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Release – Hemisphere Energy Grows Proved Reserve Value to $325 Million and Proved Net Asset Value to $3.18 per Fully Diluted Share

Posted on March 12, 2024March 12, 2024 by [email protected]

March 12, 2024 8:30 AM EDT

Vancouver, British Columbia–(Newsfile Corp. – March 12, 2024) – Hemisphere Energy Corporation (TSXV: HME) (OTCQX: HMENF) (“Hemisphere” or the “Company”) is pleased to announce highlights from its independent reserves evaluation (the “Reserve Report”), prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) and effective as at December 31, 2023.

In 2023, Hemisphere invested $16 million to drill eight successful Atlee Buffalo wells, upgrade facilities in Atlee Buffalo, purchase land and seismic, and pre-purchase some of the materials for its 2024 development program. With the Company’s capital additions, corporate production in 2023 increased by more than 10% year-over-year, to 3,124 boe/d (99% heavy oil). Production is currently trending over 3,450 boe/d (99% heavy oil, based on field estimates between February 10 – March 10, 2024), after significant downtime experienced in January and early February due to extreme cold weather and equipment failure.

During the year, Hemisphere also distributed $13.1 million in base and special dividends, purchased 3.2 million shares under its normal course issuer bid (“NCIB”) for a total price of $4.0 million (at an average price of $1.25/share), and exited the year in a cash position with working capital¹ of over $3 million.

The Company’s continued success in the development of its enhanced oil recovery projects was recognized again by McDaniel in the Reserve Report. In the Proved Developed Producing (“PDP”) category, Hemisphere replaced 104% of 2023 production and increased reserve value by 9% to $248 million NPV10 BT. Hemisphere also grew Proved (“1P”) reserve value to $325 million NPV10 BT and Proved plus Probable (“2P”) reserve value to $416 million NPV10 BT.

The Company’s new Saskatchewan lands currently account for only 5% of 1P and 7% of 2P reserves, while making up only 3% of 1P and 5% of 2P NPV10 BT valuations of Hemisphere’s reserves. Significant reserve upside remains on Hemisphere lands if the play proves successful over the course of 2024 and beyond.

Consistent with McDaniel’s 2022 year-end evaluation, the Reserve Report incorporates full corporate abandonment, decommissioning, and reclamation costs (“ADR”) in the PDP category. Hemisphere has always been cautious of acquiring additional wellbore and facility liabilities. A direct result of this strategy is that Hemisphere’s reserves retain more comparative value per barrel than companies with additional ADR liabilities that must be deducted from their base valuations. Management estimates that total undiscounted and uninflated existing ADR is $8.3 million ($2.3 million NPV10 BT, with costs inflated at 2%/yr), which includes all ADR associated with both active and inactive wells, pipelines, and facilities regardless of whether such wells, pipelines, and facilities had any attributed reserves. Based on public information, Hemisphere stands out among its industry peers as being within the top 8% of Alberta oil and gas operators for its industry-leading liability management ratio (“LMR”) of 17, resulting in Hemisphere having less than 1% of its PDP net present value impaired by ADR.

Hemisphere’s low decline, long life, and high value reserves are a sign of the tremendous resource the Company has been developing over the past number of years. These valuable assets are the backbone of Hemisphere and are expected to generate significant free cash flow as they continue to grow with planned additional development and optimization of enhanced oil recovery techniques.

2023 Reserve Highlights

Proved Developed Producing (“PDP”) Reserves

NPV10 BT of $248 million, an increase of 9% over year-end 2022 and equivalent to $2.49 per basic share.
Replaced 104% of 2023 production through organic development.
Maintained reserve volumes year-over-year at 8.2 MMboe (99.6% heavy crude oil).
Achieved a 2-year FD&A cost of $9.30/boe (including changes in future development capital (“FDC”)) for a recycle ratio of 5.4.
RLI of 7.2 years based on 2023 production.

Proved (“1P”) Reserves

NPV10 BT of $325 million, an increase of 5% over year-end 2022 and equivalent to $3.27 per basic share.
Replaced 90% of 2023 production through organic development.
Maintained reserve volumes year-over-year at 12.1 MMboe (99.4% heavy crude oil).
Achieved a 2-year FD&A cost of $14.82/boe (including changes in FDC) for a recycle ratio of 3.4.
RLI of 10.6 years based on 2023 production.
NAV of $3.18 per fully diluted share based on Reserve Report pricing assumptions.
NAV of $3.28 and $4.27 per fully diluted share based on Reserve Report run internally at McDaniel’s pricing sensitivities of US$80 and US$100 WTI flat pricing.

Proved plus Probable (“2P”) Reserves

NPV10 BT of $416 million, an increase of 5% over year-end 2022 and equivalent to $4.19 per basic share.
Replaced 125% of 2023 production through organic development.
Maintained reserve volumes at 16.3 MMboe (99.4% heavy crude oil).
Achieved a 2-year FD&A cost of $14.91/boe (including changes in FDC) for a recycle ratio of 3.4.
RLI of 14.3 years based on 2023 production.
NAV of $4.03 per fully diluted share based on Reserve Report pricing assumptions.
NAV of $4.12 and $5.36 per fully diluted share based on Reserve Report run internally at McDaniel’s pricing sensitivities of US$80 and US$100 WTI flat pricing.

2023 Independent Qualified Reserve Evaluation

The reserves data set forth below is based upon an independent reserves evaluation prepared by McDaniel dated March 11, 2024 with an effective date of December 31, 2023, and is in accordance with definitions, standards, and procedures contained within COGEH 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 Hemisphere’s Annual Information Form which will be filed on SEDAR+ on or before April 30, 2024. Due to rounding, certain totals in the columns may not add in the following tables. All dollar values are in Canadian dollars, unless otherwise noted.

Pricing Assumptions

McDaniel’s independent evaluation was based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. (the “3-Consultant Average Price Forecast”) at January 1, 2024, with the following table detailing pricing and foreign exchange rate assumptions. Hemisphere’s corporate production historically averages a discount of approximately $4.50 to WCS pricing. When compared to last year’s 3-Consultant Average Price Forecast dated January 1, 2023, the current WCS pricing outlook is down approximately 1% in 2024, and up 1% thereafter over the next 15-year period. The 2024 3-Consultant Average Price Forecast uses a 5-year 2024-28 WTI price of US$76.33/bbl and WCS price of Cdn$81.11/bbl.

3-Consultant Average Price Forecast January 1, 2023								3-Consultant Average Price Forecast January 1, 2024
	WTI Crude Oil ($US/bbl)	Edmonton Light Crude Oil ($Cdn/bbl)	Western Canadian Select WCS Crude Oil ($Cdn/bbl)	AECO Spot Price ($Cdn/MM Btu)	Inflation (%)	US/Cdn Exchange Rate ($US/$Cdn)		WTI Crude Oil ($US/bbl)	Western Canadian Select WCS Crude Oil ($Cdn/bbl)	Edmonton Light Crude Oil ($Cdn/bbl)	AECO Spot Price ($Cdn/MM Btu)	Inflation (%)	US/Cdn Exchange Rate ($US/$Cdn)


2024	78.50	97.74	77.75	4.40	2.3	0.765	2024	73.67	92.91	76.74	2.20	0	0.745
2025	76.95	95.27	77.55	4.21	2	0.768	2025	74.98	95.04	79.77	3.37	2	0.765
2026	77.61	95.58	80.07	4.27	2	0.772	2026	76.14	96.07	81.12	4.05	2	0.768
2027	79.16	97.07	81.89	4.34	2	0.775	2027	77.66	97.99	82.88	4.13	2	0.772
2028	80.74	99.01	84.02	4.43	2	0.775	2028	79.22	99.95	85.04	4.21	2	0.775
2029	82.36	100.99	85.73	4.51	2	0.775	2029	80.80	101.94	86.74	4.30	2	0.775
2030	84.00	103.01	87.44	4.60	2	0.775	2030	82.42	103.98	88.47	4.38	2	0.775
2031	85.69	105.07	89.20	4.69	2	0.775	2031	84.06	106.06	90.24	4.47	2	0.775
2032	87.40	106.69	91.11	4.79	2	0.775	2032	85.74	108.18	92.04	4.56	2	0.775
2033	89.15	108.83	92.93	4.88	2	0.775	2033	87.46	110.35	93.89	4.65	2	0.775
2034	90.93	111.00	94.79	4.98	2	0.775	2034	89.21	112.56	95.77	4.74	2	0.775
2035	92.75	113.22	96.69	5.08	2	0.775	2035	90.99	114.81	97.68	4.84	2	0.775
2036	94.61	115.49	98.62	5.18	2	0.775	2036	92.81	117.10	99.64	4.94	2	0.775
2037	96.50	117.80	100.59	5.29	2	0.775	2037	94.67	119.45	101.63	5.03	2	0.775
2038	98.43	120.16	102.60	5.40	2.00	0.78	2038	96.56	121.83	103.66	5.14	2.00	0.78

Summary of Reserves⁽¹⁾

	Heavy Oil	Conventional Natural Gas	Total
Reserves Category	(Mbbl)	(MMcf)	(Mboe)
Proved
Developed Producing	8,196	173	8,225
Developed Non-Producing	34	7	35
Undeveloped	3,756	250	3,798
Total Proved	11,987	429	12,058
Probable	4,231	188	4,262
Total Proved plus Probable	16,217	617	16,320

Note:

(1) Reserves are presented as “gross reserves” which are the Company’s working interest reserves before royalty deductions and without including any royalty interests.

Summary of Net Present Value of Future Net Revenue, Before Tax (“NPV BT”)⁽¹⁾⁽²⁾

	NPV BT (M$, except per share amount)
	Discounted at (% per Year)
Reserves Category	0%	5%	10%
Proved
Developed Producing	363,872	295,324	247,832
Developed Non-Producing	720	603	513
Undeveloped	126,954	97,757	76,777
Total Proved	491,546	393,685	325,121
Probable	190,663	126,483	91,337
Total Proved plus Probable	682,209	520,168	416,458
Per basic share⁽³⁾
Proved Developed Producing	3.66	2.97	2.49
Proved	4.95	3.96	3.27
Proved plus Probable	6.87	5.24	4.19

Notes:
(1) Based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. at January 1, 2024, as outlined in the table herein entitled “Pricing Assumptions”.
(2) It should not be assumed that the estimates of net present value of future net revenues presented in this table represent the fair market value of Hemisphere’s reserves.
(3) Based on there being 99,340,339 issued and outstanding shares of the Company as of December 31, 2023.

Future Development Costs (“FDC”)

The following summarizes the development costs deducted in the estimation of the net present value of the future net revenue attributable to 1P and 2P reserves.

	Forecast Costs (M$)
	1P	2P
2024	16,410	16,410
2025	22,959	28,051
2026	7,087	12,648
2027	3,501	3,501
Subsequent years	–	–
Total Undiscounted	49,956	60,609
Total Discounted at 10%	43,568	52,209

Finding, Development and Acquisition Costs (“FD&A”) Costs and Recycle Ratios⁽¹⁾⁽²⁾

	2023			2-Year Totals/Average
FD&A	PDP	1P	2P	PDP	1P	2P
Exploration, development and acquisition capital (M$)⁽³⁾⁽⁴⁾	14,543			31,570
Total changes in FDC (M$)	-528	4,869	10,094	-2,527	2,191	9,888
Total FD&A Capital, including changes in FDC (M$)	14,015	19,412	24,637	29,044	33,762	41,458
FD&A Reserve additions, including revisions (Mboe)	1,181	1,027	1,425	3,123	2,278	2,780
FD&A costs⁽⁵⁾, including changes in FDC ($/boe)	11.87	18.90	17.28	9.30	14.82	14.91
Recycle Ratio⁽⁶⁾	3.8	2.4	2.6	5.4	3.4	3.4

Notes:
(1) All financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, which have not yet been approved by the Company’s Audit Committee or Board of Directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors.
(2) See “Oil and Gas Advisories” and “Oil and Gas Metrics”.
(3) Exploration, development and acquisition capital excludes capitalized administration costs.
(4) The aggregate of the exploration, development and acquisition capital incurred in the financial year and change during that year in estimated future development costs generally will not reflect total finding, development and acquisition costs related to reserve additions for that year.
(5) FD&A costs are calculated as the sum of exploration, development and acquisition capital plus the change in future development capital (FDC) for the period divided by the change in reserves for the period, including on acquisition lands. FD&A costs take into account reserves revisions during the year on a per boe basis, and 2023 production of 3,124 boe/d.
(6) Recycle ratio is calculated as Operating field netback divided by FD&A costs. Operating field netback is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the sections “Non-IFRS and Other Specified Financial Measures” and “Financial Information”. The Company‘s estimated operating field netback in 2023 was $45.41/boe (unaudited) and 2-year 2022/23 average operating field netback was $50.67/boe.

Reserve Life Index (“RLI”)

	As of December 31, 2023⁽¹⁾
PDP	7.2
1P	10.6
2P	14.3

Note:
(1) Calculated as the applicable reserves volume divided by Hemisphere’s average 2023 production of 3,124 boe/d.

Net Asset Value (“NAV”)⁽¹⁾

	As at December 31, 2023
(MM$ except share amounts)	3-Consultant Average Price Forecast	US$80 WTI	US$100 WTI
1P NPV10 BT⁽²⁾	325	336	441
2P NPV10 BT⁽²⁾	416	426	558
Undeveloped Land and Seismic⁽³⁾	3
Proceeds from Stock Options	9
Working Capital⁽⁴⁾	3
Million Shares Outstanding (fully diluted)	107
1P NAV per share (fully diluted)	$3.18	$3.28	$4.27
2P NAV per share (fully diluted)	$4.03	$4.12	$5.36

Notes:
(1) Calculated using the respective net present values of 1P and 2P reserves, before tax and discounted at 10%, plus internally valued undeveloped land & seismic and proceeds from and stock options, plus working capital⁽⁴⁾, and divided by fully diluted outstanding shares. Net present values are shown at various price forecasts including the 3-Consultant Average Price Forecast used in the McDaniel Reserve Report, as well as sensitivities run internally at McDaniel’s flat WTI price forecasts of US$80 and US$100 WTI paired with US$19.32 and US$23.45 WCS differentials, respectively, and 1.37 USD/CAD FX.
(2) 100% of existing and future corporate ADR has been included in the McDaniel Reserve Report. Total corporate ADR accounted for in the 2023 reserve report, including that for future development, amounts to $3.0 million NPV10 BT in the 1P category and $3.1 million NPV10 BT in the 2P category.
(3) Based on an internal evaluation by management of Hemisphere as of December 31, 2023, with an average value of $75.87 per acre for 31,295 undeveloped net acres, and $0.55 million for seismic.
(4) Working Capital is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the section “Non-IFRS and Other Specified Financial Measures”. All financial information as at December 31, 2023 is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, which has not yet been approved by the Company’s Audit Committee or Board of Directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to changes as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors.

About Hemisphere Energy Corporation

Hemisphere is a dividend-paying Canadian oil company focused on maximizing value per share growth with the sustainable development of its high netback, low decline conventional heavy oil assets through water and polymer flood enhanced recovery methods. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol “HME” and on the OTCQX Venture Marketplace under the symbol “HMENF”.

For further information, please visit the Company’s website at www.hemisphereenergy.ca to view its corporate presentation or contact:

Don Simmons, President & Chief Executive Officer
Telephone: (604) 685-9255
Email: [email protected]

Definitions and Abbreviations

bbl	barrel	US$	United States dollar
Mbbl	thousands of barrels	Cdn$	Canadian dollar
MMbbl	millions of barrels	M$	thousand dollars
boe	barrel of oil equivalent	MM	million
boe/d	barrel of oil equivalent per day	NPV BT	Net Present Value of future net revenue, before tax
Mboe	thousands of barrels of oil equivalent	NPV10 BT	NPV BT, discounted at 10%
MMboe	millions of barrels of oil equivalent	FX	Foreign Exchange
MMcf	million cubic feet	FDC	Future Development Costs
MMbtu	million British Thermal Unit	FD&A	Finding, Development and Acquisition
AECO	Alberta Energy Company	NAV	Net Asset Value
WCS	Western Canadian Select	RLI	Reserve Life Index
WTI	West Texas Intermediate

Forward-Looking 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” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the Company’s expectations that its assets are expected to generate significant free funds flow as they continue to grow with planned additional development and optimization of enhanced oil recovery techniques; the volumes of Hemisphere’s oil and gas reserves and the estimated net present values of the future net revenues of such reserves; the Company’s estimates of ADR; and the Company’s anticipated filing date for its annual information form for the year ending December 31, 2023; upside potential on Hemisphere’s Saskatchewan properties in 2024 and beyond. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

The estimates of Hemisphere’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of Hemisphere which have been used to develop such statements and information, but which may prove to be incorrect. Although Hemisphere 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 Hemisphere 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: that Hemisphere will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities are consistent with past operations; the quality of the reservoirs in which Hemisphere operates and continued performance from existing wells; inflation rates and cost escalations; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Hemisphere’s reserve volumes; certain commodity price and other cost assumptions; continued availability of debt and equity financing and cash flow to fund Hemisphere’s current and future plans and expenditures; the impact of increasing competition; the general stability of the economic and political environment in which Hemisphere operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Hemisphere 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 Hemisphere has an interest in to operate the field in a safe, efficient and effective manner; the ability of Hemisphere 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 expansion and the ability of Hemisphere to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Hemisphere operates; and the ability of Hemisphere to successfully market its oil and natural gas products.

The forward-looking information and statements included in this news release 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: changes in commodity prices; regulatory risks, including penalties or other remedial action; the ability of the Company to maintain legal title to its properties; changes to, or restrictions of, labour, supplies, and infrastructure as a result of COVID-19; changes in the demand for or supply of Hemisphere’s products, the early stage of development of some of the evaluated areas and zones; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Hemisphere or by third party operators of Hemisphere’s properties; changes in budgets; increased debt levels or debt service requirements; inaccurate estimation of Hemisphere’s oil and gas reserve volumes; limited, unfavourable 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 Hemisphere’s public disclosure documents, (including, without limitation, those risks identified in this news release and in Hemisphere’s annual information form).

The forward-looking information and statements contained in this news release speak only as of the date of this news release, and Hemisphere 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.

Oil and Gas Advisories

All reserve references in this news release are “gross” or “Company interest reserves”. Such reserves are the Company’s total working interest reserves before the deduction of any royalties and without including any royalty interests of the Company.

It should not be assumed that the net present value of the estimated net revenues presented in this news release represent 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 reserve estimates of Hemisphere’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. Estimates of net present value and future net revenue contained herein do not necessarily represent fair market value. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions in evaluating Hemisphere’s reserves will be attained and variances could be material.

All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs and abandonment and reclamation costs and are stated prior to provision for interest and general and administrative expenses. Future net revenues have been presented in this news release on a before tax basis.

“Boe” means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Oil and Gas Metrics

This news release contains metrics commonly used in the oil and natural gas industry, such as finding, development and acquisition (“FD&A”) costs, “recycle ratio”, “operating field netback” and “reserve life index (“RLI”)”. These terms do not have a standardized meaning and the Company’s calculation of such metrics may not be comparable to the calculation method used or presented by other companies for the same or similar metrics, and therefore should not be used to make such comparisons.

“Finding, development and acquisition costs” or “FD&A costs” are calculated as the sum of exploration, development and acquisition capital plus the change in future development capital (“FDC”) for the period divided by the change in reserves for the period, including on acquisition lands. FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration, development and acquisition costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total FD&A costs related to reserves additions for that year. Management uses FD&A costs as a measure of capital efficiency for organic reserves development.

“Exploration, development and acquisition capital” means the aggregate exploration, development and acquisition costs incurred in the financial year, and excludes capitalized administration costs.

“Recycle ratio” is a Non-IFRS ratio calculated as the Operating field netback divided by the FD&A cost per boe for the year. Operating field netback is a non-IFRS financial measure (refer to the section “Non-IFRS and Other Specified Financial Measures”). Management uses recycle ratio to relate the cost of adding reserves to the expected cash flows to be generated.

“Reserve life index” is calculated as total company interest reserves divided by annual production, for the year indicated.

“NAV per fully diluted share” is calculated using the respective net present values of 1P and 2P reserves, before tax and discounted at 10%, plus internally valued undeveloped land & seismic and proceeds from warrants and stock options, plus working capital, and divided by fully diluted outstanding shares. Net present values are shown at various price forecasts including the 3-Consultant Average Price Forecasts used in the McDaniel Reserve Report, as well as sensitivities run internally at McDaniel’s flat WTI price forecasts of US$80 and US$100 WTI paired with US$19.32 and US$23.45 WCS differentials respectively, and 1.37 USD/CAD FX. Management uses NAV per share as a measure of the relative change of Hemisphere’s net asset value over its outstanding common shares over a period of time.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.

Financial Information

Certain financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, which have not yet been approved by the Company’s Audit Committee or Board of Directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors. All amounts are expressed in Canadian dollars unless otherwise noted.

Non-IFRS and Other Specified Financial Measures

Certain measures commonly used in the oil and natural gas industry referred to herein, including “Working Capital” and “Operating field netback”, do not have standardized meanings prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other companies. These non-IFRS measures are further described and defined below. Investors are cautioned that these measures should not be construed as alternatives to or more meaningful than the most directly comparable IFRS measures as indicators of Hemisphere’s performance. Set forth below are descriptions of the non-IFRS financial measures used in this news release.

“Working Capital” is closely monitored by the Company to ensure that its capital structure is maintained by a strong balance sheet to fund the future growth of the Company. Working Capital is used in this document in the context of liquidity and is calculated as the total of the Company’s bank debt plus current assets, less current liabilities, excluding the fair value of financial instruments, lease and decommissioning liabilities.

($MM)		Twelve Months Ended December 31, 2022 (unaudited)
Bank debt	$	–
Current assets		13.3
Current liabilities		(9.9	)
Working Capital	$	3.4

“Operating field netback” is calculated as oil and gas sales, less royalties, operating expenses, and transportation costs on an absolute and per barrel of oil equivalent basis. Operating netback per boe and Operating field netback per boe are calculated by dividing the respective terms by the applicable barrels of oil equivalent of production. A reconciliation of Operating netback and Operating field netback per boe to the most directly comparable measure calculated and presented in accordance with IFRS is as follows:

($/boe)		Twelve Months Ended December 31, 2022 (unaudited)
Average realized sales	$	74.05
Royalties		(14.89	)
Operating and transportation expenses		(13.75	)
Operating field netback	$	45.41

The Company has provided additional information on how these measures are calculated in the Management’s Discussion and analysis for the year ended December 31, 2022 and for the three and nine month periods ended September 30, 2023, which are available under the Company’s SEDAR+ profile at www.sedarplus.ca.

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.

1 Working Capital is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the sections “Non-IFRS and Other Specified Financial Measures” and “Financial Information”.

SOURCE: Hemisphere Energy Corporation

ATHA Energy and Latitude Uranium Complete Merger to Create Uranium Powerhouse

Posted on March 11, 2024March 11, 2024 by [email protected]

In a major development in the uranium mining sector, ATHA Energy Corp. and Latitude Uranium Inc. announced the successful completion of their merger on March 7, 2024. Through this strategic transaction, ATHA has acquired 100% of the outstanding common shares of Latitude Uranium, making the latter a wholly-owned subsidiary.

The merger brings together two promising uranium players, combining their complementary assets and expertise to create a formidable force in the industry. Latitude Uranium shareholders received 0.2769 ATHA common shares for each share held, resulting in ATHA issuing approximately 64.4 million new shares.

This deal marks a significant milestone for ATHA, adding historical resources to its portfolio and expanding its reach across multiple high-grade uranium jurisdictions. The combined company now boasts a diverse range of exploration catalysts, including the Angilak and CMB uranium discoveries, with historical resource estimates of 43.3 million lbs and 14.5 million lbs U3O8, respectively.

Moreover, ATHA now holds the largest cumulative exploration package in both the Athabasca Basin and Thelon Basin, two of the world’s most prominent basins for uranium discoveries, with a total of 6.5 million acres. Additionally, the company has a 10% carried interest in a portfolio of claims in the Athabasca Basin operated by industry leaders NexGen Energy Ltd. and IsoEnergy Ltd.

Troy Boisjoli, CEO of ATHA, expressed enthusiasm about the merger, stating, “This acquisition marks a significant milestone for the Company by adding historical resource to our portfolio and enabling us to expand the reach of our robust balance sheet across a diverse range of exploration catalysts.”

The Resurgence of Uranium Mining

The ATHA-Latitude Uranium merger comes at a time when the uranium mining industry is experiencing a resurgence, driven by the global push towards clean energy and the pivotal role of nuclear power in achieving carbon neutrality goals.

As countries around the world seek to reduce their reliance on fossil fuels and transition to more sustainable energy sources, the demand for uranium is expected to increase significantly. Nuclear power plants, which generate electricity without emitting greenhouse gases, are attracting renewed interest as a viable solution to meet energy needs while addressing climate change concerns.

This resurgence has sparked a flurry of activity in the uranium mining sector, with companies scrambling to secure promising exploration projects and develop new mines to meet the anticipated demand. Established players and emerging companies alike are vying for a share of this lucrative market, fueled by the potential for substantial returns on investment.

However, the uranium mining industry is not without its challenges. Stringent regulations, environmental concerns, and the need for significant capital investment present hurdles that companies must navigate cautiously. Responsible exploration and mining practices, combined with robust risk management strategies, are crucial for long-term success in this sector.

Nonetheless, the ATHA-Latitude Uranium merger positions the combined entity as a formidable player in the uranium mining landscape. With a diverse portfolio of assets, historical resources, and strategic partnerships, the company is well-positioned to capitalize on the growing demand for uranium and contribute to the global transition towards a more sustainable energy future.

As the world grapples with the twin challenges of meeting energy needs and addressing climate change, the uranium mining industry is poised to play a pivotal role. Companies like ATHA, armed with extensive resources and a solid growth strategy, may emerge as key players in this exciting and rapidly evolving sector.

Take a moment to take a look at Noble Capital Markets’ Senior Research Analyst Mark Reichman’s coverage list.

Release – Alvopetro Announces February 2024 Sales Volumes

Posted on March 5, 2024March 6, 2024 by [email protected]

Research News and Market Data on ALVOF

Mar 05, 2024

CALGARY, AB, March 5, 2024 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces February 2024 sales volumes of 1,477 boepd including natural gas sales of 8.3 MMcfpd, associated natural gas liquids sales from condensate of 72 bopd and oil sales of 19 bopd, based on field estimates. February sales volumes were impacted by reduced nominations from our offtaker, Bahiagás mainly in the latter half of February. Effective March 1, 2024 deliveries to Bahiagás have increased back to over 10.6 MMcfpd.

Natural gas, NGLs and crude oil sales:	February 2024	January 2024
Natural gas (Mcfpd), by field:
Caburé	7,875	9,305
Murucututu	449	382
Total Company natural gas (Mcfpd)	8,324	9,687
NGLs (bopd)	72	75
Oil (bopd)	19	9
Total Company (boepd)	1,477	1,699

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 YouTube –https://www.youtube.com/channel/UCgDn_igrQgdlj-maR6fWB0w

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

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:

boepd	=	barrels of oil equivalent (“boe”) per day
bopd	=	barrels of oil and/or natural gas liquids (condensate) per day
Mcf	=	thousand cubic feet
Mcfpd	=	thousand cubic feet per day
MMcfpd	=	million cubic feet per day
NGLs	=	natural gas liquids

BOE Disclosure. The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

Forward-Looking Statements and Cautionary Language. This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward‐looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the expected natural gas price, natural gas sales and natural gas deliveries under the Company’s long-term gas sales agreement. The forward‐looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to expectations and assumptions concerning expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, the success of future drilling, completion, and testing, equipment availability, the timing of regulatory licenses and approvals, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of global pandemics 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. 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.sedarplus.ca. 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.

Crude Oil Reaches $80 For First Time Since November

Posted on March 1, 2024March 1, 2024 by [email protected]

Oil prices have staged a strong rally over the last few trading sessions, with both Brent and West Texas Intermediate (WTI) crude futures settling above $80 and $83 per barrel respectively on Friday. This marks the highest level for oil prices since November 2023. The recent surge has been driven by growing signs of tightness in global oil supplies along with heightened geopolitical risks in the Middle East.

For investors in the oil and gas sector, the combination of bullish supply and demand fundamentals and rising geopolitical tensions point to potential upside in oil prices through 2024. Here are some of the key factors driving the latest rally:

Supply Fundamentals Point to Tightness

On the supply side, oil prices are being lifted by OPEC+’s continued restraint on production increases. The group of major oil producers is expected to extend production cuts beyond their planned exit in March, tightening global supplies. Additionally, near-term futures contracts are trading at a premium to later dated contracts, a condition known as backwardation which signals tight supplies.

Asia Demand Exceeding Expectations

At the same time, oil demand has proved resilient, especially in Asia. Demand out of Asia has exceed expectations in recent months, even as parts of Europe remain locked down. With economies reopening as vaccine rollouts accelerate, pent-up travel demand in Asia is set to further boost oil consumption over 2023. The combination of robust demand growth and limited supply increases has led to a rapid drawdown of global oil inventories since the start of the year.

Middle East Tensions Creating Geopolitical Risk Premium

On top of bullish market fundamentals, ongoing tensions in the Middle East are layering fears of potential supply disruptions. Attacks on oil tankers transiting through the critical Red Sea route has rerouted tanker traffic and added to insurance costs. Escalating violence between Israel and Hamas has raised concerns over stability in the region.

Most importantly, oil prices could spike dramatically if Iran-backed Houthis were to target vessels travelling through the Strait of Hormuz. This critical passageway between Oman and Iran handles around 30% of all seaborne-traded crude oil globally. Any military clashes or outright closure of the Strait would severely constrain global oil flows and lead to a price spike.

Upside Risks Outweigh Downsides for Oil Prices

In summary, investors should be aware of the multitude of upside risks supporting higher oil prices as we progress through 2024. While oil demand may moderate as economies eventually normalize post-pandemic, OPEC+ restraint and the risk of supply disruptions look set to keep the market tight.

As leading investment banks like Goldman Sachs have noted, their base case forecast of $70-90 per barrel for Brent could easily see upside, with geopolitics posing the main risk. For investors, oil exploration and production companies as well as oil services firms stand to benefit most from higher prices. Integrated majors may lag on share price gains though due to their downstream refining exposure. Overall, oil markets appear set to tighten further, making the case for investors to overweight the energy sector.

Take a moment to take a look at Noble Capital Markets’ Senior Research Analyst Michael Heim’s coverage list.

Release – Alvopetro Announces 2023 Year End Reserves

Posted on February 27, 2024February 27, 2024 by [email protected]

Research News and Market Data on ALVOF

Feb 26, 2024

CALGARY, AB, Feb. 26, 2024 /CNW/ – Alvopetro Energy Ltd. (TSXV:ALV) (OTCQX: ALVOF) announces our reserves as at December 31, 2023 with total proved plus probable (“2P”) reserves of 8.7 MMboe and a before tax net present value discounted at 10% (“NPV10”) of $309.7 million, risked best estimate contingent resources of 5.4 MMboe (NPV10 $126.1 million) and risked best estimate prospective resources of 9.6 Mmboe (NPV10 $184.9 million). The reserves and resources data set forth herein is based on an independent reserves and resources assessment and evaluation prepared by GLJ Ltd. (“GLJ”) dated February 26, 2024 with an effective date of December 31, 2023 (the “GLJ Reserves and Resources Report”).

The GLJ Reserves and Resources Report incorporates Alvopetro’s working interest share of remaining recoverable reserves held by Alvopetro in the Caburé and Murucututu natural gas fields and the Bom Lugar and Mãe-da-lua oil fields as well as Alvopetro’s working interest share of remaining recoverable resources held by Alvopetro in the Murucututu natural gas field. With respect to Murucututu, Bom Lugar, and Mãe-da-lua, Alvopetro’s working interest share is 100%. With respect to the unitized area (the “Unit”) which includes our Caburé and Caburé Leste fields (collectively referred to as “Caburé” in this news release) and two fields held by our third-party partner in the Unit, Alvopetro’s working interest share as of December 31, 2023 was 49.1%, with the remaining 50.9% held by our partner. As previously announced by the Company, the first redetermination of the working interests to each party commenced in the fourth quarter of 2023. The parties engaged an independent expert (the “Expert”) to evaluate the redetermination. Pursuant to the provisions of the UOA, where an Expert is engaged, the Expert’s determination shall be made using what is commonly referred to as the “pendulum” method of dispute resolution. Under this method, the Expert is not required or permitted to provide their own interpretation but is required to select the single Final Proposal (between the two partner’s respective Final Proposals), which, in the Expert’s opinion, provides the most technically justified result of the application of the relevant information and data and material provided to the Expert consistent with the UOA and all related documents. As of the date of this news release, the outcome of the Expert’s decision and the resulting working interest to Alvopetro following the decision is uncertain. The resulting impact on Alvopetro’s reserves and future cash flows may be material and may have a material adverse effect on Alvopetro. The impact on Alvopetro’s working interest will be effective on the first calendar day of the second month following the date of the decision of the Expert, subject to any government approvals that may be required. The decision of the Expert is expected near the end of the first quarter of 2024. The GLJ Reserves and Resource Report and the references included herein are based on the 49.1% interest in Caburé, Alvopetro’s working interest share as of December 31, 2023. The reserves data included in this news release and in the GLJ Reserves and Resources Report may be materially impacted following the Expert’s decision.

All references herein to $ refer to United States dollars, unless otherwise stated.

December 31, 2023 GLJ Reserves and Resource Report:

Proved reserves (“1P”) decreased 30% to 2.7 MMboe Proved reserves mainly due to 2023 production and technical revisions related to the 197-1 and 183-1 Murucututu wells. Alvopetro is working to enhance production from these wells with optimizations in 2024.
2P reserves decreased 4% from 9.0 to 8.7 MMboe after 0.8 MMboe of production in 2023. Production in 2023 was offset by improved recovery factors at Caburé due to the agreed Unit development plan and new additions associated with the discovery at the 183-A3 well in the Caruaçu Formation.
Proved plus Probable plus Possible reserves (“3P”) increased to 15.2 MMboe from 14.4 MMboe as a result of additions associated with the discovery at the 183-A3 well in the Caruaçu Formation.
2P NPV10 decreased 11% to $309.7 million due to changes in forecast natural gas prices and 2023 production offset mainly by additional value associated with discovered zones in the Caruaçu Formation on our Murucututu natural gas field.
Risked best estimate contingent resources increased from 2.9 MMboe to 5.4 MMboe at December 31, 2023 with a NPV10 of $126.1 million, increases from December 31, 2022 of 84% and 103% respectively. The increases were associated with the discovery at the 183-A3 well in the Caruaçu Formation.
Risked best estimate prospective resources decreased from 12.5 MMboe to 9.6 MMboe with a NPV10 of $184.9 million, decreases of 23% and 29% respectively from December 31, 2022. The decrease was due primarily to adjustments to the probabilistic models incorporating the logs results for the Gomo zone at the 183-A3 well.

SUMMARY

December 31, 2023 Gross Reserve and Gross Resource Volumes:^{(1)(2)(3)(4)(5)(6)}

December 31, 2023 Reserves (Gross)	Total Proved (1P)	Total Proved plus Probable (2P)	Total Proved plus Probable plus Possible (3P)
	(Mboe)	(Mboe)	(Mboe)
Caburé Natural Gas Field	1,995	3,700	4,853
Murucututu Natural Gas Field	582	4,559	9,679
Bom Lugar Oil Field	126	415	622
Mãe-da-lua Oil Field	23	36	53
Total Company Reserves	2,727	8,711	15,208

December 31, 2023 Murucututu Resources (Gross)	Low Estimate	Best Estimate	High Estimate
	(Mboe)	(Mboe)	(Mboe)
Risked Contingent Resource Risked Prospective Resource	3,500 4,790	5,356 9,646	5,919 15,222
See ‘Footnotes’ section at the end of this news release

Net Present Value Before Tax Discounted at 10%:^{(1)(2)(3)(4)(5)(6)(7)(8)}

Reserves	1P	2P	3P
	($000s)	($000s)	($000s)
Caburé Natural Gas Field	99,946	170,854	212,653
Murucututu Natural Gas Field	11,700	129,169	254,433
Bom Lugar Oil Field	3,978	8,940	13,798
Mãe-da-lua Oil Field	262	694	1,189
Total Company	115,886	309,657	482,073

Murucututu Resource	Low Estimate	Best Estimate	High Estimate
	($000s)	($000s)	($000s)
Risked Contingent Resource Risked Prospective Resource	82,489 77,906	126,134 184,859	133,884 304,997
See ‘Footnotes’ section at the end of this news release

PRICING ASSUMPTIONS – FORECAST PRICES AND COSTS

GLJ employed the following pricing and inflation rate assumptions as of January 1, 2024 in the GLJ Reserves and Resources Report in estimating reserves and resources data using forecast prices and costs.

Year	Brent Blend Crude Oil FOB North Sea ($/Bbl)	National Balancing Point (UK) ($/MMBtu)	NYMEX Henry HubNear Month Contract ($/MMBtu)	Alvopetro-Bahiagas Gas Contract $/MMBtu (Current Year)	Alvopetro-BahiagasGas Contract $/MMBtu (Previous Year)	Change from prior year
2024	77.00	11.11	2.75	10.56	10.96	-3.6 %
2025	79.50	13.00	3.85	10.08	10.79	-6.6 %
2026	81.49	11.85	4.16	10.44	11.01	-5.2 %
2027	82.58	10.75	4.25	10.51	11.12	-5.5 %
2028	84.19	10.98	4.33	10.48	10.75	-2.5 %
2029	85.90	11.20	4.42	10.63	10.73	-0.9 %
2030	87.64	11.43	4.50	10.82	10.88	-0.6 %
2031	89.37	11.65	4.60	11.04	11.09	-0.5 %
2032	91.16	11.89	4.69	11.26	11.30	-0.4 %
2033*	92.98	12.12	4.78	11.48	11.53	-0.4 %
*Escalated at 2% per year thereafter

As of February 1, 2024, Alvopetro’s contracted natural gas price under the terms of our long-term gas sales agreement is based on the ceiling price within the contract. Pricing is forecast to stay slightly below the ceiling for future price adjustments. The ceiling price incorporates assumed US inflation of 2%.

GLJ RESERVES AND RESOURCES REPORT

The GLJ Reserves and Resources Report has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) that are consistent with the standards of National Instrument 51-101 (“NI 51-101”). GLJ is a qualified reserves evaluator as defined in NI 51-101. The GLJ Reserves and Resources Report was an evaluation of all reserves of Alvopetro including our working interest share as of December 31, 2023 of the Unit (referred to herein as the Caburé natural gas field), our Murucututu natural gas project, as well as our Bom Lugar and Mãe-da-lua oil fields. The GLJ Reserves and Resources Report also includes an evaluation of the gas resources of our Murucututu natural gas field. In addition to the reserves assigned to our Murucututu field, contingent resource was assigned to the area in proximity to our existing Murucututu reserves, deemed to be discovered. The area mapped by 3D seismic west and north of the area defined as contingent was assigned prospective resource. Additional reserves and resources information as required under NI 51-101 will be included in the Company’s Annual Information Form for the 2023 fiscal year which will be filed on SEDAR+ (www.sedarplus.ca) by April 30, 2024.

December 31, 2023 Reserves Information:

Summary of Reserves ^(1)(2)(3)

Light & Medium Oil

Conventional Natural Gas

Natural Gas Liquids

Oil Equivalent

Company Gross

Company Net

Company Gross

Company Net

Company Gross

Company Net

Company Gross

Company Net

(Mbbl)

(MMcf)

(Mbbl)

(Mboe)

Proved

Producing

11,460

11,000

122

117

2,039

1,957

Developed Non-Producing

142

133

–

142

133

Undeveloped

–

2,951

2,818

546

522

Total Proved

150

140

14,411

13,818

176

169

2,727

2,612

Probable

302

285

31,175

29,859

486

465

5,983

5,726

Total Proved plus Probable

451

425

45,586

43,677

662

634

8,711

8,338

Possible

224

211

34,253

32,785

565

540

6,497

6,215

Total Proved plus Probable plus Possible

675

635

79,839

76,462

1,226

1,174

15,208

14,553

See ‘Footnotes’ section at the end of this news release

Summary of Before Tax Net Present Value of Future Net Revenue – $000s ^{(1)(2)(3)(7)(8)}

		Undiscounted	5 %	10 %	15 %	20 %
Proved
	Producing	114,762	106,922	100,204	94,364	89,230
	Developed Non-Producing	6,337	5,157	4,257	3,570	3,040
	Undeveloped	18,155	14,371	11,425	9,181	7,467
Total Proved		139,254	126,450	115,886	107,115	99,738
Probable		391,202	263,064	193,771	151,218	122,597
Total Proved plus Probable		530,456	389,514	309,657	258,333	222,335
Possible		538,835	271,641	172,416	124,475	96,580
Total Proved plus Probable plus Possible		1,069,291	661,155	482,073	382,808	318,915
See ‘Footnotes’ section at the end of this news release

Summary of After Tax Net Present Value of Future Net Revenue – $000s ^{(1)(2)(3)(7)(8)}

		Undiscounted	5 %	10 %	15 %	20 %
Proved
	Producing	107,434	100,320	94,209	88,886	84,200
	Developed Non-Producing	5,623	4,552	3,728	3,098	2,613
	Undeveloped	14,191	11,454	9,192	7,412	6,022
Total Proved		127,248	116,326	107,129	99,396	92,834
Probable		297,522	205,240	153,457	120,748	98,250
Total Proved plus Probable		424,769	321,565	260,586	220,145	191,085
Possible		388,926	204,696	133,885	98,386	77,076
Total Proved plus Probable plus Possible		813,695	526,262	394,471	318,531	268,160
See ‘Footnotes’ section at the end of this news release

Future Development Costs ^{(1)(2)(3)(7)(8)}

The table below sets out the total development costs deducted in the estimation of future net revenue attributable to proved reserves, proved plus probable reserves and proved plus probable plus possible reserves (using forecast prices and costs), by field, in the GLJ Reserves and Resources Report. Total development costs include capital costs for drilling and completing wells and for facilities but excludes abandonment and reclamation costs.

The future development costs for the Caburé field include Alvopetro’s working interest share (49.1%) for three development wells in the proved category and an additional two development wells in the probable and possible categories. Also included in future development costs for Caburé are costs associated with a facilities upgrade planned at the field for compression of natural gas to be delivered to Alvopetro’s natural gas processing facility. In prior years, Alvopetro reflected all equipment rental payments associated with our Gas Treatment Agreement with Enerflex Ltd. as part of future development costs; however in 2023, such costs are now incorporated within operating expense along with other operating costs associated with the agreement. The future costs associated with equipment rental are also reflected as a capital lease obligation on our financial statements.

The future development costs for the Murucututu field in the proved category include one development well and stimulation costs for the 183-1 and 183-A3 wells and one project to improve recovery from the 197(1) well. The probable category also includes an additional two development wells along with additional stimulation projects at the 183-1 and 183-A3 wells. The possible category includes one additional well.

The future development costs for Bom Lugar in the proved category include costs to stimulate the BL-06 well drilled by Alvopetro in 2023. Costs in the probable category also include one development well and costs for facilities upgrade. Future development costs at the Mãe-da-lua field relate to a stimulation of the existing producing well.

Alvopetro’s share of future development costs are summarized as follows:

$000s, Undiscounted		2024	2025	2026	2027	2028	Remaining	Total
Proved
	Caburé Natural Gas Field	6,993	–	–	–	–	–	6,993
	Murucututu Gas Field	2,050	6,885	–	–	–	–	8,935
	Bom Lugar Oil Field	–	510	–	–	–	–	510
	Mãe-da-lua Oil Field	–	551	–	–	–	–	551
Total Proved		9,043	7,946	–	–	–	–	16,989
Proved Plus Probable
	Caburé Natural Gas Field	6,993	2,504	–	–	–	–	9,497
	Murucututu Gas Field	3,950	20,655	–	–	–	–	24,605
	Bom Lugar Oil Field	–	6,059	–	–	–	–	6,059
	Mãe-da-lua Oil Field	–	551	–	–	–	–	551
Total Proved Plus Probable		10,943	29,769	–	–	–	–	40,712
Proved Plus Probable Plus Possible
	Caburé Natural Gas Field	6,993	2,504	–	–	–	–	9,497
	Murucututu Gas Field	3,950	27,540	–	–	–	–	31,490
	Bom Lugar Oil Field	–	6,059	–	–	–	–	6,059
	Mãe-da-lua Oil Field	–	551	–	–	–	–	551
Total Proved Plus Probable Plus Possible		10,943	36,654	–	–	–	–	47,597
See ‘Footnotes’ section at the end of this news release

Reconciliation of Alvopetro’s Gross Reserves (Before Royalty)^(1)(2)(3)(8)

	Proved(Mboe)	Probable(Mboe)	Proved Plus Probable(Mboe)	Possible (Mboe)	Proved plus Probable plus Possible (Mboe)
December 31, 2022	3,909	5,128	9,037	5,345	14,382
Discoveries	–	1,398	1,398	2,488	3,886
Extensions	–	148	148	(148)	–
Technical Revisions	(400)	(690)	(1,090)	(1,188)	(2,278)
Production	(782)	–	(782)	–	(782)
December 31, 2023	2,727	5,983	8,711	6,497	15,208
See ‘Footnotes’ section at the end of this news release.

December 31, 2023 Murucututu Contingent Resources Information:

Summary of Unrisked Company Gross Contingent Resources ^(1)(2)(5)(6)

Development Pending Economic Contingent Resources	Low Estimate	Best Estimate	High Estimate
Conventional natural gas (MMcf)	20,952	32,062	35,433
Natural gas liquids (Mbbl)	386	591	653
Oil equivalent (Mboe)	3,878	5,935	6,559
See ‘Footnotes’ section at the end of this news release.

Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Contingent Resources- $000s ^{(1)(2)(5)(6)(7)(8)}

	Undiscounted	5 %	10 %	15 %	20 %
Low Estimate	279,201	146,114	91,400	63,327	46,651
Best Estimate	470,246	226,624	139,760	97,612	73,016
High Estimate	540,860	246,103	148,348	102,781	76,691
See ‘Footnotes’ section at the end of this news release.

The GLJ Contingent Resource Report for Murucututu assumes capital deployment starting in 2025 for the drilling and completion of wells with total project costs of $20.8 million and first commercial production in 2025. The information presented herein is based on company net project development costs. The recovery technology assumed for purposes of the estimate is based on established technologies utilized repeatedly in the industry.

There can be no certainty that the project will be developed on the timelines discussed herein. The project is based on a pre-development study. Development of the project is dependent on several contingencies as further described in this news release. Significant positive factors relevant to the estimate include existing production in close proximity, proximity to infrastructure, existing long-term gas sales agreement and corporate commitment to the project. Significant negative factors relevant to the estimate include reservoir performance and the economic viability of the project (with sensitivity to low commodity prices), access to and amount of capital required to develop resources at an acceptable cost, and regulatory approvals for planned activities including stimulations and new infrastructure developments.

Summary of Development Pending Risked Company Gross Contingent Resources^(1)(2)(5)(6)

The GLJ Reserves and Resources Report estimates the Chance of Development as the product of two main contingencies associated with the project development, which are: 1) the probability of corporate sanctioning, which GLJ estimates at 95%; 2) the probability of finalization of a development plan, which GLJ estimates at 95%. The product of these two contingencies is 90%. As there is no risk related to discovery, the Chance of Commerciality for the contingent resource is therefore 90% which is the risk factor that has been applied to the Development Risked company gross contingent resources and the net present value figures reported below.

	Low Estimate	Best Estimate	High Estimate
Conventional natural gas (MMcf)	18,909	28,936	31,978
Natural gas liquids (Mbbl)	349	533	590
Oil equivalent (Mboe)	3,500	5,356	5,919
See ‘Footnotes’ section at the end of this news release.

Summary of Development Pending Risked Before Tax Net Present Value of Future Net Revenue of Contingent Resources- $000s^{(1)(5)(6)(7)(8)}

	Undiscounted	5 %	10 %	15 %	20 %
Low Estimate	251,978	131,868	82,489	57,153	42,102
Best Estimate	424,397	204,528	126,134	88,095	65,897
High Estimate	488,126	222,108	133,884	92,760	69,214
See ‘Footnotes’ section at the end of this news release.

December 31, 2023 Murucututu Prospective Resources Information:

Summary of Unrisked Company Gross Prospective Resources ^(1)(2)(4)(6)

Prospective Resources	Low	Best	High
Conventional natural gas (MMcf)	31,903	64,251	101,392
Natural gas liquids (Mbbl)	588	1,184	1,869
Oil equivalent (Mboe)	5,905	11,893	18,768
See ‘Footnotes’ section at the end of this news release.

Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Prospective Resources – $000s ^{(1)(4)(6)(7)(8)}

	Undiscounted	5 %	10 %	15 %	20 %
Low Estimate	395,126	179,911	96,052	56,094	34,354
Best Estimate	959,658	413,788	227,919	142,785	96,201
High Estimate	1,628,234	680,308	376,039	240,051	165,845
See ‘Footnotes’ section at the end of this news release.

The GLJ Reserves and Resources Report for Murucututu prospective resources assumes capital deployment starting in 2026 for the drilling and completion of wells and pipeline expansion costs, with total project costs of $75.8 million and first commercial production in 2026. The information presented herein is based on company project development costs. The recovery technology assumed for purposes of the estimate is based on established technologies utilized repeatedly in the industry.

There can be no certainty that the project will be developed on the timelines discussed herein. Development of the project is dependent on several contingencies as further described in this news release. The project is based on a conceptual study. Significant positive factors relevant to the estimate include existing production in close proximity, proximity to infrastructure, existing long-term gas sales agreement and corporate commitment to the project. Significant negative factors relevant to the estimate include reservoir performance and the economic viability of the project (with sensitivity to low commodity prices), access to and amount of capital required to develop resources at an acceptable cost, and regulatory approvals for planned activities including stimulations and new infrastructure developments.

Summary of Development Risked Company Gross Prospective Resources^(1)(2)(4)(6)

The GLJ Reserves and Resources Report estimates the Chance of Commerciality as the product between the Chance of Discovery and the Chance of Development. The Chance of Discovery of the prospective resources has been assessed at 90%, while the Chance of Development has been assessed as the same as for the Contingent Resources described above at 90%. The resulting Chance of Commerciality is 81%, which has been applied to the company gross unrisked prospective resources and the net present value figures reported below.

	Low	Best	High
Conventional natural gas (MMcf)	25,876	52,112	82,237
Natural gas liquids (Mbbl)	477	961	1,516
Oil equivalent (Mboe)	4,790	9,646	15,222
See ‘Footnotes’ section at the end of this news release.

Summary of Development Risked Before Tax Net Present Value of Future Net Revenue of Prospective Resources- $000s^{(1)(4)(6)(7)(8)}

	Undiscounted	5 %	10 %	15 %	20 %
Low Estimate	320,477	145,922	77,906	45,497	27,864
Best Estimate	778,356	335,614	184,859	115,810	78,027
High Estimate	1,320,623	551,782	304,997	194,700	134,513
See ‘Footnotes’ section at the end of this news release.

Upcoming 2023 Results and Live Webcast

Alvopetro anticipates announcing its 2023 fourth quarter and year-end results on March 19, 2024 after markets close and will host a live webcast to discuss the results at 8:00am Mountain time, on March 20, 2024. Details for joining the event are as follows:

DATE: March 20, 2024TIME: 8:00 AM Mountain/10:00 AM EasternLINK: https://us06web.zoom.us/j/83279531812 https://us06web.zoom.us/j/83920744797 DIAL-IN NUMBERS: https://us06web.zoom.us/u/kdcVycQytc WEBINAR ID: 839 2074 4797

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 [email protected].

Corporate Presentation

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

FOOTNOTES

(1)	References to Company Gross reserves or Company Gross Resources means the total working interest share of remaining recoverable reserves or resources held by Alvopetro before deductions of royalties payable to others and without including any royalty interests held by Alvopetro. With respect to the Caburé natural gas field, Alvopetro’s working interest was 49.1% as of December 31, 2023 but is subject to redetermination, the first of which is currently underway. The outcome of this redetermination is unknown and the resulting impact on the reserves presented herein may be material.
(2)	The tables above are a summary of the reserves of Alvopetro and the net present value of future net revenue attributable to such reserves as evaluated in the GLJ Reserves and Resources Report based on forecast price and cost assumptions. The tables summarize the data contained in the GLJ Reserves and Resources Report and as a result may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.
(3)	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.
(4)	Prospective Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. 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. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery as described in footnote 6.
(5)	Contingent Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates as described in footnote 6 and may be subclassified based on project maturity and/or characterized by their economic status. The Contingent Resources estimated in the GLJ Reserves and Resources Report are classified as “economic contingent resources”, which are those contingent resources that are currently economically recoverable. All such resources are further sub-classified with a project status of “development pending”, meaning that resolution of the final conditions for development are being actively pursued. The recovery estimates of the Company’s contingent resources provided herein are estimates only and there is no guarantee that the estimated resources will be recovered. There is uncertainty that it will be commercially viable to produce any portion of the resources. Actual recovered resource may be greater than or less than the estimates provided herein.
(6)	Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
	Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
	High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
(7)	The net present value of future net revenue attributable to Alvopetro’s reserves and resources are stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, well abandonment and reclamation costs for only those wells assigned reserves and material dedicated gathering systems and facilities. The net present values of future net revenue attributable to Alvopetro’s reserves and resources 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 and resource estimates of the Company’s reserves and resources provided herein are estimates only and there is no guarantee that the estimated reserves and resources will be recovered. Actual reserves and resources may be greater than or less than the estimates provided herein.
(8)	GLJ’s January 1, 2024 escalated price forecast is used in the determination of future gas sales prices under Alvopetro’s long-term gas sales agreement and for all forecasted oil sales and natural gas liquids sales. See https://www.gljpc.com/sites/default/files/pricing/Jan24.pdf for GLJ’s price forecast.

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.

All amounts contained in this news release are in United States dollars, except as otherwise noted.

Abbreviations:

1P	=	proved reserves
2P	=	proved plus probable reserves
3P	=	proved plus probable plus possible reserves
Mbbl	=	thousands of barrels
Mboe	=	thousand barrels of oil equivalent
MMbtu	=	million British Thermal Units
MMcf	=	million cubic feet
MMboe	=	million barrels of oil equivalent
$000s	=	thousands of U.S. dollars

Oil and Natural Gas Advisories

Oil and Natural Gas Reserves

The disclosure in this news release summarizes certain information contained in the GLJ Reserves and Resources Report but represents only a portion of the disclosure required under NI 51-101. Full disclosure with respect to the Company’s reserves as at December 31, 2023 will be included in the Company’s annual information form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before April 30, 2024. The GLJ Reserves and Resources Report incorporates Alvopetro’s working interest share of remaining recoverable reserves and resources. With respect to the Caburé natural gas field, Alvopetro’s working interest was 49.1% as of December 31, 2023 but is subject to redetermination, the first of which is currently underway. The outcome of this redetermination is unknown and the resulting impact on the reserves and the net presented value of future net revenue attributable to such reserves as presented herein may be material.

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, 2023. The reserves definitions used in this evaluation are the standards defined by 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. Full disclosure with respect to the Company’s contingent resources as at December 31, 2023 will be contained in the Company’s annual information form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before April 30, 2024.

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. Full disclosure with respect to the Company’s prospective resources as at December 31, 2023 will be contained in the Company’s annual information form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before April 30, 2024.

Boe Disclosure

The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

Forward-Looking Statements and Cautionary Language

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

Energy Fuels (UUUU) – Investment premise starting to become reality

Posted on February 27, 2024February 27, 2024 by [email protected]

Tuesday, February 27, 2024

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

Michael Heim, Senior Vice President, Equity Research Analyst, Energy & Transportation, Noble Capital Markets, Inc.

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

Energy Fuels reported financial results for the quarter and the year that were largely expected. Earnings for 2024 were $99.8 million or $0.62 per share. However, the positive results were due to a $119 million or $0.73 per share nonrecurring gain on the sale of property. Excluding the sale, the company would have reported a $20 million or $0.12 per share loss for the year. Quarterly losses were slightly higher than expected on limited sales.

Energy Fuel’s liquidity position has grown dramatically in recent quarters. As of December 31, 2023, the company had $222.34 million of working capital and no debt. With such a large liquidity position, the company is well positioned to expand operations without seeking external financing. This includes restarting uranium mining operations but could also fund all or most of the proposed REE Oxide circuit expansion.

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

*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.

Release – Hemisphere Energy Recognized as Top 50 TSX Venture Exchange Company

Posted on February 21, 2024February 21, 2024 by [email protected]

Research News and market Data on HMENF

February 21, 2024 7:30 AM EST | Source: Hemisphere Energy Corporation

Vancouver, British Columbia–(Newsfile Corp. – February 21, 2024) – Hemisphere Energy Corporation (TSXV: HME) (OTCQX: HMENF) (“Hemisphere” or the “Company”) is pleased to announce that it has been named as one of the top performers on the TSX Venture Exchange (“TSXV”) for the third consecutive year.

The 2024 TSXV 50 showcases the top 50 of over 1,600 TSXV issuers across five sectors: energy, mining, clean technology, life sciences, diversified industries, and technology. The ranking is an equal weighting of each company’s performance during 2023 across three key indicators: market capitalization growth, share price appreciation, and trading volume. More details can be found at the following link: www.tsx.com/venture50.

“We are proud to earn a ranking on the 2024 TSXV Venture 50 list for the third consecutive year,” said Don Simmons, President and Chief Executive Officer of Hemisphere. “The Company has continued to take great strides in growing its operations over the past year while maintaining a strong balance sheet and focusing heavily on return of capital to its shareholders.”

About Hemisphere Energy Corporation

Hemisphere is a dividend-paying Canadian oil company focused on maximizing value per share growth with the sustainable development of its high netback, low decline conventional heavy oil assets through polymer flood enhanced recovery methods. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol “HME” and on the OTCQX Venture Marketplace under the symbol “HMENF”.

For further information, please visit the Company’s website at www.hemisphereenergy.ca to view its corporate presentation or contact:

Don Simmons, President & Chief Executive Officer
Telephone: (604) 685-9255
Email: [email protected]
Website: www.hemisphereenergy.ca

SOURCE: Hemisphere Energy Corporation

Uranium’s Breakout Above $100/lb Signals Further Bull Run Ahead

Posted on February 21, 2024February 21, 2024 by [email protected]

The uranium spot price has crossed a major threshold, surging past $100/lb in January 2024 to reach $106.51/lb in early February. This long-awaited milestone marks the first time uranium has hit triple digits since the bull run leading up to the 2008 financial crisis.

The implications of breaching $100/lb are significant for the uranium market. Prices at this level indicate the serious supply and demand imbalances that have characterized the market for years are finally coming to a head. With demand outpacing available supply from mines, traders see uranium poised for further gains still.

The main driver behind January’s price spike was a cut to production forecasts from Kazatomprom, the world’s largest uranium miner. The company stunned the market by announcing lower guidance for 2024 and 2025 due to shortages of a key chemical and construction delays. This reversal came just months after Kazatomprom had planned to boost output to meet rising demand. The supply uncertainty led uranium prices to immediately jump over 8%.

For investors, Kazatomprom’s about-face signals that the supply response to uranium’s bull run may proceed slower than expected. Mine expansions and restarts are lagging, with not enough incentive yet for substantial new production. The supply picture is further complicated by uncertainty around Niger’s uranium exports following a coup there last year.

Junior uranium miners have been the biggest winners from the bullish momentum. With less exposure to long-term contracts than larger producers, juniors are benefiting from the full upside of rising spot prices. Many have announced restarts of idled capacity to take advantage of the favorable pricing environment. Their outsized gains indicate investors see juniors playing a key role in bridging future supply shortfalls.

Reaching the $100/lb mark is a psychological victory for uranium bulls who have waited years for prices to reflect positive fundamentals. Nuclear energy demand is on the rise again amid its role in carbon-free baseload power. With most forecast models predicting large supply deficits opening up over the next decade, there is a growing sense $100/lb is just the beginning.

Past experience shows reaching this triple-digit territory is when utilities truly start getting worried about security of supply. The last time uranium crossed above $100/lb in 2007, it sparked a frenzy of long-term contracting not seen before or since. While contracting volumes picked up last year, they remain below levels to fully cover global reactor requirements.

Many see $100/lb as the price needed to incentivize meaningful new mine production. Bringing large-scale conventional projects online takes over a decade when factoring in permitting and construction. Even smaller ISR operations can take several years to expand. With demand projected to outstrip supply for years to come, prices above $100/lb may be the new normal rather than an unsustainable spike.

For investors, uranium crossing $100/lb should serve as a wake-up call that a structural bull market is unfolding. Uranium has significantly outperformed most other commodity sectors over the past several years. With demand still rising and enormous lead times for new projects, supply shortfalls won’t be reversed overnight.

Now is the time for investors to gain exposure before uranium potentially keeps running toward new highs. Uranium equities offer upside well beyond movements in the underlying commodity price. Juniors in particular stand to see valuations explode higher if they can continue locking in contracts above $100/lb.

While nothing moves up forever, the fundamentals underpinning uranium’s surge past $100/lb look here to stay. Nuclear reactors need reliable fuel supply. Achieving net-zero carbon emissions globally depends on nuclear generation ramping up. With mines struggling to keep pace, all signs point to the uranium bull market having ample room left to run at these levels and beyond.

Why the Mining Sector Looks Poised for a Major Breakout

Posted on February 16, 2024February 20, 2024 by [email protected]

The mining sector has experienced boom and bust cycles throughout history, but current trends suggest we may be entering a new era of growth and opportunity. With the world transitioning to clean energy and electric vehicles, demand is surging for key minerals like lithium, cobalt, nickel and copper. This creates an attractive investment case for the mining sector.

Historic Trends

Looking back, the mining industry has gone through periods of rapid expansion and painful contraction. During economic expansions and commodity bull markets, mining companies ramp up exploration, development and production to capitalize on high prices. This leads to oversupply and when demand eventually weakens, the cycle turns downward.

We saw this play out in dramatic fashion over the past decade. High prices in the 2000s encouraged massive investment in new mines and supply capacity. But when Chinese growth began to slow around 2012, demand weakened and prices collapsed. The mining sector was forced to drastically cut back on production and capital investment.

Many mining companies barely stayed afloat during this bust period. But this reduction in supply helped set the stage for the next upcycle. Now, after years of underinvestment, mines are depleting reserves faster than they are being replenished. With commodity demand picking up again, conditions are ripe for the next mining boom.

Current Market Trends

Several key trends suggest we are now in the early stages of a new mining upcycle:

Electric vehicle revolution – EV adoption is accelerating around the world, dramatically increasing demand for lithium, cobalt, nickel, copper and other key minerals. Total EV sales increased 70% in 2021 and are projected to rise more than 5-fold by 2030. This will require a massive increase in mineral supply.
Renewable energy expansion – Solar, wind and other renewables are seeing surging growth as countries aim to cut carbon emissions. This further increases metals demand for batteries, transmission lines, wiring and other components.
Supply chain vulnerabilities – The pandemic and geopolitics have exposed risks of relying on a few key countries for critical mineral supply. Governments are now focused on developing domestic mining capacity to ensure supply security.
Decarbonization efforts – Reaching net zero emissions will require a staggering volume of minerals for clean energy infrastructure buildout. Models estimate needing 30 times more lithium and 15 times more cobalt by 2040.

These trends all point to a pending boom in mining investment and production. The demand outlook has fundamentally shifted in a more positive direction.

Take a moment to take a look at emerging growth natural resources, metals and mining companies by looking at Noble Capital Markets’ Senior Research Analyst Mark Reichman’s coverage list.

Investment Opportunities

For investors, this macro backdrop presents an opportunity to capitalize on the coming mining supercycle. Some ways to gain exposure include:

Lithium mining stocks – Lithium prices have skyrocketed 10-fold in the past two years as demand for electric vehicle batteries has soared. Leading lithium miners like Albemarle, SQM and Livent are seeing their earnings multiply. They are investing heavily to aggressively expand production capacity to ride the lithium boom. Their stocks still may have substantial upside given the tight supply and surging demand forecasts.
Nickel and cobalt miners – Clean energy technologies like batteries require vast amounts of nickel and cobalt. Both metals face looming supply deficits. Miners expanding production such as Glencore, Sherritt International and Giga Metals stand to benefit enormously from surging demand and higher prices over the coming decade. These miners offer some of the best leverage to capitalize on the EV battery revolution.
Copper miners – Copper is essential for global electrification and will be required by the millions of tons for EV charging networks, power grids, wiring and electronics. Leading copper miners like Freeport McMoRan, Southern Copper and First Quantum Minerals offer direct exposure to higher copper prices. Many are expanding production while also paying healthy dividends.
Diversified mining majors – Large diversified miners like BHP, Rio Tinto and Vale mine a broad mix of commodities from copper and iron ore to coal and potash. Their diversification provides stability while still benefiting from the overall minerals boom. These global giants pay some of the highest dividends in the market.
Junior mining stocks – Earlier stage mining companies developing new projects provide extreme upside potential leverage but also greater risk. Conduct thorough due diligence on management track record, finances, permitting status and feasibility studies before investing.
Physical gold and silver – Precious metals like gold and silver can provide a hedge against market volatility. Buying physical coins and bars or investing in ETFs offers exposure. Just a small allocation of 5-10% can help balance a portfolio.
Mining ETFs – Funds like the Global X Lithium ETF (LIT), VanEck Vectors Gold Miners ETF (GDX) and SPDR Metals & Mining ETF (XME) provide diversified exposure to mining stocks and commodities. This simplifies investing in the sector.

With mining poised to boom, investors have many options to position for the coming supercycle. As with any investment, proper due diligence and risk management remain critical. But the macro trends point to a bright future for mining stocks. For investors, now may be the ideal time to position for the coming mining supercycle.

Oil Rallies on Middle East Tensions Despite Questions Over Demand Growth

Posted on February 16, 2024February 16, 2024 by [email protected]

Oil prices are on track to post gains this week, driven higher by geopolitical tensions in the Middle East despite ongoing concerns about still high inflation and a cloudy demand outlook.

West Texas Intermediate crude futures have risen approximately 2% week-to-date and were trading around $78 per barrel on Friday. Brent crude, the international benchmark, was up 1.8% on the week to $83 per barrel.

According to analysts, speculative traders and funds are bidding up oil futures based on worries that simmering conflicts in the Middle East could disrupt global supplies. Volatility and uncertainty in the region tends to spur speculative trading in oil markets.

“This is geopolitics with flashing flights, it points right to specs taking advantage of the situation,” said Bob Yawger, managing director at Mizuho America. “They’re rolling the dice expecting something will happen.”

Tensions have escalated on the border between Israel and Lebanon after Israel conducted airstrikes in southern Lebanon this week in retaliation for rocket attacks from the area. The powerful Lebanese militia Hezbollah has vowed to strike back against Israel in response.

There are worries the Israel-Lebanon clashes could spread to a wider conflict, potentially including Israel’s ongoing offensive in Gaza. This could disrupt oil production or transit through the critical Suez Canal. The Middle East accounted for nearly 30% of global oil production last year.

Prices Shake Off Demand Worries

Notably, crude prices have shaken off downward pressure this week from stubbornly high inflation as well as forecasts for weaker demand growth in 2024.

US consumer and wholesale inflation reports this week came in hotter than expected. Persistently high inflation reduces the chances of the Federal Reserve pivoting to interest rate cuts this year which could otherwise boost oil demand.

Demand outlooks for 2024 have also been murky. The International Energy Agency (IEA) downwardly revised its 2024 oil demand growth forecast to 1.2 million barrels per day, half of 2023’s pace. It sees supply growth outpacing demand this year.

However, OPEC offered a more bullish view in its latest report, projecting world oil demand will increase by 2.2 million barrels per day in 2024. The cartel sees demand growth exceeding non-OPEC supply growth.

Investors Shake Off Bearish Signals

Given the conflicting demand forecasts, the resilience of oil prices likely reflects investor optimism over tightening fundamentals outweighing potentially bearish signals.

“There is and has been a yawning chasm in demand estimates,” said Tamas Varga, analyst at PVM brokerage. “The difference of opinions in global oil consumption for this year and the individual quarters, even for the current one, is clearly puzzling.”

Ultimately, lingering Middle East geopolitical risks appear to be overshadowing inflation and demand concerns in driving investor sentiment. With tensions still elevated, investors seem positioned for further volatility and potential price spikes on any supply disruptions.

The diverging demand forecasts and data points mean uncertainty persists around whether markets will tighten as much as OPEC expects or remain oversupplied per the IEA outlook. But with inventories still low by historical standards, prices have room to run higher on any bullish shocks.

What’s Next For Oil Markets

Looking ahead, Middle East tensions, China’s reopening, and the extent of Fed rate hikes will be key drivers of oil price trends. Any military escalation or supply disruptions from the Israel-Lebanon tensions could send crude prices spiking higher.

China’s demand recovery as it exits zero-Covid policies will also remain in focus. Signs of China’s crude imports and manufacturing activity reviving could offer a bullish boost to prices.

At the same time, stubborn inflation likely keeps the Fed on track for further rate hikes in the near term. Only clear signs of slowing price growth might promptdiscussion of rate cuts to stimulate growth. For now, Fed policy looks set to weigh on oil demand and limit significant upside.

Overall, investors should brace for continued volatility in oil markets in 2024. While prices may trend higher on tight supplies, lingering demand uncertainties and geo-political tensions look set to drive choppy price action. Nimble investors able to capitalize on price spikes and dips may find opportunities. But those with a lower risk tolerance may wish to stay on the sidelines until fundamentals stabilize.

Diamondback Energy Makes Massive $26 Billion Bet on Permian Basin with Acquisition of Endeavor Energy

Posted on February 12, 2024February 12, 2024 by [email protected]

Texas-based Diamondback Energy announced Monday that it will purchase Endeavor Energy Partners, the largest privately held oil and gas producer in the prolific Permian Basin, in a cash-and-stock deal valued at approximately $26 billion including debt.

The deal represents one of the largest energy sector acquisitions announced so far in 2024 and highlights the ongoing consolidation in the Permian as companies seek scale and improved efficiencies. Once completed, the merged company will be the third-largest producer in the basin behind only oil majors ExxonMobil and Chevron.

“Diamondback has proven itself to be a premier low-cost operator in the Permian Basin over the last 12 years, and this combination allows us to bring this cost structure to a larger asset base and allocate capital to a stronger pro forma inventory position,” said Travis Stice, CEO of Diamondback, in a statement.

The combined company is projected to pump 816,000 barrels of oil equivalent per day (boepd), with Diamondback estimating $550 million in annual cost savings. Diamondback shareholders will own approximately 60.5% of the new entity, while Endeavor owners will hold the remaining 39.5% stake.

The Permian Basin is located in West Texas and southeastern New Mexico. Technological advances in hydraulic fracturing and horizontal drilling have transformed the Permian into the most prolific oil field in the United States, responsible for about 40% of the country’s crude output.

The Diamondback-Endeavor deal is the latest in a string of major transactions aimed at consolidating Permian assets. In January, Exxon announced the purchase of independent producer Pioneer Natural Resources in a $60 billion agreement. Earlier in 2023, Permian drillers Civitas Resources and Colgate Energy revealed an all-stock merger valued at $7 billion.

Endeavor operates in the Midland sub-basin on the Texas side of the Permian, with its acreage located adjacent to existing Diamondback properties. This geographic overlap should allow for significant synergies as the companies integrate operations, infrastructure and drilling inventory.

Diamondback management highlighted Endeavor’s status as one of the Permian’s lowest-cost producers as a key rationale behind the acquisition. Folding Endeavor’s assets into Diamondback’s portfolio should lower overall expenses and boost cash flow on a per-share basis.

The merged company will hold approximately 1.1 million net acres in the Permian Basin and control over 2 billion barrels of recoverable oil equivalent resources. This expanded footprint provides enhanced scale for Diamondback to fund further development.

“This combination allows us to bring this cost structure to a larger asset base and allocate capital to a stronger pro forma inventory position,” noted Stice.

While offering enticing synergies, the partnership also carries risks if oil prices decline significantly from current levels near $80 per barrel. Diamondback is assuming roughly $7 billion of Endeavor’s debt as part of the transaction.

However, the substantial cost efficiencies and expanded production capacity position the newly merged business well for strong free cash flow generation, even in a lower price environment.

The deal is expected to close in Q4 2024 after customary approvals. Shares of Diamondback were up nearly 3% in Monday morning trading on news of the acquisition. The transaction continues the consolidation wave among Permian Basin independents as companies strive to improve margins and gain scale.

For Diamondback, the bold bet on Endeavor represents an opportunity to solidify its status as a Permian leader, while acquiring premium assets that should drive growth for years to come. The combined corporation will boast immense resources, significant capital flexibility and a management team with a proven track record in the basin.

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The Top 5 Western Oil Giants Are Courting Investors with Record Payouts Despite Profit Declines

Posted on February 8, 2024February 8, 2024 by [email protected]

The biggest publicly traded oil companies in the West had a clear message for investors this earnings season: We’re going to keep paying you billions in dividends and stock buybacks, no matter how much our profits fluctuate.

BP, Chevron, ExxonMobil, Shell and TotalEnergies doled out over $111 billion to shareholders in 2023, an all-time record for the group, according to a Reuters analysis. This lavish payout comes even as the companies’ combined net profits sank 37% from 2022’s windfall heights of $196 billion.

It’s a calculated move to reassure investors, particularly major institutional shareholders like pension funds, that the oil supermajors still deserve a place in their portfolios despite LAST year’s stark reminder of the sector’s persistent volatility.

For over a decade, Big Oil has seen its status as a stalwart, dividend-paying pillar of investors’ portfolios slowly erode. The energy sector’s weighting in the S&P 500 index sat at just 4.4% in January, down dramatically from 14% in 2012.

Several factors catalyzed this decline: poor capital discipline leading to wasted spending and subsequent dividend cuts, huge swings in oil and gas prices, the rise of the tech sector, and growing concerns about oil’s role in climate change.

But Russia’s invasion of Ukraine in 2023 sparked an unexpected fossil fuel rally, with Brent crude prices averaging over $100 per barrel and natural gas prices skyrocketing. The oil giants cashed in with their highest profits ever, starkly highlighting the sector’s persistent upside potential.

Now with economic headwinds buffeting energy markets, their mammoth payouts to shareholders seek to underscore oil’s reliability versus more speculative investments. “During a time of geopolitical turmoil and economic uncertainty, our objective remained unchanged: safely deliver higher returns and lower carbon,” said Chevron CEO Mike Wirth after announcing a 6% dividend increase.

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Besides dividends, oil majors are channeling these record buybacks to shareholders. Exxon Mobil alone spent $35 billion last year snapping up its own shares, while Shell has vowed “complete predictability” around shareholder returns.

This focus on payouts over production indicates Big Oil has absorbed the lessons of overspending on large-scale projects with uncertain demand outlooks. After former CEO John Browne spearheaded a failed push for aggressive growth at BP, lease write-downs of $60 billion soon followed.

Now with the transition to cleaner energy casting further uncertainty over long-term oil demand, companies are tightly rationing investment. Bernstein analyst Oswald Clint said investors “absolutely remember the sins of the past investment cycles and are pretty determined not to repeat those.”

While Exxon and Chevron are still expanding oil output, others like BP and Shell plan to cut production over this decade as part of their climate strategies. But all are aligning around far greater capital discipline and what they call “high-grading” their portfolios.

Rather than chasing growth, new projects must meet stricter hurdles for returns, emissions, and regulations. Tobias Wagner of Moody’s Investors Service expects only minimal investment increases industry-wide in 2024 given the cautious outlook.

So even as society decarbonizes, the oil supermajors are making a case that their stocks can still reward shareholders through the transition. Yet it remains to be seen whether investors who have fled the sector for greener pastures like clean energy and tech will find these guarantees compelling enough to return.

GM Commits $19 Billion Through 2035 to Secure EV Battery Materials From LG Chem

Posted on February 7, 2024February 7, 2024 by [email protected]

General Motors (GM) announced Wednesday its largest investment yet to lock up critical raw materials needed for its ambitious electric vehicle (EV) production plans. The Detroit automaker said it will spend $19 billion over the next decade to source cathode materials from South Korean supplier LG Chem.

The materials—including nickel, cobalt, manganese and aluminum—are key ingredients for the lithium-ion batteries that power EVs. Under the agreement spanning 2026-2035, LG Chem will ship over 500,000 tons of cathode materials to GM’s joint battery cell plants with LG spinoff Ultium Cells in the United States.

GM stated this is enough supply for approximately 5 million EVs with an estimated range of over 300 miles per charge. The materials will come from an LG Chem plant currently under construction in Tennessee.

For GM, signing a long-term purchase agreement helps mitigate risks around securing sufficient future EV battery supplies amid intensifying competition. As automakers collectively invest billions to shift their lineups to mostly EVs by 2030, critical mineral shortages could constrain production plans.

“This contract builds on GM’s commitment to create a strong, sustainable battery EV supply chain to support our fast-growing EV production needs,” said Jeff Morrison, GM vice president of global purchasing and supply chain.

The LG Chem deal ranks among the largest—if not the largest—EV supply contract inked by GM to date. It highlights an urgency by the company to lock up raw materials as the global auto industry accelerates its electric shift. GM aspires to exclusively sell EVs by 2035.

However, the 14-year LG Chem agreement also implies GM may be adapting its EV strategy to account for adoption happening slower than anticipated. The original pact was scheduled to expire in 2030, but GM extended it another five years.

After initially forecasting aggressive EV sales growth, GM has pulled back on targets amid steeping battery costs and strained consumer budgets. “We’re also being a little bit prudent about the pace at which the transition occurs,” said CEO Mary Barra.

Nonetheless, GM remains laser-focused on its EV future. It recently announced a $650 million investment to expand production of its profitable full-size SUVs—but as electric versions only by 2024. “We have the manufacturing flexibility to build EVs at scale,” said Barra.

For investors, GM’s major bet on EVs represents an opportunity to capitalize on the immense growth projected in the electric vehicle market over the next decade. Research firm IDTechEx forecasts the EV market will balloon from $287 billion in 2021 to over $1.3 trillion by 2031 as adoption accelerates globally. GM’s plan to phase out gas-powered cars and transition to an all-electric lineup positions it as a leading EV player in this booming new automotive era.

Meanwhile, LG Chem said it aims to “bolster cooperation with GM in the North American market” through the expanded cathode materials agreement. The supplier has jockeyed with China’s CATL for the title of world’s top EV battery maker.

For both LG and GM, ensuring cathode supply security with a US-based plant mitigates geopolitical risks. President Biden’s Inflation Reduction Act requires automakers to source critical minerals domestically or from allies to qualify for EV tax credits.

While the road to an all-electric future remains bumpy, GM’s huge bet on sourcing vital battery ingredients shows its commitment to phasing out the internal combustion engine. As Barra stated, “We’re on our way to an all-electric portfolio.”

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