vision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.

All amounts contained in this new release are in United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.

Abbreviations:

2P	=	proved plus probable reserves
boepd	=	barrels of oil equivalent (“boe”) per day
bopd	=	barrels of oil and/or natural gas liquids (condensate) per day
BRL	=	Brazilian Real
CAD$	=	Canadian dollars
m³	=	cubic metre
Mboe	=	thousand barrels of oil equivalent
MMboe	=	million barrels of oil equivalent
Mcf	=	thousand cubic feet
MMcf	=	million cubic feet
MMcfpd	=	million cubic feet per day
NGLs	=	natural gas liquids
Q3 2021	=	three months ended September 30, 2021
Q4 2020	=	three months ended December 31, 2020
Q4 2021	=	three months ended December 31, 2021

Oil and Natural Gas Reserves

The disclosure in this news release summarizes certain information contained in the GLJ Reserves and Resources Report but represents only a portion of the disclosure required under NI 51-101. For additional details, see our news release dated March 8, 2022. Full disclosure with respect to the Company’s reserves as at December 31, 2021 is contained in the Company’s annual information form for the year ended December 31, 2021 which has been filed on SEDAR (www.sedar.com). All net present values in this press release are based on estimates of future operating and capital costs and GLJ’s forecast prices as of December 31, 2021. The reserves definitions used in this evaluation are the standards defined by the Canadian Oil and Gas Evaluation Handbook (COGEH) reserve definitions and are consistent with NI 51-101 and used by GLJ. The net present values of future net revenue attributable to the Alvopetro’s reserves estimated by GLJ do not represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Contingent Resources

This news release discloses estimates of Alvopetro’s contingent resources and the net present value associated with net revenues associated with the production of such contingent resources as included in the GLJ Reserves and Resources Report. There is no certainty that it will be commercially viable to produce any portion of such contingent resources and the estimated future net revenues do not necessarily represent the fair market value of such contingent resources. Estimates of contingent resources involve additional risks over estimates of reserves. For additional details with respect to Alvopetro’s contingent resources evaluated as at December 31, 2021, see our news release dated March 8, 2022 and additional details contained in the Company’s annual information form for the year ended December 31, 2021 which has been filed on SEDAR (www.sedar.com).

Prospective Resources

This news release discloses estimates of Alvopetro’s prospective resources included in the GLJ Reserves and Resources Report. There is no certainty that any portion of the prospective resources will be discovered and even if discovered, there is no certainty that it will be commercially viable to produce any portion. Estimates of prospective resources involve additional risks over estimates of reserves. The accuracy of any resources estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While resources presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. For additional details with respect to Alvopetro’s prospective resources evaluated as at December 31, 2021, see our news release dated March 8, 2022 and additional details contained in the Company’s annual information form for the year ended December 31, 2021 which has been filed on SEDAR (www.sedar.com).

Non-GAAP and Other Financial Measures

This news release contains references to various non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as such terms are defined in National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. Such measures are not recognized measures under GAAP and do not have a standardized meaning prescribed by IFRS and might not be comparable to similar financial measures disclosed by other issuers. While these measures may be common in the oil and gas industry, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. The non-GAAP and other financial measures referred to in this report should not be considered an alternative to, or more meaningful than measures prescribed by IFRS and they are not meant to enhance the Company’s reported financial performance or position. These are complementary measures that are used by management in assessing the Company’s financial performance, efficiency and liquidity and they may be used by investors or other users of this document for the same purpose. Below is a description of the non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures used in this news release. For more information with respect to financial measures which have not been defined by GAAP, including reconciliations to the closest comparable GAAP measure, see the “Non-GAAP Measures and Other Financial Measures” section of the Company’s MD&A which may be accessed through the SEDAR website at www.sedar.com.

Non-GAAP Financial Measures

Operating netback

Operating netback is calculated as natural gas, oil and condensate revenues less royalties and production expenses. This calculation is provided in the “Operating Netback” section of the Company’s MD&A using our IFRS measures. The Company’s MD&A may be accessed through the SEDAR website at SEDAR website at www.sedar.com. Operating netback is a common metric used in the oil and gas industry used to demonstrate profitability from operations.

Net Asset Value

Net asset value is calculated as the net present value of the Company’s 2P reserves discounted at 10% (before-tax) plus the Company’s working capital net of debt as of December 31, 2021. Working capital net of debt is a capital management measure described in further detail below The Company uses net asset value as a way to reflect the Company’s aggregate value of oil and gas reserves and working capital net of debt.

Non-GAAP Financial Ratios

Operating netback per boe

Operating netback is calculated on a per unit basis, which is per barrel of oil equivalent (“boe”). It is a common non-GAAP measure used in the oil and gas industry and management believes this measurement assists in evaluating the operating performance of the Company. It is a measure of the economic quality of the Company’s producing assets and is useful for evaluating variable costs as it provides a reliable measure regardless of fluctuations in production. Alvopetro calculated operating netback per boe as operating netback divided by total sales volumes (barrels of oil equivalent). This calculation is provided in the “Operating Netback” section of the Company’s MD&A using our IFRS measures. The Company’s MD&A may be accessed through the SEDAR website at SEDAR website at www.sedar.com. Operating netback is a common metric used in the oil and gas industry used to demonstrate profitability from operations on a per unit basis (boe).

Funds Flow from Operations Per Share

Funds flow from operations per share is a non-GAAP ratio that includes all cash generated from operating activities and is calculated before changes in non-cash working capital, divided by the weighted the weighted average shares outstanding for the respective period. For the periods reported in this news release the cash flows from operating activities per share and funds flow from operations per share is as follows:

	Three Months Ended December 31,		Year Ended December 31,
$ per share	2021	2020	2021	2020
Per basic share:
Cash flows from operating activities	0.21	0.09	0.73	0.09
Funds flow from operations	0.19	0.13	0.74	0.19

Per diluted share:
Cash flows from operating activities	0.20	0.09	0.70	0.09
Funds flow from operations	0.18	0.13	0.71	0.18

Net Asset Value Per Share

Net asset value is calculated as the net asset value (discussed above) divided by the total shares outstanding, which is 33,903,629 as of the date of this news release. Net asset value per share is stated in CAD$ using the March 17, 2022 USD/CAD exchange rate of 1.265. The Company uses net asset value per share as a way to reflect the Company’s aggregate value of oil and gas reserves and working capital net of debt on a per share basis.

Capital Management Measures

Funds Flow from Operations

Funds flow from operations is a non-GAAP capital management measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. The most comparable GAAP measure to funds flow from operations is cash flows from operating activities. Management considers both funds flow from operations important as it helps evaluate financial performance and demonstrates the Company’s ability to generate sufficient cash to fund future growth opportunities. Funds flow from operations should not be considered an alternative to, or more meaningful than, cash flows from operating activities however management finds that the impact of working capital items on the cash flows reduces the comparability of the metric from period to period. A reconciliation of funds flow from operations to cash flows from operating activities is as follows:

	Three Months Ended December 31,		Year Ended December 31,
	2021	2020	2021	2020
Cash flows from operating activities	7,088	3,124	24,291	3,061
Add back changes in non-cash working capital	(608)	1,128	346	3,155
Funds flow from operations	6,480	4,252	24,637	6,216

Net Working Capital

Net working capital is computed as current assets less current liabilities. Net working capital is a measure of liquidity, is used to evaluate financial resources, and is calculated as follows:

	As at December 31,
	2021	2020
Total current assets	17,188	8,487
Total current liabilities	(8,091)	(2,948)
Net working capital surplus	9,097	5,539

Working Capital Net of Debt (Net Debt)

Working capital net of debt is computed as net working capital surplus decreased by the carrying amount of the Credit Facility. Working capital net of debt is used by management to assess the Company’s overall financial position. As of December 31, 2021, Alvopetro’s net working capital surplus exceeds the balance outstanding on the Credit Facility.

	As at December 31,
	2021	2020
Net working capital surplus	9,097	5,539
Credit Facility, balance outstanding	(6,545)	(15,423)
Working capital, net of debt (net debt)	2,552	(9,884)

Supplementary Financial Measures

“Average realized natural gas price – $/Mcf” is comprised of natural gas sales as determined in accordance with IFRS, divided by the Company’s natural gas sales volumes.

“Average realized NGL – condensate price – $/bbl” is comprised of condensate sales as determined in accordance with IFRS, divided by the Company’s NGL sales volumes from condensate.

“Average realized oil price – $/bbl” is comprised of oil sales as determined in accordance with IFRS, divided by the Company’s oil sales volumes.

“Average realized price – $/boe” is comprised of natural gas, condensate and oil sales as determined in accordance with IFRS, divided by the Company’s total natural gas, condensate and oil sales volumes (barrels of oil equivalent).

“Royalties per boe” is comprised of royalties, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).

“Production expenses per boe” is comprised of production expenses, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).

Forward-Looking Statements and Cautionary Language

This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward–looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the plans relating to the Company’s operational activities, the expected natural gas price, gas sales and gas deliveries under Alvopetro’s long-term gas sales agreement, forecasted earnings, and the Company’s plans for dividends in the future. The forward–looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to equipment availability, the timing of regulatory licenses and approvals, the success of future drilling, completion, testing, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of the COVID-19 pandemic and other significant worldwide events, the performance of producing wells and reservoirs, well development and operating performance, foreign exchange rates, general economic and business conditions, weather and access to drilling locations, the availability and cost of labour and services, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. In addition, the declaration, timing, amount and payment of future dividends remain at the discretion of the Board of Directors. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

SOURCE Alvopetro Energy Ltd.

Alvopetro Announces 33% Increase In Quarterly Dividend To US$0.08 Per Share, Year-End 2021 Financial Results, Filing Of Annual Information Form And An Operational Update

Posted on March 18, 2022 by Admin

Alvopetro Announces 33% Increase In Quarterly Dividend To US$0.08 Per Share, Year-End 2021 Financial Results, Filing Of Annual Information Form And An Operational Update

Research, News, and Market Data on Alvopetro Energy

All references herein to $ refer to United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.

President and CEO, Corey Ruttan commented:

Dividend

Operational Update

December 31, 2021 Reserves and Net Asset Value

Base Net Asset Value (in $000s, other than per share amounts)	Total Proved	Total Proved plus Probable	Total Proved plus Probable plus Possible
Before Tax Net Present Value^(a), discounted at 10%	173,759	297,000	416,723
Working capital, net of debt – as of December 31, 2021^(b)	2,552	2,552	2,552
Total Base Net Asset Value^(b)(c)(d)	176,311	299,552	419,275
CAD$ per basic share^(e)	6.58	11.18	15.65

(a)	See “Oil and Natural Gas Reserves” section within this new release
(b)	See “Non-GAAP and Other Financial Measures” section within this new release
(c)	Alvopetro has reflected the contractual obligations pursuant to our September 2018 Gas Treatment Agreement with Enerflex, including the equipment rental component of the agreement which is treated as a right of use asset and reflected as a capital lease obligation on our financial statements. As the future capital lease payments reduce the forecasted future net revenue in all reserves categories, the capital lease obligation as reflected on the Company’s financial statements has not been included in the table above.
(d)	The net asset value reflected above includes the present value of before tax cash flows from the Company’s reserves only. No amounts have been included with respect to contingent or prospective resource volumes.
(e)	Converted to CAD$ based on the exchange rate on March 17, 2022. The per share calculation is computed based on 33.9 million common shares outstanding as of March 17, 2022.

Financial and Operating Highlights – Fourth Quarter of 2021

Our daily sales averaged 2,432 boepd in Q4 2021, a 25% increase from the Q4 2020 average of 1,950 boepd and a 1% decrease from the Q3 2021 average of 2,459 boepd. In Q4 2021, 95.7% of our sales volumes were from natural gas with 4.2% from NGLs from condensate and the remainder from crude oil sales.
Our operating netback of $36.38 per boe in Q4 2021 improved 30% from Q4 2020 due to an increase in our realized natural gas price and improved commodity prices overall, offset by increased royalties. The current quarter’s netback was consistent with Q3 2021.
We reported net income of $2.6 million, compared to $2.8 million in Q4 2020 and $1.5 million in Q3 2021.
We generated funds flow from operations in Q4 2021 of $6.5 million ($0.19 per basic share and $0.18 per diluted share) and cash flows from operating activities of $7.1 million ($0.21 per basic share and $0.20 per diluted share).
Capital expenditures totaled $1.5 million, focused on our Murucututu/Gomo pipeline extension.
We declared our second dividend of $0.06 per share to shareholders of record on December 30, 2021. Total dividends of $2.0 million were paid on January 14, 2022.
As at December 31, 2021, we had a net working capital surplus of $9.1 million, including $11.5 million in cash and cash equivalents. The Company’s working capital net of our credit facility balance of $6.5 million improved to $2.6 million, compared to $0.3 million as of September 30, 2021. In February 2022, we repaid an additional $1.5 million of our Credit Facility, bringing the outstanding balance to $5.0 million.

Financial and Operating Highlights – Year-End 2021

Our annual sales averaged 2,358 boepd (95.5% natural gas, 4.4% NGLs from condensate and marginal crude oil production).
We recognized net income of $6.6 million, compared to $5.7 million in 2020.
We generated funds flow from operations of $24.6 million ($0.74 per basic share on $0.71 per diluted share) compared to $6.2 million in 2020 ($0.19 per basic share and $0.18 per diluted share).
Capital expenditures totaled $4.5 million, focused on our Murucututu pipeline extension and our initial costs for our planned 2022 exploration program.
We completed a share restructuring in September 2021, involving a share repurchase and a consolidation resulting in a reduction in our common shares outstanding from 99.8 million to 32.9 million immediately following the restructuring.
We commenced quarterly dividend payments of $0.06/share, with dividends declared to shareholders of record on September 29, 2021 and December 30, 2021.

	As at and Three MonthsEnded December 31,			Year EndedDecember 31,
	2021	2020	Change (%)	2021	2020
Financial
*($000s, except where noted)*
Natural gas, oil and condensate sales	9,896	5,887	68	34,980	11,308
Net income	2,575	2,754	(6)	6,614	5,706
Per share – basic ($)	0.08	0.08	–	0.20	0.17
Per share – diluted ($)⁽¹⁾	0.07	0.08	(13)	0.19	0.16
Cash flow from operating activities	7,088	3,124	127	24,291	3,061
Per share – basic ($)	0.21	0.09	133	0.73	0.09
Per share – diluted ($)⁽¹⁾	0.20	0.09	122	0.70	0.09
Funds flow from operations ⁽²⁾	6,480	4,252	52	24,637	6,216
Per share – basic ($)	0.19	0.13	46	0.74	0.19
Per share – diluted ($)⁽¹⁾	0.18	0.13	38	0.71	0.18
Capital expenditures⁽³⁾	1,470	452	225	4,513	3,814
Total assets	81,231	80,388	1	81,231	80,388
Cash and cash equivalents	11,469	5,159	122	11,469	5,159
Net working capital surplus ⁽²⁾	9,097	5,539	64	9,097	5,539
Working capital, net of debt (net debt)⁽²⁾	2,552	(9,884)	126	2,552	(9,884)
Weighted average shares outstanding (000s)
Basic	33,824	33,086	2	33,103	32,871
Diluted ⁽¹⁾	35,986	33,557	7	34,928	35,145
Operations
Natural gas, crude oil and natural gas liquids sales:
Natural gas (Mcfpd)	13,966	11,163	25	13,517	5,346
NGLs – condensate (bopd)	103	89	16	103	44
Oil (bopd)	2	–	–	2	5
Total (boepd)	2,432	1,950	25	2,358	940

Average realized prices⁽²⁾:
Natural gas ($/Mcf)	7.07	5.36	32	6.50	5.36
NGL – condensate ($/bbl)	84.36	46.97	80	75.89	46.57
Oil ($/bbl)	76.47	–	–	63.61	36.81
Company total ($/boe)	44.22	32.82	35	40.64	32.88

Operating netback ($/boe) ⁽²⁾
Realized sales price	44.22	32.82	35	40.64	32.88
Royalties	(4.22)	(1.51)	179	(3.61)	(2.15)
Production expenses	(3.62)	(3.39)	7	(3.64)	(3.88)
Operating netback	36.38	27.92	30	33.39	26.85

Notes:
(1)	The weighted average number of diluted common shares outstanding in the computation of funds flow from operations and cash flows from operating activities per share is the same as for net income per share.
(2)	See “Non-GAAP and Other Financial Measures” section within this news release.
(3)	Includes non-cash capital expenditures of $0.4 million for the year-ended December 31, 2020.

2021 Results Webcast

Alvopetro will host a live webcast to discuss the 2021 financial results at 8:00 am Mountain time on March 18, 2022. Details for joining the event are as follows:

DATE: March 18, 2022TIME: 8:00 AM Mountain/10:00 AM EasternLINK: https://zoom.us/j/99386897923 DIAL-IN NUMBERS: https://zoom.us/u/aixrWbAbO WEBINAR ID: 993 8689 7923

Corporate Presentation

Alvopetro’s updated corporate presentation is available on our website at:

http://www.alvopetro.com/corporate-presentation.

Social Media

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

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

All amounts contained in this new release are in United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.

Abbreviations:

2P	=	proved plus probable reserves
boepd	=	barrels of oil equivalent (“boe”) per day
bopd	=	barrels of oil and/or natural gas liquids (condensate) per day
BRL	=	Brazilian Real
CAD$	=	Canadian dollars
m³	=	cubic metre
Mboe	=	thousand barrels of oil equivalent
MMboe	=	million barrels of oil equivalent
Mcf	=	thousand cubic feet
MMcf	=	million cubic feet
MMcfpd	=	million cubic feet per day
NGLs	=	natural gas liquids
Q3 2021	=	three months ended September 30, 2021
Q4 2020	=	three months ended December 31, 2020
Q4 2021	=	three months ended December 31, 2021

Oil and Natural Gas Reserves

Contingent Resources

Prospective Resources

Non-GAAP and Other Financial Measures

Non-GAAP Financial Measures

Operating netback

Net Asset Value

Non-GAAP Financial Ratios

Operating netback per boe

Funds Flow from Operations Per Share

	Three Months Ended December 31,		Year Ended December 31,
$ per share	2021	2020	2021	2020
Per basic share:
Cash flows from operating activities	0.21	0.09	0.73	0.09
Funds flow from operations	0.19	0.13	0.74	0.19

Per diluted share:
Cash flows from operating activities	0.20	0.09	0.70	0.09
Funds flow from operations	0.18	0.13	0.71	0.18

Net Asset Value Per Share

Capital Management Measures

Funds Flow from Operations

	Three Months Ended December 31,		Year Ended December 31,
	2021	2020	2021	2020
Cash flows from operating activities	7,088	3,124	24,291	3,061
Add back changes in non-cash working capital	(608)	1,128	346	3,155
Funds flow from operations	6,480	4,252	24,637	6,216

Net Working Capital

Net working capital is computed as current assets less current liabilities. Net working capital is a measure of liquidity, is used to evaluate financial resources, and is calculated as follows:

	As at December 31,
	2021	2020
Total current assets	17,188	8,487
Total current liabilities	(8,091)	(2,948)
Net working capital surplus	9,097	5,539

Working Capital Net of Debt (Net Debt)

	As at December 31,
	2021	2020
Net working capital surplus	9,097	5,539
Credit Facility, balance outstanding	(6,545)	(15,423)
Working capital, net of debt (net debt)	2,552	(9,884)

Supplementary Financial Measures

“Average realized natural gas price – $/Mcf” is comprised of natural gas sales as determined in accordance with IFRS, divided by the Company’s natural gas sales volumes.

“Average realized NGL – condensate price – $/bbl” is comprised of condensate sales as determined in accordance with IFRS, divided by the Company’s NGL sales volumes from condensate.

“Average realized oil price – $/bbl” is comprised of oil sales as determined in accordance with IFRS, divided by the Company’s oil sales volumes.

“Royalties per boe” is comprised of royalties, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).

Forward-Looking Statements and Cautionary Language

SOURCE Alvopetro Energy Ltd.

Has Uranium Demand Changed with Russia Ukraine War?

Posted on March 17, 2022 by Admin

The importance of Dependable Energy, Even Nuclear, is Heightened in Recent War

Energy is important. After food and air, energy is the next most critical in day-to-day life. Since the beginning of 2022, uranium investments are up about 30%, since Russia’s invasion of Ukraine, the performance is even better. Although the yellow metal has not had the performance of crude oil, its large upward price move highlights the importance of energy resources and current fragility, especially as nations seek to lessen their use of traditional energy sources.

The mineral itself is not easily traded on open exchanges using futures contracts to the same extent that other commodities are. The reasons are obvious. But, according to data from UxC, uranium prices climbed to $59.75 a pound on March 10. That is the highest in eleven years. That’s when uranium went through a few bad years following a massive earthquake and tsunami in Japan which led to a power outage and meltdown at the Fukushima Daiichi nuclear plant, (March of 2011). This event caused a change in thinking and retrenchment of nations as they rethought their power strategy and decided to phase out nuclear on safety concerns. The price of uranium tumbled shortly after.

Recent History

Uranium prices had been trading around $43 before Russia invaded Ukraine on Feb. 24th. Uncertainty around any event historically causes risk assets to tumble and consumers’ necessities to strengthen. While the invasion hasn’t had an immediate impact on demand, or supply, there is speculation that the trend toward nuclear may increase at a faster pace than recent years, countries may even maintain existing plants longer than announced and perhaps build modern generation facilities, especially in Europe as they diversify away from natural gas provided by Russia.

Some countries are changing their positions on non-carbon emitting nuclear that they took, possibly as a knee-jerk reaction, after Fukushima. Belgium has adjusted its position on its 2025 deadline to phase out its seven nuclear power plants. The country’s Federal Agency for Nuclear Control announced some reactors may operate beyond 2025 if removing them puts energy supply security at risk.

Current State

Russia’s war with Ukraine has raised global risks to energy supplies. Since Russia is among the world’s biggest exporters of oil and natural gas, oil prices have climbed to their highest levels since 2008, while gas prices (Dutch TTF), have recently bounced off record highs.

While the US is not dependent on Russian oil or natural gas, it has relied on Russia for 16% of its enriched uranium supply, while Europe relies on Russia for 20%.

Global nuclear-power generation grew by 3.5% in 2021. China had the largest increase of growth measuring 11%. The US actually shrank 1.5%.

Other Uranium Demand

Investors of physical uranium are adding to the demand for U308. A physical investment takes production offline, so those in a physical trust enhance positive price action. The Sprott Physical Uranium Trust (SRUUF), the world’s largest physical uranium fund, has seen its stores of the fuel climb to over 51 million pounds from 18.1 million a year ago, and its net asset value grow to over $3 billion from $630 million since its launch. In 2022 lone shares of the trust have climbed more than 20% this year (a/o March 15).

Increased interest in uranium investments comes as much of the world has adopted an anti-carbon position related to climate change commitments. Nuclear power does not emit carbon in the generation process and can produce significant energy without regard to sun or wind conditions. The stigma of being an environmental nightmare has shifted to one of being an environmental savior. As other types of fuels costs rise, so will the alternative uranium.

Paul Hoffman

Managing Editor, Channelchek

Suggested Reading

Why Uranium Mining Stocks Can Continue Climbing Higher

How Does Uranium Fit Into the ESG Energy Landscape?

AMC is Thinking Outside the Box Office and Diversifying

Why JP Morgan’s Guru has Maintained a Positive Stance on Stocks

Sources

https://www.energy.gov/ne/articles/nuclear-power-most-reliable-energy-source-and-its-not-even-close

https://www.world-nuclear-news.org/Articles/Belgian-regulator-says-reactors-could-operate-beyo

https://www.iea.org/fuels-and-technologies/nuclear

Stay up to date. Follow us:

InPlay Oil (IPOOF)(IPO:CA) – Doubling Our Price Target On Higher Production And Energy Prices

Posted on March 17, 2022 by Admin

Thursday, March 17, 2022

InPlay Oil (IPOOF)(IPO:CA)
Doubling Our Price Target On Higher Production And Energy Prices

As of April 24, 2020, Noble Capital Markets research on InPlay Oil is published under ticker symbols (IPOOF and IPO:CA). The price target is in USD and based on ticker symbol IPOOF. Research reports dated prior to April 24, 2020 may not follow these guidelines and could account for a variance in the price target. 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 OTCQZ Exchange under the symbol IPOOF.

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

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

Fourth-quarter and 2021 results were generally in line with expectations and previous management guidance. Adjusted funds flow rose 532% in response to higher energy prices, a 45% increase in production volumes, reduced operating costs per unit produced and lower financing costs. Management raised its guidance for AFF in 2022 to $141-$150 million from $111-117 million as it raised its assumed energy prices towards current levels. A previously-announced boost in drilling following a tuck-in acquisition last fall is coming to fruition and will help grow production in 2022.

Higher energy prices are good but InPlay is really a story of improved operating results. The company drilled two wells this quarter in lands acquired in the Prairie Storm acquisition and both are producing above expectations. It also drilled three wells in existing Pembina territories that are also producing above expectations. The company enters the second quarter with the drilling program six …

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 (UUUU)(EFR:CA) – Ramp Up Is Coming Slowly But Higher Prices Could Spur Activity

Posted on March 17, 2022 by Admin

Thursday, March 17, 2022

Energy Fuels (UUUU)(EFR:CA)
Ramp Up Is Coming Slowly But Higher Prices Could Spur Activity

As of April 24, 2020, Noble Capital Markets research on Energy Fuels is published under ticker symbols (UUUU and EFR:CA). The price target is in USD and based on ticker symbol UUUU. Research reports dated prior to April 24, 2020 may not follow these guidelines and could account for a variance in the price target.

Energy Fuels is the largest uranium producer in the U.S. and holds more production capacity and uranium resources than any other U.S. producer. The Company also produces vanadium. Headquartered in Colorado, Energy Fuels holds three of America’s key uranium production centers: the White Mesa Mill in Utah, the Nichols Ranch ISR Facility in Wyoming, and the Alta Mesa ISR Facility in Texas. The producing White Mesa Mill is the only conventional uranium mill in the U.S. and has a licensed capacity of 8 million pounds of U3O8 per year. Nichols Ranch is in production and has a licensed capacity of 2 million pounds of U3O8 per year. Alta Mesa is currently on standby. Energy Fuels also owns several licensed and developed uranium and vanadium mines on standby and other projects in development.

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

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

Energy Fuels reported 2021 results generally in line with expectations. Given limited sales, results are largely a function of costs and fairly easy to predict. UUUU reported an operating loss for the year of $35.3 million, slightly larger than our $32.4 million estimate. Net income was $1.5 million versus our estimate of $(36.4) million but if one removes a $35.7 million gain on the sale of assets, results were in line. The company’s cash and inventory positions remain strong and there is growing optimism that rising prices could lead to sales.

Not much for developments in the last quarter, mainly a rehash of 2021’s top press releases. Management announced that has begun separating Lanthanum and Cerium in its rare earth elements (REE) processing operations. It also announced the execution of a memorandum of understanding to develop a new technology to produce REE metals at a lower costs. Outside those announcements, the only other thing …

This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).

Alvopetro Energy (ALVOF)(ALV:CA) – Coverage Initiated

Posted on March 16, 2022 by Admin

Wednesday, March 16, 2022

Alvopetro Energy (ALVOF)(ALV:CA)
Coverage Initiated With Outperform Rating and a $10 Target

Alvopetro Energy Ltd is a Canada based resource company engaged in the exploration, acquisition, development, and production of hydrocarbons in Brazil. The company holds interests in the Cabure and Gomo natural gas assets, two oil fields (Bom Lugar and Mae-da-lua) and seven other exploration assets in the Reconcavo basin onshore Brazil.

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

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

Alvopetro is well positioned to take advantage of the recent rise in energy prices. The price Alvopetro receives is set semi-annually based on oil and gas index pricing, heat content and the Brazilian-U.S. exchange rate. In February 2022, prices rose to approximately $11.28/mcf, a 59% increase over the realized price in the last quarter. With operating costs expected to remain at historical levels, the company should begin to see very large operating netbacks and free cash flow.

Management is in a very enviable position of choosing between expanding or returning proceeds to shareholders. Most likely, it will do both. An initial dividend set in September has already been raised once to an indicated annual rate of $0.24 per share (yield of 7.0%). At the same time, the company has begun an active drilling program and indicated plans to expand midstream operations. Production …

This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).

Release – InPlay Oil Corp. Announces Record Setting 2021 Financial Operating and Reserves Results

Posted on March 16, 2022 by Admin

InPlay Oil Corp. Announces Record Setting 2021 Financial, Operating and Reserves Results

News and Market Data on InPlay Oil Corp

CALGARY, Alberta, March 16, 2022 (GLOBE NEWSWIRE) — InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its record setting financial and operating results for the three and twelve months ended December 31, 2021, and the results of its independent oil and gas reserves evaluation effective December 31, 2021 (the “Reserve Report”) prepared by Sproule Associates Limited (“Sproule”). InPlay’s audited annual financial statements and notes, as well as Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2021 will be available at “www.sedar.com” and our website at “www.inplayoil.com”.

2021 Highlights:

Completed the acquisition of Prairie Storm Resources Corp. on November 30, 2022 at attractive transaction metrics which enhances InPlay’s position as a sizable producer and acreage holder with a deep and highly economic drilling inventory in the light oil window of Central Alberta’s Cardium fairway.
Achieved record average annual production of 5,768 boe/d⁽¹⁾ (65% light crude oil and NGLs), an increase of 45% from 2020 at 3,985 boe/d⁽¹⁾ (68% light crude oil and NGLs) and an increase of 15% compared to pre-COVID levels of 5,000 boe/d⁽¹⁾ (66% light crude oil and NGLs) in 2019. Annual average production per weighted average basic share increased 31% compared to 2020.
Generated record annual adjusted funds flow (“AFF”)⁽²⁾ of $47.0 million ($0.67 per weighted average basic share⁽³⁾), an increase of 532% compared to $7.4 million ($0.11 per weighted average basic share) in 2020 and an increase of 45% compared to $32.5 million ($0.48 per weighted average basic share) in 2019, our prior record year. Excluding the impact of realized hedging losses, AFF for 2021 would have been $59.9 million.
Increased operating netbacks⁽⁴⁾ by 203% to $34.63/boe from $11.45/boe in 2020 and 52% from $22.75/boe in 2019.
Realized annual record operating income⁽⁴⁾ and operating income profit margin⁽⁴⁾ of $72.9 million and 64% respectively compared to $16.7 million and 40% in 2020; $41.5 million and 55% in 2019.
Reduced operating expenses to an annual record $12.83/boe compared to $14.43/boe in 2020 and $14.36/boe in 2019, despite rising costs of services in the industry.
Generated annual free adjusted funds flow (“FAFF”)⁽⁴⁾ of $13.6 million.
Lowered annual net debt⁽²⁾ to earnings before interest, taxes and depletion (“EBITDA”)⁽⁴⁾ ratio to 1.5, compared to 6.7 in 2020 and 1.6 in 2019. Fourth quarter 2021 annualized net debt to EBITDA ratio was 1.1 compared to 4.0 in 2020 and 1.6 in 2019 achieving the lowest leverage ratios in our corporate history.
Achieved significant growth in reserves and reserves per weighted average basic share:
- Proved developed producing (“PDP”) reserves increased 64% (61% per weighted average basic share) to 15,890 mboe (58% light and medium crude oil & NGLs)
- Total proved (“TP”) reserves increased 112% (106% per weighted average basic share) to 45,891 mboe (62% light and medium crude oil & NGLs)
- Total proved plus probable (“TPP”) reserves increased 85% (81% per weighted average basic share) to 60,640 mboe (63% light and medium crude oil & NGLs)
Achieved record NPV BT10 reserve and net asset values (“NAV”)⁽⁶⁾:
- NPV BT10: $206 million (PDP), $471 million (TP) and $686 million (TPP)
- NAV: $1.85 per weighted average basic share (PDP), $4.92 per weighted average basic share (TP) and $7.41 per weighted average basic share (TPP)
- West Texas Intermediate (“WTI”) prices used in the Reserve Report to value the Company’s reserves are approximately 22% and 15% less than current strip pricing for 2022 (US $72.83 vs. approximately US $89.00) and 2023 (US $68.78 vs. approximately US $79.00) respectively.
Finding, Development and Acquisition (“FD&A”)⁽⁵⁾ costs, associated recycle ratios and capital efficiencies which are top tier amongst light oil weighted peers.
- FD&A⁽⁵⁾ costs of $8.47/boe (PDP), $12.03/boe (TP) and $9.56/boe (TPP), consistent with three year averages of $9.67/boe (PDP), $10.98/boe (TP) and $9.23 (TPP).
- Recycle ratios⁽⁵⁾ of 4.1 (PDP), 2.9 (TP) and 3.6 (TPP) compared to 1.2 (PDP), 2.0 (TP) and 1.4 (TPP) in 2020.
- InPlay added new light oil weighted production at a capital efficiency⁽⁵⁾ of $12,583 per boe/d.
Materially increased the reserve life index of our assets which in turn improves the long term sustainability of the Company:
- PDP reserve life index⁽⁵⁾ of 7.5 years compared to 6.6 years in 2020
- TP reserve life index of 21.8 years compared to 14.8 years in 2020
- TPP reserve life index of 28.8 years compared to 22.5 years in 2020
Successful development and A&D activity resulting in top-tier reserve replacement⁽⁵⁾:
- PDP replacement of 395% (2020 – 166%)
- TP replacement of 1,253% (2020 – 309%)
- TPP replacement of 1,422% (2020 – 479%)
Increased liquidity through an increased capacity within our Senior Credit Facility from $65.0 million to $85.0 million and total debt capacity of $111 million.
Abandonment and Reclamation Obligations spending of $2.3 million, reducing our liability by 3% through the successful abandonment of 75 wellbores and the reclamation of 22 well sites.
Achieved a 20% reduction to the Company’s emissions (Scope 1 and 2) on a per boe basis compared to 2020.

Notes:

See “Reader Advisories – Production Breakdown by Product Type”
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
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”.
“FD&A”, “recycle ratio”, “reserve replacement”, “reserve life index” and “capital efficiency” do not have standardized meanings and therefore may not be comparable to similar measures presented for other entities. Refer to section “Performance Measures” for the determination and calculation of these measures.
See “Corporate Reserves Information” and “Net Asset Value” for detailed information from the Reserve Report and associated calculations.

Message to Shareholders:

The Company exited 2021 in its best operational and financial position to date. The disciplined and measured steps taken during 2020 and 2021, allowed us to implement a strategy focused on measured growth combined with generating strong free adjusted funds flow once oil prices began to recover in mid-2021. InPlay initially directed its free adjusted funds flow to debt reduction ensuring a strong and sustainable balance sheet from which to grow the Company. The strategy led to record annual AFF of $47.0 million and record annual FAFF of $13.6 million for the year while also reducing net debt, resulting in InPlay’s lowest historic leverage ratios. As the Company solidified its financial position, the strategy evolved to the point where InPlay was able to evaluate and execute upon accretive acquisition opportunities. Following up on a small but highly successful tuck-in acquisition during Q4 2020 (where InPlay grew production from 300 boe/d to 2,900 boe/d⁽²⁾ in Q4 2021), InPlay closed the highly accretive corporate acquisition of Prairie Storm Resources Corp. on November 30, 2022. This acquisition enhanced the Company’s sustainability by adding low decline production, sizeable economic drilling inventory that complements InPlay’s own high internal rate of return, quick payout inventory, and increased reserve life while also adding material scale to the Company. All of these attributes enhance InPlay’s ability to grow and to continue to generate sustained long term FAFF per share⁽¹⁾. Immediately post closing, InPlay started drilling two wells on the Prairie Storm lands with results exceeding our expectations, confirming our technical evaluation of the assets. InPlay management is proud to be able to consistently deliver top tier reserve, production and AFF per share growth while also generating significant FAFF per share growth.

The Company’s sustainability has improved significantly with a very strong weighting of PDP reserves relative to TP and TPP reserves which now represent approximately 35% and 26% of the Company’s TP and TPP reserves respectively, with long-life reserves providing RLI’s of 7.5 years (PDP), 21.8 years (TP) and 28.8 years (TPP). InPlay’s long life reserves combined with the expected 2022 PDP base production decline rate of 23.2% (compared to 25.9% in 2021) puts the Company in a solid position to sustainably deliver long term per share growth and shareholder returns.

InPlay continued to deliver on our track record of drilling efficiency, operational expertise and accretive strategic acquisition activity, driving attractive light oil reserve addition metrics. FD&A costs per boe were $8.47, $12.03 and $9.56 in PDP, TP and TPP reserve categories respectively. These costs were consistent with InPlay’s three year FD&A averages of $9.67/boe (PDP), $10.98/boe (TP) and $9.23 (TPP). The Prairie Storm acquisition provided highly accretive and economic reserve additions that are expected to generate strong production and FAFF growth. The 2021 capital program continued to convert the Company’s high quality drilling inventory into reliable cash flow capital efficiencies of $12,583 per boe/d, representing a new record for the Company.

Notes:

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”.
See “Production Breakdown by Product Type” at the end of this press release.

2022 Outlook Update

InPlay’s focus has been concentrated on reducing debt and improving leverage ratios. Execution of this focus is significantly ahead of schedule with the increased commodity prices. With our sound financial footing and projected liquidity capacity, InPlay is expected to be able to deliver measured production per share growth and strong free adjusted funds flow which positions the Company to execute on strategic accretive opportunities with the ultimate goal of maximizing returns to shareholders.

InPlay is forecasting 2022 to be another record year for the Company, and reiterates its previously announced January 12, 2022 average production guidance of 8,900 to 9,400 boe/d⁽¹⁾. With the recent sustained increase in commodity prices, we are updating our price forecast using USD $90/bbl WTI, $4.30/mcf AECO and a CAD/USD exchange rate of 0.80. Based on this revised commodity price forecast, InPlay is now expected to generate 2022 AFF of $141 to $150 million and 2022 FAFF of $83 to $92 million which would result in InPlay being in a positive working capital position, in excess of debt, by year end.

The table below outlines InPlay’s financial results of the board approved capital budget based on several WTI pricing scenarios for the remainder of 2022 (assuming an average Q1/22 WTI price of US$91.50/bbl):

2022	US$70 WTI	US$80 WTI	US$90 WTI	US$100 WTI	US$110 WTI
Production (boe/d)⁽¹⁾⁽²⁾	9,150	9,150	9,150	9,150	9,150
Debt adjusted prod. per share growth (%)⁽³⁾	67%	79%	90%	102%	109%
AFF ($ millions)⁽⁴⁾	$121	$134	$146	$156	$162
FAFF ($ millions)⁽³⁾	$63	$76	$88	$98	$104
FAFF Yield (%)⁽³⁾⁽⁶⁾	24%	29%	33%	37%	40%
Year-end Working Capital / (Net Debt) ($ millions)⁽⁴⁾	($19)	($6)	$6	$16	$22
Annual Net Debt / EBITDA⁽³⁾	0.2	0.0	0.0	(0.1)	(0.1)
EV / DAAFF⁽³⁾⁽⁶⁾	2.2	1.9	1.7	1.5	1.4

Notes:

See “Production Breakdown by Product Type” at the end of this press release.
This reflects the mid-point of the Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.
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”.
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release. .
See “Reader Advisories – Forward Looking Information and Statements” for key budget and underlying assumptions related to our 2022 capital program and associated guidance.
Assumes a share price of $3.06.

Operations Update

InPlay’s capital program for the first quarter of 2022 was initiated in mid December 2021 due to the availability of services and the desire to take advantage of strong commodity prices, including winter natural gas prices. The two (1.6 net) wells that were drilled in December 2021 on the Prairie Storm lands were brought on production in the second half of January and are currently exceeding forecasts. The average initial production (“IP”) rates from these wells are as follows:

	IP 30 (% light crude oil and NGLs)	Current (% light crude oil and NGLs)
1.5 mile well	593 boe/d (80%)	368 boe/d (77%)
1.0 mile well	203 boe/d (83%)	165 boe/d (78%)

An additional three (3.0 net) Extended Reach Horizontal (“ERH”) wells were drilled in Pembina during January and February and were brought on production ahead of schedule in late February. These wells are in the early clean up stage and are also currently producing above forecasts. The average combined IP rates from these wells are as follows:

IP 15 (% light crude oil and NGLs)	Current (% light crude oil and NGLs)
1,022 boe/d (79%)	1,354 boe/d (71%)

Current corporate production is approximately 9,050 boe/d⁽¹⁾ (62% light crude oil and NGLs), based on field estimates.

Plans for the remainder of the first quarter of 2022 consist of completing two (1.7 net) wells that were drilled on our recently acquired Prairie Storm lands. These wells are expected to be on production before the end of the first quarter. In addition, InPlay will bring on production one (0.2 net) non-operated Cardium ERH well.

Looking forward, the Company has started capital preparations for the second quarter of 2022. Due to strong commodity prices and access to our preferred service providers, the Company expects to start the second quarter drilling program early, with certain operations including lease construction already completed. It is expected that drilling operations will commence approximately six weeks ahead of schedule.

Notes:

See “Production Breakdown by Product Type” at the end of this press release.
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”.

Financial and Operating Results:

(CDN) ($000’s)	Three months ended December 31				Year ended December 31
	2021		2020		2021		2020
Financial
Oil and natural gas sales	37,255		12,829		113,854		41,934
Adjusted funds flow⁽¹⁾	17,149		3,291		47,028		7,436
Per share – basic⁽²⁾	0.23		0.05		0.67		0.11
Per share – diluted⁽²⁾	0.22		0.05		0.66		0.11
Per boe⁽²⁾	27.87		8.40		22.34		5.10
Comprehensive income (loss)	55,191		(3,227	)	115,071		(112,629	)
Per share – basic	0.74		(0.05	)	1.65		(1.65	)
Per share –diluted	0.71		(0.05	)	1.61		(1.65	)
Capital expenditures – PP&E and E&E	6,024		10,633		33,434		23,134
Property acquisitions (dispositions)	–		1,875		(84	)	1,610
Net Corporate acquisitions⁽³⁾⁽⁴⁾	38,287		–		38,287		–
Net debt⁽¹⁾	(80,196	)	(73,681	)	(80,196	)	(73,681	)
Shares outstanding	86,214,751		68,256,616		86,214,751		68,256,616
Basic weighted-average shares	74,338,118		68,256,616		69,798,836		68,256,616
Diluted weighted-average shares	77,669,551		68,256,616		71,681,264		68,256,616

Operational
Daily production volumes
Light and medium crude oil (bbls/d)	3,156		2,194		2,981		2,031
Natural gas liquids (boe/d)	932		708		782		668
Conventional natural gas (Mcf/d)	15,589		8,141		12,030		7,715
Total (boe/d)	6,687		4,259		5,768		3,985
Realized prices⁽²⁾
Light and medium crude oil & NGLs ($/bbls)	79.83		40.41		70.08		35.90
Conventional natural gas ($/Mcf)	5.04		2.72		4.01		2.29
Total ($/boe)	60.56		32.74		54.08		28.75
Operating netbacks ($/boe)⁽⁴⁾
Oil and natural gas sales	60.56		32.74		54.08		28.75
Royalties	(7.53	)	(1.78	)	(5.51	)	(2.00	)
Transportation expense	(1.09	)	(0.80	)	(1.11	)	(0.87	)
Operating costs	(12.51	)	(14.35	)	(12.83	)	(14.43	)
Operating netback⁽⁴⁾	39.43		15.81		34.63		11.45
Realized (loss) on derivative contracts	(5.67	)	(0.38	)	(6.20	)	(0.82	)
Operating netback (including realized derivative contracts)⁽⁴⁾	33.76		15.43		28.43		10.63

(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)		This amount consists of total gross consideration of $49.9, net of $11.6 million in working capital balances assumed on closing of the Prairie Storm acquisition.
(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”

2021 Financial & Operations Overview:

Production averaged 5,768 boe/d (65% light crude oil & NGLs) ⁽¹⁾ in 2021, a 45% increase compared to 3,985 boe/d (68% light crude oil & NGLs)⁽¹⁾ in 2020 and a 15% increase compared to 5,000 boe/d (66% light crude oil & NGLs)⁽¹⁾ in 2019. The four quarter sales volumes were slightly affected due to the following factors; operational downtime caused by extreme cold, third party processing facility shut downs and a larger build in period ending oil inventories of approximately 9,000 barrels.

InPlay’s 2021 capital program consisted of $33.4 million of development capital. The Company drilled eight (8.0 net) ERH wells in Pembina, and two (1.6) Willesden Green ERH wells on our newly acquired Prairie Storm assets during the year, for a total of 12 (10.0 net) wells drilled during the year. The Company also participated in one (0.2 net) Nisku ERH well and one (0.2 net) Willesden Green ERH well in 2021. This activity amounted to the drilling of an equivalent of 20.5 gross horizontal miles (15.4 net horizontal miles). This capital spending also included the construction of a multi-well battery in Pembina, which is anticipated to accommodate future development in the area over the next three years. InPlay also accelerated the start of its 2022 capital program at the end of 2021, initiating construction operations and the start of drilling activities on a three well pad in Pembina due to optimal timing and availability of services.

Efficient field operations resulted in the Company achieving record low operating costs of $12.83/boe. This result was achieved despite rising power costs throughout the year and in services in the second half of the year. The resulting operating income⁽²⁾ and operating income profit margin⁽²⁾ for 2021 were also annual records for the Company at $72.9 million and 64% respectively.

Note:

See “Reader Advisories – Production Breakdown by Product Type”
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”.

2021 Reserves Overview:

As a result of the Company’s efficient execution of development capital in 2021, strategic A&D activity and the quality of our asset base, significant reserve growth was generated in all reserve categories compared to 2020. PDP reserves increased by 64% in 2021 to 15,890 mboe, TP reserves increased by 112% to 45,891 mboe and TPP reserves increased by 85% to 60,640 mboe. This reserve based growth easily replaced our 2021 production, with 395% of production being replaced on a PDP basis, 1,253% on a TP basis and 1,422% on a TPP basis.

This significant reserve growth and improvements to commodity prices resulted in strong 2021 year-end reserve net present values of future net revenues before tax (“NPV BT”) and net asset values per basic share (“NAVPS”). This resulted in reserve values of NPV BT10 of $206 million (PDP), $471 million (TP) and $686 million (TPP) using a three independent reserve evaluators average pricing forecast and foreign exchange rates as at December 31, 2021 as used in the Reserve Report. This equates to Net Asset Values of $160 million and $1.85 NAVPS (PDP), $424 million and $4.92 NAVPS (TP) and $639 million and $7.41 NAVPS (TPP)⁽¹⁾, representing 81% (PDP), 154% (TP) and 112% (TPP) growth for each category respectively on a per weighted average basic share basis over 2020.

Note:

See “Net Asset Value” for detailed calculations.

Corporate Reserves Information:

The following summarizes certain information contained in the Reserve Report. The Reserve Report was prepared in accordance with the definitions, standards and procedures contained in the COGE Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form (“AIF”) which will be filed on SEDAR by the end of March 2022.

December 31, 2021	Light and Medium		Conventional	Oil	BTAX NPV	Future Development	Net Undeveloped
Reserves Category^(1)(2)(3)(4)⁽⁵⁾	Crude Oil	NGLs	Natural Gas	Equivalent	10%	Capital	Wells
Reserves Category^(1)(2)(3)(4)⁽⁵⁾	Mbbl	Mbbl	MMcf	MBOE	($000’s)	($000’s)	Booked

Proved developed producing	6,224.8	2,972.1	40,156	15,889.6	206,481	287	–
Proved developed non-producing	595.9	254.1	3,191	1,381.9	19,464	3,617	–
Proved undeveloped	14,151.6	4,028.9	62,633	28,619.3	245,156	412,786	179.2
Total proved	20,972.4	7,255.2	105,979	45,890.7	471,100	416,690	179.2
Probable developed producing	1,467.2	713.3	9,611	3,782.3	39,024	8	–
Probable developed non-producing	153.9	74.1	867	372.6	4,298	–	–
Probable undeveloped	6,159.6	1,260.0	19,048	10,594.3	171,090	57,533	25.8
Total probable	7,780.6	2,047.5	29,526	14,749.2	214,412	57,541	25.8
Total proved plus probable⁽⁶⁾	28,753.0	9,302.6	135,505	60,639.9	685,513	474,232	205.0

Notes:

Reserves have been presented on a gross basis which are the Company’s total working interest (operating and non-operating) share before the deduction of any royalties and without including any royalty interests of the Company.
Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2021, as outlined in the table herein entitled “Pricing Assumptions”.
It should not be assumed that the NPV amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of InPlay’s light and medium crude oil, natural gas liquids and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual light and medium crude oil, conventional natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment, decommissioning and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.
The Company has included abandonment, decommissioning and reclamation costs for all active and inactive assets including non-producing and suspended wells, facilities and pipelines. December 31, 2021 reserve NPV values are also inclusive of currently enacted carbon taxes.
Totals may not add due to rounding.

Net Asset Value:


December 31, 2021	BTAX NPV 5%				BTAX NPV 10%
	($000’s)		$/share⁽⁶⁾		($000’s)		$/share⁽⁶⁾
PDP NPV⁽¹⁾⁽²⁾	226,629		2.63		206,481		2.39
Undeveloped acreage⁽³⁾	33,474		0.39		33,474		0.39
Net debt⁽⁴⁾⁽⁵⁾	(80,196	)	(0.93	)	(80,196	)	(0.93	)
Net Asset Value (basic)	179,907		2.09		159,759		1.85


December 31, 2021	BTAX NPV 5%				BTAX NPV 10%
	($000’s)		$/share⁽⁶⁾		($000’s)		$/share⁽⁶⁾
TP NPV⁽¹⁾⁽²⁾	608,756		7.06		471,100		5.46
Undeveloped acreage⁽³⁾	33,474		0.39		33,474		0.39
Net debt⁽⁴⁾⁽⁵⁾	(80,196	)	(0.93	)	(80,196	)	(0.93	)
Net Asset Value (basic)	562,034		6.52		424,378		4.92


December 31, 2021	BTAX NPV 5%				BTAX NPV 10%
	($000’s)		$/share⁽⁶⁾		($000’s)		$/share⁽⁶⁾
TPP NPV⁽¹⁾⁽²⁾	904,526		10.49		685,513		7.95
Undeveloped acreage⁽³⁾	33,474		0.39		33,474		0.39
Net debt⁽⁴⁾⁽⁵⁾	(80,196	)	(0.93	)	(80,196	)	(0.93	)
Net Asset Value (basic)	857,804		9.95		638,791		7.41

Notes:

Evaluated by Sproule as at December 31, 2021. The estimated NPV does not represent fair market value of the reserves.
Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2021.
Duvernay land holdings attributed a value of $19.9 million ($847/acre) for 23,440 net acres based on internal valuations. The remaining undeveloped acreage is based on an internal valuation totaling $13.6 million ($256/acre) for 53,159 net acres. These internal valuations are based on land sale results in the area.
Net debt as at December 31, 2021.
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
Based upon 86,214,751 common shares outstanding as at December 31, 2021.

Future Development Costs (“FDCs”):

FDCs increased by $246.9 million on a Total Proved basis and $215.7 million on a Total Proved plus Probable basis.

Future Development Capital Costs (amounts in $million)
	Total Proved	Total Proved + Probable
2022	58.9	66.6
2023	99.2	111.7
2024	100.5	114.0
2025	95.3	110.5
Remainder	62.7	71.4
Total undiscounted FDC	416.7	474.2
Total discounted FDC at 10% per year	332.4	377.8

Note: FDC as per Reserve Report based on forecast pricing as outlined in the table herein entitled “Pricing Assumptions”

Performance Measures:

	2019	2020	2021	3 Year Avg
Average WTI crude oil price (US$/bbl)	57.02	39.40	67.91	54.78
Capital expenditures – PP&E and E&E ($000’s)⁽¹⁾	30,689	22,213	33,434	–
Production boe/d – FY⁽³⁾	5,000	3,985	5,768	4,918
Production boe/d – Q4⁽³⁾	4,998	4,259	6,687	5,315
Operating netback $/boe – FY⁽²⁾	22.75	11.45	34.63	24.32
Proved Developed Producing
Total Reserves mboe	8,718	9,677	15,890	11,428
Reserves additions mboe	2,195	2,418	8,318	12,930
FD&A (including FDCs) $/boe⁽¹⁾	13.98	9.85	8.47	9.67
FD&A (excluding FDCs) $/boe⁽¹⁾	13.98	9.85	8.47	9.67
Recycle Ratio⁽⁴⁾	1.6	1.2	4.1	2.5
Reserves Replacement⁽⁵⁾	120%	166%	395%	240%
RLI (years)⁽⁶⁾	4.8	6.6	7.5	6.4
Total Proved
Total Reserves mboe	18,573	21,624	45,891	28,696
Reserves additions mboe	1,540	4,509	26,372	32,421
FD&A (including FDCs) $/boe⁽¹⁾	7.92	5.86	12.03	10.98
FD&A (excluding FDCs) $/boe⁽¹⁾	19.93	5.28	2.67	3.86
Recycle Ratio⁽⁴⁾	2.9	2.0	2.9	2.2
Reserves Replacement⁽⁵⁾	84%	309%	1,253%	602%
RLI (years)⁽⁶⁾	10.2	14.8	21.8	16.0
Proved Plus Probable
Total Reserves mboe	27,295	32,816	60,640	40,250
Reserves additions mboe	2,057	6,980	29,929	38,965
FD&A (including FDCs) $/boe⁽¹⁾	7.82	8.21	9.56	9.23
FD&A (excluding FDCs) $/boe⁽¹⁾	14.92	3.41	2.36	3.21
Recycle Ratio⁽⁴⁾	2.9	1.4	3.6	2.6
Reserves Replacement⁽⁵⁾	113%	479%	1,422%	723%
RLI (years)⁽⁶⁾	15.0	22.5	28.8	22.4

In 2021, InPlay’s successful exploration, development and acquisition/disposition capital program achieved a capital efficiency of $12,583 per boe/d and a three year average of $15,354 per boe/d.⁽⁷⁾

Notes:

Finding, Development & Acquisition (“FD&A”) costs are used as a measure of capital efficiency. The calculation includes the period’s capital expenditures, including Exploration and Development (“E&D”) and Acquisition and Disposition (“A&D”) expended in the year, less capitalized G&A expenses and undeveloped land expenditures acquired with no reserves. This total of capital expenditures, including the change in the FDC over the period, is then divided by the change in reserves, other than from production, for the period incorporating additions/reductions from extensions, infill drilling, technical revisions, acquisitions/dispositions and economic factors. For example: 2021 TPP = ($33.4 million E&D – $1.2 million capitalized G&A – $nil million of land acquisitions + $38.2 million net acquisition/disposition capital + $215.8 million FDC) / (60,640 mboe – 32,816 mboe + 2,105 mboe) = $9.56 per boe. Finding and Development Costs (“F&D”) are calculated the same as FD&A costs, however adjusted to exclude the capital expenditures and reserve additions/reductions from acquisition/disposition activity. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
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”
See “Reader Advisories – Production Breakdown by Product Type”
Recycle Ratio is calculated by dividing the year’s operating netback per boe by the FD&A costs for that period. For example: 2021 TPP = ($34.63/$9.56) = 3.6. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year. For example: 2021 TPP = (60,640 mboe – 32,816 mboe + 2,105 mboe) / 2,105 mboe = 1422%, which reflects the extent to which the Company was able to replace production and add reserves throughout the year. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
RLI is calculated by dividing the reserves in each category by the 2021 average annual production. For example 2021 TPP = (60,640 mboe) / (5,768 boe/day) = 28.8 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
Capital Efficiency is calculated as the total annual exploration & development and acquisition and disposition capital expended in the year, less capitalized G&A and land acquisition costs divided by production additions comparing the fourth quarter of the previous year using a decline rate of 29% over the course of the year, calculated as follows: ($33.4 million E&D – $1.2 million capitalized G&A – $nil million of land acquisitions – $0.1 million net acquisition/disposition capital + $9.2 million of 2020 capital adding reserves in 2021 – $3.0 million of capital not adding reserves in 2021) / (Q4/2021 production of 6,687 boe/d – Q4/2020 production of 4,259 boe/d + 2021 declined production at 29% of 1,218 boe/d – Q4/2021 Prairie Storm production of 600 boe/d). See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.

Pricing Assumptions:

The following tables set forth the benchmark reference prices, as at December 31, 2021, reflected in the Reserve Report. These price assumptions were an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at the effective date of the Reserve Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS⁽¹⁾
as of December 31, 2021
FORECAST PRICES AND COSTS

Year	WTI Cushing Oklahoma ($US/Bbl)	Canadian Light Sweet 40^oAPI ($Cdn/Bbl)	Cromer LSB 35^o API ($Cdn/Bbl)	Natural Gas AECO-C Spot ($Cdn/ MMBtu)	NGLs Edmonton Propane ($Cdn/Bbl)	NGLs Edmonton Butanes ($Cdn/Bbl)	Edmonton Pentanes Plus ($Cdn/Bbl)	Operating Cost Inflation Rates %/Year	Capital Cost Inflation Rates %/Year	Exchange Rate⁽²⁾ ($Cdn/$US)
Forecast⁽³⁾
2022	72.83	86.82	87.30	3.56	43.38	57.49	91.85	0.0%	0.0%	0.80
2023	68.78	80.73	82.30	3.21	35.92	50.17	85.53	2.3%	2.3%	0.80
2024	66.76	78.01	79.69	3.05	34.62	48.53	82.98	2.0%	2.0%	0.80
2025	68.09	79.57	81.29	3.11	35.31	49.50	84.63	2.0%	2.0%	0.80
2026	69.45	81.16	82.92	3.17	36.02	50.49	86.33	2.0%	2.0%	0.80
2027	70.84	82.78	84.50	3.23	36.74	51.50	88.05	2.0%	2.0%	0.80
2028	72.26	84.44	86.27	3.30	37.47	52.53	89.82	2.0%	2.0%	0.80
2029	73.70	86.13	87.99	3.36	38.22	53.58	91.61	2.0%	2.0%	0.80
2030	75.18	87.85	89.75	3.43	38.99	54.65	93.44	2.0%	2.0%	0.80
2031	76.68	89.61	91.55	3.50	39.77	55.74	95.32	2.0%	2.0%	0.80
2032	78.21	91.40	93.38	3.57	40.56	56.86	97.22	2.0%	2.0%	0.80
	Thereafter Escalation rate of 2.0%

Notes:

This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
The exchange rate used to generate the benchmark reference prices in this table.
As at December 31, 2021.

Environmental, Social and Governance (“ESG”) Update

InPlay’s commitment to ESG is evident through its operational track record, corporate culture and strong governance. The Company is pleased to announce that it expects to release its inaugural sustainability report this summer. InPlay looks forward to sharing the Company’s strategy and governance related to ESG and reporting ESG related metrics with shareholders.

The Company completed an active abandonment and reclamation program throughout 2021, spending $2.3 million on the abandonment of 75 wellbores and the reclamation of 22 well sites. This resulted in a reduction to our Abandonment and Reclamation obligation of 3% during 2021. Efficient field operations resulted in a 20% reduction to the Company’s emissions (Scope 1 and 2) on a per boe basis compared to 2020.

Included in our 2022 forecast is a commitment to materially reducing the Company’s abandonment and reclamation obligations. Approximately 30 abandonment operations and 20 reclamations are currently planned for 2022, which is estimated to result in a $3 million or 3% reduction to our ARO and a projected improvement in our Liability Management Rating (“LMR”) to 2.85.

We look forward to continuing to deliver returns to our shareholders and thank all of those that have supported InPlay since the Company’s inception. The future for InPlay and the industry are very promising and we will continue to operate the Company in a prudent, sustainable and responsible manner.

For further information please contact:

Doug Bartole		Darren Dittmer
President and Chief Executive Officer		Chief Financial Officer
InPlay Oil Corp.		InPlay Oil Corp.
Telephone: (587) 955-0632		Telephone: (587) 955-0634

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”, “free adjusted funds flow per share”, “FAFF Yield”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA”, “Net corporate acquisitions”, “Debt adjusted production per share” and “EV / DAAFF”. 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 / FAFF per share

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 free adjusted funds flow, free adjusted funds flow per share and a reconciliation of free adjusted funds flow to the nearest GAAP measure, adjusted funds flow.

(thousands of dollars)	Three Months Ended December 31				Year Ended December 31
	2021		2020		2021		2020
Adjusted funds flow	17,149		3,291		47,028		7,436
Exploration and dev. capital expenditures	(6,024	)	(10,633	)	(33,434	)	(23,134	)
Property dispositions (acquisitions)	–		(1,875	)	84		(1,610	)
Free adjusted funds flow	11,125		(9,217	)	13,678		(17,308	)
Weighted average outstanding shares	74.3		68.3		69.8		68.3
FAFF per share	0.15		(0.14	)	0.20		(0.25	)

Free Adjusted Funds Flow Yield

InPlay uses “free adjusted funds flow yield” as a key performance indicator. Free adjusted funds flow is calculated by the Company as free adjusted funds flow divided by the market capitalization of the Company. Management considers FAFF yield to be an important performance indicator as it demonstrates a Company’s ability to generate cash to pay down debt and provide funds for potential distributions to shareholders. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast 2022 free adjusted funds flow yield.

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 December 31				Year Ended December 31
	2021		2020		2021		2020
Revenue	37,255		12,829		113,854		41,934
Royalties	(4,632	)	(697	)	(11,595	)	(2,924	)
Operating expenses	(7,695	)	(5,622	)	(27,009	)	(21,043	)
Transportation expenses	(673	)	(314	)	(2,346	)	(1,271	)
Operating income	24,255		6,196		72,904		16,696

Sales volume (Mboe)	615.2		391.8		2,105.1		1,458.5
Per boe
Revenue	60.56		32.74		54.08		28.75
Royalties	(7.53	)	(1.78	)	(5.51	)	(2.00	)
Operating expenses	(12.51	)	(14.35	)	(12.83	)	(14.43	)
Transportation expenses	(1.09	)	(0.80	)	(1.11	)	(0.87	)
Operating netback per boe	39.43		15.81		34.63		11.45
Operating income profit margin	65	%	48	%	64	%	40	%

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. 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 below for a calculation of Net Debt / EBITDA.

(thousands of dollars)	Year Ended December 31
	2021	2020
Net debt	80,196	73,681
Adjusted funds flow	47,028	7,436
Interest expense (Credit Facility and other)	5,594	3,523
Interest expense (Lease liabilities)	20	47
Earnings before interest, taxes and depletion (“EBITDA”)	52,642	11,006
Net Debt to EBITDA	1.5	6.7

Net Corporate Acquisitions
Management considers Net corporate acquisitions an important measure as it is a key metric to evaluate the corporate acquisition in comparison to other transactions using the negotiated consideration value and ignoring changes to the fair value of the share consideration between the signing of the definitive agreement and the closing of the transaction. Net corporate acquisitions should not be considered as an alternative to or more meaningful than “Corporate acquisitions, net of cash acquired” as determined in accordance with GAAP as an indicator of the Company’s performance. Net corporate acquisitions is calculated as total consideration with share consideration adjusted to the value negotiated with the counterparty, less working capital balances assumed on the corporate acquisition. Refer below for a calculation of Net corporate acquisitions and reconciliation to the nearest GAAP measure, “Corporate acquisitions, net of cash acquired”.

(thousands of dollars)	Three Months Ended December 31			Year Ended December 31
	2021		2020	2021		2020
Corporate acquisitions, net of cash acquired	29,277		–	29,277		–
Share consideration⁽¹⁾	9,985		–	9,985		–
Non-cash working capital acquired	(1,156	)	–	(1,156	)	–
Derivative contracts	181		–	181		–
Net Corporate acquisitions	38,287		–	38,287		–

(1)		For purposes of the corporate acquisition, the share consideration had a negotiated value of $1.20 per share. For accounting purposes in accordance with IFRS 3, the shares issued as consideration have been valued at $2.07 per share, based on the closing price of InPlay shares on November 29, 2021.
(2)		Net working capital acquired equals the fair value of cash and cash equivalents, accounts receivable and accrued liabilities, prepaid expenses and deposits, inventory, accounts payable and accrued liabilities and derivative contracts acquired as disclosed in note 5 of the Company’s consolidated financial statements.

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 to the “Forward Looking Information and Statements” section for a calculation of forecast Production per debt adjusted share.

EV / DAAFF
InPlay uses “enterprise value to debt adjusted AFF” or “EV/DAAFF” as a key performance indicator. EV/DAAFF is calculated by the Company as enterprise value divided by debt adjusted AFF for the relevant period. Debt adjusted AFF (“DAAFF”) is calculated by the Company as adjusted funds flow plus financing costs. Enterprise value is a capital management measures that is used in the calculation of EV/DAAFF. Enterprise value is calculated as the Company’s market capitalization plus net debt. Enterprise value is calculated as market capitalization plus net debt. Management considers enterprise value a key performance indicator as it identifies the total capital structure of the Company. Management considers EV/DAAFF a key performance indicator as it is a key metric used to evaluate the sustainability of the Company relative to other companies while incorporating the impact of differing capital structures. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast 2022 EV/DAAFF.

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 recognition of significant additional reserves under the heading “Corporate Reserves Information”, the future net value of InPlay’s reserves, the future development capital and costs, the life of InPlay’s reserves and the net asset values disclosed under the heading “Net Asset Value” including the internal value ascribed to undeveloped acreage; 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; the expectation that the reserve additions from the Prairie Storm acquisition will generate strong production and FAFF growth; the expectation that InPlay will be in a positive net cash position in the fourth quarter of 2022 using a pricing scenario of US $90 WTI and positive working capital position by 2022 year end; that 2022 will be another record year for the Company; the expectation that the Company will experience inflationary cost pressures in the second half of 2022; the expectation that costs will begin to normalize later in 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 expectation that the Company will start the second quarter capital program early; the planned release of InPlay’s inaugural sustainability report prior to June 30, 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 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; 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; 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; 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.

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.

InPlay’s 2021 annual guidance and a comparison to 2021 actual results are outlined below.

		2021 Guidance⁽¹⁾	2021 Actual	Variance	Variance (%)
Production⁽⁶⁾	Boe/d	5,750 – 6,000	5,768	–	–
Adjusted Funds Flow⁽⁷⁾	$ millions	$51.0 – $54.0	$47.0	($5)⁽³⁾	(7%)
Capital Expenditures	$ millions	$32.5⁽²⁾	$33.4	$1⁽⁴⁾	3%
Free Adjusted Funds Flow⁽⁸⁾	$ millions	$17.5 – $20.5	$13.6	($4)⁽³⁾⁽⁴⁾	(20%)
Net Debt⁽⁶⁾	$ millions	$76.5 – $79.5	$80.2	$1^(3)(4)(5)	1%

Notes:

As previously released September 28, 2021.
As previously released November 30, 2021 (previously $32.5 – $34.5 million on September 28, 2021).
This variance is due to the following:
- Lower fourth quarter sales volumes due to operational downtime caused by extreme cold, third party processing facility mechanical shut downs, a larger build in period ending oil inventories of approximately 9,000 barrels, and the later than initially expected drilling of the two well pad drilled in the fourth quarter of 2021. In addition, new production from the 2021 drilling program had a slightly higher gas weighting and lower NGL yield than forecasted.
- The effect of shorter royalty incentive periods for recently drilled wells in the improved pricing environment and higher trucking costs on new wells.
- Significant improvements in the Company’s share price in the later portion of 2021, resulting in additional expenses incurred from the vesting and revaluation of deferred share units, and the accelerated vesting of certain DSUs.
- Increased hedging losses as a result of higher annual average WTI prices of US $1.06/bbl.
This variance is due to the acceleration of the start of the 2022 capital program at the end of 2021 through the initiation of lease construction and starting drilling activities on a three well pad in Pembina due to optimal conditions and availability of services.
This net debt variance is due to the higher positive net debt assumed on the Prairie Storm acquisition in addition to additional proceeds from the over-allotment option being exercised on the bought deal financing which both contributed to an additional $3 million positive net debt impact, net of the $4 million reduction to free adjusted funds flow.
See “Reader Advisories – Production Breakdown by Product Type”
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
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”

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	$72.50	$90.00
NGL Price	$/boe	$37.79	$42.75	$52.35
AECO	$/GJ	$3.44	$3.30	$4.30
Foreign Exchange Rate	CDN$/US$	0.80	0.78	0.80
MSW Differential	US$/bbl	$3.88	$3.50	$3.00
Production	Boe/d	5,768	8,900 – 9,400	8,900 – 9,400
Royalties	$/boe	5.51	5.25 – 5.75	9.80 – 10.60
Operating Expenses	$/boe	12.83	10.00 – 13.00	10.00 – 13.00
Transportation	$/boe	1.11	0.85 – 1.10	0.85 – 1.10
Interest	$/boe	2.67	0.85 – 1.25	0.75 – 1.15
General and Administrative	$/boe	2.83	2.00 – 2.60	2.00 – 2.60
Hedging loss	$/boe	6.20	0.00 – 0.20	0.35 – 0.65
Decommissioning Expenditures	$ millions	$1.4	$2.0 – $2.5	$2.0 – $2.5
Adjusted Funds Flow	$ millions	$47.0	$111.0 – $117.0	$141 – $150
Weighted average outstanding shares	# millions	69.8	86.2	86.2
Adjusted Funds Flow per share	$/share	0.67	1.28 – 1.36	1.64 – 1.75

		Actuals FY 2021	Previous Guidance FY 2022	Updated Guidance FY 2022
Adjusted Funds Flow	$ millions	$47.0	$111.0 – $117.0	$141 – $150
Capital Expenditures	$ millions	$33.3	$58.0	$58.0
Free Adjusted Funds Flow	$ millions	$13.6	$53.5 – $59.5	$83 – $92
Share outstanding, end of year	# millions	86.2		86.2
Assumed Share price	$	2.18⁽³⁾		3.06
Market capitalization	$ millions	$188		$264
FAFF Yield	%	7%	N/A⁽⁵⁾	31% – $35%

		Actuals FY 2021	Previous Guidance FY 2022⁽¹⁾	Updated Guidance FY 2022
Adjusted Funds Flow	$ millions	$47.0	$111.0 – $117.0	$141 – $150
Interest	$/boe	2.67	0.85 – 1.25	0.75 – 1.15
EBITDA	$ millions	$52.6	$115.0 – $120.0	$144 – $153
Net Debt/(Positive working capital, in excess of debt)	$ millions	$80.2	$22.0 – $28.0	($1) – ($10)
Net Debt/EBITDA		1.5	0.2 – 0.3	0.0 – 0.1

		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	$76.5 – $79.5	$80.2
Ending Net Debt/(Pos. working capital, in excess of debt)	$ millions	$80.2	$22.0 – $28.0	($1) – ($10)
Weighted average outstanding shares	# millions	69.8	86.2	86.2
Assumed Share price	$	1.16⁽⁴⁾	2.18	3.06
Production per debt adjusted share growth⁽²⁾		31%	76% – 86%	85% – 95%

		Actuals FY 2021	Previous Guidance FY 2022	Updated Guidance FY 2022
Share outstanding, end of year	# millions	86.2		86.2
Assumed Share price	$	2.18⁽³⁾		3.06
Market capitalization	$ millions	$188		$264
Net Debt/(Positive working capital, in excess of debt)	$ millions	$80.2		($1) – ($10)
Enterprise value	$millions	$268.2		$253 – $261
Adjusted Funds Flow	$ millions	$44.1		$141 – $150
Interest	$/boe	2.67		0.75 – 1.15
Debt Adjusted AFF	$ millions	$49.7		$144 – $153
EV/DAAFF		5.4	N/A⁽⁵⁾	1.6 – 1.8

(1)		As previously released January 12, 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 share price at December 31, 2021.
(3)		Ending share price at December 31, 2021.
(4)		Weighted average share price throughout 2021.
(5)		Guidance had not been previously released for this measure.

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.

Information Regarding Disclosure on Oil and Gas Reserves and Operational Information
Our oil and gas reserves statement for the year ended December 31, 2021, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com on or before March 31, 2022. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Company’s belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed above under the heading “Forward-Looking Information and Statements”.

This press release contains metrics commonly used in the oil and natural gas industry, such as “finding, development and acquisition costs”, “finding and development costs”, “operating netbacks”, “recycle ratios”, “reserve replacement” and “reserve life index” or “RLI”. Each of these terms are calculated by InPlay as described in the section “Performance Measures” in this press release. These terms do not have standardized meanings 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. Such metrics have been included herein to provide readers with additional information to evaluate the Company’s performance, however such metrics should not be unduly relied upon.

Finding, development and acquisition (“FD&A”) and finding and development (“F&D”) costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated future development costs may not reflect total finding and development costs related to reserves additions for that year. Finding, development and acquisition costs have been presented in this press release because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure. Exploration & development capital means the aggregate exploration and development costs incurred in the financial year on exploration and on reserves that are categorized as development. Exploration & development capital excludes capitalized administration costs. Acquisition capital amounts to the total amount of cash and share consideration net of any working capital balances assumed with an acquisition on closing.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare InPlay’s operations over time, however such measures are not reliable indicators of InPlay’s future performance and future performance may not be comparable to the performance in prior periods. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes, however such measures are not reliable indicators on InPlay’s future performance and future performance may not be comparable to the performance in prior periods.

References to light 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“).

Test Results and Initial Production 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)
Q4 2019 Average Production	2,466	869	9,978	4,998
2019 Average Production	2,626	697	10,058	5,000
Q4 2020 Average Production	2,194	708	8,141	4,259
2020 Average Production	2,031	668	7,715	3,985
Q4 2021 Average Production	3,156	933	15,590	6,687
2021 Average Production	2,981	782	12,030	5,768
2022 Annual Guidance	4,332	1,312	21,035	9,150⁽¹⁾
Tuck-in Acquisition Q4 2021 Avg. Prod	1,452	302	6,815	2,900
Current Corporate Average Production	4,019	1,455	21,464	9,050

Note:

This reflects the mid-point of the Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.
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.

Release – Energy Fuels Announces 2021 Results

Posted on March 16, 2022 by Admin

Energy Fuels Announces 2021 Results, Including Net Profits, Strong Cash Position, and Market-Leading U.S. Uranium, Rare Earth and Vanadium Position

Research, News, and Market Data on Energy Fuels

LAKEWOOD, Colo., March 15, 2022 /CNW/ – Energy Fuels Inc. (NYSE American: UUUU) (TSX: EFR) (“Energy Fuels” or the “Company”) today reported its financial results for the year ended December 31, 2021. The Company’s annual report on Form 10-K has been filed with the U.S. Securities and Exchange Commission (“SEC“) and may be viewed on the Electronic Document Gathering and Retrieval System (“EDGAR“) at www.sec.gov/edgar.shtml, on the System for Electronic Document Analysis and Retrieval (“SEDAR“) at www.sedar.com, and on the Company’s website at www.energyfuels.com. Unless noted otherwise, all dollar amounts are in U.S. dollars.

Highlights:

Energy Fuels reported a net income of $1.5 million for 2021.
At December 31, 2021, the Company had a robust balance sheet with $143.2 million of working capital, including $113.0 million of cash and marketable securities, $30.8 million of inventory, and no short term (or long term) debt. At current commodity prices, the Company’s December 31, 2021 product inventory would have a value of approximately $60.6 million.
During 2021, prices for all the commodities Energy Fuels produces, or has the ability to produce, rose significantly. Uranium oxide (“U₃O₈“) prices increased approximately 38%, neodymium-praseodymium oxide (“NdPr“) prices increased approximately 112%, and vanadium oxide (“V₂O₅“) prices increased approximately 62%. Prices for each of these commodities have continued to show significant strength to date in 2022. The Company continues to closely follow developments related to Russia’s invasion of Ukraine, as Russia is a major supplier of uranium and nuclear fuel to U.S. and European customers. Prices of uranium have risen sharply in recent days.
While the Company chose to not sell any uranium during 2021, it is now actively engaged in pursuing selective long-term uranium sales contracts.
The Company produced approximately 270 metric tonnes of mixed rare earth element (“REE“) carbonate (“RE Carbonate“), containing 120 metric tonnes of total rare earth oxides (“TREO“) during 2021, as it commenced ramping up its REE recovery infrastructure. Energy Fuels’ RE Carbonate is the most advanced REE material being produced in the U.S. today.
The Company is currently in active discussions with several sources of natural monazite sands around the world to significantly increase the supply of feed for its growing REE initiative.
During Q1-2022, the Company began commercially separating Lanthanum (La) and Cerium (Ce) on a small scale from its RE Carbonate, using an existing solvent extraction circuit at the Mill. This represents the first commercial level REE separation to occur in the U.S. in many years.
The Company is planning to install a full separation circuit at its White Mesa Mill (the “Mill“) to produce both “light” and “heavy” separated REE oxides in the coming years, subject to successful licensing, financing, and commissioning, and continued strong market conditions. The Company has hired Carester SAS (“Carester“), a global leader in producing separated REE oxides, to support these REE separation initiatives.
On December 15, 2021, the Company announced a strategic venture with Nanoscale Powders LLC (“NSP“) for the development of a novel technology that would potentially produce REE metals. The technology has the potential to reduce the costs of production, energy consumption, and greenhouse gas emissions versus existing technologies.
In 2021, the Company sold small quantities of its existing V₂O₅ inventory to capitalize on recent market strength. The Company expects to continue to sell vanadium as prices increase and is evaluating the potential to resume vanadium recovery at the Mill, where its tailings pond solutions contain an estimated additional 1.0 to 3.0 million recoverable pounds of V₂O₅.
In July 2021, the Company announced the execution of a Strategic Alliance Agreement with RadTran, LLC to evaluate the potential recovery of thorium and radium from the Company’s existing RE Carbonate and uranium process streams for use in the production of medical isotopes for emerging targeted alpha therapy (“TAT“) cancer therapeutics. This initiative complements the Company’s existing uranium and RE Carbonate businesses, as it investigates the potential recovery of isotopes in existing process streams at the Mill for medical purposes.
In September 2021, the Company announced its establishment of the San Juan County Clean Energy Foundation (the “Foundation“), a fund specifically designed to contribute to the communities surrounding the Mill in southeastern Utah by providing funding to support local economic development and local priorities.
In October 2021, the Company completed the sale of certain, permitted non-core conventional uranium assets to Consolidated Uranium Inc. (“CUR”), including the Daneros mine, the Tony M mine, and the Rim mine. The Company reported a gain on the value of this transaction of $35.7 million, resulting in a significant improvement in the Company’s results of operations and net income for 2021.
On January 25, 2022, the Board appointed Dr. Ivy Estabrooke as a Director of Energy Fuels, bringing to the Company experience in commercial-stage biotech, research and development program leadership, and technology solutions for national security and public health challenges.

Mark S. Chalmers, Energy Fuels’ President and CEO, stated:

“In 2021, we believe Energy Fuels further strengthened its position as America’s leading multi-commodity, critical mineral company, as we made excellent progress on our uranium, REEs, vanadium and medical isotope initiatives. We are deploying our ‘one-of-a-kind’ licenses, facilities, and expertise to responsibly recover the critical elements needed for carbon-free nuclear energy, electric vehicle powertrains, wind generation, advanced electronics, grid-scale batteries, other clean energy and advanced technologies, and potentially cancer therapeutics.

“We are particularly proud of our accomplishments in REEs. We announced our entry into the REE business less than two years ago, and today we are ramping up our production of commercial quantities of RE Carbonate, which is a more advanced REE material than any other U.S. company is producing, as we are chemically recovering the REEs in a high-purity material that is ready for REE separation. We are also moving toward licensing and installing the infrastructure needed to produce separated REE oxides on a full commercial scale in the coming years. The proven processing technology for producing separated REE oxides is solvent extraction, or ‘SX,’ and our White Mesa Mill has over 40 years of experience producing uranium and vanadium using SX. With the support of Carester, a leading global consultant in the production of separated REE products, we believe it is a logical ‘next step’ for Energy Fuels to produce separated REE oxides on a full commercial scale at the Mill. We have already successfully performed La, Ce, and NdPr separations at pilot scale in the Mill’s lab over the past several months, and we recently began ramping up our commercial separation of La and Ce from our RE Carbonate on a small scale using an existing SX circuit at the Mill. Our primary REE focuses in 2022 will be building our supply of monazite ore, designing and licensing a new full commercial scale REE separation circuit at the Mill, and advancing our innovative REE metal initiative with NSP.

“With the recent events in Ukraine, security of supply in the U.S. for uranium is crucial. Energy Fuels continues to be the leading low-cost U.S. uranium producer with more production facilities and capacity than any other U.S. company, and we stand ready to be a reliable, large-scale supplier to U.S. nuclear utilities. We are seeing an increase in utility interest for long-term contracts. We are pursuing uranium sales contracts with pricing and terms that return acceptable project margins and maintain exposure to further uranium market upside.

“Vanadium prices are rising, as well. In 2019, we built a significant inventory of vanadium to sell into the abrupt upside price volatility that vanadium markets often experience, most recently in late 2018. The next upward cycle may have begun, as prices have risen sharply in the first months of 2022, and we are selling some of our inventory. As we sell, we will evaluate the potential to resume production from the Mill’s pond solutions or our conventional deposits to replace our sold inventory. We estimate our pond solutions alone contain another 1.0 to 3.0 million pounds of recoverable V₂O₅ and would be first and lowest cost to market.

“A few words on our medical isotope initiative. This is another area where we are able to deploy our unique facilities, licenses, and expertise to potentially help create a domestic supply chain for emerging cancer therapies. Recovering radioisotopes for use in cancer treatments from our existing process streams, thereby recycling valuable material that would otherwise be lost to direct disposal, would, if successful, be a great way to maximally use all of our feeds. And we would be accomplishing this in a way that is environmentally beneficial and highly congruent with Energy Fuels’ recycling and sustainability goals.

“We are also very pleased to announce that, on January 25, 2022 Dr. Ivy Estabrooke was appointed to the Board of Energy Fuels. Dr. Estabrooke brings to the Company an impressive background that is highly pertinent, not only to our new REE and TAT cancer therapeutics initiatives, but also to our core uranium business, which is of the utmost importance to national security at this time.”

Webcast at 1:00 pm EDT on March 17, 2022:

Energy Fuels will be hosting a video webcast on March 17, 2022 at 1:00 pm EDT (11:00 am MDT) to discuss its FY-2021 financial results, the outlook for 2022, uranium, rare earths, vanadium, and medical isotopes. To join the webcast and access the presentation and viewer-controlled webcast slides, please click on the link below:

Webcast Link

If you would like to participate in the webcast and ask questions, please dial in to 1-888-664-6392 (toll free in the U.S. and Canada).

A link to a recorded version of the proceedings will be available on the Company’s website shortly after the webcast by calling 1-888-390-0541 (toll free in the U.S. and Canada) and by entering the code 179864#. The recording will be available until March 31, 2022.

Selected Summary Financial Information:


$000’s, except per share data	Year ended December 31, 2021		Year ended December 31, 2020		Year ended December 31, 2019
Total revenues	$	3,184	$	1,658	$	5,865
Gross profit (loss)	1,370		14		(12,433)
Operating profit (loss)	(35,425)		(24,627)		(40,581)
Net income (loss) attributable to the company	1,541		(27,776)		(37,978)
Basic and diluted net income (loss) per common share	0.01		(0.23)		(0.40)


$000’s	As at December 31, 2021		As at December 31, 2020
Financial Position:
Working capital	$	143,190	$	40,158
Property, plant and equipment, net	21,983		23,621
Mineral properties, net	83,539		83,539
Total assets	315,446		183,236
Total long-term liabilities	13,805		13,376

Financial Discussion:

At December 31, 2021, the Company had $143.2 million of working capital, including $113.0 million of cash and marketable securities and $30.8 million of inventory, including approximately 691,000 pounds of uranium and 1,650,000 pounds of vanadium, both in the form of immediately marketable product. The spot price of U₃O₈ at March 11, 2022 was $58.50 per pound, according to TradeTech (up from $42.00 per pound at December 31, 2021. The current mid-point spot price of V₂O₅ at March 11, 2022 was $12.25 per pound after remaining relatively flat near the 2021 year-end, according to FastMarkets. Based on today’s spot prices, the Company’s December 31, 2021 uranium and vanadium inventories would have a current market value of $40.4 million and $20.2 million, respectively, totaling approximately $60.6 million. On October 27, 2021, the Company completed the sale of certain non-core conventional assets to CUR. In addition to receiving $2 million cash at closing, the Company now holds 19.1% of the outstanding shares of CUR as of December 31, 2021, for a total value to the Company of $32.2 million as at December 31, 2021.

During the year ended December 31, 2021, the Company realized net income of $1.5 million, compared to a net loss of $27.9 for the year ended December 31, 2020. The net income in 2021 was primarily due to the sale of non-core conventional uranium assets to CUR. The Company spent $10.75 million for development of the Company’s properties, primarily due to the development and ramping up of the RE Carbonate production program at the Mill. The Company also incurred underutilized capacity production costs applicable to rare earth concentrates during the year of $0.53 million. The underutilized capacity production costs are due to low throughput rates as the Mill ramps-up to commercial-scale production at full capacity. To date, the Mill has focused on producing commercially salable RE Carbonate at low throughput rates and has been very pleased with the resulting product it is shipping for separation. The Mill expects to increase its throughput rates as its supplies of monazite sands increase. The Company is in advanced discussions with several additional sources of monazite sands that, if successfully secured, we expect to result in sufficient throughput to reduce underutilized capacity production costs and allow the Company to realize its expected margins on a continuous basis.

Rare Earth Achievements in 2021 and To Date in 2022:

On March 1, 2021, the Company and Neo Performance Materials Limited (“Neo“) announced a new rare earth production initiative spanning European and North American critical material supply chains. Under an agreement in principle signed on March 1, 2021 and finalized into a definitive agreement in July 2022, Energy Fuels will process natural monazite sands, currently being mined in the state of Georgia by The Chemours Company, into an RE Carbonate at the Mill and ship a portion of the produced RE Carbonate to Neo’s rare earth separations facility in Sillamäe, Estonia (“Silmet“). Silmet will then process the RE Carbonate into separated rare earth materials for use in rare earth permanent magnets and other rare earth-based advanced materials.

On July 7, 2021, the Company announced that the first container (approximately 20 tonnes of product) of an expected 15 containers of mixed RE Carbonate had been successfully produced by Energy Fuels at the Mill and was en route to Silmet. This commercial-scale production of RE Carbonate by Energy Fuels from a U.S. mined rare earth resource positions Energy Fuels as the only company in North America that currently produces a monazite-derived, enhanced rare earth material. The physical delivery of this product also represents the launch of a new, environmentally responsible rare earth supply chain that allows for source validation and tracking from mining through to final end-use applications for manufacturers in North America, Europe, Japan, and other nations.

The Company also announced on March 1, 2021 that, in addition to supplying RE Carbonate to Neo, Energy Fuels is evaluating the potential to develop U.S. separation capabilities at the Mill, or nearby, as it works to increase its monazite sand supplies, thereby fully integrating a U.S. rare earth supply chain in the coming years, in addition to supplying RE Carbonate to European markets. On April 27, 2021, the Company announced it had engaged Carester to prepare a scoping study for the development of a solvent extraction REE separation circuit at the Mill utilizing the Mill’s existing equipment and infrastructure to the extent applicable, to create a continuous, integrated and optimized rare earth production sequence. Based in Lyon, France, Carester is one of the world’s leading global consultants on rare earth supply chains, with expertise in designing, constructing, operating and optimizing REE production facilities globally. Carester’s scoping work included an evaluation of the Mill’s current monazite leaching process, preparation of an REE separation flow sheet, capital and operating expense estimates, incorporation of new technologies where applicable, and recommendations on equipment vendors. The Company is planning to install a full separation circuit at its White Mesa Mill to produce both “light” and “heavy” separated REE oxides in the coming years, subject to successful licensing, financing, and commissioning, and continued strong market conditions. The Company has hired Carester to perform a second scoping study to support these REE separation initiatives.

During Q1-2022, the Company began commercially separating La and Ce from its RE Carbonate on a small scale using an existing solvent extraction circuit at the Mill. This represents the first commercial level REE separation to occur in the U.S. in many years. The Company has been performing laboratory-scale REE separations for the last several months on a 24/7 basis, successfully executing the La, Ce, and NdPr separations at high-purities and with excellent recoveries.

On December 15, 2021, the Company announced the execution of an MOU with NSP for the development of a novel technology for the potential production of REE metals, subject to the finalization of definitive agreements. We believe this technology, which was initially developed by NSP, and will be advanced by the Company and NSP working together, has the potential to revolutionize the rare earth metal making industry by reducing costs of production, reducing energy consumption, and significantly reducing greenhouse gas emissions. Producing REE metals and alloys is a key step in a fully integrated REE supply chain, after production of separated REE oxides and before the manufacture of neodymium iron boron (“NdFeB“) magnets used in electric vehicles, wind generation and other clean energy and advanced technologies.

In addition, during 2022, the Company announced the execution of a non-binding memorandum of understanding (“MOU“) for the supply of natural monazite sands from IperionX Limited’s (“IperionX’s“, formerly known as Hyperion Metals Limited) Titan Project in Tennessee, if and when the project is developed and mined. IperionX’s Titan Project covers a large area of heavy mineral sands properties in Tennessee prospective for titanium, zircon, monazite and other valuable minerals such as high-grade silica sand and other refractory minerals.

In 2021, the Company also announced that the U.S. Department of Energy (“DOE“) Office of Fossil Energy and National Energy Technology Laboratory had exercised its option to award Energy Fuels, working with a team from Penn State University, an additional $1.75 million to complete a feasibility study on the production of REE products from natural coal-based resources, as well as from other materials such as REE-containing ores like the natural monazite sands the Company is currently processing at the Mill. This award follows the DOE providing Energy Fuels a $150,000 contract in 2020 for the successful completion of a conceptual design for the same initiative, resulting in a total award to Energy Fuels of $1.9 million.

Update on Medical Isotope Initiative:

On July 28, 2021, the Company announced the execution of a Strategic Alliance Agreement with RadTran, LLC, a technology development company focused on closing critical gaps in the procurement of medical isotopes for emerging TAT cancer therapeutics and other applications. Under this strategic alliance, the Company is evaluating the feasibility of recovering Th-232, and Ra-226 from its existing RE Carbonate and uranium process streams at the Mill and, together with RadTran, is evaluating the feasibility of recovering Ra-228 from the Th-232, Th-228 from the Ra-228 and concentrating Ra-226 at the Mill using RadTran technologies. Recovered Ra-228, Th-228 and Ra-226 would then be sold to pharmaceutical companies and others to produce Pb-212, Ac-225, Bi-213, Ra-224 and Ra-223, which are the leading medically attractive TAT isotopes for the treatment of cancer. Existing supplies of these isotopes for TAT applications are in short supply, and methods of production are costly and currently cannot be scaled to meet the demand created as new drugs are developed and approved. This is a major roadblock in the research and development of new TAT drugs as pharmaceutical companies wait for scalable and affordable production technologies to become available. Under this initiative, the Company has the potential to recover valuable isotopes from its existing process streams, therefore recycling back into the market material that would otherwise be lost to disposal for use in treating cancer.

Establishment of San Juan County Clean Energy Foundation:

On September 16, 2021, the Company announced its establishment of the San Juan County Clean Energy Foundation, a fund specifically designed to contribute to the communities surrounding the Mill in Southeastern, Utah. The Company made an initial deposit of $1 million into the Foundation and anticipates providing ongoing annual funding equal to 1% of the Mill’s future revenues, providing funding to support local economic development and local priorities. The Foundation will focus on supporting education, the environment, health/wellness, and local economic development in the City of Blanding, San Juan County, the White Mesa Ute Community, the Navajo Nation and other area communities.

Sale of Non-Core Assets to Consolidated Uranium Inc.:

On October 27, 2021, CUR and the Company jointly announced the closing of a transaction whereby CUR acquired a portfolio of Energy Fuels’ non-core conventional uranium projects located in Utah and Colorado, including the Daneros mine, the Tony M mine (formerly a part of the Henry Mountains Project), the Rim mine, the Sage Plain project, and several DOE leases located in Colorado, in consideration for a 19.9% share ownership interest in CUR (as of the 2021 year-end, 19.1%) and other consideration. The Company reported a gain on the value of this transaction of $35.7 million, resulting in a significant improvement in the Company’s results of operations and net income for 2021.

Proposed U.S. Uranium Reserve:

On December 27, 2020, Congress passed the COVID-Relief and Omnibus Spending Bill, which includes $75 million for the proposed establishment of a strategic U.S. Uranium Reserve (the “U.S. Uranium Reserve“) and was signed into law by the president then serving. This key funding opens the door for the U.S. government to purchase domestically produced uranium to guard against potential commercial and national security risks presented by the country’s near-total reliance on foreign imports of uranium. Russia’s recent invasion of Ukraine has raised concerns about the United States’ reliance on imports of Russian uranium and enrichment services, which could provide further impetus for the U.S. government to bring this program into effect.

The Company stands ready to benefit from this program through future production from its mines and facilities and potentially sales out of its existing uranium inventories. However, because the U.S. Uranium Reserve has yet to be established at this time, the details of implementation of activities pursuant to the new law have not yet been defined. As a result, there can be no certainty as to the outcome of the U.S. Uranium Reserve, including the process for and details of its development, and any resulting support for the Company’s ongoing and planned activities or for any further evaluations of the Working Group.

Appointment of New Director:

On January 25, 2022, the Board appointed Dr. Ivy Estabrooke as a Director of Energy Fuels, bringing to the Company experience in commercial-stage biotech, research and development program leadership, and technology solutions for national security and public health challenges. Dr. Estabrooke is currently the Vice President of Operations and Corporate Affairs at IDbyDNA Inc., a venture backed commercial stage biotech company. She has led innovative research and development programs in both the public and private sectors delivering technology solutions for national security and public health challenges. Prior roles include as a technical program manager for the U.S. Department of the Navy, the executive director of the State of Utah’s technology-based economic development agency, and science advisor to the Governor of Utah. She earned her doctorate in neuroscience at Georgetown University in 2005, received a master’s degree in national resource strategy from the National Defense University in 2013, and a bachelor’s degree in biological sciences from Smith College in 1998. Dr. Estabrooke is also an engaged member in her local community, serving on the board of the Girl Scouts of Utah and as a member of the Utah District Export Council.

Operations Update and Outlook for 2022:

Overview

The Company continues to believe that uranium supply and demand fundamentals point to higher sustained uranium prices in the future. In addition, Russia’s recent invasion of Ukraine and the recent entry into the uranium market by financial entities purchasing uranium on the spot market to hold for the long-term has the potential to result in higher sustained spot and term prices and, perhaps, induce utilities to enter into more long-term contracts with non-Russian producers like Energy Fuels to ensure security of supply and more certain pricing. However, the Company has not yet entered into sufficient long-term supply agreements to justify commencing uranium production at the Company’s mines and in-situ recovery (“ISR“) facilities. As a result, the Company expects to maintain uranium recovery at reduced levels until such time when sustained increased market strength is observed, additional suitable term sales contracts can be procured, or the U.S. government buys uranium from the Company following the establishment of the proposed U.S. Uranium Reserve. The Company also holds significant uranium inventories and is evaluating selling all or a portion of these inventories on the spot market in response to future upside price volatility or for delivery into contracts.

The Company will also continue to seek new sources of revenue, including through its emerging REE business, as well as new sources of other uranium-bearing materials not derived from conventional material and sourced by third parties (“Alternate Feed Materials“) and new fee processing opportunities at the White Mesa Mill that can be processed under existing market conditions (i.e., without reliance on current uranium sales prices). The Company is also seeking new sources of natural monazite sands for its emerging REE business, is evaluating the potential to recover radioisotopes for use in the development of TAT medical isotopes for the treatment of cancer, and continues its support of U.S. governmental activities to assist the U.S. uranium mining industry, including the proposed establishment of the U.S. Uranium Reserve.

Extraction and Recovery Activities Overview

During the year ended December 31, 2021, the Company did not package any significant quantities of its final uranium product, U₃O₈, at any of its facilities_.At the Mill, the Company focused on ramping up its mixed RE Carbonate production and produced approximately 120 tonnes of mixed RE Carbonate during 2021. The Company recovered small quantities of uranium at the Mill during 2021, but such uranium was retained in-circuit and was not packaged in 2021. The Company also continued to maintain its Nichols Ranch and Alta Mesa ISR facilities on standby.

During 2022, the Company plans to recover 100,000 to 120,000 pounds of uranium at the Mill. The Company does not plan to extract and/or recover any amounts of uranium of any significance from its Nichols Ranch Project in 2022, which was placed on standby in the second quarter of 2020 due to the depletion of its seven constructed wellfields. In addition, the Company expects to keep the Alta Mesa Project and its conventional mining properties on standby during 2022.

During 2022, the Company expects to recover approximately 650 to 1,000 tonnes of mixed RE Carbonate containing approximately 300 to 450 tonnes of TREO at the Mill, subject to the receipt of sufficient quantities of natural monazite ore. No vanadium production is currently planned during 2022, though the Company is currently evaluating potential vanadium production in light of recent market improvements in vanadium pricing.

ISR Activities

The Company expects to produce insignificant quantities of U₃O₈ in the year ending December 31, 2022 from Nichols Ranch. Until such time when market conditions improve sufficiently, suitable term sales contracts can be procured, or the proposed U.S. Uranium Reserve is established, the Company expects to maintain the Nichols Ranch Project on standby and defer development of further wellfields and header houses. The Company expects to continue to keep the Alta Mesa Project on standby until such time that market conditions improve sufficiently, suitable term sales contracts can be procured, or the proposed U.S. Uranium Reserve is established.

Conventional Activities

Conventional Extraction and Recovery Activities

During the year ended December 31, 2021, the Mill did not package any material quantities of U₃O₈, focusing instead on developing its REE recovery business. During the year ended December 31, 2021, the Mill produced approximately 270 tonnes of RE Carbonate, containing approximately 120 tonnes of TREO. The Mill recovered small quantities of uranium in 2021, which were retained in circuit. During 2022, the Company expects to recover 100,000 to 120,000 pounds of uranium at the Mill. The Company expects to recover approximately 650 to 1,000 tonnes of mixed RE Carbonate containing approximately 300 to 450 tonnes of TREO at the Mill, subject to the receipt of sufficient quantities of natural monazite ore. The Company is in advanced discussions with several sources of natural monazite sands, including the Company’s existing supplier, to secure additional supplies of monazite sands, which if successful, would be expected to allow the Company to increase RE Carbonate production. In addition to its 691,000 pounds of finished uranium inventories currently located at a North American conversion facility and at the Mill, the Company has approximately 355,000 pounds of U₃O₈ contained in stockpiled Alternate Feed Material and mineralized material inventory at the Mill that can be recovered relatively quickly in the future, as general market conditions may warrant (totaling about 1,046,000 pounds of U₃O₈ of total uranium inventory).

In addition, there remains an estimated 1.0 to 3.0 million pounds of solubilized recoverable V₂O₅ inventory remaining in tailings solutions awaiting future recovery, as market conditions may warrant.

Conventional Standby, Permitting and Evaluation Activities

During the year ended December 31, 2021, standby and environmental compliance activities continued at the Company’s fully permitted and substantially developed Pinyon Plain Project.

The Company is selectively advancing certain permits at its other major conventional uranium projects, such as the Roca Honda Project, which is a large, high-grade conventional project in New Mexico. The Company is also continuing to maintain required permits at its conventional projects, including the Sheep Mountain Project, La Sal Complex and Whirlwind Project. In addition, the Company will continue to evaluate the Bullfrog Project. All of these projects serve as important pipeline assets for the Company’s future conventional production capabilities, as market conditions may warrant.

Uranium Sales

During the year ended December 31, 2021, the Company elected not to complete any sales of uranium; however, the Company is now actively engaged in pursuing selective long-term uranium sales contracts with suitable quantities, pricing, and other terms.

Vanadium Sales

During the year ended December 31, 2021, the Company sold 5,000 pounds of ferrovanadium (“FeV“) for an average, weighted price of $14.74 per pound. The Company expects to sell the remaining finished vanadium product when justified into the metallurgical industry, as well as other markets that demand a higher purity product, including the aerospace, chemical, and potentially the vanadium battery industries.

Rare Earth Sales

The Company commenced its ramp-up to commercial production of a mixed RE Carbonate in March 2021 and has shipped all of its RE Carbonate produced to-date to Silmet, where it is currently being fed into their separation process. All RE Carbonate produced at the Mill in 2022 is expected to be sold to Neo for separation at Silmet. Until such time as the Company expects to permit and construct its own separation circuits at the Mill, production in future years is expected to be sold to Neo for separation at Silmet and, potentially, to other REE separation facilities outside the U.S. To the extent not sold, the Company expects to stockpile mixed RE Carbonate at the Mill for future separation and other downstream REE processing at the Mill or elsewhere.

As the Company continues to ramp up its mixed RE Carbonate production and additional funds are spent on process enhancements, improving recoveries, product quality and other optimization, profits from this initiative are expected to be minimal until such time when monazite throughput rates are increased and optimized. However, even at the current throughput rates, the Company is recovering most of its direct costs of this growing initiative, with the other costs associated with ramping up production, process enhancements and evaluating future separation capabilities at the Mill being expensed as development expenditures. Throughout this process, the Company is gaining important knowledge, experience and technical information, all of which will be valuable for current and future mixed RE Carbonate production and expected future production of separated REE oxides and other advanced REE materials at the Mill.

About Energy Fuels: Energy Fuels is a leading U.S.-based uranium mining company, supplying U₃O₈ to major nuclear utilities. The Company also produces vanadium from certain of its projects, as market conditions warrant, and is ramping up to full commercial-scale production of RE 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 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 produce vanadium when market conditions warrant, as well as RE Carbonate from various uranium-bearing ores. The Nichols Ranch ISR Project is currently on standby and has a licensed capacity of 2 million pounds of U₃O₈ per year. The Alta Mesa ISR Project is also currently on standby. In addition to the above production facilities, Energy Fuels also has one of the largest S-K 1300 and 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.

Cautionary Note Regarding Forward-Looking Statements: This news release contains certain “Forward Looking Information” and “Forward Looking Statements” within the meaning of applicable United States and Canadian securities legislation, which may include, but are not limited to, statements with respect to: production and sales forecasts; costs of production; any expectation that the Company will continue to be ready to supply uranium into the proposed U.S. Uranium Reserve once it is established; scalability, and the Company’s ability and readiness to re-start, expand or deploy any of its existing projects or capacity to respond to any improvements in uranium market conditions or in response to the proposed U.S. Uranium Reserve; any expectation regarding any remaining dissolved vanadium in the Mill’s tailings facility solutions or the ability of the Company to recover any such vanadium at acceptable costs or at all; the ability of the Company to secure any new sources of Alternate Feed Materials or other processing opportunities at the Mill; expected timelines for the permitting and development of projects; the Company’s expectations as to longer term fundamentals in the market and price projections; any expectation that the Company will maintain its position as a leading uranium company in the United States; any expectation that the proposed U.S. Uranium Reserve will be implemented and if implemented the manner in which it will be implemented and the timing of implementation; any expectation with respect to timelines to production; any expectation that the Mill will be successful in producing RE Carbonate on a full-scale commercial basis; any expectation that Neo will be successful in separating the Mill’s RE Carbonate on a commercial basis; any expectation that Energy Fuels will be successful in developing U.S. separation, or other value-added U.S. REE production capabilities at the Mill, or otherwise; any expectation that the Company and Neo will be successful in jointly developing a fully integrated U.S.-European REE supply chain; any expectation that the Company will be successful in building a low-cost, fully integrated U.S. rare earth supply chain; any expectation with respect to the future demand for REEs; any expectation with respect to the quantities of monazite sands to be acquired by Energy Fuels, the quantities of RE Carbonate to be produced by the Mill or the quantities of contained TREO in the Mill’s RE Carbonate; any expectation that additional supplies of monazite sands will result in sufficient throughput at the Mill to reduce underutilized capacity production costs and allow the Company to realize its expected margins on a continuous basis; any expectation that the Company’s strategic venture with NSP to develop technology for the production of REE metals will be successful or that the technology has the potential to reduce the costs of production, energy consumption, or greenhouse gas emissions versus existing technologies; any expectation that IperionX’s Titan Project in Tennessee will be developed and mined, or that the Company will receive any monazite sands from the project; any expectation that the Company’s evaluation of thorium and radium recovery at the Mill will be successful; any expectation that the potential recovery of medical isotopes from any thorium and radium recovered at the Mill will be feasible; any expectation that any thorium, radium and other isotopes can be recovered at the Mill and sold on a commercial basis; any expectation as to the value to the Company of its ownership interest in CUR resulting from its sale of certain non-core assets in 2021; any expectation that the Company will be successful in completing one or more contracts for the sale of uranium to U.S. utilities; and any expectation that the Company will generate net income in future periods. Generally, these forward-looking statements can be identified by the use of forward-looking terminology such as “plans,” “expects,” “does not expect,” “is expected,” “is likely,” “budgets,” “scheduled,” “estimates,” “forecasts,” “intends,” “anticipates,” “does not anticipate,” or “believes,” or variations of such words and phrases, or state that certain actions, events or results “may,” “could,” “would,” “might” or “will be taken,” “occur,” “be achieved” or “have the potential to.” All statements, other than statements of historical fact, herein are considered to be forward-looking statements. Forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements express or implied by the forward-looking statements. Factors that could cause actual results to differ materially from those anticipated in these forward-looking statements include risks associated with: commodity prices and price fluctuations; processing and mining difficulties, upsets and delays; permitting and licensing requirements and delays; changes to regulatory requirements; legal challenges; the availability of sources of Alternate Feed Materials and other feed sources for the Mill; competition from other producers; public opinion; government and political actions; the appropriations for the proposed U.S. Uranium Reserve not being allocated to that program and the U.S. Uranium Reserve not being implemented; the manner in which the proposed U.S. Uranium Reserve, if established, will be implemented; the Company not being successful in selling any uranium into the proposed U.S. Uranium Reserve at acceptable quantities or prices, or at all; available supplies of monazite sands; the ability of the Mill to produce RE Carbonate to meet commercial specifications on a commercial scale at acceptable costs; the ability of Neo to separate the RE Carbonate produced by the Mill to meet commercial specifications on a commercial scale at acceptable costs; market factors, including future demand for REEs; the ability of the Mill to be able to separate thorium and radium at reasonable costs or at all; the ability of the Company and RadTran to be able to recover other isotopes from thorium and radium recovered at the Mill at reasonable costs or at all; market prices and demand for medical isotopes; and the other factors described under the caption “Risk Factors” in the Company’s most recently filed Annual Report on Form 10-K, which is available for review on EDGAR at www.sec.gov/edgar.shtml, on SEDAR at www.sedar.com, and on the Company’s website at www.energyfuels.com. Forward-looking statements contained herein are made as of the date of this news release, and the Company 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. The Company assumes no obligation to update the information in this communication, except as otherwise required by law.

SOURCE Energy Fuels Inc.

Energy Fuels Announces 2021 Results, Including Net Profits, Strong Cash Position, and Market-Leading U.S. Uranium, Rare Earth and Vanadium Position

Posted on March 16, 2022 by Admin

Energy Fuels Announces 2021 Results, Including Net Profits, Strong Cash Position, and Market-Leading U.S. Uranium, Rare Earth and Vanadium Position

Research, News, and Market Data on Energy Fuels

Highlights:

Energy Fuels reported a net income of $1.5 million for 2021.
At December 31, 2021, the Company had a robust balance sheet with $143.2 million of working capital, including $113.0 million of cash and marketable securities, $30.8 million of inventory, and no short term (or long term) debt. At current commodity prices, the Company’s December 31, 2021 product inventory would have a value of approximately $60.6 million.
During 2021, prices for all the commodities Energy Fuels produces, or has the ability to produce, rose significantly. Uranium oxide (“U₃O₈“) prices increased approximately 38%, neodymium-praseodymium oxide (“NdPr“) prices increased approximately 112%, and vanadium oxide (“V₂O₅“) prices increased approximately 62%. Prices for each of these commodities have continued to show significant strength to date in 2022. The Company continues to closely follow developments related to Russia’s invasion of Ukraine, as Russia is a major supplier of uranium and nuclear fuel to U.S. and European customers. Prices of uranium have risen sharply in recent days.
While the Company chose to not sell any uranium during 2021, it is now actively engaged in pursuing selective long-term uranium sales contracts.
The Company produced approximately 270 metric tonnes of mixed rare earth element (“REE“) carbonate (“RE Carbonate“), containing 120 metric tonnes of total rare earth oxides (“TREO“) during 2021, as it commenced ramping up its REE recovery infrastructure. Energy Fuels’ RE Carbonate is the most advanced REE material being produced in the U.S. today.
The Company is currently in active discussions with several sources of natural monazite sands around the world to significantly increase the supply of feed for its growing REE initiative.
During Q1-2022, the Company began commercially separating Lanthanum (La) and Cerium (Ce) on a small scale from its RE Carbonate, using an existing solvent extraction circuit at the Mill. This represents the first commercial level REE separation to occur in the U.S. in many years.
The Company is planning to install a full separation circuit at its White Mesa Mill (the “Mill“) to produce both “light” and “heavy” separated REE oxides in the coming years, subject to successful licensing, financing, and commissioning, and continued strong market conditions. The Company has hired Carester SAS (“Carester“), a global leader in producing separated REE oxides, to support these REE separation initiatives.
On December 15, 2021, the Company announced a strategic venture with Nanoscale Powders LLC (“NSP“) for the development of a novel technology that would potentially produce REE metals. The technology has the potential to reduce the costs of production, energy consumption, and greenhouse gas emissions versus existing technologies.
In 2021, the Company sold small quantities of its existing V₂O₅ inventory to capitalize on recent market strength. The Company expects to continue to sell vanadium as prices increase and is evaluating the potential to resume vanadium recovery at the Mill, where its tailings pond solutions contain an estimated additional 1.0 to 3.0 million recoverable pounds of V₂O₅.
In July 2021, the Company announced the execution of a Strategic Alliance Agreement with RadTran, LLC to evaluate the potential recovery of thorium and radium from the Company’s existing RE Carbonate and uranium process streams for use in the production of medical isotopes for emerging targeted alpha therapy (“TAT“) cancer therapeutics. This initiative complements the Company’s existing uranium and RE Carbonate businesses, as it investigates the potential recovery of isotopes in existing process streams at the Mill for medical purposes.
In September 2021, the Company announced its establishment of the San Juan County Clean Energy Foundation (the “Foundation“), a fund specifically designed to contribute to the communities surrounding the Mill in southeastern Utah by providing funding to support local economic development and local priorities.
In October 2021, the Company completed the sale of certain, permitted non-core conventional uranium assets to Consolidated Uranium Inc. (“CUR”), including the Daneros mine, the Tony M mine, and the Rim mine. The Company reported a gain on the value of this transaction of $35.7 million, resulting in a significant improvement in the Company’s results of operations and net income for 2021.
On January 25, 2022, the Board appointed Dr. Ivy Estabrooke as a Director of Energy Fuels, bringing to the Company experience in commercial-stage biotech, research and development program leadership, and technology solutions for national security and public health challenges.

Mark S. Chalmers, Energy Fuels’ President and CEO, stated:

Webcast at 1:00 pm EDT on March 17, 2022:

Webcast Link

If you would like to participate in the webcast and ask questions, please dial in to 1-888-664-6392 (toll free in the U.S. and Canada).

Selected Summary Financial Information:


$000’s, except per share data	Year ended December 31, 2021		Year ended December 31, 2020		Year ended December 31, 2019
Total revenues	$	3,184	$	1,658	$	5,865
Gross profit (loss)	1,370		14		(12,433)
Operating profit (loss)	(35,425)		(24,627)		(40,581)
Net income (loss) attributable to the company	1,541		(27,776)		(37,978)
Basic and diluted net income (loss) per common share	0.01		(0.23)		(0.40)


$000’s	As at December 31, 2021		As at December 31, 2020
Financial Position:
Working capital	$	143,190	$	40,158
Property, plant and equipment, net	21,983		23,621
Mineral properties, net	83,539		83,539
Total assets	315,446		183,236
Total long-term liabilities	13,805		13,376

Financial Discussion:

Rare Earth Achievements in 2021 and To Date in 2022:

Update on Medical Isotope Initiative:

Establishment of San Juan County Clean Energy Foundation:

Sale of Non-Core Assets to Consolidated Uranium Inc.:

Proposed U.S. Uranium Reserve:

Appointment of New Director:

Operations Update and Outlook for 2022:

Overview

Extraction and Recovery Activities Overview

ISR Activities

Conventional Activities

Conventional Extraction and Recovery Activities

Conventional Standby, Permitting and Evaluation Activities

During the year ended December 31, 2021, standby and environmental compliance activities continued at the Company’s fully permitted and substantially developed Pinyon Plain Project.

Uranium Sales

Vanadium Sales

Rare Earth Sales

SOURCE Energy Fuels Inc.

InPlay Oil Corp. Announces Record Setting 2021 Financial, Operating and Reserves Results

Posted on March 16, 2022 by Admin

InPlay Oil Corp. Announces Record Setting 2021 Financial, Operating and Reserves Results

News and Market Data on InPlay Oil Corp

2021 Highlights:

Completed the acquisition of Prairie Storm Resources Corp. on November 30, 2022 at attractive transaction metrics which enhances InPlay’s position as a sizable producer and acreage holder with a deep and highly economic drilling inventory in the light oil window of Central Alberta’s Cardium fairway.
Achieved record average annual production of 5,768 boe/d⁽¹⁾ (65% light crude oil and NGLs), an increase of 45% from 2020 at 3,985 boe/d⁽¹⁾ (68% light crude oil and NGLs) and an increase of 15% compared to pre-COVID levels of 5,000 boe/d⁽¹⁾ (66% light crude oil and NGLs) in 2019. Annual average production per weighted average basic share increased 31% compared to 2020.
Generated record annual adjusted funds flow (“AFF”)⁽²⁾ of $47.0 million ($0.67 per weighted average basic share⁽³⁾), an increase of 532% compared to $7.4 million ($0.11 per weighted average basic share) in 2020 and an increase of 45% compared to $32.5 million ($0.48 per weighted average basic share) in 2019, our prior record year. Excluding the impact of realized hedging losses, AFF for 2021 would have been $59.9 million.
Increased operating netbacks⁽⁴⁾ by 203% to $34.63/boe from $11.45/boe in 2020 and 52% from $22.75/boe in 2019.
Realized annual record operating income⁽⁴⁾ and operating income profit margin⁽⁴⁾ of $72.9 million and 64% respectively compared to $16.7 million and 40% in 2020; $41.5 million and 55% in 2019.
Reduced operating expenses to an annual record $12.83/boe compared to $14.43/boe in 2020 and $14.36/boe in 2019, despite rising costs of services in the industry.
Generated annual free adjusted funds flow (“FAFF”)⁽⁴⁾ of $13.6 million.
Lowered annual net debt⁽²⁾ to earnings before interest, taxes and depletion (“EBITDA”)⁽⁴⁾ ratio to 1.5, compared to 6.7 in 2020 and 1.6 in 2019. Fourth quarter 2021 annualized net debt to EBITDA ratio was 1.1 compared to 4.0 in 2020 and 1.6 in 2019 achieving the lowest leverage ratios in our corporate history.
Achieved significant growth in reserves and reserves per weighted average basic share:
- Proved developed producing (“PDP”) reserves increased 64% (61% per weighted average basic share) to 15,890 mboe (58% light and medium crude oil & NGLs)
- Total proved (“TP”) reserves increased 112% (106% per weighted average basic share) to 45,891 mboe (62% light and medium crude oil & NGLs)
- Total proved plus probable (“TPP”) reserves increased 85% (81% per weighted average basic share) to 60,640 mboe (63% light and medium crude oil & NGLs)
Achieved record NPV BT10 reserve and net asset values (“NAV”)⁽⁶⁾:
- NPV BT10: $206 million (PDP), $471 million (TP) and $686 million (TPP)
- NAV: $1.85 per weighted average basic share (PDP), $4.92 per weighted average basic share (TP) and $7.41 per weighted average basic share (TPP)
- West Texas Intermediate (“WTI”) prices used in the Reserve Report to value the Company’s reserves are approximately 22% and 15% less than current strip pricing for 2022 (US $72.83 vs. approximately US $89.00) and 2023 (US $68.78 vs. approximately US $79.00) respectively.
Finding, Development and Acquisition (“FD&A”)⁽⁵⁾ costs, associated recycle ratios and capital efficiencies which are top tier amongst light oil weighted peers.
- FD&A⁽⁵⁾ costs of $8.47/boe (PDP), $12.03/boe (TP) and $9.56/boe (TPP), consistent with three year averages of $9.67/boe (PDP), $10.98/boe (TP) and $9.23 (TPP).
- Recycle ratios⁽⁵⁾ of 4.1 (PDP), 2.9 (TP) and 3.6 (TPP) compared to 1.2 (PDP), 2.0 (TP) and 1.4 (TPP) in 2020.
- InPlay added new light oil weighted production at a capital efficiency⁽⁵⁾ of $12,583 per boe/d.
Materially increased the reserve life index of our assets which in turn improves the long term sustainability of the Company:
- PDP reserve life index⁽⁵⁾ of 7.5 years compared to 6.6 years in 2020
- TP reserve life index of 21.8 years compared to 14.8 years in 2020
- TPP reserve life index of 28.8 years compared to 22.5 years in 2020
Successful development and A&D activity resulting in top-tier reserve replacement⁽⁵⁾:
- PDP replacement of 395% (2020 – 166%)
- TP replacement of 1,253% (2020 – 309%)
- TPP replacement of 1,422% (2020 – 479%)
Increased liquidity through an increased capacity within our Senior Credit Facility from $65.0 million to $85.0 million and total debt capacity of $111 million.
Abandonment and Reclamation Obligations spending of $2.3 million, reducing our liability by 3% through the successful abandonment of 75 wellbores and the reclamation of 22 well sites.
Achieved a 20% reduction to the Company’s emissions (Scope 1 and 2) on a per boe basis compared to 2020.

Notes:

See “Reader Advisories – Production Breakdown by Product Type”
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
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”.
“FD&A”, “recycle ratio”, “reserve replacement”, “reserve life index” and “capital efficiency” do not have standardized meanings and therefore may not be comparable to similar measures presented for other entities. Refer to section “Performance Measures” for the determination and calculation of these measures.
See “Corporate Reserves Information” and “Net Asset Value” for detailed information from the Reserve Report and associated calculations.

Message to Shareholders:

Notes:

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”.
See “Production Breakdown by Product Type” at the end of this press release.

2022 Outlook Update

2022	US$70 WTI	US$80 WTI	US$90 WTI	US$100 WTI	US$110 WTI
Production (boe/d)⁽¹⁾⁽²⁾	9,150	9,150	9,150	9,150	9,150
Debt adjusted prod. per share growth (%)⁽³⁾	67%	79%	90%	102%	109%
AFF ($ millions)⁽⁴⁾	$121	$134	$146	$156	$162
FAFF ($ millions)⁽³⁾	$63	$76	$88	$98	$104
FAFF Yield (%)⁽³⁾⁽⁶⁾	24%	29%	33%	37%	40%
Year-end Working Capital / (Net Debt) ($ millions)⁽⁴⁾	($19)	($6)	$6	$16	$22
Annual Net Debt / EBITDA⁽³⁾	0.2	0.0	0.0	(0.1)	(0.1)
EV / DAAFF⁽³⁾⁽⁶⁾	2.2	1.9	1.7	1.5	1.4

Notes:

See “Production Breakdown by Product Type” at the end of this press release.
This reflects the mid-point of the Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.
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”.
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release. .
See “Reader Advisories – Forward Looking Information and Statements” for key budget and underlying assumptions related to our 2022 capital program and associated guidance.
Assumes a share price of $3.06.

Operations Update

	IP 30 (% light crude oil and NGLs)	Current (% light crude oil and NGLs)
1.5 mile well	593 boe/d (80%)	368 boe/d (77%)
1.0 mile well	203 boe/d (83%)	165 boe/d (78%)

IP 15 (% light crude oil and NGLs)	Current (% light crude oil and NGLs)
1,022 boe/d (79%)	1,354 boe/d (71%)

Current corporate production is approximately 9,050 boe/d⁽¹⁾ (62% light crude oil and NGLs), based on field estimates.

Notes:

See “Production Breakdown by Product Type” at the end of this press release.
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”.

Financial and Operating Results:

(CDN) ($000’s)	Three months ended December 31				Year ended December 31
	2021		2020		2021		2020
Financial
Oil and natural gas sales	37,255		12,829		113,854		41,934
Adjusted funds flow⁽¹⁾	17,149		3,291		47,028		7,436
Per share – basic⁽²⁾	0.23		0.05		0.67		0.11
Per share – diluted⁽²⁾	0.22		0.05		0.66		0.11
Per boe⁽²⁾	27.87		8.40		22.34		5.10
Comprehensive income (loss)	55,191		(3,227	)	115,071		(112,629	)
Per share – basic	0.74		(0.05	)	1.65		(1.65	)
Per share –diluted	0.71		(0.05	)	1.61		(1.65	)
Capital expenditures – PP&E and E&E	6,024		10,633		33,434		23,134
Property acquisitions (dispositions)	–		1,875		(84	)	1,610
Net Corporate acquisitions⁽³⁾⁽⁴⁾	38,287		–		38,287		–
Net debt⁽¹⁾	(80,196	)	(73,681	)	(80,196	)	(73,681	)
Shares outstanding	86,214,751		68,256,616		86,214,751		68,256,616
Basic weighted-average shares	74,338,118		68,256,616		69,798,836		68,256,616
Diluted weighted-average shares	77,669,551		68,256,616		71,681,264		68,256,616

Operational
Daily production volumes
Light and medium crude oil (bbls/d)	3,156		2,194		2,981		2,031
Natural gas liquids (boe/d)	932		708		782		668
Conventional natural gas (Mcf/d)	15,589		8,141		12,030		7,715
Total (boe/d)	6,687		4,259		5,768		3,985
Realized prices⁽²⁾
Light and medium crude oil & NGLs ($/bbls)	79.83		40.41		70.08		35.90
Conventional natural gas ($/Mcf)	5.04		2.72		4.01		2.29
Total ($/boe)	60.56		32.74		54.08		28.75
Operating netbacks ($/boe)⁽⁴⁾
Oil and natural gas sales	60.56		32.74		54.08		28.75
Royalties	(7.53	)	(1.78	)	(5.51	)	(2.00	)
Transportation expense	(1.09	)	(0.80	)	(1.11	)	(0.87	)
Operating costs	(12.51	)	(14.35	)	(12.83	)	(14.43	)
Operating netback⁽⁴⁾	39.43		15.81		34.63		11.45
Realized (loss) on derivative contracts	(5.67	)	(0.38	)	(6.20	)	(0.82	)
Operating netback (including realized derivative contracts)⁽⁴⁾	33.76		15.43		28.43		10.63

(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)		This amount consists of total gross consideration of $49.9, net of $11.6 million in working capital balances assumed on closing of the Prairie Storm acquisition.
(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”

2021 Financial & Operations Overview:

Note:

See “Reader Advisories – Production Breakdown by Product Type”
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”.

2021 Reserves Overview:

Note:

See “Net Asset Value” for detailed calculations.

Corporate Reserves Information:

December 31, 2021	Light and Medium		Conventional	Oil	BTAX NPV	Future Development	Net Undeveloped
Reserves Category^(1)(2)(3)(4)⁽⁵⁾	Crude Oil	NGLs	Natural Gas	Equivalent	10%	Capital	Wells
Reserves Category^(1)(2)(3)(4)⁽⁵⁾	Mbbl	Mbbl	MMcf	MBOE	($000’s)	($000’s)	Booked

Proved developed producing	6,224.8	2,972.1	40,156	15,889.6	206,481	287	–
Proved developed non-producing	595.9	254.1	3,191	1,381.9	19,464	3,617	–
Proved undeveloped	14,151.6	4,028.9	62,633	28,619.3	245,156	412,786	179.2
Total proved	20,972.4	7,255.2	105,979	45,890.7	471,100	416,690	179.2
Probable developed producing	1,467.2	713.3	9,611	3,782.3	39,024	8	–
Probable developed non-producing	153.9	74.1	867	372.6	4,298	–	–
Probable undeveloped	6,159.6	1,260.0	19,048	10,594.3	171,090	57,533	25.8
Total probable	7,780.6	2,047.5	29,526	14,749.2	214,412	57,541	25.8
Total proved plus probable⁽⁶⁾	28,753.0	9,302.6	135,505	60,639.9	685,513	474,232	205.0

Notes:

Reserves have been presented on a gross basis which are the Company’s total working interest (operating and non-operating) share before the deduction of any royalties and without including any royalty interests of the Company.
Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2021, as outlined in the table herein entitled “Pricing Assumptions”.
It should not be assumed that the NPV amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of InPlay’s light and medium crude oil, natural gas liquids and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual light and medium crude oil, conventional natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment, decommissioning and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.
The Company has included abandonment, decommissioning and reclamation costs for all active and inactive assets including non-producing and suspended wells, facilities and pipelines. December 31, 2021 reserve NPV values are also inclusive of currently enacted carbon taxes.
Totals may not add due to rounding.

Net Asset Value:


December 31, 2021	BTAX NPV 5%				BTAX NPV 10%
	($000’s)		$/share⁽⁶⁾		($000’s)		$/share⁽⁶⁾
PDP NPV⁽¹⁾⁽²⁾	226,629		2.63		206,481		2.39
Undeveloped acreage⁽³⁾	33,474		0.39		33,474		0.39
Net debt⁽⁴⁾⁽⁵⁾	(80,196	)	(0.93	)	(80,196	)	(0.93	)
Net Asset Value (basic)	179,907		2.09		159,759		1.85


December 31, 2021	BTAX NPV 5%				BTAX NPV 10%
	($000’s)		$/share⁽⁶⁾		($000’s)		$/share⁽⁶⁾
TP NPV⁽¹⁾⁽²⁾	608,756		7.06		471,100		5.46
Undeveloped acreage⁽³⁾	33,474		0.39		33,474		0.39
Net debt⁽⁴⁾⁽⁵⁾	(80,196	)	(0.93	)	(80,196	)	(0.93	)
Net Asset Value (basic)	562,034		6.52		424,378		4.92


December 31, 2021	BTAX NPV 5%				BTAX NPV 10%
	($000’s)		$/share⁽⁶⁾		($000’s)		$/share⁽⁶⁾
TPP NPV⁽¹⁾⁽²⁾	904,526		10.49		685,513		7.95
Undeveloped acreage⁽³⁾	33,474		0.39		33,474		0.39
Net debt⁽⁴⁾⁽⁵⁾	(80,196	)	(0.93	)	(80,196	)	(0.93	)
Net Asset Value (basic)	857,804		9.95		638,791		7.41

Notes:

Evaluated by Sproule as at December 31, 2021. The estimated NPV does not represent fair market value of the reserves.
Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2021.
Duvernay land holdings attributed a value of $19.9 million ($847/acre) for 23,440 net acres based on internal valuations. The remaining undeveloped acreage is based on an internal valuation totaling $13.6 million ($256/acre) for 53,159 net acres. These internal valuations are based on land sale results in the area.
Net debt as at December 31, 2021.
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
Based upon 86,214,751 common shares outstanding as at December 31, 2021.

Future Development Costs (“FDCs”):

FDCs increased by $246.9 million on a Total Proved basis and $215.7 million on a Total Proved plus Probable basis.

Future Development Capital Costs (amounts in $million)
	Total Proved	Total Proved + Probable
2022	58.9	66.6
2023	99.2	111.7
2024	100.5	114.0
2025	95.3	110.5
Remainder	62.7	71.4
Total undiscounted FDC	416.7	474.2
Total discounted FDC at 10% per year	332.4	377.8

Note: FDC as per Reserve Report based on forecast pricing as outlined in the table herein entitled “Pricing Assumptions”

Performance Measures:

	2019	2020	2021	3 Year Avg
Average WTI crude oil price (US$/bbl)	57.02	39.40	67.91	54.78
Capital expenditures – PP&E and E&E ($000’s)⁽¹⁾	30,689	22,213	33,434	–
Production boe/d – FY⁽³⁾	5,000	3,985	5,768	4,918
Production boe/d – Q4⁽³⁾	4,998	4,259	6,687	5,315
Operating netback $/boe – FY⁽²⁾	22.75	11.45	34.63	24.32
Proved Developed Producing
Total Reserves mboe	8,718	9,677	15,890	11,428
Reserves additions mboe	2,195	2,418	8,318	12,930
FD&A (including FDCs) $/boe⁽¹⁾	13.98	9.85	8.47	9.67
FD&A (excluding FDCs) $/boe⁽¹⁾	13.98	9.85	8.47	9.67
Recycle Ratio⁽⁴⁾	1.6	1.2	4.1	2.5
Reserves Replacement⁽⁵⁾	120%	166%	395%	240%
RLI (years)⁽⁶⁾	4.8	6.6	7.5	6.4
Total Proved
Total Reserves mboe	18,573	21,624	45,891	28,696
Reserves additions mboe	1,540	4,509	26,372	32,421
FD&A (including FDCs) $/boe⁽¹⁾	7.92	5.86	12.03	10.98
FD&A (excluding FDCs) $/boe⁽¹⁾	19.93	5.28	2.67	3.86
Recycle Ratio⁽⁴⁾	2.9	2.0	2.9	2.2
Reserves Replacement⁽⁵⁾	84%	309%	1,253%	602%
RLI (years)⁽⁶⁾	10.2	14.8	21.8	16.0
Proved Plus Probable
Total Reserves mboe	27,295	32,816	60,640	40,250
Reserves additions mboe	2,057	6,980	29,929	38,965
FD&A (including FDCs) $/boe⁽¹⁾	7.82	8.21	9.56	9.23
FD&A (excluding FDCs) $/boe⁽¹⁾	14.92	3.41	2.36	3.21
Recycle Ratio⁽⁴⁾	2.9	1.4	3.6	2.6
Reserves Replacement⁽⁵⁾	113%	479%	1,422%	723%
RLI (years)⁽⁶⁾	15.0	22.5	28.8	22.4

Notes:

Finding, Development & Acquisition (“FD&A”) costs are used as a measure of capital efficiency. The calculation includes the period’s capital expenditures, including Exploration and Development (“E&D”) and Acquisition and Disposition (“A&D”) expended in the year, less capitalized G&A expenses and undeveloped land expenditures acquired with no reserves. This total of capital expenditures, including the change in the FDC over the period, is then divided by the change in reserves, other than from production, for the period incorporating additions/reductions from extensions, infill drilling, technical revisions, acquisitions/dispositions and economic factors. For example: 2021 TPP = ($33.4 million E&D – $1.2 million capitalized G&A – $nil million of land acquisitions + $38.2 million net acquisition/disposition capital + $215.8 million FDC) / (60,640 mboe – 32,816 mboe + 2,105 mboe) = $9.56 per boe. Finding and Development Costs (“F&D”) are calculated the same as FD&A costs, however adjusted to exclude the capital expenditures and reserve additions/reductions from acquisition/disposition activity. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
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”
See “Reader Advisories – Production Breakdown by Product Type”
Recycle Ratio is calculated by dividing the year’s operating netback per boe by the FD&A costs for that period. For example: 2021 TPP = ($34.63/$9.56) = 3.6. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year. For example: 2021 TPP = (60,640 mboe – 32,816 mboe + 2,105 mboe) / 2,105 mboe = 1422%, which reflects the extent to which the Company was able to replace production and add reserves throughout the year. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
RLI is calculated by dividing the reserves in each category by the 2021 average annual production. For example 2021 TPP = (60,640 mboe) / (5,768 boe/day) = 28.8 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
Capital Efficiency is calculated as the total annual exploration & development and acquisition and disposition capital expended in the year, less capitalized G&A and land acquisition costs divided by production additions comparing the fourth quarter of the previous year using a decline rate of 29% over the course of the year, calculated as follows: ($33.4 million E&D – $1.2 million capitalized G&A – $nil million of land acquisitions – $0.1 million net acquisition/disposition capital + $9.2 million of 2020 capital adding reserves in 2021 – $3.0 million of capital not adding reserves in 2021) / (Q4/2021 production of 6,687 boe/d – Q4/2020 production of 4,259 boe/d + 2021 declined production at 29% of 1,218 boe/d – Q4/2021 Prairie Storm production of 600 boe/d). See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.

Pricing Assumptions:

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS⁽¹⁾
as of December 31, 2021
FORECAST PRICES AND COSTS

Year	WTI Cushing Oklahoma ($US/Bbl)	Canadian Light Sweet 40^oAPI ($Cdn/Bbl)	Cromer LSB 35^o API ($Cdn/Bbl)	Natural Gas AECO-C Spot ($Cdn/ MMBtu)	NGLs Edmonton Propane ($Cdn/Bbl)	NGLs Edmonton Butanes ($Cdn/Bbl)	Edmonton Pentanes Plus ($Cdn/Bbl)	Operating Cost Inflation Rates %/Year	Capital Cost Inflation Rates %/Year	Exchange Rate⁽²⁾ ($Cdn/$US)
Forecast⁽³⁾
2022	72.83	86.82	87.30	3.56	43.38	57.49	91.85	0.0%	0.0%	0.80
2023	68.78	80.73	82.30	3.21	35.92	50.17	85.53	2.3%	2.3%	0.80
2024	66.76	78.01	79.69	3.05	34.62	48.53	82.98	2.0%	2.0%	0.80
2025	68.09	79.57	81.29	3.11	35.31	49.50	84.63	2.0%	2.0%	0.80
2026	69.45	81.16	82.92	3.17	36.02	50.49	86.33	2.0%	2.0%	0.80
2027	70.84	82.78	84.50	3.23	36.74	51.50	88.05	2.0%	2.0%	0.80
2028	72.26	84.44	86.27	3.30	37.47	52.53	89.82	2.0%	2.0%	0.80
2029	73.70	86.13	87.99	3.36	38.22	53.58	91.61	2.0%	2.0%	0.80
2030	75.18	87.85	89.75	3.43	38.99	54.65	93.44	2.0%	2.0%	0.80
2031	76.68	89.61	91.55	3.50	39.77	55.74	95.32	2.0%	2.0%	0.80
2032	78.21	91.40	93.38	3.57	40.56	56.86	97.22	2.0%	2.0%	0.80
	Thereafter Escalation rate of 2.0%

Notes:

This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
The exchange rate used to generate the benchmark reference prices in this table.
As at December 31, 2021.

Environmental, Social and Governance (“ESG”) Update

For further information please contact:

Doug Bartole		Darren Dittmer
President and Chief Executive Officer		Chief Financial Officer
InPlay Oil Corp.		InPlay Oil Corp.
Telephone: (587) 955-0632		Telephone: (587) 955-0634

Reader Advisories

Non-GAAP and Other Financial Measures

Non-GAAP Financial Measures and Ratios

Free Adjusted Funds Flow / FAFF per share

(thousands of dollars)	Three Months Ended December 31				Year Ended December 31
	2021		2020		2021		2020
Adjusted funds flow	17,149		3,291		47,028		7,436
Exploration and dev. capital expenditures	(6,024	)	(10,633	)	(33,434	)	(23,134	)
Property dispositions (acquisitions)	–		(1,875	)	84		(1,610	)
Free adjusted funds flow	11,125		(9,217	)	13,678		(17,308	)
Weighted average outstanding shares	74.3		68.3		69.8		68.3
FAFF per share	0.15		(0.14	)	0.20		(0.25	)

Free Adjusted Funds Flow Yield

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

(thousands of dollars)	Three Months Ended December 31				Year Ended December 31
	2021		2020		2021		2020
Revenue	37,255		12,829		113,854		41,934
Royalties	(4,632	)	(697	)	(11,595	)	(2,924	)
Operating expenses	(7,695	)	(5,622	)	(27,009	)	(21,043	)
Transportation expenses	(673	)	(314	)	(2,346	)	(1,271	)
Operating income	24,255		6,196		72,904		16,696

Sales volume (Mboe)	615.2		391.8		2,105.1		1,458.5
Per boe
Revenue	60.56		32.74		54.08		28.75
Royalties	(7.53	)	(1.78	)	(5.51	)	(2.00	)
Operating expenses	(12.51	)	(14.35	)	(12.83	)	(14.43	)
Transportation expenses	(1.09	)	(0.80	)	(1.11	)	(0.87	)
Operating netback per boe	39.43		15.81		34.63		11.45
Operating income profit margin	65	%	48	%	64	%	40	%

(thousands of dollars)	Year Ended December 31
	2021	2020
Net debt	80,196	73,681
Adjusted funds flow	47,028	7,436
Interest expense (Credit Facility and other)	5,594	3,523
Interest expense (Lease liabilities)	20	47
Earnings before interest, taxes and depletion (“EBITDA”)	52,642	11,006
Net Debt to EBITDA	1.5	6.7

(thousands of dollars)	Three Months Ended December 31			Year Ended December 31
	2021		2020	2021		2020
Corporate acquisitions, net of cash acquired	29,277		–	29,277		–
Share consideration⁽¹⁾	9,985		–	9,985		–
Non-cash working capital acquired	(1,156	)	–	(1,156	)	–
Derivative contracts	181		–	181		–
Net Corporate acquisitions	38,287		–	38,287		–

(1)		For purposes of the corporate acquisition, the share consideration had a negotiated value of $1.20 per share. For accounting purposes in accordance with IFRS 3, the shares issued as consideration have been valued at $2.07 per share, based on the closing price of InPlay shares on November 29, 2021.
(2)		Net working capital acquired equals the fair value of cash and cash equivalents, accounts receivable and accrued liabilities, prepaid expenses and deposits, inventory, accounts payable and accrued liabilities and derivative contracts acquired as disclosed in note 5 of the Company’s consolidated financial statements.

Production per Debt Adjusted Share

Capital Management Measures

Adjusted Funds Flow

Net Debt

Supplementary Measures

“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.

InPlay’s 2021 annual guidance and a comparison to 2021 actual results are outlined below.

		2021 Guidance⁽¹⁾	2021 Actual	Variance	Variance (%)
Production⁽⁶⁾	Boe/d	5,750 – 6,000	5,768	–	–
Adjusted Funds Flow⁽⁷⁾	$ millions	$51.0 – $54.0	$47.0	($5)⁽³⁾	(7%)
Capital Expenditures	$ millions	$32.5⁽²⁾	$33.4	$1⁽⁴⁾	3%
Free Adjusted Funds Flow⁽⁸⁾	$ millions	$17.5 – $20.5	$13.6	($4)⁽³⁾⁽⁴⁾	(20%)
Net Debt⁽⁶⁾	$ millions	$76.5 – $79.5	$80.2	$1^(3)(4)(5)	1%

Notes:

As previously released September 28, 2021.
As previously released November 30, 2021 (previously $32.5 – $34.5 million on September 28, 2021).
This variance is due to the following:
- Lower fourth quarter sales volumes due to operational downtime caused by extreme cold, third party processing facility mechanical shut downs, a larger build in period ending oil inventories of approximately 9,000 barrels, and the later than initially expected drilling of the two well pad drilled in the fourth quarter of 2021. In addition, new production from the 2021 drilling program had a slightly higher gas weighting and lower NGL yield than forecasted.
- The effect of shorter royalty incentive periods for recently drilled wells in the improved pricing environment and higher trucking costs on new wells.
- Significant improvements in the Company’s share price in the later portion of 2021, resulting in additional expenses incurred from the vesting and revaluation of deferred share units, and the accelerated vesting of certain DSUs.
- Increased hedging losses as a result of higher annual average WTI prices of US $1.06/bbl.
This variance is due to the acceleration of the start of the 2022 capital program at the end of 2021 through the initiation of lease construction and starting drilling activities on a three well pad in Pembina due to optimal conditions and availability of services.
This net debt variance is due to the higher positive net debt assumed on the Prairie Storm acquisition in addition to additional proceeds from the over-allotment option being exercised on the bought deal financing which both contributed to an additional $3 million positive net debt impact, net of the $4 million reduction to free adjusted funds flow.
See “Reader Advisories – Production Breakdown by Product Type”
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
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”

		Actuals FY 2021	Previous Guidance FY 2022⁽¹⁾	Updated Guidance FY 2022
WTI	US$/bbl	$67.91	$72.50	$90.00
NGL Price	$/boe	$37.79	$42.75	$52.35
AECO	$/GJ	$3.44	$3.30	$4.30
Foreign Exchange Rate	CDN$/US$	0.80	0.78	0.80
MSW Differential	US$/bbl	$3.88	$3.50	$3.00
Production	Boe/d	5,768	8,900 – 9,400	8,900 – 9,400
Royalties	$/boe	5.51	5.25 – 5.75	9.80 – 10.60
Operating Expenses	$/boe	12.83	10.00 – 13.00	10.00 – 13.00
Transportation	$/boe	1.11	0.85 – 1.10	0.85 – 1.10
Interest	$/boe	2.67	0.85 – 1.25	0.75 – 1.15
General and Administrative	$/boe	2.83	2.00 – 2.60	2.00 – 2.60
Hedging loss	$/boe	6.20	0.00 – 0.20	0.35 – 0.65
Decommissioning Expenditures	$ millions	$1.4	$2.0 – $2.5	$2.0 – $2.5
Adjusted Funds Flow	$ millions	$47.0	$111.0 – $117.0	$141 – $150
Weighted average outstanding shares	# millions	69.8	86.2	86.2
Adjusted Funds Flow per share	$/share	0.67	1.28 – 1.36	1.64 – 1.75

		Actuals FY 2021	Previous Guidance FY 2022	Updated Guidance FY 2022
Adjusted Funds Flow	$ millions	$47.0	$111.0 – $117.0	$141 – $150
Capital Expenditures	$ millions	$33.3	$58.0	$58.0
Free Adjusted Funds Flow	$ millions	$13.6	$53.5 – $59.5	$83 – $92
Share outstanding, end of year	# millions	86.2		86.2
Assumed Share price	$	2.18⁽³⁾		3.06
Market capitalization	$ millions	$188		$264
FAFF Yield	%	7%	N/A⁽⁵⁾	31% – $35%

		Actuals FY 2021	Previous Guidance FY 2022⁽¹⁾	Updated Guidance FY 2022
Adjusted Funds Flow	$ millions	$47.0	$111.0 – $117.0	$141 – $150
Interest	$/boe	2.67	0.85 – 1.25	0.75 – 1.15
EBITDA	$ millions	$52.6	$115.0 – $120.0	$144 – $153
Net Debt/(Positive working capital, in excess of debt)	$ millions	$80.2	$22.0 – $28.0	($1) – ($10)
Net Debt/EBITDA		1.5	0.2 – 0.3	0.0 – 0.1

		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	$76.5 – $79.5	$80.2
Ending Net Debt/(Pos. working capital, in excess of debt)	$ millions	$80.2	$22.0 – $28.0	($1) – ($10)
Weighted average outstanding shares	# millions	69.8	86.2	86.2
Assumed Share price	$	1.16⁽⁴⁾	2.18	3.06
Production per debt adjusted share growth⁽²⁾		31%	76% – 86%	85% – 95%

		Actuals FY 2021	Previous Guidance FY 2022	Updated Guidance FY 2022
Share outstanding, end of year	# millions	86.2		86.2
Assumed Share price	$	2.18⁽³⁾		3.06
Market capitalization	$ millions	$188		$264
Net Debt/(Positive working capital, in excess of debt)	$ millions	$80.2		($1) – ($10)
Enterprise value	$millions	$268.2		$253 – $261
Adjusted Funds Flow	$ millions	$44.1		$141 – $150
Interest	$/boe	2.67		0.75 – 1.15
Debt Adjusted AFF	$ millions	$49.7		$144 – $153
EV/DAAFF		5.4	N/A⁽⁵⁾	1.6 – 1.8

(1)		As previously released January 12, 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 share price at December 31, 2021.
(3)		Ending share price at December 31, 2021.
(4)		Weighted average share price throughout 2021.
(5)		Guidance had not been previously released for this measure.

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.

	Light and Medium Crude oil (bbls/d)	NGLS (boe/d)	Conventional Natural gas (Mcf/d)	Total (boe/d)
Q4 2019 Average Production	2,466	869	9,978	4,998
2019 Average Production	2,626	697	10,058	5,000
Q4 2020 Average Production	2,194	708	8,141	4,259
2020 Average Production	2,031	668	7,715	3,985
Q4 2021 Average Production	3,156	933	15,590	6,687
2021 Average Production	2,981	782	12,030	5,768
2022 Annual Guidance	4,332	1,312	21,035	9,150⁽¹⁾
Tuck-in Acquisition Q4 2021 Avg. Prod	1,452	302	6,815	2,900
Current Corporate Average Production	4,019	1,455	21,464	9,050

Note:

This reflects the mid-point of the Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.
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.

Alvopetro Energy (ALVOF)(ALV:CA) – Coverage Initiated With Outperform Rating and a $10 Target

Posted on March 16, 2022 by Admin

Wednesday, March 16, 2022

Alvopetro Energy (ALVOF)(ALV:CA)
Coverage Initiated With Outperform Rating and a $10 Target

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

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

This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).

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

Has Uranium Demand Changed with Russia Ukraine War?

Is it Too Late to Benefit from Higher Oil?

Uranium and Natural Gas Investments Turn Green in 2023

Investor Information on Three Segments of the Uranium Energy Sector

Delta Air Lines Signs 75 Million Gallon Per Year Agreement with Gevo

Alvopetro Announces 33% Increase In Quarterly Dividend To US$0.08 Per Share, Year-End 2021 Financial Results, Filing Of Annual Information Form And An Operational Update

Alvopetro Announces 33% Increase In Quarterly Dividend To US$0.08 Per Share, Year-End 2021 Financial Results, Filing Of Annual Information Form And An Operational Update

The importance of Dependable Energy, Even Nuclear, is Heightened in Recent War

Why Uranium Mining Stocks Can Continue Climbing Higher

How Does Uranium Fit Into the ESG Energy Landscape?

AMC is Thinking Outside the Box Office and Diversifying

Why JP Morgan’s Guru has Maintained a Positive Stance on Stocks

InPlay Oil (IPOOF)(IPO:CA)Doubling Our Price Target On Higher Production And Energy Prices

Energy Fuels (UUUU)(EFR:CA)Ramp Up Is Coming Slowly But Higher Prices Could Spur Activity

Alvopetro Energy (ALVOF)(ALV:CA)Coverage Initiated With Outperform Rating and a $10 Target

InPlay Oil Corp. Announces Record Setting 2021 Financial, Operating and Reserves Results

Energy Fuels Announces 2021 Results, Including Net Profits, Strong Cash Position, and Market-Leading U.S. Uranium, Rare Earth and Vanadium Position

Energy Fuels Announces 2021 Results, Including Net Profits, Strong Cash Position, and Market-Leading U.S. Uranium, Rare Earth and Vanadium Position

InPlay Oil Corp. Announces Record Setting 2021 Financial, Operating and Reserves Results

Alvopetro Energy (ALVOF)(ALV:CA)Coverage Initiated With Outperform Rating and a $10 Target

InPlay Oil (IPOOF)(IPO:CA)
Doubling Our Price Target On Higher Production And Energy Prices

Energy Fuels (UUUU)(EFR:CA)
Ramp Up Is Coming Slowly But Higher Prices Could Spur Activity

Alvopetro Energy (ALVOF)(ALV:CA)
Coverage Initiated With Outperform Rating and a $10 Target

Alvopetro Energy (ALVOF)(ALV:CA)
Coverage Initiated With Outperform Rating and a $10 Target