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Valaris MS-1 Commences Rig Move Activities For Sasanof-1
The Company is pleased to announce that Western Gas (“WGC”) has provided an operational update on the drilling of the Sasanof-1 exploration well.
Highlights
- Valaris MS-1 rig has commenced mobilisation activities for departure to the Sasanof Prospect on the North West Shelf
- Secondary anchors securing the rig at Dampier outer harbour have been pulled, and the rig is secured to the GO Spica support vessel bridle for the tow to the Sasanof-1 exploration well location
- Primary anchors will then be recovered by the Far Senator, and the tow commenced. Transit time is expected to be approximately four days, weather dependent
- All required equipment has been loaded onto the rig for commencement of drilling
- Preliminary preparations for drilling operations are being conducted:
- Mud mat, low pressure wellhead housing and conductors prepared for deployment
- 13-3/8” casing stands made up and racked in preparation for deployment on completion of 17-1/2” hole section
- Third party services equipment being installed and tested
- Drilling operations (conductor jetting) are expected to commence during week starting Monday 23 May 2022
ABOUT SASANOF
The Sasanof Prospect covers an area of up to 400 km2 and is on trend and updip of Western Gas’ liquids rich, low C02 Mentorc Field.
ERCE estimates the Sasanof Prospect to contain a 2U Prospective Resource of 7.2 Tcf gas and 176 Million bbls condensate (P501), with a high case 3U Prospective Resource estimate of 17.8 Tcf gas and 449 Million bbls condensate (P101).
Sasanof is a large, seismic amplitude supported, structural-stratigraphic trap in the high-quality reservoir sands at the top of the Cretaceous top Lower Barrow Group formation on the Barrow Delta within the Exmouth Plateau.
Sasanof-1 will be Western Gas’ first well drilled from its extensive exploration portfolio surrounding the existing Equus Gas Project that contains a discovered resource of 2 Tcf and 42 MMbbl (2C Gaffney Cline2). The Equus Gas Project has a historic exploration drilling success rate of 88%, with 15 discoveries from 17 wells.
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This article includes content from [Company Name], licensed for the purpose of publishing on Investing News Australia. This article does not constitute financial product advice. It is your responsibility to perform proper due diligence before acting upon any information provided here. Please refer to our full disclaimer here.
Operations Update
Elixir Energy Limited (“Elixir” or the “Company”) is pleased to provide an operations update on its 100% owned Grandis and Nomgon projects located in Queensland and Mongolia respectively.
HIGHLIGHTS
- Coiled tubing unit cleaning out Daydream-2 wellbore in preparation for DFITs
- Significant stimulation and testing program at Grandis on track for April through to June
- Nomgon Pilot Project continues reservoir de-pressurisation process
Grandis Project
A coiled tubing unit has recently been mobilised and is currently cleaning out the Daydream-2 cased wellbore.
Coiled tubing unit at Daydream-2
This cleanout is a pre-cursor to the Diagnostic Formation Integrity Test (DFIT) program which will follow shortly thereafter. The results of this DFIT program will then be used to optimize the subsequent stimulation and flow testing phases of Daydream-2, which will run from April through to around June.
The detailed design of the stimulation and testing program has now been finalized, with a total of 6 zones to be stimulated. These zones cover ~47 metres of pay out a total of 245 metres (being the final sandstone net pay of 180 metres and coals of 65 metres) recorded in the Daydream 2 wellbore (19% of the total net interval). The sandstone net pay advised to the market on 14 December 2023 of 154 metres has been revised upwards following an external independent expert review.
The zones selected represent a cross-section of permeable sands, tight sands and coals. The total zones being tested in Daydream-2 are guided by the key principle of maximizing useful data acquisition from an appraisal well – that would then inform how future development wells would be designed.
In such future development wells, much greater pay would likely be stimulated and flowed. The results from the stimulation program in Daydream-2 will guide the targeting of further zones in future wells and can be extrapolated over the entire gas prone intervals.
The stimulation program, to be conducted by global leading contractor Halliburton, will be followed by a series of flow tests in May and June.
Nomgon Project
In conjunction with this intense program in Queensland, operations also continue at the Nomgon Pilot Project in Mongolia. In Mongolia, the current key objective is to continue to de-pressurise the gas- bearing coal reservoir through the ongoing pumping of water therefrom.
Recently one of the pilot wells, Nomgon-10, was worked over, with a larger downhole pump installed. Increased water rates have already been observed. Elixir’s engineers are actively managing the Pilot Plant to maximise water production and therefore accelerate the time to reach desorption pressure. Data analysis from the Nomgon field indicates that steady progress is being made in reducing the reservoir pressure required to reach the gas desorption pressure.
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This article includes content from Elixir Energy, licensed for the purpose of publishing on Investing News Australia. This article does not constitute financial product advice. It is your responsibility to perform proper due diligence before acting upon any information provided here. Please refer to our full disclaimer here.
Saturn Oil & Gas Inc. Reports 2023 Year-End Results Highlighted by Record Annual Production and Free Funds Flow
Saturn Oil & Gas Inc. (TSX: SOIL) (FSE: SMKA) (OTCQX: OILSF) ("Saturn" or the "Company") is pleased to report its financial and operating results for the three and twelve months ended December 31, 2023.
"2023 was a tremendous year of progress for Saturn in creating a substantial and sustainable free cash generating enterprise. In addition to doubling our production base over last year, we have assembled a deep inventory of high-quality development drilling locations to sustain current production levels for decades," commented John Jeffrey, Chief Executive Officer. "Saturn has maintained its strategic focus on developing light oil focused assets and optimizing our cost structure to deliver some of the highest cash flow margins in Canada, and to further our ultimate goal of shareholder value creation."
2023 Fourth Quarter and Annual Highlights:
- Delivered record crude oil and natural gas production with fourth quarter 2023 averaging 26,891 boe/d (82% oil and NGLs), compared to 12,514 boe/d (96% oil and NGLs) in the fourth quarter of 2022, an increase of 115%;
- Generated quarterly adjusted EBITDA(1) of $100.1 million compared to $62.2 million in the fourth quarter of 2022, an increase of 61%;
- Achieved record quarterly adjusted funds flow(1) of $80.2 million compared to $50.7 million in the fourth quarter of 2022, an increase of 58%;
- Invested $57.2 million of capital expenditures(1) in the fourth quarter, drilling 19 (16.9 net) horizontal wells;
- Generated free funds flow(1) of $23.1 million in the fourth quarter 2023, compared to $15.1 million in the fourth quarter of 2022, an increase of 53%; and
- Exited 2023 with net debt(1) of $460.5 million, realizing a net debt to fourth quarter annualized adjusted funds flow(1) of 1.4x.
Three months ended December 31, | Year ended December 31, | ||||||||||||
(CAD $000s, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||
FINANCIAL HIGHLIGHTS | |||||||||||||
Petroleum and natural gas sales | 185,384 | 111,558 | 693,891 | 367,957 | |||||||||
Cash flow from operating activities | 75,380 | 58,100 | 283,988 | 102,314 | |||||||||
Operating netback, net of derivatives(1) | 104,328 | 64,661 | 382,890 | 153,450 | |||||||||
Adjusted EBITDA(1) | 100,092 | 62,191 | 363,143 | 146,740 | |||||||||
Adjusted funds flow(1) | 80,247 | 50,729 | 278,138 | 118,658 | |||||||||
per share | - Basic | 0.58 | 0.85 | 2.20 | 2.67 | ||||||||
- Diluted | 0.56 | 0.84 | 2.15 | 2.64 | |||||||||
Free funds flow(1) | 23,072 | 15,053 | 147,565 | 29,553 | |||||||||
per share | - Basic | 0.17 | 0.25 | 1.17 | 0.67 | ||||||||
- Diluted | 0.16 | 0.25 | 1.14 | 0.66 | |||||||||
Net income (loss) | 131,456 | (16,728 | ) | 290,623 | 74,815 | ||||||||
per share | - Basic | 0.94 | (0.28 | ) | 2.30 | 1.68 | |||||||
- Diluted | 0.92 | (0.28 | ) | 2.25 | 1.66 | ||||||||
Net Debt(1), end of period | 460,483 | 219,803 | 460,483 | 219,803 |
Three months ended December 31, | Year ended December 31, | |||||||||||
(CAD $000s, except per share amounts) | 2023 | 2022 | 2023 | 2022 | ||||||||
OPERATING HIGHLIGHTS | ||||||||||||
Average production volumes | ||||||||||||
Crude oil (bbls/d) | 19,407 | 11,590 | 18,177 | 8,841 | ||||||||
NGLs (bbls/d) | 2,533 | 428 | 1,992 | 353 | ||||||||
Natural gas (mcf/d) | 29,704 | 2,971 | 24,559 | 2,392 | ||||||||
Total boe/d | 26,891 | 12,514 | 24,262 | 9,593 | ||||||||
% Oil and NGLs | 82% | 96% | 83% | 96% | ||||||||
Average realized prices | ||||||||||||
Crude oil ($/bbl) | 95.09 | 103.03 | 96.75 | 111.84 | ||||||||
NGLs ($/bbl) | 44.21 | 51.47 | 43.75 | 58.41 | ||||||||
Natural gas ($/mcf) | 2.49 | 5.36 | 2.77 | 5.57 | ||||||||
Processing expenses ($/boe) | (0.61 | ) | (1.56 | ) | (0.53 | ) | (1.52 | ) | ||||
Petroleum and natural gas sales ($/boe) | 74.93 | 96.90 | 78.35 | 105.09 | ||||||||
Operating netback ($/boe) | ||||||||||||
Petroleum and natural gas sales | 74.93 | 96.90 | 78.35 | 105.09 | ||||||||
Royalties | (9.75 | ) | (9.57 | ) | (9.10 | ) | (13.61 | ) | ||||
Net operating expenses(1) | (18.17 | ) | (22.42 | ) | (20.33 | ) | (24.67 | ) | ||||
Transportation expenses | (1.25 | ) | (0.45 | ) | (1.28 | ) | (0.61 | ) | ||||
Operating netback(1) | 45.76 | 64.46 | 47.64 | 66.20 | ||||||||
Realized loss on derivatives | (3.59 | ) | (8.29 | ) | (4.41 | ) | (22.38 | ) | ||||
Operating netback, net of derivatives(1) | 42.17 | 56.17 | 43.23 | 43.82 | ||||||||
Common shares outstanding, end of period | 139,313 | 59,892 | 139,313 | 59,892 | ||||||||
Weighted average, basic | 139,313 | 59,869 | 126,230 | 44,402 | ||||||||
Weighted average, diluted | 142,292 | 60,363 | 129,225 | 44,955 |
Message to Shareholders
In 2023, Saturn achieved its third consecutive year of growth in production and cash flow from operations:
- Average production increased 153% to 24,262 boe/d, compared to 9,593 boe/d average production in 2022;
- Adjusted EBITDA(1) increased 147% to $363.1 million, compared to $146.7 million in 2022; and
- Adjusted funds flow(1) increased 134% to $278.1 million, compared to $118.7 million in 2022.
During 2023, Saturn successfully drilled and rig released a total of 59 gross (48.8 net) horizontal wells across its four core operating areas, comprised of:
- 28 gross (25.2 net) wells in Southeast Saskatchewan;
- 19 gross (14.3 net) wells in West Central Saskatchewan;
- 8 gross (5.3 net) wells in Central Alberta; and
- 4 gross (4.0 net) wells in North Alberta.
The February acquisition of privately held oil and gas producer, Ridgeback Resources Inc. ("Ridgeback"), was a key contributor to Saturn's growth in 2023, adding 670 net sections of land featuring development opportunities to sustain the Company's production going forward. The acquisition of Ridgeback was highly synergistic to the Company's existing Southeast Saskatchewan assets expanding its high cash flow, light oil production base by approximately 65%; more than doubling the light oil reserve volumes in the area; and added a large undeveloped land position featuring Bakken light oil resource that Saturn can continue to develop. In addition to growing the Company's Saskatchewan footprint, the acquisition also expanded Saturn's operations into Alberta's prolific Cardium, Kaybob and Swan Hills areas.
The Company has continued to focus on streamlining its cost structure by reducing overall royalties, decreasing operating costs and improving average hedging pricing:
- Average royalties decreased to 11.5% in 2023, compared 12.8% in 2022;
- Average net operating expenses(1) decreased 18% to $20.33 per boe in 2023, compared to $24.67 per boe in 2022; and
- Average realized loss on derivatives decreased 80% to $4.41 per boe in 2023, compared to $22.38 in 2022.
In light of the above cost reduction impacts, the Company's 2023 operating netback(1), net of derivatives of $43.23 per boe, was comparable to the $43.82 per boe in 2022, despite an approximately 17% drop in the average benchmark WTI oil price to US $77.60 in 2023, compared to an average WTI oil price of US $94.25 in 2022.
Saturn drilled as operator in 2023, 47 gross (45.2 net) wells, with the results of the 46 gross operated wells that were placed on production summarized in the table below:
Gross Wells Drilled by Formation (number): | Avg. IP30 per Location (boe/d) | 2023 Guidance Type Curve (boe/d) | Performance vs. Type Curve (%) | Total Gross Capital Invested ($MM) | Capital Efficiency ($ per boe/d) |
SE Sask - Frob. & Midale (10) | 80.4 | 69.0 | +17 | 13.2 | 16,420 |
SE Sask - Spearfish (6) | 89.2 | 77.0 | +16 | 7.1 | 13,270 |
SE Sask - Stimulated Bakken (7) | 109.7 | 101.0 | +9 | 12.3 | 16,020 |
SE Sask - OHML Bakken (2) | 168.5 | 147.0 | +15 | 4.6 | 13,650 |
WC Sask - Viking (12) | 97.9 | 68.0 | +44 | 19.4 | 16,510 |
Central AB - Lochend Cardium (3) | 279.0 | 260.0 | +7 | 17.7 | 21,150 |
Central AB - Pembina (2) | 239.5 | 248.0 | -3 | 9.4 | 19,620 |
North AB - Montney (4) | 314.4 | 330.0 | -5 | 14.3 | 11,390 |
Weighted Average | 134.6 | 121.0 | +11 | 98.0 | 15,830 |
Commitment to Debt Repayment
On February 28, 2023, the Company expanded its Senior Term Loan by $375.0 million in relation to the acquisition of Ridgeback. Saturn continues to prioritize the rapid repayment of its Senior Term Loan, and in 2023, the Company made principal payments totaling approximately $164.5 million, with additional aggregate payments of approximately $50.7 million made to date in 2024, for a total of $215.2 million of principal payments since December 31, 2022. The Company intends to continue directing free cash flow to ongoing debt repayment and balance sheet strengthening.
Southeast Saskatchewan
In Q4 of 2023, Saturn rig released six gross (4.6 net) Bakken wells, of which two gross wells (2.0 net) were drilled as open hole multi-lateral ("OHML") wells. These OHML wells feature seven to eight horizontal legs per well and represent the first on which Saturn has deployed this innovative drilling technique. The Company's Bakken light oil development has been a strong addition to its capital program in Southeast Saskatchewan, where Saturn has already successfully drilled a total of 11 gross (9.1 net) Bakken wells in 2023. Saturn has 197 net booked Bakken drilling locations (including 16.9 net OHML locations) and has identified over 100 net unbooked Bakken wells for future development.
Saturn successfully drilled three gross (2.3 net) Frobisher wells in Q4 of 2023 for an annual total of 11 gross (10.1 net) Mississippian wells, including two gross (1.9 net) Midale wells, which collectively outperformed IP30 type curve expectations by 17%. The six gross (6.0 net) Spearfish wells drilled in 2023 were a highlight of the year's development program, outperforming IP30 type curve expectations by 16%, while experiencing lower than expected declines. Further budgeted development of Frobisher and Spearfish light oil is expected to be a prominent component of Saturn's 2024 capital investment plan.
For the three months ended December 31, 2023, the Company's Southeast Saskatchewan assets collectively averaged 12,550 boe/d of production, an increase of 67% from 7,522 boe/d in the comparative 2022 period.
West Central Saskatchewan
The Company added a third rig to the fourth quarter development plan in order to extend the drilling success of its Viking light oil targets in West Central Saskatchewan, adding four additional wells with 100% working interest. In 2023 Saturn successfully drilled 19 gross (14.3 net) Viking wells and continued to follow up on its best performing areas of Hershel and Plato with 12 operated wells. These 12 wells were drilled with 100% working interest, had an average IP30 of 97.9 bbls/d of light oil, which outperformed the type curve expectations by 44%. Saturn has 165 net locations booked for future Viking development.
The Company's West Central Saskatchewan assets averaged 3,504 boe/d of production for the three months ended December 31, 2023, compared to 4,992 boe/d in the prior year.
Central Alberta
Saturn successfully drilled three Cardium horizontal wells in the fourth quarter of 2023, with 100% working interest, for a total of eight gross (5.3 net) Cardium wells being rig released in 2023. The 2023 Cardium wells drilled by Saturn were Extended Reach Horizontal ("ERH") wells having an average lateral length of 2.2 miles. Five of the Saturn operated Cardium wells were put on production in Q4 of 2023, with IP30 rates consistent with type cure expectations, and delivering approximately 1,316 boe/d in aggregate during the first 30 days on production. The 6th Cardium well drilled in late 2023 has now been completed along with an additional three gross (3.0 net) ERH Cardium wells drilled to date in 2024. The four new wells are expected to be brought online before the end of Q1 2024. In total during 2024, Saturn expects to drill eight net Cardium ERH wells.
For the three months ended December 31, 2023, the Company's Central Alberta assets produced an average of 8,066 boe/d.
North Alberta
In December 2023, the Company brought on production a four well pad in Kaybob, with 100% working interest to Saturn. The four wells were within expectations of the Montney type curve for this area and delivered an IP30 rate of approximately 1,254 boe/d in aggregate. Saturn plans to drill an additional four well pad in Kaybob during 2024.
For the three months ended December 31, 2023, the Company's North Alberta assets produced an average of 2,771 boe/d.
ESG Initiatives
Saturn continued its dedication to responsible environmental stewardship by directing approximately $10.7 million in 2023 to decommissioning expenditures, including the abandonment of 114 wells that no longer had economic production potential, amounting to approximately 2x the number of gross new wells the Company drilled in 2023.
Outlook
Saturn's Board of Directors has approved the Company's largest ever development plan in 2024, with a budget of approximately $145.6 million targeting the drilling of up to 61 net wells. With Saturn's extensive pipeline network and facilities infrastructure within each of its core operating areas, the Company has ample capacity to handle incremental new production coming on-stream. Over 85% of the Company's 2024 development capital expenditures will be directed to drilling, completions, equipping and tie-in of new production.
Through the first quarter of 2024, the Company employed a full-time rig in Southeast Saskatchewan, resulting in the drilling of five gross (5.0 net) conventional wells (two Frobisher, two Spearfish, one Tilston) all of which have been put onto production. The Company is now drilling the first of two Bakken OHML wells that will continue through the first half of 2024 with 100% working interest to Saturn.
Additional details on Saturn's 2024 Capital Investment Program is available within the Company's Guidance Presentation now available on the website at https://saturnoil.com/investors/#presentations-and-events.
Investor Webcast
Saturn will host a webcast at 10:00 AM MDT (12:00 PM Noon EDT) on Wednesday, March 13, 2024, to review the year end and fourth quarter 2023 financial results and provide additional colour on the Company's operational highlights. Participants can access the live webcast via https://saturnoil.com/invest/q4-2023-results-webcast. A recorded archive of the webcast will be available afterwards on the Company's website.
About Saturn Oil & Gas Inc.
Saturn Oil & Gas Inc. is a growing Canadian energy company focused on generating positive shareholder returns through the continued responsible development of high-quality, light oil weighted assets, supported by an acquisition strategy that targets highly accretive, complementary opportunities. Saturn has assembled an attractive portfolio of free-cash flowing, low-decline operated assets in Saskatchewan and Alberta that provide a deep inventory of long-term economic drilling opportunities across multiple zones. With an unwavering commitment to building an ESG-focused culture, Saturn's goal is to increase reserves, production and cash flows at an attractive return on invested capital. Saturn's shares are listed for trading on the TSX under ticker 'SOIL' on the Frankfurt Stock Exchange under symbol 'SMKA' and on the OTCQX under the ticker 'OILSF'.
The Company's consolidated financial statements and corresponding Management's Discussion and Analysis for the three months and year ended December 31, 2023 are available on SEDAR+ at www.sedarplus.com and on Saturn's website at www.saturnoil.com. Copies of the materials can also be obtained upon request without charge by contacting the Company directly. Please note, currency figures presented herein are reflected in Canadian dollars, unless otherwise noted.
Further information and a corporate presentation is available on Saturn's website at www.saturnoil.com.
Saturn Oil & Gas Investor & Media Contacts:
John Jeffrey, MBA - Chief Executive Officer
Tel: +1 (587) 392-7900
www.saturnoil.com
Kevin Smith, MBA - VP Corporate Development
Tel: +1 (587) 392-7900
info@saturnoil.com
Note:
(1) See Reader Advisory "Non-GAAP and Other Financial Measures"
Reader Advisory
Non-GAAP and Other Financial Measures
Throughout this news release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures provided by other issuers. Non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS. The disclosure under the section "Non-GAAP and Other Financial Measures" including non-GAAP financial measures and ratios, capital management measures and supplementary financial measures in the Company's Condensed consolidated interim financial statements and MD&A are incorporated by reference into this news release.
This press release uses the terms "adjusted EBITDA", "adjusted funds flow", "free funds flow" and "net debt" which are capital management measures. See the disclosure under "Capital Management" in our audited consolidated financial statements for the three months and the year ended December 31, 2023, for an explanation and composition of these measures and how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.
Free funds flow
The Company considers free funds flow to be a key capital management measure as it is used to determine the efficiency and liquidity of Saturn's business, measuring its funds available after capital investment available for debt repayment, pursue acquisitions and gauge optionality to pay dividends and/or return capital to shareholders through share repurchases. Saturn calculates Free funds flow as Adjusted funds flow in the period less expenditures on property, plant and equipment and exploration and evaluation assets, together "capital expenditures". By removing the impact of current period capital expenditures from adjusted funds flow, management monitors its free funds flow to inform its capital allocation decisions.
Three months ended December 31, | Year ended December 31, | |||||||||||
($000s) | 2023 | 2022 | 2023 | 2022 | ||||||||
Adjusted funds flow | 80,247 | 50,729 | 278,138 | 118,658 | ||||||||
Capital expenditures | (57,175 | ) | (35,676 | ) | (130,573 | ) | (89,105 | ) | ||||
Free funds flow | 23,072 | 15,053 | 147,565 | 29,553 |
Capital Expenditures
Saturn uses capital expenditures to monitor its capital investments relative to those budgeted by the Company on an annual basis. Saturn's capital budget excludes acquisition and disposition activities as well as the accounting impact of any accrual changes or payments under certain lease arrangements. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. The following table reconciles capital expenditures and capital expenditures, net acquisitions and dispositions ("A&D") to the nearest GAAP measure, cash flow used in investing activities.
Three months ended December 31, | Year ended December 31, | |||||||||||
($000s) | 2023 | 2022 | 2023 | 2022 | ||||||||
Cash flow used in investing activities | 38,725 | 41,747 | 576,405 | 318,238 | ||||||||
Change in non-cash working capital | 18,450 | (5,266 | ) | 20,830 | 19,234 | |||||||
Capital expenditures, net A&D | 57,175 | 36,481 | 597,235 | 337,472 | ||||||||
Acquisitions, net of cash acquired | - | (805 | ) | (466,662 | ) | (248,367 | ) | |||||
Capital expenditures | 57,175 | 35,676 | 130,573 | 89,105 |
Net operating expenses
Net operating expense is calculated by deducting processing income primarily generated by processing third party production at processing facilities where the Company has an ownership interest, from operating expenses presented on the Statement of income (loss). Where the Company has excess capacity at one of its facilities, it will process third-party volumes to reduce the cost of ownership in the facility. The Company's primary business activities are not that of a midstream entity whose activities are focused on earning processing and other infrastructure-based revenues, and as such third-party processing revenue is netted against operating expenses in the MD&A. This metric is used by management to evaluate the Company's net operating expenses on a unit of production basis. Net operating expense per boe is a non-GAAP financial ratio and is calculated as net operating expense divided by total barrels of oil equivalent produced over a specific period of time. The calculation of the Company's net operating expenses is shown within the net operating expenses section of our MD&A for the three months and year ended December 31, 2023.
Operating netback and Operating netback, net of derivatives
The Company's operating netback is determined by deducting royalties, net operating expenses and transportation expenses from petroleum and natural gas sales. The Company's operating netback, net of derivatives is calculated by adding or deducting realized financial derivative commodity contract gains or losses from the operating netback. The Company's operating netback and operating netback, net of derivatives are used in operational and capital allocation decisions. Presenting operating netback and operating netback, net of derivatives on a per boe basis is a non-GAAP financial ratio and allows management to better analyze performance against prior periods on a per unit of production basis. The calculation of the Company's operating netbacks and operating netback, net of derivatives are summarized as follows.
Three months ended December 31, | Year ended December 31, | |||||||||||
($000s) | 2023 | 2022 | 2023 | 2022 | ||||||||
Petroleum and natural gas sales | 185,384 | 111,558 | 693,891 | 367,957 | ||||||||
Royalties | (24,124 | ) | (11,022 | ) | (80,565 | ) | (47,640 | ) | ||||
Net operating expenses | (44,945 | ) | (25,817 | ) | (180,074 | ) | (86,379 | ) | ||||
Transportation expenses | (3,094 | ) | (518 | ) | (11,314 | ) | (2,139 | ) | ||||
Operating netback | 113,221 | 74,201 | 421,938 | 231,799 | ||||||||
Realized loss on financial derivatives | (8,893 | ) | (9,540 | ) | (39,048 | ) | (78,349 | ) | ||||
Operating netback, net of derivatives | 104,328 | 64,661 | 382,890 | 153,450 | ||||||||
($ per boe amounts) | ||||||||||||
Petroleum and natural gas sales | 74.93 | 96.90 | 78.35 | 105.09 | ||||||||
Royalties | (9.75 | ) | (9.57 | ) | (9.10 | ) | (13.61 | ) | ||||
Net operating expenses | (18.17 | ) | (22.42 | ) | (20.33 | ) | (24.67 | ) | ||||
Transportation expenses | (1.25 | ) | (0.45 | ) | (1.28 | ) | (0.61 | ) | ||||
Operating netback | 45.76 | 64.46 | 47.64 | 66.20 | ||||||||
Realized loss on financial derivatives | (3.59 | ) | (8.29 | ) | (4.41 | ) | (22.38 | ) | ||||
Operating netback, net of derivatives | 42.17 | 56.17 | 43.23 | 43.82 |
Adjusted EBITDA
The Company considers adjusted EBITDA to be a key capital management measure as it is both used within certain financial covenants prescribed under the Company's Senior Term Loan (note 11) and demonstrates Saturn's standalone profitability, operating and financial performance in terms of cash flow generation, adjusting for interest related to its capital structure. Adjusted EBITDA is defined by the Company as earnings before interest, taxes, depreciation, amortization and other noncash or extraordinary items.
Adjusted funds flow
The Company considers adjusted funds flow to be a key capital management measure as it demonstrates Saturn's ability to generate the necessary funds to manage production levels and fund future growth through capital investment. Management believes that this measure provides an insightful assessment of Saturn's operations on a continuing basis by eliminating certain non-cash charges, actual settlements of decommissioning obligations, of which the nature and timing of expenditures may vary based on the stage of the Company's assets and operating areas, and transaction costs which vary based on the Company's acquisition and disposition activity.
Free funds flow
The Company considers free funds flow to be a key capital management measure as it is used to determine the efficiency and liquidity of Saturn's business, measuring its funds available after capital investment available for debt repayment, pursue acquisitions and gauge optionality to pay dividends and/or return capital to shareholders through share repurchases. Saturn calculates free funds flow as adjusted funds flow in the period less expenditures on property, plant and equipment and exploration and evaluation assets, together "capital expenditures". By removing the impact of current period capital expenditures from adjusted funds flow, management monitors its free funds flow to inform its capital allocation decisions.
The following table reconciles adjusted EBITDA, adjusted funds flow and free funds flow to cash flow from operating activities:
Year ended December 31, | ||||||
($000s) | 2023 | 2022 | ||||
Cash flow from operating activities | 283,988 | 102,314 | ||||
Change in non-cash working capital | (20,993 | ) | 14,536 | |||
Decommissioning expenditures | 10,486 | 582 | ||||
Transaction costs | 4,657 | 1,226 | ||||
Current tax recovery | (1,915 | ) | - | |||
Net interest(1) | 86,920 | 28,082 | ||||
Adjusted EBITDA | 363,143 | 146,740 | ||||
Current Tax Recovery | 1,915 | - | ||||
Net Interest(1) | (86,920 | ) | 28,082 | |||
Adjusted Funds Flow | 278.138 | 118,658 | ||||
Capital Expenditures(2) | (130,573 | ) | (89,105 | ) | ||
Free Funds Flow | 147,565 | 29,553 | ||||
(1) Calculated as interest expense, net of interest revenue. (2) Calculated as expenditures on exploration and development assets on the consolidated statements of cash flows. |
Market capitalization and net debt
Management considers net debt a key capital management measure in assessing the Company's liquidity. Total market capitalization and net debt to annualized quarterly adjusted funds flow are used by management and the Company's investors in analyzing the Company's balance sheet strength and liquidity. The summary of total market capitalization, net debt, annualized quarterly adjusted funds flow and net debt to annualized quarterly adjusted funds flow is as follows:
Year ended December 31, | ||||||
($000s) | 2023 | 2022 | ||||
Total common shares outstanding (000s) | 139,313 | 59,892 | ||||
Share price(1) | 2.20 | 2.35 | ||||
Total market capitalization | 306,489 | 140,746 | ||||
Adjusted working capital(2) | 8,240 | (3,128 | ) | |||
Senior Term Loan | 451,153 | 240,843 | ||||
Convertible notes | 1,090 | 2,361 | ||||
Long-term deposit | - | (21,101 | ) | |||
Promissory notes | - | 828 | ||||
Net debt | 460,483 | 219,803 | ||||
Current quarter adjusted funds flow | 80,247 | 50,729 | ||||
Annualized factor | 4 | 4 | ||||
Annualized quarterly adjusted funds flow | 320,988 | 202,916 | ||||
Net debt to annualized quarterly adjusted funds flow | 1.4x | 1.1x | ||||
(1) Represents the closing share price on the TSX on the last day of trading of the period. (2) Adjusted working capital is calculated as cash, accounts receivable, deposits and prepaids net of accounts payable. |
Supplemental Information Regarding Product Types
References herein to boe/d include gas or natural gas and NGLs which refer to conventional natural gas and natural gas liquids product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), except where specifically noted otherwise.
The following table is intended to provide the product type composition for each of the production figures provided herein, where not already disclosed within tables above for average production for the three months and the year ended December 31, 2023 and 2022:
Three months ended December 31, 2023 | Three months ended December 31, 2022 | |||||||
Crude oil (bbls/d) | NGLs (bbls/d) | Natural gas (mcf/d) | Total (boe/d) | Crude oil (bbls/d) | NGLs (bbls/d) | Natural gas (mcf/d) | Total (boe/d) | |
Southeast Saskatchewan | 10,832 | 939 | 4,673 | 12,550 | 6,714 | 398 | 2,457 | 7,522 |
West Central Saskatchewan | 3,389 | 29 | 514 | 3,504 | 4,876 | 30 | 514 | 4,992 |
Central Alberta | 3,543 | 1,172 | 20,105 | 8,066 | - | - | - | - |
North Alberta | 1,643 | 393 | 4,412 | 2,771 | - | - | - | - |
Total boe/d | 19,407 | 2,533 | 29,704 | 26,891 | 11,590 | 428 | 2,971 | 12,514 |
Year ended December 31, 2023 | Year ended December 31, 2022 | |||||||
Crude oil (bbls/d) | NGLs (bbls/d) | Natural gas (mcf/d) | Total (boe/d) | Crude oil (bbls/d) | NGLs (bbls/d) | Natural gas (mcf/d) | Total (boe/d) | |
Southeast Saskatchewan | 9,596 | 770 | 3,968 | 11,027 | 6,401 | 340 | 2,118 | 7,094 |
West Central Saskatchewan | 4,262 | 20 | 468 | 4,360 | 2,440 | 13 | 274 | 2,499 |
Central Alberta | 3,005 | 915 | 16,602 | 6,687 | - | - | - | - |
North Alberta | 1,314 | 287 | 3,521 | 2,188 | - | - | - | - |
Total boe/d | 18,177 | 1,992 | 24,559 | 24,262 | 8,841 | 353 | 2,392 | 9,593 |
Initial Production Rates
Any reference in this news release to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Any reference in this news release to initial production rates consist of the above noted product types, using a conversion rate of 1 bbl : 6 MCF (where applicable). Readers are cautioned not to place undue reliance on such rates in calculating aggregate production for Saturn.
Per boe or ($/boe)
Any reference in this news release to disclosures for petroleum and natural gas sales, royalties, operating expenses, transportation expenses and marketing expenses on a per boe basis are supplementary financial measures that are calculated by dividing each of these respective GAAP measures by Saturn's total production volumes for the period.
Per Share Amounts
Per share amounts noted in this news release are based on Saturn's weighted average issued and outstanding common shares as of December 31, 2023, unless noted otherwise.
Boe Presentation
Boe means barrel of oil equivalent. All boe conversions in this news release are derived by converting gas to oil at the ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of oil. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 Bbl: 6 Mcf, utilizing a conversion ratio of 1 Bbl : 6 Mcf may be misleading as an indication of value.
Forward-Looking Information and Statements.
Certain information included in this press release constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project", "scheduled", "will" or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this press release may include, but is not limited to, the Company's drilling and development plans, timing of bringing wells on-stream, 2024 production, expectations regarding netbacks, the business plan, cost model and strategy of the Company.
The forward-looking statements contained in this press release are based on certain key expectations and assumptions made by Saturn, including expectations and assumptions concerning: the timing of and success of future drilling, development and completion activities, the performance of existing wells, the performance of new wells, the availability and performance of facilities and pipelines, the ability to allocate capital to pay down debt and grow or maintain production, the geological characteristics of Saturn's properties, the application of regulatory and licensing requirements and the availability of capital, labour and services.
Although Saturn believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Saturn can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), constraints in the availability of services, commodity price and exchange rate fluctuations, actions of OPEC and OPEC+ members, changes in legislation impacting the oil and gas industry, adverse weather or break-up conditions and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. These and other risks are set out in more detail in Saturn's Annual Information Form for the year ended December 31, 2023.
Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may prove to be incorrect. Although Saturn believes that the expectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because Saturn can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this press release, assumptions have been made regarding and are implicit in, among other things, our capital expenditure and drilling programs, drilling inventory and booked locations, production and revenue guidance, ESG initiatives, debt repayment plans and future growth plans. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.
The forward-looking information contained in this press release is made as of the date hereof and Saturn undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking information contained in this press release is expressly qualified by this cautionary statement.
All dollar figures included herein are presented in Canadian dollars, unless otherwise noted.
Source Rock Royalties Declares Monthly Dividend
Source Rock Royalties Ltd. ("Source Rock") (TSXV: SRR), a pure-play oil and gas royalty company with an established portfolio of oil royalties, announces that its board of directors has declared a monthly dividend of $0.006 per common share, payable in cash on April 15, 2024 to shareholders of record on March 29, 2024.
This dividend is designated as an "eligible dividend" for Canadian income tax purposes.
About Source Rock Royalties Ltd.
Source Rock is a pure-play oil and gas royalty company with an existing portfolio of oil royalties in southeast Saskatchewan, central Alberta and west-central Saskatchewan. Source Rock targets a balanced growth and yield business model, using funds from operations to pursue accretive royalty acquisitions and to pay dividends. By leveraging its niche industry relationships, Source Rock identifies and acquires both existing royalty interests and newly created royalties through collaboration with industry partners. Source Rock's strategy is premised on maintaining a low-cost corporate structure and achieving a sustainable and scalable business, measured by growing funds from operations per share and maintaining a strong netback on its royalty production.
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 of this release.
Investing in Green Hydrogen
Green hydrogen is rapidly emerging as a reliable means of furthering the global quest toward decarbonization and the clean energy transition. For all its benefits, hydrogen energy has yet to achieve mainstream recognition — but investors in the clean energy space are slowly taking notice of its potential.
Gaining a deeper understanding of that potential — and of the resource itself — can help investors make better, more informed decisions when evaluating green hydrogen opportunities.
Hydrogen: An overview
Simultaneously the simplest and most abundant element on the planet, hydrogen comprises an estimated 75 percent of the mass in the known universe. Due to its chemical composition, the element is also uniquely suited for energy production and storage. Used extensively in industrial processes and as a component in rocket fuel, hydrogen has also emerged as a viable replacement for natural gasses such as methane.
To be usable for industry and energy, hydrogen must be refined into a liquid or a gas. In both cases, the end product of this refinement is known as dihydrogen, which in addition to fuel is also used for food packaging, as an antioxidant and as an electron donor. Dihydrogen may be produced through a multitude of production pathways, each represented by a color code.
- Blue hydrogen is primarily created by subjecting natural gas to superheated water in the form of steam. The process, known as steam reforming, produces both hydrogen and carbon dioxide. Blue hydrogen is often known as low-carbon hydrogen, as the carbon produced by the process is managed through carbon capture and storage (CCS) technology.
- Grey hydrogen is the most common source of hydrogen. It's created through steam reforming as with blue hydrogen, albeit without CCS. Typically, either methane or natural gas is used for this process.
- Black hydrogen and brown hydrogen are produced primarily from either black coal or brown coal, also known as lignite. The terms may also be used to describe hydrogen produced through the gasification of fossil fuels. This is the most environmentally damaging form of hydrogen production.
- Pink hydrogen is produced by nuclear-powered electrolysis. It may also be referred to as red hydrogen or purple hydrogen. The energy produced by nuclear reactors may also be used to produce other forms of hydrogen, such as blue or gray.
- Turquoise hydrogen is created through a relatively new process known as methane pyrolysis. When subjected to thermal decomposition, the natural gas produces hydrogen and solid carbon as byproducts. Although promising as a source of low-emission hydrogen, it's not yet known if this process is viable at scale.
- White hydrogen is a form of naturally occurring hydrogen created through fracking in underground deposits. It has yet to be leveraged in any capacity.
- Green hydrogen is made by using renewable energy to electrolyse water, splitting it into its base components. When green hydrogen is produced using solar energy, it may also be referred to as yellow hydrogen. Currently, this form of hydrogen represents only a small percentage of total production, as it is still relatively expensive to produce. This may soon change, however. Let’s explore why.
The burgeoning green hydrogen market
Green hydrogen presents many benefits, which include a significant reduction in emissions, more efficient energy storage, and the decarbonization of energy systems. Hydrogen is also an incredibly versatile resource. In addition to the aforementioned use cases, the element is also used to produce ammonia, create nylon, manufacture plastics, create flat glass and as a carrier gas in the fabrication of electronics.
Lastly, hydrogen can be produced virtually anywhere — meaning it's completely divorced from the supply chain challenges and concerns plaguing most other resources. By transitioning to hydrogen, countries have the potential to reduce their reliance on fossil fuels. Consequently, this allows them to improve both economic stability and energy security.
Green hydrogen production is not without its challenges, however. The resource requires specialized infrastructure for refinement, storage and distribution. Existing pipelines and transportation systems are not sufficient to fully expand green hydrogen’s potential. Hydrogen's low ignition point and high flammability can also make handling, storage and transportation of the resource incredibly dangerous without proper regulations and training.
These factors together mean hydrogen requires considerable investment to scale it to the point at which it could feasibly replace other energy and fuel sources. For context, PwC predicts hydrogen demand could reach up to 500 million metric tons per year by 2050. Clean hydrogen production capacity stands at roughly 11 million metric tons as of 2021.
The current market outlook for hydrogen is also promising. Globally, the market is expected to achieve a 39.5 percent compounded annual growth rate, reaching $60.56 billion by 2030. Production costs are also expected to drop 50 percent in the same timeframe then continue to steadily decrease until 2050.
Three companies making progress with green hydrogen
Several companies have already made considerable inroads in the production of green hydrogen, including some of the world's largest oil and gas corporations. Below, we've listed several of the most promising.
1. FuelCell Energy (NASDAQ:FCEL)
As the name suggests, FuelCell Energy designs, manufactures and operates environmentally friendly direct fuel cell power plants. With operations in over 50 countries around the world, the company also maintains several of the world's largest fuel cell parks. The company primarily produces green hydrogen from biogas and natural gas.
2. Adani Green Energy (NSE:ADANIGREEN)
Headquartered in India, Adani owns and operates one of the world's largest photovoltaic solar plants. A subsidiary of the Adani Group, the company produces green hydrogen by applying thermal reforming to hydrocarbon feedstocks. The company is playing a pivotal role in supporting India's transition to a net-zero economy.
3. Charbone Hydrogen (TSXV:CH,OTCQB:CHHYF,FWB:K47)
A green hydrogen group based in Canada, but servicing North America with a roadmap of 16 planned facilities by 2030, Charbone is the first company in Canada to produce green hydrogen and the first Canadian hydrogen producer listed on the TSX. Leveraging its hydroelectric assets and other renewable energy sources, the company is wholly committed to the production of clean hydrogen. Charbone is also founded and backed by energy specialists with decades of experience.
Charbone’s pipeline of new projects is paving the way for the company to become one of the leading producers of green dihydrogen in North America. The company stands to benefit from both the Canadian and US governments’ strategies to boost hydrogen production to aid with decarbonization goals.
Investor takeaway
Hydrogen has played an important role in multiple industrial and manufacturing processes for many years. Today, the element is quickly coming into its own as an essential building block for the clean energy transition. As we move inexorably closer to a more sustainable future, the market for green hydrogen will continue to grow — as will its value to investors.
This INNSpired article is sponsored by Charbone Hydrogen (TSXV:CH,OTCQB:CHHYF,FWB:K47) This INNSpired article provides information which was sourced by the Investing News Network (INN) and approved by Charbone Hydrogenin order to help investors learn more about the company. Charbone Hydrogenis a client of INN. The company’s campaign fees pay for INN to create and update this INNSpired article.
This INNSpired article was written according to INN editorial standards to educate investors.
INN does not provide investment advice and the information on this profile should not be considered a recommendation to buy or sell any security. INN does not endorse or recommend the business, products, services or securities of any company profiled.
The information contained here is for information purposes only and is not to be construed as an offer or solicitation for the sale or purchase of securities. Readers should conduct their own research for all information publicly available concerning the company. Prior to making any investment decision, it is recommended that readers consult directly with Charbone Hydrogen and seek advice from a qualified investment advisor.
HEVI Eyeing Production at the End of 2024, CEO Says
Helium Evolution (TSXV:HEVI) has completed the drilling and casing of the farm-out well located at 9-35-3-9W3 (Test Well Area #1), and while testing is ongoing, President and CEO Greg Robb said the company is aiming to proceed with production at the end of the year.
“We’ve been pursuing drilling at Mankota for around a year now with our partner North American Helium, (and) testing a bunch of anomalies. Over the last two years we’ve drilled about 11 wells, a number of them in the Mankota area, and we discovered helium from the last three,” he explained.
"The next step is getting reservoir valuation. You flow them and then you shut them in for a period of time, and you build up and put analysis for a better understanding of the reservoir. And we’ll be proceeding later (this year) for further drilling, pipelining and probably bringing in a plant, then aiming for production at the end of the year. So Mankota is a major turning point for us," Robb added.
Watch the full interview with Helium Evolution President and CEO Greg Robb above.
Disclaimer: This interview is sponsored by Helium Evolution (TSXV:HEVI). This interview provides information which was sourced by the Investing News Network (INN) and approved by Helium Evolution in order to help investors learn more about the company. Helium Evolution is a client of INN. The company’s campaign fees pay for INN to create and update this interview.
INN does not provide investment advice and the information on this profile should not be considered a recommendation to buy or sell any security. INN does not endorse or recommend the business, products, services or securities of any company profiled.
The information contained here is for information purposes only and is not to be construed as an offer or solicitation for the sale or purchase of securities. Readers should conduct their own research for all information publicly available concerning the company. Prior to making any investment decision, it is recommended that readers consult directly with Helium Evolutionand seek advice from a qualified investment advisor.
This interview may contain forward-looking statements including but not limited to comments regarding the timing and content of upcoming work programs, receipt of property titles, etc. Forward-looking statements address future events and conditions and therefore involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated in such statements. The issuer relies upon litigation protection for forward-looking statements. Investing in companies comes with uncertainties as market values can fluctuate.
Charbone Hydrogen: The Only Publicly Listed Green Hydrogen Player in Canada
Charbone Hydrogen (TSXV:CH,OTCQB:CHHYF,FWB:K47),OTCQB:CHHYF,FWB:K47) eyes expansion across North America (US and Canada) with a pipeline of new projects as the world races to find effective solutions to meet its net-zero ambitions by 2050. Green hydrogen could be a perfect fit as a potentially low-emitting fuel source and a low-emissions substitute for fossil fuels in residential and industrial use cases.
Charbone’s focus on “green hydrogen” strengthens its position among investors looking for opportunities to invest in sustainable energy solutions. Green hydrogen is produced when the energy used to power electrolysis comes from renewable sources like wind, water, solar or nuclear. Charbone has clearly stated its intentions to leverage hydropower and nuclear energy to produce hydrogen.
The company plans to construct 16 hydrogen projects across North America (six in Canada and 10 in the US) over the next four years. The first of which is under construction at Sorel-Tracy in Quebec, which is expected to be production-ready by mid-2024. The Sorel-Tracy facility is located on a 40,000-square-meter land parcel along Quebec Highway 30. The highway is known as the “Steel Highway” because of the numerous steel mills and process plants operating along the highway.
Company Highlights
- Charbone Hydrogen is a Canada-based producer of green hydrogen and is the only publicly listed green hydrogen producer in Canada.
- The company aims to develop a pipeline of 16 green hydrogen projects across the US and Canada. Of which, the first facility at Sorel-Tracy (Quebec, Canada) is under construction and is expected to be production-ready in mid-2024.
- The company will leverage hydropower and nuclear energy to produce green hydrogen which will allow it to control production costs while lowering emissions. Energy costs remain a significant portion of hydrogen production and the ability to lower these costs will make Charbone’s offering more competitive.
- Charbone has developed several strategic partnerships aimed at strengthening its position in the hydrogen market. This includes a construction agreement with EBC, a supply agreement with NEK Community Broadband, and an MOU with Oakland County for the development of the first green hydrogen plant in the US.
- In December 2023, the company announced the closing of the second tranche of private placement. When combined with the previous closing, the company has raised an aggregate of $499,877, which will be used to fund the construction of the Sorel-Tracy Project.
- Charbone is well positioned to participate in the rise of green hydrogen as a potential low-emitting alternative to fossil fuels.
This Charbone Hydrogen profile is part of a paid investor education campaign.*
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