Mark Reichman, Managing Director, Equity Research Analyst, Natural Resources, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Results of the Clayton Valley feasibility study. Century released the results of a feasibility study (FS) for its Clayton Valley lithium project in Nevada. A phased approach was adopted. Phase I and II mining rates of 7,500 tonnes per day and 15,000 tonnes per day, respectively, are maintained over five years each, while the Phase III mining rate of 22,500 tonnes per day is maintained for 30 years. The production plan reflects a life-of-mine average of 34,000 tonnes per year of battery-grade lithium carbonate or 13,000 tonnes and 27,000 tonnes per year during Phases I and II, respectively, and 41,000 tonnes per year during Phase III.
Key assumptions and net present value. Key assumptions include: 1) initial capital expenditures of $1.5 billion, $651 million for Phase II, and $1.3 billion for Phase III, 2) a lithium carbonate price of $24,000 per tonne, 3) average operating cost of $8,223 per tonne of lithium carbonate produced, or $2,766 per tonne after sales of surplus sodium hydroxide, 4) a lithium recovery rate of 78%, and 5) sustaining capital of $315 million over the life of the project. Based on an 8% discount rate, the project is expected to generate an after-tax net present value of $3.01 billion and 17.1% internal rate of return.
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Large-Scale Nevada-based Lithium Project: three-phase production plan will generate a life-of-mine average of 34,000 tonnes per annum (tpa) of battery-quality lithium carbonate (Li2CO3)
Innovative Approach in Processing: patent-pending chloride leaching process combined with Direct Lithium Extraction (DLE), the Feasibility Study is supported by 2+ years of testing at the Company’s Pilot Plant
Mineral Resource Estimate: Measured and Indicated resources totaling 1,207.33 million tonnes (Mt) at an average grade of 957 parts per million (ppm) lithium (Li) containing 1.155 Mt of Li or 6.148 Mt of lithium carbonate equivalent (LCE)
Long 40-Year Mine Life: Proven and Probable Mineral Reserve Estimate totaling 287.65 Mt at an average grade of 1,149 ppm Li containing 0.330 Mt of lithium or 1.759 Mt of LCE
Initial Project: Phase 1 Capital Cost $1.537 billion for production capacity of 13,000 tpa LCE
Designed for Expansion: Phase 2 $0.651 billion for 28,000 tpa LCE, and Phase 3 $1.336 billion for 41,000 tpa LCE; Project expansions are capitalized with Project cash flow
Low Operating Cost: average operating cost $8,223/t of Li2CO3 produced, or $2,766/t after sales of surplus sodium hydroxide (NaOH)
After-tax IRR of 17.1% at $24,000/t Li2CO3: $3.01 billion after-tax net present value (NPV) at 8% discount rate and a 17.1% after-tax internal rate of return (IRR), using price assumptions of $24,000/t for Li2CO3 and $600/dry metric tonne (dmt) for NaOH
April 29, 2024 – Vancouver, Canada – Century Lithium Corp. (TSXV:LCE) (OTCQX: CYDVF) (Frankfurt: C1Z) (Century Lithium or the Company) is pleased to announce the results of a National Instrument 43-101 (NI 43-101) feasibility study (Feasibility Study, FS or Study) completed on its 100% owned Clayton Valley Lithium Project (Project) in Nevada, USA. The Feasibility Study was prepared by Wood Group USA, Inc. (Wood) and Global Resource Engineering, Ltd. (GRE). All currency amounts in this news release are presented in U.S. dollars.
“Century Lithium is proud to present our Feasibility Study. The Study indicates our Project has robust economics, made possible with our unique chlor-alkali and DLE processes” commented Bill Willoughby, President, and CEO. “Completion of the Study marks a major milestone for the Company and is the result of the dedicated work and efforts of our team of employees and consultants.”
“Our process technology was developed by way of many trials and successes at our Pilot Plant in Amargosa Valley. As one of the few lithium-focused Pilot Plants in North America, we continue to operate safely and recently passed two years of testing. The data generated to date supports the Feasibility Study, and we continue to test various conditions and ideas to improve our process flow sheet,” said Bill Willoughby.
With the Feasibility Study completed, the Company will now direct its focus on engineering and permitting. The Company is concurrently advancing discussions with government agencies, strategic partners, and other interested parties to provide funding to advance the Project and maximize the value to the Company’s shareholders that is reflected in the FS.
FEASIBILITY STUDY SUMMARY
The information in the following tables highlight the Project’s production and economic summaries.
Production Summary
Phase
Years
Mine tonnes per day (tpd)
Li2CO3 (tpa)
Capital Cost (B$)
1
1-5
7,500
13,000
$1.537
2
6-10
15,000
28,000
$0.651
3
11+
22,500
41,000
$1.336
Economic Summary
Units
Amount
Operating Costs (average)
$/t
8,223
Operating Costs (average w/NaOH credit)
$/t
2,766
After-tax NPV @ 8% Discount Rate
$ billion
3.01
After-tax IRR
%
17.1
RESOURCE AND RESERVES
The Mineral Resource and Reserve Estimates for the Project were updated for the Feasibility Study and built using geologic data and 1,318 lithium assays from 45 core holes drilled between 2017 and 2022. The constrained Measured and Indicated Resource Estimate is 1,207.33 Mt with an average grade of 957 ppm lithium and contains 1.155 Mt of Li or 6.148 Mt of LCE. The Proven and Probable Mineral Reserve Estimate was derived from the constrained Mineral Resources and contains 287.65 Mt with an average grade of 1,149 ppm lithium and contains 0.330 Mt of Li or 1.759 Mt of LCE and reflects an increase of 74.6 Mt and 0.48 Mt LCE compared to the 2021 Mineral Reserve Estimate. The Mineral Resources were generated with a pit shell that encompasses all mineralized material within the Property excluding all areas that will be used for Project infrastructure and placement of tailings, waste, and low-grade material.
Mineral Resource Estimate
Domain
Tonnes Above Cut-off (millions)
Li Grade (ppm)
Li Contained (million t)
LCE (million t)
Measured
858.38
990
0.849
4.524
Indicated
348.95
875
0.305
1.625
Measured & Indicated
1,207.33
957
1.155
6.148
Inferred
119.03
827
0.098
0.524
The effective date of the Mineral Resource Estimate is December 15, 2022. The QP for the estimate is Ms. Terre Lane, MMSA, an employee of GRE and independent of Century. The Mineral Resources are constrained by a pit shell with a 200 ppm Li cut-off and density of 1.505 g/cm3. The cut-off grade considers an operating cost of $16.90/t mill feed, process recovery of 83% and a long-term lithium carbonate price of $20,000/t. The Mineral Resource estimate was prepared in accordance with CIM Definition Standards (CIM, 2014) and the CIM Estimation of Mineral Resources and Mineral Reserves Best Practice Guidelines (CIM, 2019). Mineral Resource figures were rounded. One tonne of lithium = 5.323 tonnes lithium carbonate. Mineral Resources are inclusive of Mineral Reserves.
Mineral Reserve Estimate
Domain
Tonnes Above Cut-off (millions)
Li Grade (ppm)
Li Contained (million t)
LCE (million t)
Proven
266.39
1,147
0.306
1.626
Probable
21.26
1,174
0.025
0.133
Proven & Probable
287.65
1,149
0.330
1.759
The effective date of the Mineral Reserve Estimate is December 15, 2022. The QP for the estimate is Ms. Terre Lane, MMSA, an employee of GRE and independent of Century. The Mineral Reserve estimate was prepared in accordance with CIM) Definition Standards (CIM, 2014) and the CIM Estimation of Mineral Resources and Mineral Reserves Best Practice Guidelines (CIM, 2019). Mineral Reserves are reported within the final pit design at a mining cut-off of 900 ppm. The cut-off grade considers a mine operating cost of $1.98/t, a process operating cost of $14.27/t milled, a G&A cost of $0.65/t milled, process recovery of 83% and a long-term lithium carbonate price of $20,000/t. The cut-off of 900 ppm is an elevated cut-off selected for the mine production schedule as the elevated cutoff is 4.5 times higher than the break-even cut-off grade. Mineral Reserve figures have been rounded. One tonne of lithium = 5.323 tonnes lithium carbonate. Mineral Resources are inclusive of Mineral Reserves.
PROCESS METALLURGY & CHLOR-ALKALI PLANT
Metallurgical testing through 2020 focused on using sulfuric acid (H2SO4) to extract lithium from the clay. In late 2020, testing shifted to hydrochloric acid (HCl) for its improved compatibility with the deposit’s chemistry. These benefits included higher lithium extractions, lower reagent consumptions, significantly better filtration of solids, and the ability to utilize certain DLE technologies in the recovery and concentration of lithium from the leach solutions.
A key component of the Project with chloride-based leaching is a chlor-alkali plant. The chlor-alkali plant provides the ability to produce the key reagents HCl and NaOH on-site from the electrolysis of a sodium chloride (NaCl) solution. A chlor-alkali plant represents a greater capital investment relative to that of a sulfuric acid plant but has important environmental and economic benefits for the sustainability of the Project. These benefits include replacing the purchase and transportation of sulfur with regionally sourced salt, and a reduction in emissions and the physical footprint of the operation with dryer, non-sulfate tailings.
Additionally, the chlor-alkali plant will generate significant quantities of NaOH surplus to the Project’s operational needs and therefore available for sale. The chlor-alkali plant will utilize modern electrochemical cell technology thereby producing membrane grade sodium hydroxide without the energy consumption and environmental problems of older technologies. The surplus amounts of NaOH are inherent to the operation of the plant and the sales represent a significant offset to the Project’s operating costs.
PILOT PLANT
In 2021, Century Lithium constructed a Pilot Plant in Nevada to leach one tonne per day of lithium clay and produce a high-grade lithium chloride solution which is processed off-site at Saltworks Technologies, Inc. (Saltworks), at their Richmond, British Columbia processing plant to make battery-quality Li2CO3. To maximize lithium recovery, the Company purchased the license rights and pilot-stage equipment to DLE an ion-exchange-based process and incorporated it into the Pilot Plant. The DLE license is held in perpetuity and royalty free by the Project.
Throughout its Pilot Plant program, the Company has sought improvement in its process methods. The Company obtained a provisional patent in 2023 with the U.S. Patent and Trademark Office, U.S. Department of Commerce. The provisional patent is titled System and Method for Extracting Lithium from Clay and Other Materials in a Chloride Solution Using Individualized Pretreatments. The patent pending process encompasses the Company’s flowsheet and protects its methods of leaching lithium-bearing solids and handling solutions, precipitates, and residues.
LITHIUM EXTRACTION, RECOVERY & Li2CO3 PRODUCTION
A lithium recovery of 78% is used in the Feasibility Study, based on the data collected in over two years of operations at the Pilot Pant.
Feed material grades averaged 1,100 ppm
Leach solution samples varied from 200 to 320 ppm Li
Lithium extractions averaged 88% and varied from 80 to 95%
DLE lithium recoveries were typically above 90%
10% of the lithium in solution is retained in the moisture remaining in the tailings
Extraction rates do not account for losses downstream and are only indicative of the potential overall recovery. Work at the Pilot Plant continues to focus on reducing losses of lithium to tailings. A small loss of lithium from processing the DLE product solutions into Li2CO3, and the recycling of process solutions to the DLE and leach areas is anticipated.
During 2022 and 2023, Saltworks processed the DLE product solutions from the Pilot Plant and made battery-quality Li2CO3 at greater than 99.5% purity. Modifications at the Pilot Plant in mid-2023 increased lithium solution grades to over 14 grams per liter which simplified the flowsheet and eliminated the evaporation stage for production of Li2CO3.
PRODUCTION PLAN
The Project’s production plan comprises three equal phases of production rate increases, Phase 1 and Phase 2 production rates are maintained over five years each and Phase 3 is maintained for 30 years. This approach was selected to reduce capital exposure and risk by dividing the Project’s production schedule into realistic phases of construction and equipment installation. The plan fully utilizes the Project’s Mineral Reserve.
Phase 1 includes all work required to implement the Initial Project Plan including all necessary mining and processing infrastructure. The Phase 2 cost estimate focuses on an expansion within the footprint of Phase 1. Phase 3 development includes an additional processing plant and facilities not built in the previous phases and allows for a fourth phase of expansion.
LITHIUM CARBONATE AND SODIUM HYDROXIDE SALES PRICES
A price of $24,000/t of Li2CO3 is used in the Feasibility Study as the Project base case. This price is selected as a conservative mid-point between current market prices which are under $20,000/t Li2CO3 and forecast prices obtained from Benchmark Mineral Intelligence which are in the range of $23,000 to $39,000/t Li2CO3 during Phase 1 and $29,000 to $31,000/t Li2CO3 thereafter (Benchmark Mineral Intelligence, Lithium Forecast Q1 2024). The sales price is free on board (FOB) the Project site for battery quality Li2CO3.
NaOH is a product of the chlor-alkali process and a sales price of $600/dmt FOB the Project is used in the Feasibility Study as the Project base case. Based on the material mass balance, it is expected that surplus NaOH will be available for sale at rates of 120,000 to 360,000 dmt per annum, depending on Project Phase. This price is based on a February 2023 market study by Global Exchange and Trading, Inc. where it was determined the Project’s surplus NaOH can be readily sold in the western U.S. which currently relies heavily on imports arriving at west coast ports.
CAPITAL COST ESTIMATE
The basis for the capital cost estimate follows AACE Class 3 for feasibility studies. Contributors to the estimates are GRE (mining), Wood (process plant and infrastructure), ThyssenKrupp Nucera (chlor-alkali plant) and Century Lithium (property information and owners’ costs). The capital cost estimates by phase are summarized as follows.
Installed Capital Costs
Initial Phase 1 ($M)
Expansion Phase 2 ($M)
Expansion Phase 3 ($M)
Mining & Site Preparation
$64
$7
$27
Process Facilities
$517
$205
$477
Chlor-Alkali Plant
$496
$336
$496
Buildings, Services & Infrastructure
$130
$5
$42
Indirect & Owners Costs
$234
$72
$190
Contingency
$96
$27
$105
Total Capital Cost
$1,537
$651
$1,336
Notes: Totals may not sum due to rounding, Contingency and site Indirects for chlor-alkali plant is included in the Chlor-Alkali Plant line item, contingency for mining is included in the Contingency line item, indirect costs for mining are not included in the Indirects and Owner’s Costs line item
The Phase 2 capital costs represent the expansion of the process facilities and infrastructure established in Phase 1. The Phase 3 capital costs support an additional processing plant and facilities not built in the previous phases. In the Project schedule, a 2-year period is allocated for the time to construct and commission each phase.
Sustaining capital over the life of the Project is estimated at $315 million for tailings facility expansion and equipment replacements. These costs are in addition to the expansion capital costs shown above.
OPERATING COST ESTIMATES
The following information highlights the operating cost estimates for each phase in dollars per tonne of Li2CO3, before and after deducting sales of surplus NaOH.
Initial Phase 1 (7,500 tpd mill feed)
$ (000s)/y
$/t mill feed
$/t LCE
Mining
$13,754
$5.43
$1,205
Processing and G&A
$57,515
$21.01
$4,428
Chlor-Alkali Plant
$61,787
$22.57
$4,757
Total Operating Cost
$133,056
$49.01
$10,390
Less NaOH Sales (FOB mine)
$78,272
$28.95
$6,026
Net Operating Cost
$54,784
$20.06
$4,364
Note: Totals may not sum due to rounding
Expansion Phase 2 (15,000 tpd mill feed)
$ (000s)/y
$/t mill feed
$/t LCE
Mining
$24,901
$4.26
$766
Processing and G&A
$82,018
$14.98
$3,157
Chlor-Alkali Plant
$105,138
$19.20
$4,047
Total Operating Cost
$212,057
$38.44
$7,970
Less NaOH Sales (FOB mine)
$142,350
$26.00
$5,479
Net Operating Cost
$69,707
$12.44
$2,491
Note: Totals may not sum due to rounding
Expansion Phase 3 (22,500 tpd mill feed)
$ (000s)/y
$/t mill feed
$/t LCE
Mining
$22,064
$2.70
$561
Processing and G&A
$119,945
$14.60
$3,078
Chlor-Alkali Plant
$151,325
$18.43
$3,884
Total Operating Cost
$293,334
$35.73
$7,523
Less NaOH Sales (FOB mine)
$213,525
$25.99
$5,479
Net Operating Cost
$79,809
$9.74
$2,044
Note: Totals may not sum due to rounding
ECONOMIC MODEL AND SENSITIVITY
The cash flow model is developed using base prices of $24,000/t for Li2CO3 and $600/dmt for NaOH.
Average Annual Values
Units
Initial Phase 1
Expansion Phase 2
Expansion Phase 3
Li2CO3 Sales
t
11,885
26,753
39,098
NaOH Sales
dmt
130,488
237,250
355,875
Gross Sales
$ million
$282.4
$635.7
$929.0
Before-tax Cash Flow
$ million
$231.3
$553.3
$825.3
Lithium carbonate sales are the average over each Phase including ramp up to the stated production rate. Gross sales are revenues from Li2CO3 and NaOH sales are before operating costs and after royalty. Before-tax Cash Flow is gross sales minus operating costs. Taxes are applied at federal, state and county rates after allowances for amortization, depletion, and depreciation only. Possible tax credits under the U.S. Inflation Reduction Act or other programs are not included.
The Project base case generates a 17.1% after-tax IRR and NPV-8% of $3.01 billion. These results are sensitive to changes in operating assumptions including the sales price of Li2CO3.
At 75% of the base case, or $18,000/t LCE, the after-tax NPV@ 8% is $1.52 billion, and the after-tax IRR is 12.9%.
At 125% of the base case, or $30,000/t LCE, the after-tax NPV@ 8% is $4.47 billion, and the after-tax IRR is 20.9%.
For every $1,000/t change in the price of lithium carbonate, the after-tax NPV@8% changes by about $250 million.
Project Sensitivity
Units
75%
Base Case
125%
Lithium Price
$/t LCE
$18,000
$24,000
$30,000
NPV-8%
$ billion
$1.52
$3.01
$4.47
IRR
%
12.9
17.1
20.9
PROJECT ADVANCEMENT
The Company has completed multiple environmental studies in advance of permitting and is examining ways to optimize power requirements and incorporate alternative energy solutions.
The recommendations of the FS include continuing the permitting process, engaging with governmental agencies and other parties, and proceeding with detailed engineering to further advance the Project.
Among these steps, the Company has contacted the U.S. Department of Energy’s (DOE) Loan Programs Office (LPO) and plans to initiate the pre-application process under the Title Seven Clean Energy Financing program when the Feasibility Study report is complete.
CONFERENCE CALL
Century Lithium will host a live webcast and conference call for analysts and investors on Monday, April 29, 2024, at 11:00 am ET (8:00 am PT), followed by a question-and-answer session.
A replay of the webcast will be available on our website shortly following the conclusion of the conference call.
QUALITY ASSURANCE
The data in this news release was prepared in accordance with NI 43-101 standards by the following Qualified Persons (QP).
Terre Lane, Principal Mining Engineer, GRE, is an independent QP as defined by NI 43-101 and has reviewed and approved the contents of this news release and verified by site visits and personal examination the information and original documents that relate to preparation of the Mineral Resource Estimate, Mineral Reserve Estimate, mine plan, mine capital and operating cost estimation, economic analysis, and marketing.
Hamid Samari, Principal Geologist, GRE, is an independent QP as defined by NI43-101 and has reviewed and approved the contents of this news release and verified by site visits and personal examination the information and original documents that relate to preparation of the description of the deposit, geological setting, and mineralization, deposit type, exploration, drilling, sample preparation, analyses and security, and data verification.
Todd Fayram, Senior Vice President Metallurgy, Century Lithium, is a non-independent QP as defined by NI 43-101 and has reviewed and approved the contents of this news release and verified by site visits and personal examination the information and original documents that relate to preparation of the description of metallurgical testing, lithium recovery, and design operation and results of the Pilot Plant.
Alan Drake, Manager – Process Engineering, Wood, is an independent QP as defined by NI 43-101 and has reviewed and approved the contents of this news release and verified by site visits and personal examination the information and original documents that relate to preparation of the description and estimates related to recovery methods.
Haiming (Peter) Yuan, PE, PhD, Principal Geotechnical Engineer, WSP USA Environment & Infrastructure Inc., is an independent QP as defined by NI 43-101 and has reviewed and approved the contents of this news release and verified by site visits and personal examination the information and original documents that relate to preparation of the description related to infrastructure, environment and permitting.
Paul Baluch, Technical Director, Civil, Wood, is an independent QP as defined by NI 43-101 and has reviewed and approved the contents of this news release and verified by personal examination the information and original documents that relate to preparation of the description and estimates of infrastructure.
Farzad Kossari, Cost Estimating Manager, Wood, is an independent QP as defined by NI 43-101 and has reviewed and approved the contents of this news release and verified by personal examination the information and original documents that relate to preparation of the description and summary of capital and operating cost estimates.
Further information about the Project, including a description of the key assumptions, parameters, description of sampling methods, data verification and quality assurance (QA) / quality control (QC) programs, methods relating to Mineral Resources and Mineral Reserves and factors that may affect those estimates will be contained in a NI 43-101 Technical Report on the Feasibility Study of the Clayton Valley Lithium Project. Following Section 3.4 of NI 43-101 the report will be available on SEDAR+ and on the Company’s website within 45 days of the date of this news release.
ABOUT CENTURY LITHIUM CORP.
Century Lithium Corp. is an advanced stage lithium company, focused on developing its 100%-owned Clayton Valley Lithium Project in west-central Nevada, USA. Century Lithium recently completed a Feasibility Study on its Clayton Valley Lithium Project and is currently in the permitting stage, with the goal of becoming a domestic producer of lithium for the growing electric vehicle and battery storage market.
ON BEHALF OF CENTURY LITHIUM CORP. WILLIAM WILLOUGHBY, PhD., PE President & Chief Executive Officer
NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THE CONTENT OF THIS NEWS RELEASE.
This release contains certain forward-looking statements within the meaning of applicable Canadian securities legislation. In certain cases, forward-looking statements can be identified by the use of words such as “plans”, “expects” or “does not anticipate”, or “believes”, or variations of such words and phrases or statements that certain actions, events or results “may”, “could”, “would”, “might” or “will be taken”, “occur” or “be achieved” and similar expressions suggesting future outcomes or statements regarding an outlook.
Forward-looking statements relate to any matters that are not historical facts and statements of our beliefs, intentions and expectations about developments, results and events which will or may occur in the future, without limitation, statements with respect to the potential development and value of the Project and benefits associated therewith, statements with respect to the expected project economics for the Project, such as estimates of life of mine, lithium prices, production and recoveries, capital and operating costs, IRR, NPV and cash flows, any projections outlined in the Feasibility Study in respect of the Project, the permitting status of the Project and the Company’s future development plans.
These and other forward-looking statements and information are subject to various known and unknown risks and uncertainties, many of which are beyond the ability of the Company to control or predict, that may cause their actual results, performance or achievements to be materially different from those expressed or implied thereby, and are developed based on assumptions about such risks, uncertainties and other factors set out herein. These risks include those described under the heading “Risk Factors” in the Company’s most recent annual information form and its other public filings, copies of which can be under the Company’s profile at www.sedarplus.com. The Company expressly disclaims any obligation to update-forward-looking information except as required by applicable law. No forward-looking statement can be guaranteed and actual future results may vary materially. Accordingly, readers are advised not to place reliance on forward-looking statements or information. Furthermore, Mineral Resources that are not Mineral Reserves do not have demonstrated economic viability.
Increased coal sales volumes to 8.7 million tons, up 2.4% year-over-year
Record oil & gas royalty volumes of 898 MBOE, up 18.3% year-over-year and 11.0% sequentially
First quarter 2024 total revenue of $651.7 million, net income of $158.1 million, and EBITDA of $235.0 million
Enhanced liquidity position to $551.3 million, which included $134.0 million in cash and $417.3 million of borrowings available under credit facilities
In April 2024, declared quarterly cash distribution of $0.70 per unit, or $2.80 per unit annualized
TULSA, Okla.–(BUSINESS WIRE)– Alliance Resource Partners, L.P. (NASDAQ: ARLP) (“ARLP” or the “Partnership”) today reported financial and operating results for the quarter ended March 31, 2024 (the “2024 Quarter”). This release includes comparisons of results to the quarter ended March 31, 2023 (the “2023 Quarter”) and to the quarter ended December 31, 2023 (the “Sequential Quarter”). All references in the text of this release to “net income” refer to “net income attributable to ARLP.” For a definition of EBITDA and related reconciliation to its comparable GAAP financial measure, please see the end of this release.
Total revenues in the 2024 Quarter decreased slightly to $651.7 million compared to $662.9 million for the 2023 Quarter primarily as a result of lower average coal sales prices, partially offset by higher oil & gas royalties and other revenues. Net income for the 2024 Quarter was $158.1 million, or $1.21 per basic and diluted limited partner unit, compared to $191.2 million, or $1.45 per basic and diluted limited partner unit, for the 2023 Quarter as a result of lower revenues and increased total operating expenses. EBITDA for the 2024 Quarter was $235.0 million compared to $270.9 million in the 2023 Quarter.
Compared to the Sequential Quarter, total revenues in the 2024 Quarter increased 4.2% primarily as a result of higher average coal sales prices, which increased 6.9% to $64.78 per ton sold compared to $60.60 per ton sold in the Sequential Quarter. Net income and EBITDA in the 2024 Quarter increased 36.9% and 28.6%, respectively, compared to the Sequential Quarter.
CEO Commentary
“We had a solid start to the year operationally, with all our mines running as expected and strong volumes coming from our Oil & Gas Royalties segment,” commented Joseph W. Craft III, Chairman, President and Chief Executive Officer. “Our contracted coal position also contributed to our performance for the 2024 Quarter mitigating the impact of mild winter weather and low natural gas prices. On the strength of our heavily contracted coal order book and continued growth in our Oil & Gas Royalties business, we are pleased to reiterate full-year guidance.”
Segment Results and Analysis
% Change
2024 First
2023 First
Quarter /
2023 Fourth
% Change
(in millions, except per ton and per BOE data)
Quarter
Quarter
Quarter
Quarter
Sequential
Coal Operations (1)
Illinois Basin Coal Operations
Tons sold
6.437
6.190
4.0
%
6.419
0.3
%
Coal sales price per ton sold
$
57.58
$
54.43
5.8
%
$
55.06
4.6
%
Segment Adjusted EBITDA Expense per ton
$
36.21
$
33.45
8.3
%
$
35.26
2.7
%
Segment Adjusted EBITDA
$
140.3
$
132.0
6.3
%
$
130.1
7.8
%
Appalachia Coal Operations
Tons sold
2.237
2.279
(1.8
)%
2.194
2.0
%
Coal sales price per ton sold
$
85.49
$
106.13
(19.4
)%
$
76.82
11.3
%
Segment Adjusted EBITDA Expense per ton
$
52.53
$
55.20
(4.8
)%
$
63.52
(17.3
)%
Segment Adjusted EBITDA
$
74.2
$
116.6
(36.3
)%
$
29.8
149.4
%
Total Coal Operations
Tons sold
8.674
8.469
2.4
%
8.613
0.7
%
Coal sales price per ton sold
$
64.78
$
68.34
(5.2
)%
$
60.60
6.9
%
Segment Adjusted EBITDA Expense per ton
$
40.85
$
39.66
3.0
%
$
42.91
(4.8
)%
Segment Adjusted EBITDA
$
210.9
$
245.7
(14.2
)%
$
156.2
35.0
%
Royalties (1)
Oil & Gas Royalties
BOE sold (2)
0.898
0.759
18.3
%
0.809
11.0
%
Oil percentage of BOE
44.2
%
47.3
%
(6.6
)%
46.3
%
(4.5
)%
Average sales price per BOE (3)
$
41.22
$
45.42
(9.2
)%
$
44.60
(7.6
)%
Segment Adjusted EBITDA Expense
$
4.9
$
4.4
11.7
%
$
4.7
5.7
%
Segment Adjusted EBITDA
$
31.4
$
30.0
4.5
%
$
31.0
1.1
%
Coal Royalties
Royalty tons sold
5.512
5.057
9.0
%
5.018
9.8
%
Revenue per royalty ton sold
$
3.39
$
3.07
10.4
%
$
3.33
1.8
%
Segment Adjusted EBITDA Expense
$
6.3
$
5.4
16.3
%
$
6.6
(5.3
)%
Segment Adjusted EBITDA
$
12.4
$
10.1
22.9
%
$
10.2
22.5
%
Total Royalties
Total royalty revenues
$
56.1
$
51.1
9.8
%
$
53.0
5.7
%
Segment Adjusted EBITDA Expense
$
11.2
$
9.8
14.2
%
$
11.3
(0.7
)%
Segment Adjusted EBITDA
$
43.8
$
40.2
9.2
%
$
41.2
6.4
%
Consolidated Total
Total revenues
$
651.7
$
662.9
(1.7
)%
$
625.4
4.2
%
Segment Adjusted EBITDA Expense
$
358.3
$
339.3
5.6
%
$
376.6
(4.9
)%
Segment Adjusted EBITDA
$
260.6
$
291.9
(10.7
)%
$
203.2
28.2
%
_______________________
(1)
For definitions of Segment Adjusted EBITDA Expense and Segment Adjusted EBITDA and related reconciliations to comparable GAAP financial measures, please see the end of this release. Segment Adjusted EBITDA Expense per ton is defined as Segment Adjusted EBITDA Expense – Coal Operations (as reflected in the reconciliation table at the end of this release) divided by total tons sold.
(2)
Barrels of oil equivalent (“BOE”) for natural gas volumes is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).
(3)
Average sales price per BOE is defined as oil & gas royalty revenues excluding lease bonus revenue divided by total BOE sold.
Coal Operations
In the Illinois Basin, coal sales prices increased by 5.8% and 4.6% compared to the 2023 Quarter and Sequential Quarter, respectively, as a result of improved domestic price realizations. In Appalachia, coal sales price per ton decreased by 19.4% compared to the 2023 Quarter due primarily to reduced domestic pricing from our Tunnel Ridge mine, which benefited from significantly elevated pricing during the 2023 Quarter. Compared to the Sequential Quarter, Appalachian coal sales prices were higher by 11.3% as a result of improved domestic price realizations across the region. Tons sold increased by 4.0% in the Illinois Basin compared to the 2023 Quarter due primarily to increased sales volumes from our Hamilton and Warrior mines. Appalachian coal sales volumes decreased by 1.8% compared to the 2023 Quarter primarily due to fewer operating units at our MC Mining operation. Compared to the Sequential Quarter, tons sold in Appalachia increased by 2.0% as a result of increased volumes from our Mettiki operation, which experienced challenging geologic conditions in the Sequential Quarter. ARLP ended the 2024 Quarter with total coal inventory of 1.9 million tons, representing an increase of 0.6 million tons and 0.5 million tons compared to the end of the 2023 Quarter and Sequential Quarter, respectively.
Segment Adjusted EBITDA Expense per ton for the 2024 Quarter increased by 8.3% in the Illinois Basin compared to the 2023 Quarter, due primarily to reduced production and recoveries at our River View mine. Compared to the Sequential Quarter, Segment Adjusted EBITDA Expense per ton in the Illinois Basin increased by 2.7% due to higher inventory charges at several mines. In Appalachia, Segment Adjusted EBITDA Expense per ton decreased by 4.8% and 17.3% compared to the 2023 Quarter and Sequential Quarter, respectively, due to increased production and recoveries at our Mettiki mine during the 2024 Quarter.
Royalties
Segment Adjusted EBITDA for the Oil & Gas Royalties segment increased to $31.4 million in the 2024 Quarter compared to $30.0 million and $31.0 million in the 2023 Quarter and Sequential Quarter, respectively. Improved Segment Adjusted EBITDA in the 2024 Quarter was due to record oil & gas volumes, which rose to 898 MBOE sold in the 2024 Quarter, representing increases of 18.3% and 11.0% compared to the 2023 Quarter and Sequential Quarter, respectively, as a result of increased drilling and completion activities on our interests and acquisitions of additional oil & gas mineral interests.
Segment Adjusted EBITDA for the Coal Royalties segment increased to $12.4 million for the 2024 Quarter compared to $10.1 million and $10.2 million for the 2023 Quarter and Sequential Quarter, respectively. Higher average royalty rates per ton and increased royalty tons sold contributed to improved results for the 2024 Quarter.
Balance Sheet and Liquidity
As of March 31, 2024, total debt and finance leases outstanding were $441.0 million, including $284.6 million in ARLP’s 2025 senior notes. The Partnership’s total and net leverage ratios were 0.49 times and 0.34 times debt to trailing twelve months Adjusted EBITDA, respectively, as of March 31, 2024. ARLP ended the 2024 Quarter with total liquidity of $551.3 million, which included $134.0 million of cash and cash equivalents and $417.3 million of borrowings available under its revolving credit and accounts receivable securitization facilities.
During the 2024 Quarter, the Partnership increased its accounts receivable securitization facility by 50% to $90.0 million and entered into a new $54.6 million, four-year amortizing term loan maturing February 2028 to replace a prior equipment financing that matured in November 2023.
Distributions
On April 26, 2024, we announced that the Board of Directors of ARLP’s general partner (the “Board”) approved a cash distribution to unitholders for the 2024 Quarter of $0.70 per unit (an annualized rate of $2.80 per unit), payable on May 15, 2024, to all unitholders of record as of the close of trading on May 8, 2024. The announced distribution is consistent with the cash distributions for the 2023 Quarter and Sequential Quarter.
Outlook
“With our operations running as expected year-to-date and a well-contracted order book, we are reiterating our full-year guidance,” commented Mr. Craft. “We continue to maintain a small, uncontracted tonnage position that we can flex to either domestic or export markets as demand dictates, while our Oil & Gas Royalties business is off to a strong start that should set the tone for another robust year.”
“Our focus in 2024 will continue to be the safe operations of our assets, delivering the same level of reliability that our customers value so greatly, while also executing major infrastructure projects at our Tunnel Ridge, Hamilton, Warrior and River View complexes,” Mr. Craft continued. “Over the past year, grid planners nearly doubled the five-year electricity demand growth forecast (from 2.6% to 4.7%) on a nationwide basis per FERC filings. We expect this rapid growth in electricity demand will lead to delays and extensions in the premature closure of critical coal power plants in the markets we serve. We are making investments today that will position us to be the low-cost, reliable provider in a market seeking to respond to accelerated demand associated with the electrification of new industry, and rapid load growth associated with data centers and artificial intelligence. These trends represent fundamental changes to consumption patterns, reinforcing our belief that coal, and our operations in particular, will remain critical to a reliable, affordable grid for many years to come.”
ARLP is reiterating the following guidance for the full year ended December 31, 2024 (the “2024 Full Year”):
2024 Full Year Guidance
Coal Operations
Volumes (Million Short Tons)
Illinois Basin Sales Tons
24.5 — 25.8
Appalachia Sales Tons
9.5 — 10.0
Total Sales Tons
34.0 — 35.8
Committed & Priced Sales Tons
2024 — Domestic / Export / Total
28.1 / 4.5 / 32.6
2025 — Domestic / Export / Total
15.2 / 1.1 / 16.3
Coal Sales Price Per Ton Sold (1)
Illinois Basin
$54.50 — $56.00
Appalachia
$80.50 — $83.50
Total
$61.75 — $63.75
Segment Adjusted EBITDA Expense Per Ton Sold (2)
Illinois Basin
$35.25 — $37.25
Appalachia
$54.25 — $57.25
Total
$41.00 — $43.00
Royalties
Oil & Gas Royalties
Oil (000 Barrels)
1,400 — 1,500
Natural gas (000 MCF)
5,600 — 6,000
Liquids (000 Barrels)
675 — 725
Segment Adjusted EBITDA Expense (% of Oil & Gas Royalties Revenue)
~ 12.0%
Coal Royalties
Royalty tons sold (Million Short Tons)
20.4 — 22.2
Revenue per royalty ton sold
$3.15 — $3.35
Segment Adjusted EBITDA Expense per royalty ton sold
$1.15 — $1.25
Consolidated(Millions)
Depreciation, depletion and amortization
$280 — $300
General and administrative
$80 — $85
Net interest expense
$20 — $25
Income tax expense
$17 — $19
Total capital expenditures
$450 — $500
Growth capital expenditures
$25 — $30
Maintenance capital expenditures
$425 — $470
_______________________
(1)
Sales price per ton is defined as total coal sales revenue divided by total tons sold.
(2)
Segment Adjusted EBITDA Expense is defined as operating expenses, coal purchases and other expenses.
Conference Call
A conference call regarding ARLP’s 2024 Quarter financial results is scheduled for today at 10:00 a.m. Eastern. To participate in the conference call, dial (877) 407-0784 and request to be connected to the Alliance Resource Partners, L.P. earnings conference call. International callers should dial (201) 689-8560 and request to be connected to the same call. Investors may also listen to the call via the “Investors” section of ARLP’s website at www.arlp.com.
An audio replay of the conference call will be available for approximately one week. To access the audio replay, dial U.S. Toll Free (844) 512-2921; International Toll (412) 317-6671 and request to be connected to replay using access code 13745713.
About Alliance Resource Partners, L.P.
ARLP is a diversified energy company that is currently the largest coal producer in the eastern United States, supplying reliable, affordable energy domestically and internationally to major utilities, metallurgical and industrial users. ARLP also generates operating and royalty income from mineral interests it owns in strategic coal and oil & gas producing regions in the United States. In addition, ARLP is evolving and positioning itself as a reliable energy partner for the future by pursuing opportunities that support the advancement of energy and related infrastructure.
News, unit prices and additional information about ARLP, including filings with the Securities and Exchange Commission (“SEC”), are available at www.arlp.com. For more information, contact the investor relations department of ARLP at (918) 295-7673 or via e-mail at investorrelations@arlp.com.
The statements and projections used throughout this release are based on current expectations. These statements and projections are forward-looking, and actual results may differ materially. These projections do not include the potential impact of any mergers, acquisitions or other business combinations that may occur after the date of this release. We have included more information below regarding business risks that could affect our results.
FORWARD-LOOKING STATEMENTS: With the exception of historical matters, any matters discussed in this press release are forward-looking statements that involve risks and uncertainties that could cause actual results to differ materially from projected results. Those forward-looking statements include expectations with respect to our future financial performance, coal and oil & gas consumption and expected future prices, our ability to increase unitholder distributions in future quarters, business plans and potential growth with respect to our energy and infrastructure transition investments, optimizing cash flows, reducing operating and capital expenditures, infrastructure projects at our existing properties, growth in domestic electricity demand, preserving liquidity and maintaining financial flexibility, and our future repurchases of units and senior notes, among others. These risks to our ability to achieve these outcomes include, but are not limited to, the following: decline in the coal industry’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion, the cost and perceived benefits of other sources of electricity and fuels, such as oil & gas, nuclear energy, and renewable fuels and the planned retirement of coal-fired power plants in the U.S.; our ability to provide fuel for growth in domestic electricity demand, should it materialize; changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position; changes in global economic and geo-political conditions or changes in industries in which our customers operate; changes in commodity prices, demand and availability which could affect our operating results and cash flows; the outcome or escalation of current hostilities in Ukraine and the Israel-Gaza conflict; the severity, magnitude and duration of any future pandemics and impacts of such pandemics and of businesses’ and governments’ responses to such pandemics on our operations and personnel, and on demand for coal, oil, and natural gas, the financial condition of our customers and suppliers and operators, available liquidity and capital sources and broader economic disruptions; actions of the major oil-producing countries with respect to oil production volumes and prices could have direct and indirect impacts over the near and long term on oil & gas exploration and production operations at the properties in which we hold mineral interests; changes in competition in domestic and international coal markets and our ability to respond to such changes; potential shut-ins of production by the operators of the properties in which we hold oil & gas mineral interests due to low commodity prices or the lack of downstream demand or storage capacity; risks associated with the expansion and investments into the infrastructure of our operations and properties; our ability to identify and complete acquisitions and to successfully integrate such acquisitions into our business and achieve the anticipated benefits therefrom; our ability to identify and invest in new energy and infrastructure transition ventures; the success of our development plans for our wholly owned subsidiary, Matrix Design Group, LLC, and our investments in emerging infrastructure and technology companies; dependence on significant customer contracts, including renewing existing contracts upon expiration; adjustments made in price, volume, or terms to existing coal supply agreements; the effects of and changes in trade, monetary and fiscal policies and laws, central bank policy actions including interest rates, bank failures and associated liquidity risks; the effects of and changes in taxes or tariffs and other trade measures adopted by the United States and foreign governments; legislation, regulations, and court decisions and interpretations thereof, both domestic and foreign, including those relating to the environment and the release of greenhouse gases, mining, miner health and safety, hydraulic fracturing, and health care; deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions; investors’ and other stakeholders’ increasing attention to environmental, social, and governance matters; liquidity constraints, including those resulting from any future unavailability of financing; customer bankruptcies, cancellations or breaches to existing contracts, or other failures to perform; customer delays, failure to take coal under contracts or defaults in making payments; our productivity levels and margins earned on our coal sales; disruptions to oil & gas exploration and production operations at the properties in which we hold mineral interests; changes in equipment, raw material, service or labor costs or availability, including due to inflationary pressures; changes in our ability to recruit, hire and maintain labor; our ability to maintain satisfactory relations with our employees; increases in labor costs including costs of health insurance and taxes resulting from the Affordable Care Act, adverse changes in work rules, or cash payments or projections associated with workers’ compensation claims; increases in transportation costs and risk of transportation delays or interruptions; operational interruptions due to geologic, permitting, labor, weather, supply chain shortage of equipment or mine supplies, or other factors; risks associated with major mine-related accidents, mine fires, mine floods or other interruptions; results of litigation, including claims not yet asserted; foreign currency fluctuations that could adversely affect the competitiveness of our coal abroad; difficulty maintaining our surety bonds for mine reclamation as well as workers’ compensation and black lung benefits; difficulty in making accurate assumptions and projections regarding post-mine reclamation as well as pension, black lung benefits, and other post-retirement benefit liabilities; uncertainties in estimating and replacing our coal mineral reserves and resources; uncertainties in estimating and replacing our oil & gas reserves; uncertainties in the amount of oil & gas production due to the level of drilling and completion activity by the operators of our oil & gas properties; uncertainties in the future of the electric vehicle industry and the market for EV charging stations; the impact of current and potential changes to federal or state tax rules and regulations, including a loss or reduction of benefits from certain tax deductions and credits; difficulty obtaining commercial property insurance, and risks associated with our participation in the commercial insurance property program; evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches, or other actions; and difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control.
Additional information concerning these, and other factors can be found in ARLP’s public periodic filings with the SEC, including ARLP’s Annual Report on Form 10-K for the year ended December 31, 2023, filed on February 23, 2024. Except as required by applicable securities laws, ARLP does not intend to update its forward-looking statements.
Comstock (NYSE: LODE) innovates technologies that contribute to global decarbonization and circularity by efficiently converting under-utilized natural resources into renewable fuels and electrification products that contribute to balancing global uses and emissions of carbon. The Company intends to achieve exponential growth and extraordinary financial, natural, and social gains by building, owning, and operating a fleet of advanced carbon neutral extraction and refining facilities, by selling an array of complimentary process solutions and related services, and by licensing selected technologies to qualified strategic partners. To learn more, please visit www.comstock.inc.
Mark Reichman, Managing Director, Equity Research Analyst, Natural Resources, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Agreement executed with RenFuel K2B AB. Comstock completed agreements to invest up to $3 million in RenFuel K2B AB over a three-year period. The investment will support commercialization of joint development applications and renewable fuel technologies, along with the development of a 100 thousand tonnes per year (TPY) biorefinery joint venture project in Sweden. The agreements call for the purchase of up to $3 million in 7% senior secured convertible notes funded in quarterly installments of $250 thousand for three years.
The power of partnership. Comstock’s partnership with RenFuel has accelerated the commercialization of its technologies. The companies’ joint venture project is strategic to Comstock’s plan to commercialize its proprietary Bioleum product. Comstock uses RenFuel’s patented catalytic esterification technology to refine Bioleum derivatives into Hydro-deoxygenated Bioleum Oil (HBO) for use by advanced biofuel refineries to produce sustainable aviation and renewable diesel fuel.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
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.
G Mining Ventures (GMIN) is supercharging its growth strategy with the $875 million acquisition of junior explorer Reunion Gold and its massive Oko West gold project in Guyana. This transformative transaction instantly vaults GMIN into the elite ranks of premier mid-tier producers and showcases the huge rewards awaiting those who can execute on major discoveries.
Oko West already boasts an eye-popping 4.3 million ounces of indicated gold resources grading a robust 2.05 g/t. On top of that, it hosts another 1.6 million ounces of inferred resources at 2.59 g/t – over 1 million of those ounces are high-grade underground at 3.12 g/t. With this incredible size and scale, Oko West has all the hallmarks of a monster gold deposit ideally suited for a large-scale open-pit and underground mining operation.
Under the deal terms, Reunion shareholders receive 0.285 GMIN shares for each share held – representing about C$0.65 per share, a 29% premium. They also gain upside through an 80% stake in a spin-out vehicle holding Reunion’s other assets, funded with $15 million from GMIN.
For existing GMIN investors, Oko West provides a powerful second operational asset to go alongside the company’s near-term cash flow generator, the Tocantinzinho gold mine in Brazil on-track for late 2024 production. GMIN shrewdly raised $50 million in upfront equity financing from key backers La Mancha and Franco-Nevada to help fund Oko West, minimizing future shareholder dilution.
The lofty valuation GMIN paid underscores the premium attached to large, high-margin gold deposits in elite mining jurisdictions like the prolific Guiana Shield of South America. With exceptional projects of this caliber becoming extremely rare, an M&A frenzy is brewing as established producers race to replenish their ravaged reserve pipelines before valuations escalate further.
Soaring gold prices, tight supply, and escalating costs have heightened the appeal of de-risked, economically-resilient projects like Oko West already advanced to later stages. Few explorers can match GMIN’s powerful combination of a quality anchor asset generating cash flows, accomplished construction team with regional experience, and robust financial warchest to help crystallize Oko West’s full value.
A key advantage is GMIN’s in-house construction arm G Mining Services, which boasts extensive Guiana Shield expertise including delivering Newmont’s Merian mine ahead of schedule and under budget. This unmatched skill set is invaluable for safely navigating the complexities of developing a large, remote project like Oko West.
In addition to acquiring Oko West, GMIN gains exposure to new regional discoveries through Reunion’s spin-out company. This junior exploration vehicle is led by Reunion’s proven team and backed by a $15 million treasury to pursue the next big find across the underexplored Guiana Shield which continues delivering large, high-quality gold deposits.
The GMIN-Reunion merger showcases an emerging class of ambitious mid-tier producers diligently building diversified portfolios of long-life, high-margin assets across the Americas’ premiere mining districts. Through aggressive yet disciplined M&A of compelling discoveries demonstrating robust economics, GMIN aims to establish itself as a preeminent regional consolidator and operators.
With dwindling reserve inventories plaguing the sector, securing high-quality acquisitions in choice jurisdictions has become a strategic imperative for all but the most senior gold producers. Prolific belts like the Guiana Shield are rife with consolidation opportunities for well-capitalized counterparts able to fund and maximize development of world-class discoveries trapped within explorers’ portfolios.
Transformative deals like GMIN’s capture the upside of combining quality exploration assets with complementary construction capabilities under a single corporate engine optimized for growth. By uniting prospective resources with seasoned mine builders and operators, new mid-tiers are creating compelling vehicles to power the next big commodities M&A cycle.
In the perpetual hunt to replace dwindling reserves, the limited availability of sizable, high-grade resources in stable jurisdictions opens the pocketbooks of acquisitive producers. Projects like Oko West that flaunt elite size, grade and metallurgy across investment-friendly locales simply become irresistible targets for bigger fish further up the food chain.
GMIN’s Reunion acquisition stands as a tantalizing template for investors seeking the next emerging gold producer capable of rapidly ascending the value curve. Companies that stitch together prized asset bases could become the next sought-after prizes as industry consolidation kicks into overdrive.
Mark Reichman, Managing Director, Equity Research Analyst, Natural Resources, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Agreement to sell the flagship Kingsway project. Labrador Gold agreed to sell its 100% interest in the Kingsway project to New Found Gold Corp. (TSXV: NFG) for C$20 million in NFG shares, including all property and mining rights. The number of shares received will be determined by dividing the purchase price by the closing price of NFG shares on the last trading day prior to the closing of the transaction.
Closing expected in the third quarter of 2024. The transaction is expected to close in the third quarter of 2024 and is subject to certain conditions, including receipt of regulatory and stock exchange approvals and approval from a 66 2/3% majority of the votes cast by Labrador Gold shareholders at a special meeting to be scheduled in early July 2024. Directors, officers, and certain shareholders of Labrador Gold have entered into voting support agreements with NFG and have agreed to vote their shares in favor of the transaction. According to the company’s corporate presentation, insiders own approximately 13.2% of Labrador’s outstanding shares and institutional investors own 23.0%.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
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.
TORONTO, April 22, 2024 (GLOBE NEWSWIRE) — Labrador Gold Corp. (TSX.V:LAB | OTCQX:NKOSF | FNR: 2N6) (“ LabGold ” or the “ Company ”) is pleased to announce that it has entered into a property purchase agreement (the “ Definitive Agreement ”) with New Found Gold Corp. (“ NFG ”), whereby NFG will acquire a 100% interest in the Kingsway Project, including all property and mining rights associated with the property, (the “ Transaction ”) in exchange for $20,000,000 CAD (the “ Purchase Price ”) payable and satisfied by the delivery to LabGold of such number of NFG Common Shares (the “ Consideration Shares ”) determined by dividing the Purchase Price by the closing price of the NFG Common Shares on the TSX Venture Exchange (“ TSXV ”) on the last trading day prior to the closing of the Transaction. The Consideration Shares will be subject to a resale restriction of four months and one day from the closing of the Transaction.
“The LabGold team has worked hard over the last four years to generate and test targets along the prospective Appleton Fault Zone. This work resulted in the discovery of seven gold occurrences from the nine targets drill tested, a 78% success rate,” said Roger Moss, President and CEO of Labrador Gold. “As shown in the recently completed NI43-101 Technical Report, a number of untested targets remain on the property, in addition to potential extensions of many of the gold occurrences. However, we understand the significant amount of drilling required to make these discoveries and we are happy that New Found Gold is proposing to take up the challenge at Kingsway. We believe that their experience at Queensway to the south will be critical as they explore the Kingsway Project and demonstrate the true potential of the district,” Moss added.
LabGold’s board of directors has unanimously recommended that LabGold’s shareholders vote in favour of the Transaction. The directors and officers of LabGold have entered into voting and support agreements with NFG, pursuant to which they have agreed, among other things, to vote their shares in favour of the Transaction.
The Transaction is expected to close in the third quarter of 2024 and is subject to customary conditions, including receipt of necessary regulatory and stock exchange approvals and approval from a 66 2/3% majority of the votes cast by LabGold Shareholders at the next annual general and special meeting of LabGold to be scheduled for early July, 2024.
The Definitive Agreement includes customary deal-protection provisions. LabGold has agreed not to solicit or initiate any discussion regarding any other business combination or acquisition. In the event that LabGold validly terminates the Definitive Agreement to accept a Superior Proposal (as defined in the Definitive Agreement), LabGold will be required to pay NFG a termination fee of $500,000.
Additional information regarding this proposed Transaction will be provided in the management information circular that will be mailed to registered shareholders and filed on SEDAR at www.sedarplus.com.
The TSX Venture Exchange has in no way passed upon the merits of the proposed Transaction and has neither approved nor disapproved the contents of this news release.
About Labrador Gold
Labrador Gold is a Canadian based mineral exploration company focused on the acquisition and exploration of prospective gold projects in Eastern Canada. Labrador Gold’s flagship property is the 100% owned Kingsway project in the Gander area of Newfoundland. The four licenses comprising the Kingsway project cover approximately 12km of the Appleton Fault Zone which is associated with numerous gold occurrences in the region. Infrastructure in the area is excellent located just 18km from the town of Gander with road access to the project, nearby electricity and abundant local water. LabGold’s drilling targeting high-grade epizonal gold mineralization along the Appleton Fault Zone has outlined seven gold prospects to date. The Company has approximately $6.5 million in working capital.
The Hopedale property covers much of the Florence Lake greenstone belt that stretches over 60 km. The belt is typical of greenstone belts around the world but has been underexplored by comparison. Work to date by Labrador Gold show gold anomalies in rocks, soils and lake sediments over a 3 kilometre section of the northern portion of the Florence Lake greenstone belt in the vicinity of the known Thurber Dog gold showing where grab samples assayed up to 7.8g/t gold. In addition, anomalous gold in soil and lake sediment samples occur over approximately 40 km along the southern section of the greenstone belt. Labrador Gold now controls approximately 40km strike length of the Florence Lake Greenstone Belt.
The Company has 170,009,979 common shares issued and outstanding and trades on the TSX Venture Exchange under the symbol LAB.
For more information please contact: Roger Moss, President and CEO Tel: 416-704-8291
This News Release should not be considered a comprehensive summary of the Transaction. Additional information will be disseminated at a future date. Completion of the Transaction is subject to a number of conditions including, but not limited to, TSXV approval. The Transaction cannot close until the required shareholder approval is obtained. There can be no assurance that the Transaction will be completed as proposed or at all.
Investors are cautioned that, except as disclosed in the Information Circular to be prepared in connection with the Transaction, any information released or received with respect to the Transaction may not be accurate or complete and should not be relied upon.
Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release .
Forward-Looking Statements: This news release contains forward-looking statements that involve risks and uncertainties, which may cause actual results to differ materially from the statements made. When used in this document, the words “may”, “would”, “could”, “will”, “intend”, “plan”, “anticipate”, “believe”, “estimate”, “expect” and similar expressions are intended to identify forward-looking statements. Such statements reflect our current views with respect to future events and are subject to risks and uncertainties. Many factors could cause our actual results to differ materially from the statements made, including those factors discussed in filings made by us with the Canadian securities regulatory authorities. Should one or more of these risks and uncertainties, such as actual results of current exploration programs, the general risks associated with the mining industry, the price of gold and other metals, currency and interest rate fluctuations, increased competition and general economic and market factors, occur or should assumptions underlying the forward looking statements prove incorrect, actual results may vary materially from those described herein as intended, planned, anticipated, or expected. We do not intend and do not assume any obligation to update these forward-looking statements, except as required by law. Shareholders are cautioned not to put undue reliance on such forward-looking statements.
April 19, 2024 – Vancouver, Canada – Century Lithium Corp. (TSXV:LCE) (OTCQX: CYDVF) (Frankfurt: C1Z) (Century Lithium or Company) reports that the Feasibility Study on the Company’s Clayton Valley Lithium Project (Project), in Nevada, USA, under the direction of Wood PLC and Global Resource Engineering Ltd., is currently under review by the Qualified Persons, and the Company anticipates its announcement imminently.
To date, the Company’s Feasibility Study team has revised and updated estimates for a phased production approach at the Project. These revisions also included assessment and evaluation of the economic benefit of sales of the surplus sodium hydroxide produced by the chlor-alkali plant.
The Company’s Lithium Extraction Facility (Pilot Plant) in Amargosa Valley, Nevada is now in its third year of testing the processing of lithium-bearing claystone from the Project. All data collected has been essential to the Feasibility Study. Century Lithium continues to work toward permitting the Project including the collection of baseline data collection for biology, surface and groundwater hydrology, and social impacts. Earlier this year, baseline reports were submitted by the Company’s consultants and were accepted by the appropriate government agencies. Multiple reports have been completed which will aide in the preparation of a Plan of Operations to initiate the National Environmental Policy Act (NEPA) process.
About Century Lithium Corp.
Century Lithium Corp. (formerly Cypress Development Corp.) is an advanced stage lithium company, focused on developing its 100%-owned Clayton Valley Lithium Project in west-central Nevada, USA. Century Lithium is currently in the pilot stage of testing on material from its lithium-bearing claystone deposit at its Lithium Extraction Facility in Amargosa Valley, Nevada and progressing towards completing a Feasibility Study and permitting, with the goal of becoming a domestic producer of lithium for the growing electric vehicle and battery storage market.
ON BEHALF OF CENTURY LITHIUM CORP. WILLIAM WILLOUGHBY, PhD., PE President & Chief Executive Officer
NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THE CONTENT OF THIS NEWS RELEASE.
This release includes certain statements that may be deemed to be “forward-looking statements”. Forward-looking statements are subject to risks, uncertainties and assumptions and are identified by words such as “expects,” “estimates,” “projects,” “anticipates,” “believes,” “could,” “scheduled,” and other similar words. All statements in this release, other than statements of historical facts, that address events or developments that management of the Company expects, are forward-looking statements. Although management believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance, and actual results or developments may differ materially from those in the forward-looking statements. The Company undertakes no obligation to update these forward-looking statements if management’s beliefs, estimates or opinions, or other factors, should change. Factors that could cause actual results to differ materially from those in forward-looking statements, include market prices, exploration, and development successes, continued availability of capital and financing, and general economic, market or business conditions. Please see the public filings of the Company at www.sedar.comfor further information.
Escalating hostilities between Israel and Iran have injected a new wave of supply disruption fears into global oil markets, sending crude prices surging to multi-month highs. The flareup threatens to further tighten supplies at a time when producers already appear maxed out, setting the stage for another potential energy price shock.
Crude benchmarks spiked over $90 a barrel in overnight trading after Israeli missiles struck Iran overnight. The attack came in retaliation for an Iranian drone and missile barrage targeting Israel just days earlier. While Iran has downplayed the impact so far, the tit-for-tat actions raised the specter of a broader military conflict that could imperil energy shipments throughout the Middle East.
Front-month Brent futures, the global pricing benchmark, jumped as high as $92 per barrel before paring gains. U.S. West Texas Intermediate crude topped $89 per barrel. Though off their overnight peaks, both contracts remained up over 2% on the day, hitting levels not seen since late 2023.
The aerial attacks have put the market on edge over the potential for supply chokeholds out of the Persian Gulf. Any protracted disruptions in that key oil shipping chokepoint would severely crimp available exports to global markets from regional producers like Saudi Arabia, Iran, and Iraq.
With the oil market already grappling with reduced supply from Russia due to sanctions, as well as chronic underinvestment by drillers, even modest additional shortfalls could quickly drain limited spare capacity buffers. OPEC and its allies have struggled to boost output to offset losses amid the broader underinvestment cycle.
For consumers still reeling from high energy costs, another bullish jolt to oil prices is an unwelcome development. After pulling back from 2022’s dizzying peaks, U.S. gasoline prices have started rebounding in recent weeks. The current $3.67 per gallon national average is up 21 cents just over the past month, according to AAA.
Some of that increase was expected due to seasonal refinery maintenance impacts. But the renewed geopolitical turmoil could propel gasoline and other fuel prices significantly higher nationwide if the conflict engulfing Israel and Iran deteriorates further.
The energy spike compounds existing inflationary headwinds plaguing the global economy. From restricted supplies of grains and fertilizers to manufacturing disruptions, the shockwaves from Russia’s invasion of Ukraine continue to ripple far and wide over a year later. Rapidly escalating tensions in the Middle East risk aggravating those pressures at a time when central banks are still struggling to restore price stability.
While some of the risk premium prompted by the Israel-Iran conflict may already be priced into crude, the threat of escalating retaliatory actions between the two adversaries keeps bullish risks elevated. Additional supply hits to global markets from further hostilities could easily drive oil prices back towards triple-digit territory not seen since 2022.
On Wall Street, stock futures were initially rattled by the rising geopolitical tensions, though markets stabilized in early trading as Iran refrained from immediate retaliation. Still, the volatility injected reinforces the nebulous risks confronting investors from the ever-simmering Middle East powder keg.
With so much at stake for inflation outlooks, policymakers at the Federal Reserve and other central banks will be monitoring the region with hawkish vigilance. Though diplomatically challenging to resolve, an extended sectarian conflict jeopardizing the secure flow of oil could compel another crusade of aggressive interest rate hikes historically anathema to financial markets.
For both consumers and investors, the situation serves as a stark reminder that geopolitical shocks exposing vulnerabilities in tight energy markets remain an omnipresent threat overhanging the economic outlook. Whether this clash proves fleeting or portends protracted hostilities remains to be seen, but the reverberations have oil prices surging once again.
Vancouver, British Columbia–(Newsfile Corp. – April 18, 2024) – Hemisphere Energy Corporation (TSXV: HME)(OTCQX: HMENF) (“Hemisphere” or the “Company”) is pleased to provide its financial and operating results for the fourth quarter and year ended December 31, 2023.
2023 Highlights
Increased fourth quarter production by 16% to a record of 3,386 boe/d (99% heavy oil), and annual production by 11% to 3,125 boe/d (99% heavy oil), as compared to 2022.
Achieved annual revenue of $84.5 million, with adjusted funds flow from operations (“AFF”)(1) of $39.4 million.
Invested $16.9 million to drill eight successful Atlee Buffalo wells, one unsuccessful exploration well, upgrade facilities, purchase land and seismic, and pre-purchase materials for the 2024 development program.
Generated $22.5 million of free funds flow (“FFF”)(1).
Distributed $10.1 million in quarterly dividends to shareholders.
Distributed $3.0 million in special dividends to shareholders.
Purchased and cancelled 3.2 million shares at an average price of $1.28 per share under the Company’s normal course issuer bid (“NCIB”), returning $4.1 million to shareholders.
Exited the year with a positive working capital(1) position of $3.6 million compared to a net debt(1) position of $0.8 million at December 31, 2022.
Increased Proved Developed Producing (PDP) NPV10 BT reserve value by 9% to $248 million and maintained reserve volumes at 8.2 MMboe (99.6% heavy oil).
Increased Proved (1P) NPV10 BT reserve value by 5% to $325 million and maintained reserve volumes at 12.1 MMboe (99.4% heavy oil).
Increased Proved plus Probable (2P) NPV10 BT reserve value by 5% to $416 million and maintained reserve volumes at 16.3 MMboe (99.4% heavy oil).
Note: (1)Non-IFRS financial measure that is not a standardized financial measure under International Financial Reporting Standards (“IFRS”) and may not be comparable to similar financial measures disclosed by other issuers. Refer to “Non-IFRS and Other Financial Measures” section below.
Financial and Operating Summary
Selected financial and operational highlights should be read in conjunction with Hemisphere’s audited annual financial statements and related Management’s Discussion and Analysis for the year ended December 31, 2023. These reports, including the Company’s Annual Information Form for the year ended December 31, 2023, are available on SEDAR+ at www.sedarplus.ca and on Hemisphere’s website at www.hemisphereenergy.ca. All amounts are expressed in Canadian dollars unless otherwise noted.
Three Months Ended December 31
Years Ended December 31
($000s except per unit and share amounts)
2023
2022
2023
2022
FINANCIAL
Petroleum and natural gas revenue
$
22,423
$
19,564
$
84,472
$
96,699
Operating field netback(1)
13,517
10,926
51,843
58,270
Operating netback(1)
14,428
11,396
52,118
51,995
Cash provided by operating activities
13,496
8,995
44,241
45,091
Adjusted funds flow from operations (AFF)(1)
11,295
11,011
39,411
46,686
Per share, basic(1)
0.11
0.11
0.39
0.47
Per share, diluted(1)
0.11
0.11
0.39
0.46
Free funds flow (FFF)(1)
9,144
4,921
22,539
28,420
Net income
3,981
3,253
24,195
21,317
Per share, basic
0.04
0.03
0.24
0.21
Per share, diluted
0.04
0.03
0.24
0.21
Dividends
5,489
2,560
13,083
7,683
Per share, basic
0.025
0.025
0.130
0.075
NCIB share repurchases
2,085
1,694
4,095
3,387
Capital expenditures (1)
2,151
6,090
16,872
18,266
Working capital (Net debt)(1)
3,589
(766
)
3,589
(766
)
OPERATING
Average daily production
Heavy oil (bbl/d)
3,364
2,884
3,100
2,801
Natural gas (Mcf/d)
132
138
147
158
Combined (boe/d)
3,386
2,907
3,125
2,828
Oil weighting
99%
99%
99%
99%
Average sales prices
Heavy oil ($/bbl)
$
72.36
$
73.52
$
74.53
$
94.29
Natural gas ($/Mcf)
2.19
4.76
2.56
5.03
Combined ($/boe)
$
71.97
$
73.16
$
74.07
$
93.69
Operating netback ($/boe)
Petroleum and natural gas revenue
$
71.97
$
73.16
$
74.07
$
93.69
Royalties
(14.07
)
(16.50
)
(14.71
)
(23.71
)
Operating costs
(11.49
)
(13.16
)
(10.87
)
(11.09
)
Transportation costs
(3.03
)
(2.64
)
(3.03
)
(2.43
)
Operating field netback(1)
43.38
40.86
45.46
56.46
Realized commodity hedging gain (loss)
2.92
1.76
0.24
(6.08
)
Operating netback(1)
$
46.30
$
42.62
$
45.70
$
50.38
General and administrative expense
(5.63
)
(4.92
)
(4.05
)
(3.94
)
Interest expense and foreign exchange (loss)
(0.44
)
(0.70
)
(0.58
)
(1.00
)
Current tax expense
(3.98
)
4.18
(6.51
)
(0.21
)
Adjusted funds flow from operations(1) ($/boe)
$
36.25
$
41.18
$
34.56
$
45.23
Note: (1)Non-IFRS financial measure that is not a standardized financial measure under IFRS Accounting Standards (“IFRS”) and may not be comparable to similar financial measures disclosed by other issuers. Refer to “Non-IFRS and Other Financial Measures” section of the MD&A.
COMMON SHARES
April 17, 2024
December 31, 2023
December 31, 2022
Common shares issued and outstanding
97,951,239
99,340,339
101,978,939
Stock options
7,563,000
7,563,000
6,075,000
Total fully diluted shares outstanding
105,514,239
106,903,339
108,053,939
Operations Update and Outlook
2023 was another rewarding year for Hemisphere, resulting in production growth of 11%, significant shareholder returns of $0.17 per share paid in dividends and NCIB purchases (representing a FFF payout ratio(2) of 76%), and the transformation from a net debt to a cash position.
Additionally, Hemisphere purchased mineral rights in a Saskatchewan oil resource play during the year, and kicked off the first quarter of 2024 by successfully drilling a 5-well pad (3 producers and 2 injectors) into the pool. The Company anticipates bringing the wells on production in the third quarter of the year, after commissioning a new polymer flood facility and oil treating battery in the area. The remainder of Hemisphere’s 2024 capital development program will be spent in its core Atlee Buffalo property later this summer.
Following significant downtime due to extreme cold weather in January and early February, Hemisphere’s corporate production during the latter half of the quarter has reached all-time highs of over 3,500 boe/d (February 15 – March 31, 2024 field estimates, 99% heavy oil), bringing average first quarter production to 3,135 boe/d.
Pricing outlook for heavy oil is bullish across the industry with the Trans Mountain pipeline anticipated to commence operations in May. With this additional egress capacity, WCS differential forecasts for the year have narrowed substantially. Combined with strong WTI pricing and a weak Canadian dollar, Hemisphere is optimistic about the year ahead as it tests its new Saskatchewan play while continuing to deliver top-tier free funds flow yields to its shareholders from ultra-low decline, high-value reserves in Atlee Buffalo.
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 oil 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
Note: (2) Non-IFRS Financial Ratio that is not a standardized financial measure under IFRS and may not be comparable to similar ratios disclosed by other issuers. Free funds flow, a non-IFRS financial measure, is used as a component of the non-IFRS ratio. The ratio is calculated as dividends of $13.1 million plus NCIB of $4.1 million divided by FFF of $22.5 million, equals a FFF payout ratio of 76% to shareholders.
Forward-looking Statements
Certain statements included in this news release constitute forward-looking statements or forward-looking information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “potential”, “target” and similar words suggesting future events or future performance. In particular, but without limiting the generality of the foregoing, this news release includes forward-looking statements regarding Hemisphere’s expectations that it will bring wells in Saskatchewan on production in the third quarter of the year, after commissioning a new polymer flood facility and oil treating battery in the area; that the remainder of Hemisphere’s 2024 capital development program will be spent in its core Atlee Buffalo property later this summer; outlook for heavy oil and commencement of operations for the Trans Mountain pipeline; anticipated WCS differential forecasts for the year and Hemisphere’s outlook for the year. In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.
Forward‐looking statements are based on a number of material factors, expectations or assumptions of Hemisphere which have been used to develop such statements and information, but which may prove to be incorrect. Although Hemisphere believes that the expectations reflected in such forward‐looking statements or information are reasonable, undue reliance should not be placed on forward‐looking statements because Hemisphere can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the current and go-forward oil price environment; that Hemisphere will continue to conduct its operations in a manner consistent with past operations; that results from drilling and development activities are consistent with past operations; timing of operations for the Trans Mountain pipeline; completion of commissioning a new polymer flood facility and oil treating battery in in its Saskatchewan operating area in the manner (and on the timing) currently expected; the quality of the reservoirs in which Hemisphere operates and continued performance from existing wells; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Hemisphere’s reserve volumes; certain commodity price and other cost assumptions; continued availability of debt and equity financing and cash flow to fund Hemisphere’s current and future plans and expenditures; the impact of increasing competition; the general stability of the economic and political environment in which Hemisphere operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Hemisphere to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Hemisphere has an interest in to operate the field in a safe, efficient and effective manner; the ability of Hemisphere to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Hemisphere to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Hemisphere operates; and the ability of Hemisphere to successfully market its oil and natural gas products.
The forward‐looking statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward‐looking statements including, without limitation: changes in commodity prices; changes in the demand for or supply of Hemisphere’s products, the early stage of development of some of the evaluated areas and zones; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Hemisphere or by third party operators of Hemisphere’s properties, increased debt levels or debt service requirements; inaccurate estimation of Hemisphere’s oil and gas reserve volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time‐to‐time in Hemisphere’s public disclosure documents, (including, without limitation, those risks identified in this news release and in Hemisphere’s Annual Information Form).
The forward‐looking statements contained in this news release speak only as of the date of this news release, and Hemisphere does not assume any obligation to publicly update or revise any of the included forward‐looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
Non-IFRS and Other Financial Measures
This news release contains the terms adjusted funds flow from operations, free funds flow, operating field netback and operating netback, capital expenditures and net debt, which are considered “non-IFRS financial measures” and any of these measures calculated on a per boe basis, which are considered “non-IFRS financial ratios”. These terms do not have a standardized meaning prescribed by IFRS. Accordingly, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. Investors are cautioned that these measures should not be construed as an alternative to net income (loss) or cashflow from operations determined in accordance with IFRS and these measures should not be considered to be more meaningful than IFRS measures in evaluating the Company’s performance.
a) Adjusted funds flow from operations (“AFF”) (Non-IFRS Financial Measure and Ratio if calculated on a per boe basis): The Company considers AFF to be a key measure that indicates the Company’s ability to generate the funds necessary to support future growth through capital investment and to repay any debt. AFF is a measure that represents cash flow generated by operating activities, before changes in non-cash working capital and adjusted for decommissioning expenditures, and may not be comparable to measures used by other companies. The most directly comparable IFRS measure for AFF is cash provided by operating activities. AFF per share is calculated using the same weighted-average number of shares outstanding as in the case of the earnings per share calculation for the period.
A reconciliation of AFF to cash provided by operating activities is presented as follows:
Three Months Ended December 31
Years Ended December 31
($000s, except per share amounts)
2023
2022
2023
2022
Cash provided by operating activities
$
13,496
$
8,995
$
44,240
$
45,091
Change in non-cash working capital
(2,259
)
1,447
(5,266
)
911
Adjust: Decommissioning obligation expenditures
58
569
437
684
Adjusted funds flow from operations
$
11,295
$
11,011
$
39,411
$
46,686
Per share, basic
$
0.11
$
0.11
$
0.39
$
0.47
Per share, diluted
$
0.11
$
0.11
$
0.39
$
0.46
b)Free funds flow (“FFF”) (Non-IFRS Financial Measures): Is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions. Management believes that free funds flow provides a useful measure to determine Hemisphere’s ability to improve returns and to manage the long-term value of the business.
Three Months Ended December 31
Years Ended December 31
($000s, except per share amounts)
2023
2022
2023
2022
Adjusted funds flow
$
11,295
$
11,011
$
39,411
$
46,686
Capital expenditures
(2,151
)
(6,090
)
(16,872
)
(18,266
)
Free funds flow
$
9,144
$
4,921
$
22,539
$
28,420
Per share, basic
$
0.09
$
0.05
$
0.22
$
0.29
Per share, diluted
$
0.09
$
0.05
$
0.22
$
0.28
c) Capital Expenditures (Non-IFRS Financial Measure): Management uses the term “capital expenditures” as a measure of capital investment in exploration and production assets, and such spending is compared to the Company’s annual budgeted capital expenditures. The most directly comparable IFRS measure for capital expenditures is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to capital expenditures is set forth below:
Three Months Ended December 31
Years Ended December 31
($000s)
2023
2022
2023
2022
Cash used in investing activities
$
3,745
$
4,680
$
19,456
$
18,847
Change in non-cash working capital
(1,594
)
1,410
(2,584
)
(581
)
Capital expenditures
$
2,151
$
6,090
$
16,872
$
18,266
d) Operating field netback (Non-IFRS Financial Measure and Ratio if calculated on a per boe basis): Is a benchmark used in the oil and natural gas industry and a key indicator of profitability relative to current commodity prices. Operating field netback is calculated as oil and gas sales, less royalties, operating expenses and transportation costs on an absolute and per barrel of oil equivalent basis. These terms should not be considered an alternative to, or more meaningful than, cash flow from operating activities or net income or loss as determined in accordance with IFRS as an indicator of the Company’s performance.
e) Operating netback (Non-IFRS Financial Measure and Ratio if calculated on a per boe basis): Is calculated as the operating field netback plus the Company’s realized commodity hedging gain (loss) on an absolute and per barrel of oil equivalent basis.
f) Net debt (Non-IFRS Financial Measure): Is closely monitored by the Company to ensure that its capital structure is maintained by a strong balance sheet to fund the future growth of the Company. Net debt is used in this document in the context of liquidity and is calculated as the total of the Company’s current assets, less current liabilities, excluding the fair value of financial instruments, lease and warrant liabilities, and including the bank debt. There is no IFRS measure that is reasonably comparable to net debt.
The following table outlines the Company calculation of net debt:
As at December 31
2023
2022
Current assets(1)
$
14,110
$
5,825
Current liabilities(1)
(10,521
)
(6,591
)
Working capital / (Net debt)
$
3,589
$
(765
)
Note: (1)Excluding fair value of financial instruments, and lease and decommissioning obligations.
g)Supplementary Financial Measures and Ratios
“Adjusted Funds Flow from operations per basic share” is comprised of funds from operations divided by basic weighted average common shares. “Adjusted Funds Flow from operations per diluted share” is comprised of funds from operations divided by diluted weighted average common shares. “Operating expense per boe” is comprised of operating expense, as determined in accordance with IFRS, divided by the Company’s total production. “Free Funds Flow Payout Ratio” is a non-IFRS financial ratio comprised of dividends declared during the year plus NCIB expenditures during the year divided by free funds flow (a non-IFRS financial measure) for the applicable year. “Realized heavy oil price” is comprised of heavy crude oil commodity sales from production, as determined in accordance with IFRS, divided by the Company’s crude oil production. “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. “Realized combined price” is comprised of total commodity sales from production, as determined in accordance with IFRS, divided by the Company’s total production. “Royalties per boe” is comprised of royalties, as determined in accordance with IFRS, divided by the Company’s total production. “Transportation costs per boe” is comprised of transportation expense, as determined in accordance with IFRS, divided by the Company’s total production.
The Company has provided additional information on how these measures are calculated in the Management’s Discussion and Analysis for the year ended December 31, 2023, which is available under the Company’s SEDAR+ profile at www.sedarplus.ca.
Oil and Gas Advisories
All estimated reserve volumes and the estimated net present values of the future net revenues of such reserve estimates included in this news release are as attributed by McDaniel Associates & Consultants Ltd., the Company’s independent reserve evaluators in its report as at December 31, 2023 and prepared in accordance with the COGE Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.
A barrel of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
It should not be assumed that the net present value of the estimated net revenues of the reserves presented in this news release represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions upon which such estimates are made will be attained and variances could be material. The reserve estimates of Hemisphere’s crude oil, natural gas liquids and natural gas reserves and any estimated recovery factors provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
Definitions and Abbreviations
bbl
barrel
Mcf
thousand cubic feet
bbl/d
barrels per day
Mcf/d
thousand cubic feet per day
$/bbl
dollar per barrel
$/Mcf
dollar per thousand cubic feet
boe
barrel of oil equivalent
NGL
natural gas liquids
boe/d
barrel of oil equivalent per day
NPV10 BT
Net Present Value discounted at 10%, before tax
$/boe
dollar per barrel of oil equivalent
IFRS
International Financial Reporting Standards
Mboe
thousand barrels of oil equivalent
WCS
Western Canadian Select
MMboe
million barrels of oil equivalent
US$
United States Dollar
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.
Mark Reichman, Managing Director, Equity Research Analyst, Natural Resources, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Exploration plan. Aurania’s 2024 exploration program will focus on the Kuri-Yawi epithermal gold target. In 2020 and 2021, nine scout holes were drilled, totaling 4,957 meters, to test soil geochemistry anomalies and one of the geophysical anomalies detected during a MobileMT survey in 2021. The results revealed intense and pervasive hydrothermal clay mineral alteration and silica-carbonate veinlets exhibiting epithermal textures which are features consistent with proximity to an epithermal system.
Private placement financing.Aurania expects to complete a private placement of up to 20 million units at a price of C$0.20 per unit resulting in gross proceeds of up to C$4 million. Each unit will consist of one common share and one common share purchase warrant. Each warrant will entitle the holder to purchase one common share at an exercise price of C$0.45 per warrant share for a period of 24 months following the closing of the offering. The equity offering, which may close in tranches, is expected to be completed in May and is subject to approval by the TSX Venture Exchange.
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The unrelenting surge in gold prices has shown no signs of abating, with the precious metal blasting through the $2,400 an ounce level to set fresh all-time highs. Propelled by a combination of geopolitical turmoil, stubborn inflation, and prospects for more dovish U.S. monetary policy, bullion’s blistering rally has lifted the fortunes of mining companies along with it.
On Monday, gold futures settled at a record $2,383 per ounce after Iran fired missiles at Israel, amplifying safe-haven demand. While the imminent threat was neutralized, the escalation underscored bullion’s appeal as a hedge against geopolitical instability.
But it’s not just tensions abroad fueling gold’s ascent. The anchoring factor has been the prospect of easier monetary conditions from the Federal Reserve to tame hot inflation. Hotter-than-expected price data has raised odds of two rate cuts by year-end, buffering non-yielding bullion’s appeal relative to other asset classes like bonds.
The stellar gains have unsurprisingly turbocharged mining stocks. The VanEck Gold Miners ETF (GDX) has skyrocketed over 20% year-to-date, far outperforming the metal itself. Industry titans like Newmont Corp (NEM) have risen nearly 20% as the merger with Newcrest has fattened production levels and profit margins at current lofty gold prices.
While big miners are prospering, it’s the juniors and smaller explorers that have seen the most spectacular returns. Fueled by improved economics at higher bullion levels, higher prices breathed new life into marginal projects long-shelved during the bear cycle, while re-ratings sent neglected equities rocketing higher.
According to Citi analysts, the minimum “price floor” at which mines can profitably produce has risen from around $1,000 previously to $2,000 currently. This bodes extremely well for industry profitability and increased capital spending to bring on additional supply.
In fact, Citi sees no stopping gold’s rally, projecting a push towards $3,000 an ounce over the next 6-18 months on potential stagflation risks. Goldman Sachs has also jumped on the bullish bandwagon, revising their gold target up to $2,700 by year-end. Lofty forecasts like these imply juniors may have plenty of room to run if realized.
For investors, the juniors offer a high beta play on higher gold pricing but come with elevated risks compared to the senior miners. Many are single-asset companies with higher costs, making them more susceptible to operational snags and gold price fluctuations.
However, their outsize returns in a bull market are also apparent. Juniors like Equinox (EQX) have delivered nearly triple the gains of the major producers. Their improved ability to raise capital for growth also enhances the upside potential. If the $3,000 an ounce forecast is achieved, the re-rating and bull market in juniors could be just beginning.
With a potent combination of easy money policies, inflation risks, and simmering geopolitical flashpoints buoying bullion, gold’s uptrend shows no signs of abating. As the rally rages on, the mining industry from large to small is prospering – but it’s the high-risk, high-reward juniors that have emerged as the most compelling opportunity to capitalize on gold’s unstoppable ascent.
TULSA, Okla.–(BUSINESS WIRE)– Alliance Resource Partners, L.P. (NASDAQ: ARLP) will report its first quarter 2024 financial results before the market opens on Monday, April 29, 2024. Alliance management will discuss these results during a conference call beginning at 10:00 a.m. Eastern that same day.
To participate in the conference call, dial U.S. Toll Free (877) 407-0784 and request to be connected to the Alliance Resource Partners, L.P. earnings conference call. International callers should dial (201) 689-8560 and request to be connected to the same call. Investors may also listen to the call via the “Investors” section of ARLP’s website at www.arlp.com.
An audio replay of the conference call will be available for approximately one week. To access the audio replay, dial U.S. Toll Free (844) 512-2921; International Toll (412) 317-6671 and request to be connected to replay using access code 13745713.
About Alliance Resource Partners, L.P.
ARLP is a diversified energy company that is currently the largest coal producer in the eastern United States, supplying reliable, affordable energy domestically and internationally to major utilities, metallurgical and industrial users. ARLP also generates operating and royalty income from mineral interests it owns in strategic coal and oil & gas producing regions in the United States. In addition, ARLP is evolving and positioning itself as a reliable energy partner for the future by pursuing opportunities that support the advancement of energy and related infrastructure.
News, unit prices and additional information about ARLP, including filings with the Securities and Exchange Commission (“SEC”), are available at www.arlp.com. For more information, contact the investor relations department of ARLP at (918) 295-7673 or via e-mail at investorrelations@arlp.com.
