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Release – Alvopetro Announces 2023 Year End Reserves

Posted on February 27, 2024February 27, 2024 by aweinsoff@channelchek.com

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 socialmedia@alvopetro.com.

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.

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

All amounts contained in this 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 cpereira@noblefcm.com

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 aweinsoff@channelchek.com

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: info@hemisphereenergy.ca
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 slightbourne@noblecapitalmarkets.com

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.

Oil Rallies on Middle East Tensions Despite Questions Over Demand Growth

Posted on February 16, 2024February 16, 2024 by slightbourne@noblecapitalmarkets.com

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 slightbourne@noblecapitalmarkets.com

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.

Take a moment to take a look at a few emerging growth energy companies by taking a look at Noble Capital Markets’ Senior Research Analyst Michael Heim’s coverage list.

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

Posted on February 8, 2024February 8, 2024 by slightbourne@noblecapitalmarkets.com

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.

Take a moment to take a look at emerging growth companies by taking a look at Noble Capital Markets’ Research Analyst Michael Heim’s coverage list.

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.

Release – InPlay Oil Corp. Confirms Monthly Dividend for February 2024

Posted on February 2, 2024February 2, 2024 by aweinsoff@channelchek.com

Research News and Market Data on IPOOF

Feb 01, 2024, 18:00 ET

CALGARY, AB, Feb. 1, 2024 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) is pleased to confirm that its Board of Directors has declared a monthly cash dividend of $0.015 per common share payable on February 29, 2024, to shareholders of record at the close of business on February 15, 2024. The monthly cash dividend is expected to be designated as an “eligible dividend” for Canadian federal and provincial income tax purposes.

About InPlay Oil Corp.

InPlay is a junior oil and gas exploration and production company with operations in Alberta focused on light oil production. The company operates long-lived, low-decline properties with drilling development and enhanced oil recovery potential as well as undeveloped lands with exploration possibilities. The common shares of InPlay trade on the Toronto Stock Exchange under the symbol IPO and the OTCQX Exchange under the symbol IPOOF.

SOURCE InPlay Oil Corp.

For further information: please contact: Doug Bartole, President and Chief Executive Officer, InPlay Oil Corp., Telephone: (587) 955-0632, www.inplayoil.com; Darren Dittmer, Chief Financial Officer, InPlay Oil Corp., Telephone: (587) 955-0634

InPlay Oil (IPOOF) – Updated guidance reflects reduced production expectations

Posted on January 31, 2024January 31, 2024 by cpereira@noblefcm.com

Wednesday, January 31, 2024

InPlay Oil is a junior oil and gas exploration and production company with operations in Alberta focused on light oil production. The company operates long-lived, low-decline properties with drilling development and enhanced oil recovery potential as well as undeveloped lands with exploration possibilities. The common shares of InPlay trade on the Toronto Stock Exchange under the symbol IPO and the OTCQX Exchange under the symbol IPOOF.

Michael Heim, 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.

Management updated its 2023 guidance. The adjustment reflects a drop in production expectations. New guidance is significantly below the 9,700 boe/d production flow reported from the field on November 9, 2023. The decline may represent a sharper decline rate from initial production rates than had previously been expected by management. The drop in production lead to a sharp reduction in projected Adjusted Funds Flow and Free Funds Flow.

Management also sharply reduced its 2024 production estimates. New guidance calls for 2024 production that is only slightly higher than newly revised 2023 guidance despite the drilling of 14-15 new wells and an expected reduction in curtailment. While it is possible that management is simply being conservative, it may also reflect well decline rates as discussed above.

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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).

Release – InPlay Oil Corp. Announces 2024 Capital Budget

Posted on January 29, 2024January 29, 2024 by aweinsoff@channelchek.com

Research News and Market Data on IPOOF

Jan 29, 2024, 08:00 ET

CALGARY, AB, Jan. 29, 2024 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) is pleased to announce that its Board of Directors have approved a capital program of $64 – $67 million for 2024.

2024 Capital Program Highlights

InPlay’s 2024 exploration and development capital program of $64 – $67 million is forecast to deliver the following⁽⁵⁾:

Annual average production of 9,000 – 9,500 boe/d (59% – 61% light crude oil and NGLs);
Drilling program focused on high return oil weighted locations driving annual oil production growth at the midpoint of guidance of 7% over 2023;
Operating income profit margin⁽²⁾ of approximately 59%;
Reduction in capital spending of 20% – 25% compared to 2023 including reduced facilities and infrastructure spending by over 50% providing strong capital efficiencies;
Adjusted Funds Flow (“AFF”)⁽⁴⁾ of $89 – $96 million;
Free Adjusted Funds Flow (“FAFF”)⁽²⁾ of $22 – $32 million;
Net debt⁽⁴⁾ of $37 – $44 million with a net debt to EBITDA ratio⁽²⁾ of 0.4 – 0.5 times which is among the lower leverage ratios amongst our peers;
Base dividend of $16 – $17 million at the current monthly dividend rate of $0.015/share ($0.18/share annualized) which represents approximately an 8% yield at the current share price; and
Significant unutilized financial liquidity which can be used to pursue potential tactical capital investments.

The table below highlights our 2024 guidance:

	2024⁽⁵⁾
WTI (US$/bbl)	75.00
Production (boe/d) ⁽¹⁾	9,000 – 9,500
Capital ($ millions)	64 – 67
Net wells	14.0 – 15.0
AFF ($ millions)⁽⁴⁾	89 – 96
FAFF ($ millions)⁽²⁾	22 – 32
Net Debt at Year-end ($ millions)⁽⁴⁾	(44) – (37)
Annual Net Debt / EBITDA ⁽²⁾	0.4 – 0.5
Dividend ($ millions)	16 – 17

The amounts above do not include potential future purchases through the Company’s normal course issuer bid (“NCIB”).

With continued commodity price volatility, specifically weak natural gas fundamentals, and current low investor sentiment, InPlay has taken a measured and disciplined approach to capital allocation for 2024, seeking to maximize capital efficiencies, AFF⁽²⁾, and FAFF⁽²⁾ supporting strong returns to shareholders with a priority on maintaining our pristine balance sheet. Despite a 20% to 25% reduction in capital spending year over year, InPlay is forecasting to deliver approximately 7% growth in our oil volumes as we focus on higher oil weighted assets that deliver greater returns. The capital program is designed to responsibly manage the pace of development, maintain flexibility and remain focused on delivering return of capital to shareholders.

Given the higher rate of return of InPlay’s oil weighted properties, the Company plans to direct its 2024 capital budget towards oil weighted drilling in the Cardium and Belly River. Plans are to drill approximately 11 – 12 net Extended Reach Horizontal (“ERH”) Cardium wells in Willesden Green and Pembina. Also, 3.0 net wells are planned in the Belly River taking advantage of the very high oil weighting of approximately 90%. These Belly River wells exhibit increasing oil rates over the first three quarters of production and a low decline rate thereafter. Our two most recent horizontal wells drilled in the Belly River, which came online in November 2022, have delivered operating netbacks of approximately $71.25/boe since being brought on production. Our higher oil weighted locations are characterized by strong light oil rates with lower total boe/d rate relative to wells with higher natural gas weightings. The Company’s 2024 drilling program plans on drilling fewer wells in 2024 compared to 2023, as a result of our cautious, disciplined capital approach for the year and is structured to take advantage of improving differentials starting in the second quarter of 2024 and throughout the balance of the year. Facility capital in 2024 is forecasted to be approximately $6.4 million less than 2023 due to the reduced drilling program and significant capital spent on two major natural gas plant upgrades completed in 2023.

InPlay’s first quarter of 2024 drilling program consists of five (4.9 net) ERH Cardium wells and three (0.7 net) non-operated ERH Cardium wells. Drilling has started on a two well (1.9 net) pad in Willesden Green which is expected to come on production in February. Capital activity will then move to Pembina to drill three (3.0 net) Cardium ERH wells. These wells will offset our five successful wells drilled in 2023 characterized by low decline rates and high light oil and liquids weighting with average initial production (“IP”) rates of 257 boe/d (89% light crude oil and liquids), 265 boe/d (86% light crude oil and liquids) and 239 boe/d (82% light crude oil and liquids) over their first 30, 60 and 180 days respectively.

InPlay made significant investments in 2023 to increase operated natural gas takeaway capacity for future growth in Willesden Green and to mitigate potential production issues arising from third party outage and capacity constraints. These projects have already shown their value by reducing back pressure on wells, lowering declines and providing more consistent runtimes while improving our liquids weighting with a higher natural gas liquids recovery. To further enhance our natural gas takeaway capabilities, InPlay has entered into a long term Gas Handling Agreement with an industry partner guaranteeing access to natural gas takeaway and processing capacity in the Company’s Pembina area where we were initially curtailed by approximately 6 mmcfd and associated oil and liquids starting on February 15, 2023 with the gradual reduction in curtailments and the full resumption of production in September 2023. This contract will allow InPlay to restart with certainty of capacity the development of this prolific and strong rate of return growth area where drilling activity has not occurred since the spring of 2022. InPlay plans on drilling a three (3.0 net) ERH Cardium well pad in this area in the third quarter of 2024. The Company projects fewer operated and non-operated turnarounds and other infrastructure issues during 2024 after an unprecedented high level of disruptions in 2023.

To mitigate risk and add stability during periods of market volatility, commodity hedges have been secured through 2024 and into 2025 as summarized below.

	Q1/24	Q2/24	Q3/24	Q4/24	Q1/25
Natural Gas AECO Swap (mcf/d)	–	1,900	1,900	640	–
Hedged price ($AECO/mcf)	–	2.00	2.00	2.00	–
Natural Gas AECO Costless Collar (mcf/d)	4,870	3,790	3,790	5,050	3,790
Hedged price ($AECO/mcf)	2.48 – 3.82	2.08 – 2.77	2.08 – 2.77	2.27 – 3.04	2.48 – 3.46
Crude Oil Costless Collar (bbl/d)	–	1,000	–	–	–
Hedged price ($USD WTI/bbl)	–	72.00 – 80.25	–	–	–
Crude Oil Costless Collar (bbl/d)	330	–	–	–	–
Hedged price ($CAD WTI/bbl)	95.00 – 110.00	–	–	–	–

Crude Oil WTI Three-way Collar (bbl/d)⁽⁷⁾	–	–	1,000	1,000	–
Low sold put price ($USD WTI/bbl)	–	–	64.00	64.00	–
Mid bought put price ($USD WTI/bbl)	–	–	74.00	74.00	–
High sold call price ($USD WTI/bbl)	–	–	82.48	82.48	–

InPlay will continue to prudently allocate capital resources and adjust its capital plans in consideration of commodity prices, inflationary cost pressures and other aspects impacting our business. Should commodity prices improve and stabilize, InPlay will remain disciplined and flexible and can quickly adjust capital activity to respond to changing market conditions.

2023 Update

InPlay’s fourth quarter capital program consisted of drilling two (1.6 net) ERH wells in Willesden Green that were brought on production in November. Also, the company drilled its first (1.0 net) multilateral Belly River horizontal well which was brought on production in December. The well has been on production for approximately one month and is still in its initial stages of cleanup and early production results are meeting our internal expectations with oil cuts increasing, consistent with offsetting wells.

The increase in North American natural gas production coupled with a warm start to winter has natural gas storage inventories at very high levels resulting in weaker than expected natural gas prices during the fourth quarter that continued into 2024. Crude oil differentials began to weaken in November and widened throughout the quarter which impacted realized oil pricing during this period. Higher differentials are extending into the first quarter of 2024 but forward indices show them improving and narrowing starting in the second quarter of 2024 and throughout the remainder of the year.

Annual average production for 2023 is forecast to be approximately 9,050 boe/d⁽¹⁾(58% light crude oil & NGLs) which was impacted by approximately 650 boe/d over the year due to extraordinary curtailments experienced from third party capacity constraints and turnarounds, Alberta wildfires, and from delays in starting up our natural gas facility in the third quarter as discussed in our prior press releases.

The table below highlights our updated forecasted 2023 guidance:

	2023⁽³⁾
WTI (US$/bbl)	77.61
Production (boe/d) ⁽¹⁾	9,000 – 9,100
Capital ($ millions)	84.5
Net wells	17.1
AFF ($ millions)⁽⁴⁾	91 – 93
FAFF ($ millions)⁽²⁾	6 – 8
Net Debt at Year-end ($ millions)⁽⁴⁾	(45) – (47)
Dividend ($ millions)	16

See Reader Advisories for previous guidance and underlying assumptions.

As commented on above, continued commodity price volatility and current weak industry sentiment has resulted in the Company taking a conservative, disciplined approach to capital allocation in 2024. Preliminary estimates and plans for 2025 and beyond will be dependent on the stability of commodity prices and industry sentiment balancing manageable growth and ensuring the long term sustainability of our return of capital to shareholder strategy. As a result, the Company withdraws its preliminary estimates and plans for 2025.

We look forward to the profitable development of our high rate of return asset base and continuing to provide strong returns to shareholders through 2024 and beyond. On behalf of our employees, management team and Board of Directors, we would like to thank our shareholders for their support.

For further information please contact:

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

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

Notes:
1.	See “Reader Advisories – Production Breakdown by Product Type”
2.	Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release.
3.	Based on estimated, unaudited year-end 2023 results. See “Reader Advisories – Forward Looking Information and Statements” for underlying assumptions related to our estimated, unaudited year-end 2023 results.
4.	Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
5.	See “Reader Advisories – Forward Looking Information and Statements” for key budget and underlying assumptions related to our 2024 capital program and associated guidance.
6.	Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
7.	The WTI three-way collars are a combination high priced sold call, low priced sold put and a mid-priced bought put. The high sold call price is the maximum price the Company will receive for the contract volumes. The mid bought put price is the minimum price InPlay will receive, unless the market price falls below the low sold put strike price, in which case InPlay receives market price plus the difference between the mid bought put price minus the low sold put price.

Reader Advisories

Non-GAAP and Other Financial Measures

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

Non-GAAP Financial Measures and Ratios

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

Free Adjusted Funds Flow

Management considers FAFF an important measure to identify the Company’s ability to improve its financial condition through debt repayment and its ability to provide returns to shareholders. FAFF should not be considered as an alternative to or more meaningful than AFF as determined in accordance with GAAP as an indicator of the Company’s performance. FAFF is calculated by the Company as AFF less exploration and development capital expenditures and property dispositions (acquisitions) and is a measure of the cashflow remaining after capital expenditures before corporate acquisitions that can be used for additional capital activity, corporate acquisitions, repayment of debt or decommissioning expenditures or potentially return of capital to shareholders. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast FAFF.

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

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

Net Debt to EBITDA

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

Production per Debt Adjusted Share

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

EV / DAAFF

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

Capital Management Measures

Adjusted Funds Flow

Management considers adjusted funds flow to be an important measure of InPlay’s ability to generate the funds necessary to finance capital expenditures. Adjusted funds flow is a GAAP measure and is disclosed in the notes to the Company’s financial statements for the year ending December 31, 2022 and the most recently filed quarterly financial statements. All references to adjusted funds flow throughout this document are calculated as funds flow adjusting for decommissioning expenditures and transaction and integration costs. Decommissioning expenditures are adjusted from funds flow as they are incurred on a discretionary and irregular basis and are primarily incurred on previous operating assets. Transaction costs are non-recurring costs for the purposes of an acquisition, making the exclusion of these items relevant in Management’s view to the reader in the evaluation of InPlay’s operating performance. The Company also presents adjusted funds flow per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of profit per common share.

Net Debt

Net debt is a GAAP measure and is disclosed in the notes to the Company’s financial statements for the year ending December 31, 2022 and the most recently filed quarterly financial statements. The Company closely monitors its capital structure with the goal of maintaining a strong balance sheet to fund the future growth of the Company. The Company monitors net debt as part of its capital structure. The Company uses net debt (bank debt plus accounts payable and accrued liabilities less accounts receivables and accrued receivables, prepaid expenses and deposits and inventory) as an alternative measure of outstanding debt. Management considers net debt an important measure to assist in assessing the liquidity of the Company.

Supplementary Measures

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

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

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

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

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

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

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

Preliminary Financial Information

The Company’s expectations set forth in the updated forecasted 2023 guidance are based on, among other things, the Company’s anticipated financial results for the three and twelve month periods ended December 31, 2023. The Company’s anticipated financial results are unaudited and preliminary estimates that: (i) represent the most current information available to management as of the date of hereof; (ii) are subject to completion of audit procedures that could result in significant changes to the estimated amounts; and (iii) do not present all information necessary for an understanding of the Company’s financial condition as of, and the Company’s results of operations for, such periods. The anticipated financial results are subject to the same limitations and risks as discussed under “Forward Looking Information and Statements” below. Accordingly, the Company’s anticipated financial results for such periods may change upon the completion and approval of the financial statements for such periods and the changes could be material.

Forward-Looking Information and Statements

This news release contains certain forward–looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the Company’s business strategy, milestones and objectives; all estimates and guidance related to the year ended 2023 results; the Company’s planned 2024 capital program including wells to be drilled and completed and the timing of the same; 2024 guidance based on the planned capital program and all associated underlying assumptions set forth in this press release including, without limitation, forecasts of 2024 annual average production levels, adjusted funds flow, free adjusted funds flow, Net Debt/EBITDA ratio, operating income profit margin, and Management’s belief that the Company can grow some or all of these attributes and specified measures; light crude oil and NGLs weighting estimates; expectations regarding future commodity prices; future oil and natural gas prices; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition, development and infrastructure activities and related capital expenditures, including our planned 2024 capital program; the amount and timing of capital projects;; and methods of funding our capital program.

The internal projections, expectations, or beliefs underlying our Board approved 2024 capital budget and associated guidance are subject to change in light of, among other factors, the impact of world events including the Russia/Ukraine conflict and war in the Middle East, ongoing results, prevailing economic circumstances, volatile commodity prices, and changes in industry conditions and regulations. InPlay’s 2024 financial outlook and guidance provides shareholders with relevant information on management’s expectations for results of operations, excluding any potential acquisitions or dispositions, for such time periods based upon the key assumptions outlined herein. Readers are cautioned that events or circumstances could cause capital plans and associated results to differ materially from those predicted and InPlay’s guidance for 2024 may not be appropriate for other purposes. Accordingly, undue reliance should not be placed on same.

Without limitation of the foregoing, readers are cautioned that the Company’s future dividend payments to shareholders of the Company, if any, and the level thereof will be subject to the discretion of the Board of Directors of InPlay. The Company’s dividend policy and funds available for the payment of dividends, if any, from time to time, is dependent upon, among other things, levels of FAFF, leverage ratios, financial requirements for the Company’s operations and execution of its growth strategy, fluctuations in commodity prices and working capital, the timing and amount of capital expenditures, credit facility availability and limitations on distributions existing thereunder, and other factors beyond the Company’s control. Further, the ability of the Company to pay dividends will be subject to applicable laws, including satisfaction of solvency tests under the Business Corporations Act (Alberta), and satisfaction of certain applicable contractual restrictions contained in the agreements governing the Company’s outstanding indebtedness.

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

The forward-looking information and statements included herein are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: the continuing impact of the Russia/Ukraine conflict and war in the Middle East; inflation and the risk of a global recession; changes in our planned 2023 capital program; changes in our approach to shareholder returns; changes in commodity prices and other assumptions outlined herein; the risk that dividend payments may be reduced, suspended or cancelled; the potential for variation in the quality of the reservoirs in which we operate; changes in the demand for or supply of our products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans or strategies of InPlay or by third party operators of our properties; changes in our credit structure, increased debt levels or debt service requirements; inaccurate estimation of our light crude oil and natural gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in InPlay’s continuous disclosure documents filed on SEDAR including our Annual Information Form and our MD&A.

This press release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about InPlay’s financial and leverage targets and objectives, potential dividends, share buybacks and beliefs underlying our Board approved 2024 capital budget and associated guidance, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. The actual results of operations of InPlay and the resulting financial results will likely vary from the amounts set forth in this press release and such variation may be material. InPlay and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s reasonable estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, InPlay undertakes no obligation to update such FOFI. FOFI contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about InPlay’s anticipated future business operations and strategy. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein.

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

Risk Factors to FLI

Risk factors that could materially impact successful execution and actual results of the Company’s 2023 and 2024 capital program and associated guidance and estimates include:

volatility of petroleum and natural gas prices and inherent difficulty in the accuracy of predictions related thereto;
the extent of any unfavourable impacts of wildfires in the province of Alberta.
changes in Federal and Provincial regulations;
the Company’s ability to secure financing for the Board approved 2024 capital program and longer-term capital plans sourced from AFF, bank or other debt instruments, asset sales, equity issuance,
infrastructure financing or some combination thereof; and
those additional risk factors set forth in the Company’s MD&A and most recent Annual Information Form filed on SEDAR

Key Budget and Underlying Material Assumptions to FLI

The key budget and underlying material assumptions used by the Company in the development of its current and previous 2023 guidance and 2024 guidance are as follows:

The change in production per debt adjusted share growth between previous and updated guidance is primarily due to 2023 production being impacted by approximately 650 boe/d as a result of curtailments, Alberta wildfires, natural gas facility startup delays as discussed in the body of this press release.

⁽¹⁾	As previously released August 14, 2023.
⁽²⁾	As previously released November 9, 2023.
⁽³⁾	As previously released January 18, 2023.
⁽⁴⁾	Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Debt adjusted shares is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. Future share prices are assumed to be consistent with the current share price.
⁽⁵⁾	Weighted average share price throughout 2022 and 2023.
⁽⁶⁾	Ending share price at December 31, 2022 and December 31, 2023.
⁽⁷⁾	The change in the 2023 forecasted results from prior guidance results from an increase in capital expenditures and decrease in adjusted funds flow as a result of a reduction to production, a higher natural gas weighting of total production and lower AECO natural gas prices than previously forecasted.
⁽⁸⁾	The Company has withdrawn its 2024 and 2025 production per debt adjusted share and EV/DAAFF forecast for 2024 and 2025. The Company believes that these metrics can be quite variable and hard to reasonably estimate given the volatility in the Company’s share price, which is a material assumption used in the calculation of these metrics.
⁽⁹⁾	Continued commodity price volatility and current weak industry sentiment has resulted in the Company taking a conservative and disciplined approach to capital allocation in 2024 and future years. Preliminary estimates and plans for 2025 and beyond will be dependent on the stability of commodity prices and industry sentiment balancing manageable growth and ensuring the long term sustainability of our return of capital to shareholder strategy. As a result, the Company withdraws its preliminary estimates and plans for 2025.

See “Production Breakdown by Product Type” below
Quality and pipeline transmission adjustments may impact realized oil prices in addition to the MSW Differential provided above
Changes in working capital are not assumed to have a material impact between the years presented above.

Production Breakdown by Product Type

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

Notes:
1.	This reflects the mid-point of the Company’s 2023 updated production guidance range of 9,000 to 9,100 boe/d.
2.	This reflects the mid-point of the Company’s 2023 previous production guidance range of 9,100 to 9,500 boe/d.
3.	This reflects the mid-point of the Company’s 2024 production guidance range of 9,000 to 9,500 boe/d.
4.	This reflects the midpoint of the Company’s annual production previous preliminary estimate range.
5.	With respect to forward–looking production guidance, product type breakdown is based upon management’s expectations based on reasonable assumptions but are subject to variability based on actual well results.

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

BOE Equivalent

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

Initial Production Rates

References in this press release to IP rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary.

SOURCE InPlay Oil Corp.

Hemisphere Energy (HMENF) – Hemisphere reports production levels near expectations, offers initial 2024 guidance

Posted on January 26, 2024January 26, 2024 by cpereira@noblefcm.com

Friday, January 26, 2024

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.

Hemisphere Energy reported 2024-4Q production results. Hemisphere Energy reported production of 3,375 boe/d, a 16% increase over the same period in 2022 and an 11% increase over 2023-3Q results. Production for the most recent quarter surpassed the 3,325 boe/d rate we had been using in our models.

Management gives initial 2024 production, pricing, and cost guidance. Management gave initial 2024 production, cash flow and capital expenditure guidance. Guidance was largely in line with our expectations.

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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).

Rotating Into Mining: The Overlooked Opportunity in Natural Resources

Posted on January 23, 2024January 23, 2024 by slightbourne@noblecapitalmarkets.com

In the investing world, money often rotates between different sectors over time. After a long period of technology stocks dominating, we may now be entering a new cycle where mining and natural resource stocks start to outperform other industries and sectors. There are several compelling reasons mining could be the next big thing for investors.

First, demand is soaring for the critical minerals and metals used in electric vehicles, batteries, and clean energy. Metals like lithium, nickel, cobalt, and copper are essential for manufacturing electric car batteries, solar panels, wind turbines, and other green technologies. With many countries pushing for faster adoption of EVs and renewable power, demand for these key minerals is skyrocketing. Major automakers have announced ambitious electric vehicle plans, which requires secure access to raw materials. This imbalance between booming demand and limited supply bodes well for mining firms.

Additionally, the pandemic exposed risks of relying on a few countries for critical minerals. It revealed the need for domestic mining capacity to ensure stable access to essential inputs like lithium. For instance, the U.S. aims to boost domestic production of strategic minerals and reduce dependence on China. The EU also has a new plan to secure rare earth supplies within Europe. This focus on mineral independence is a plus for miners in North America and Europe.

Rising inflation and gold prices also bolster the case for mining stocks. With central banks printing huge amounts of money, many investors see gold as an inflation hedge. This has helped push gold prices to an 8-month high around $1900/ounce. Higher inflation tends to lift gold and silver prices as people flock to hard assets. Many miners produce both precious metals alongside base metals. They benefit from rising gold and silver prices.

Additionally, gold often rises when risks are high, like the current Russia-Ukraine and Israel-Gaza crises. Its safe haven appeal attracts buyers during geopolitical tensions. Between high inflation and geopolitical uncertainty, the macroeconomic environment seems favorable for both precious metal and base metal prices. This could kickstart a broad recovery across the mining sector.

The recent wave of mergers and acquisitions in mining also signals a positive shift. . In November 2023, Newmont Corporation completed its acquisition of Newcrest Mining Limited to create a leading global gold mining company with robust copper production. Just this month, Rio Tinto announced an $825 million lithium project purchase to support its battery materials business. These deals indicate big miners are positioning to capitalize on the electric vehicle revolution. Other companies like Century Lithium Corp. aim to produce lithium for the electric vehicle and battery storage market.

Additionally, mining stocks have held up well compared to the broader market’s decline. The global lithium stock index has surged over 110% in the past year. Many mining stocks linked to EVs have shown resilience amidst the tech stock plunge. This relative strength highlights the bullish outlook for miners enabling the energy transition. Noble Capital Markets’ investment banker Francisco Penafiel shared that “In the recent past, battery minerals have been getting the attention from investors, especially critical metals such as lithium and cobalt. However, base metals like copper and nickel should also gain a healthy traction from the investment community, narrowing the existing valuation gap for junior miners, due to the expected increase in their market demand as those are essential in the creation process of more efficient battery technologies”.

After years of underperformance, mining stocks also look attractive relative to potential growth. For instance, the price-to-earnings ratio for diversified mining giant Glencore is under 6x, a bargain compared to high-flying tech stocks. While mining is volatile, long-term investors could be rewarded handsomely for their patience. The time seems ripe for mining stocks to revert upward after years of neglect.

Of course, risks exist like policy changes, permitting issues, cost inflation, and ESG concerns. But the overarching trend toward electrification seems unstoppable. While mining is cyclical, we appear to be entering an upcycle driven by underinvestment in new supply and exploding demand for the minerals needed to power the green transition.

Noble Capital Markets’ Senior Research Analyst, Mark Reichman states, “Our outlook for the mining sector remains favorable, particularly for the precious metals mining sub-sector. We believe growing electrification among developed nations and increased infrastructure spending bodes well for the long-term outlooks for metals such as copper, lithium, rare earths, and nickel. We think M&A activity will continue as large mining, energy, car manufacturers, and battery makers seek to de-risk their long-term strategies by ensuring long-term supplies of raw materials.”

In summary, mining stocks check many important boxes right now – strong demand drivers, favorable macro conditions, M&A activity, and reasonable valuations after a prolonged slump. The long-overlooked mining space seems poised for a renaissance, offering investors exciting opportunities. The winds appear to be shifting in favor of mining stocks as we embark on the new year and beyond. After years stuck in the doldrums, mining finally looks set to retake the spotlight.

Take a moment to take a look at Haynes International, a leading developer, manufacturer, and marketer of technologically advanced, nickel and cobalt-based high-performance alloys.

Sunoco’s Blockbuster $7.3B Acquisition of NuStar to Reshape Energy Landscape

Posted on January 22, 2024January 22, 2024 by slightbourne@noblecapitalmarkets.com

The energy sector experienced a major shakeup today as Sunoco LP announced it will acquire NuStar Energy in an all-stock deal valued at approximately $7.3 billion including debt. The blockbuster acquisition aims to create a more diversified and vertically integrated energy company with an expanded footprint across the value chain.

For Sunoco, the deal provides a number of key benefits that will strengthen its operations and financial position. Most notably, it will gain NuStar’s extensive pipeline and storage terminal network which spans over 9,500 miles across the United States. This will provide greater scale and diversification to Sunoco’s current focus on fuel distribution and retail. As pipeline assets generate steady contracted revenues, the acquisition is expected to add stability and predictability to cash flows.

The larger cash flow base will also improve Sunoco’s credit profile and enhance its financial flexibility. This will enable accelerated deleveraging while also supporting steady distribution growth. Management estimates the deal will be immediately accretive to distributable cash flow per unit by 10%+ within three years. Ongoing synergies of $150 million annually will also boost the bottom line.

Vertically integrating NuStar’s transportation and storage activities with Sunoco’s strengths in distribution and retail is another major strategic benefit. This will help optimize operations across the integrated value chain and lead to further efficiency gains over time. Cost savings are forecasted at $50 million per year.

For the energy sector overall, the deal also has important implications. The combined entity will control critical infrastructure delivering refined products across the United States. With its expanded footprint, Sunoco will play an even more pivotal role ensuring energy supplies are reliably transported to end-users nationwide.

The acquisition also arrives at a challenging time for the industry. Many energy companies are facing pressure from the transition towards renewable power. By combining forces, Sunoco and NuStar can cut costs, leverage their size and scale, and invest in new growth opportunities. This will ultimately strengthen their competitiveness and staying power.

However, the deal does raise some regulatory concerns. With its extensive control over pipelines and storage capacity, the merged company could potentially restrict competitors’ access. Watchdogs will want to ensure open access at fair rates. Still, management emphasized the acquisition will have a positive financial outlook and support continued distribution growth. This should benefit both sets of unitholders if the deal is approved as expected.

Looking ahead, the acquisition positions Sunoco and NuStar to play a pivotal role in the future of US energy infrastructure. Their integrated network will be crucial for delivering traditional and renewable fuels as the industry evolves. With enhanced financial strength and flexibility, the combined giants now have greater capacity to adapt and seize new opportunities in the years ahead.

Take a look at Noble Capital Markets’ Senior Research Analyst Michael Heim’s coverage universe to take a look at some emerging growth energy companies.