| From: pstad60 | 10/15/2024 2:25:18 PM | | | | | | For anyone in the Calgary area .....
Along with a good number of other O&G companies,Touchstone Exploration is participating during the 11:10 - 11:45am time slot in Presentation Room 5 on Saturday Oct 19 at the Schachter "Catch The Energy" Conference .....
https://energynow.ca/2024/10/be-our-guest-attend-the-schachter-catch-the-energy-conference-calgary-october-19-2024-mount-royal-university-come-face-to-face-with-canadas-energy-leaders/ |
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| From: LoneClone | 10/24/2024 3:33:57 PM | | | | | | QIMC Unveils Landmark Geophysical Survey Findings in its natural hydrogen Ville Marie project
newsfilecorp.com
October 24, 2024 8:00 AM EDT | Source: Quebec Innovative Materials Corp.
Lachute, Quebec--(Newsfile Corp. - October 24, 2024) - Quebec Innovative Materials Corp. (CSE: QIMC) (FSE: 7FJ) ("QI Materials", "QIMC" or the "Company"), is proud to announce the very successful results of the non-invasive geophysical surveys conducted in the St-Bruno-de-Guigues area of Témiscamingue. These surveys were commissioned by QIMC to its partner the INRS following the detection of high hydrogen soil-gas anomalies during its summer soil sampling covering an area of 80km2.
"We are thrilled with the outcome of these geophysical surveys on the first 3 lines measured, said John Karagiannidis, CEO of QIMC. " The results are in line with our expectations and further confirms Professor Marc Richer-Lafleche hydrogen model of a deep seated hydrothermal source. Even without drilling data, the anomalies seen in the imagery along line 1 suggest a break in the clay horizon's integrity, potentially allowing hydrogen to migrate to the surface. Also, the disturbances on line 3, combined with strong hydrogen soil anomalies, point to the likely presence of gas in the sediments. This geophysics data provides a clear and detailed understanding of the Quaternary geology underlying the hydrogen anomalies and the reservoirs. These findings are critical for future exploration and natural hydrogen development in our natural hydrogen Ville Marie project, as they provide a comprehensive understanding of the area's geology, faulting and gas seepage dynamics reservoir structures"
To document the characteristics of the terrain beneath these high hydrogen soil anomalies, QIMC partnered with the Institut national de la recherche scientifique (INRS) to carry out cutting-edge geoelectric tomography (GTS). This technique allows for the detailed mapping of subsurface geological features without the need for invasive stratigraphic drilling.
Surveys
The first survey (figure 1), carried out in October 2024, involved the production of sub-surface imagery with very high spatial resolution (inter-electrode distance spacing of 5 m). This will be followed, in November 2024, by a geoelectric tomography survey with a vertical penetration of the order of 350 m (inter-electrode distance spacing of 20 m), and subsequently by an audiomagnetotellurics (AMT) survey with high vertical penetration of the kilometer order. Being particularly sensitive to the presence of electrical discontinuities associated with faults, this method should make it possible to locate and prioritize the importance of faults associated with the Témiscamingue graben. Concurrently with these surveys, a gravity survey (50m stations) is being currently carried out to document regional variations in the thickness of the sedimentary rock basin.
Figure 1. Line 1 survey line and line 3 East and North survey lines
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Objective
One of the objectives of INRS and QIMC is to identify areas of maximum thickening of the sedimentary rock sequence overlying the Archean basement in order to identify the most likely places for the reservoirs. This objective should be easy to achieve, given the difference in density between the Proterozoic and Ordovician sedimentary rocks and the volcanic and intrusive rocks of the Baby Group (greenstone belt).
The data generated by the galvanic and electromagnetic geoelectric surveys will also be used to optimize the injection and recording parameters for the electromagnetic data (TDEM) to be measured in winter 2024 going into early 2025. The latter will be acquired using a mobile ground-based system capable of producing electrical resistivity and electrical chargeability sections with vertical penetration of the order of 100-200 m and horizontal resolution of the order of 15 cm. This system is essential for locating fractures and faults masked by glaciolacustrine deposits, and for distinguishing Ordovician sedimentary rocks (less resistive) from Proterozoic sedimentary rocks (more resistive).
Geoelectric tomographic survey
The INRS team carried out a very high-resolution geoelectrical tomography (electrical resistivity and chargeability) survey to produce electrical resistivity and chargeability imagery along lines 1 and 3Est and north of line 3E. The objectives of the survey were to: 1) provide imagery to assess overburden thickness variability, 2) clarify the stratigraphy of Quaternary sediments overlying sedimentary rocks, and 3) verify that the strong hydrogen anomalies detected during the Soil-Gas survey are not associated with simple sulfide weathering processes. "This last point is critical", notes Professor Marc Richer-Laflèche, head of INRS' Applied Geoscience Laboratory, "as the aim of the project is to locate hydrogen anomalies originating from deep-seated sources, rather than small local anomalies associated with the weathering of sulphides located at the contact between mineralized bedrock and local groundwater. "
The survey was carried out using a Terameter LS (10 channels) and multi-connector cables. Acquisitions were carried out in gradient mode. Zond RS2D software was used for quality control, data inversion and 2D imaging.
"The results obtained indicate that geoelectrical tomography is an effective method that works remarkably well in the electrically conductive terrain of St-Bruno-de Guigues" states Professor Richer-Laflèche. "In the very high spatial resolution acquisition mode, the method reveals the presence of several sedimentary horizons in the Quaternary sequence, and pinpoints the position of the contact with the rocks of the sedimentary basin."
Section Line 1
Figure 2. A) High-resolution geoelectrical tomographic imaging of a portion of the rang IV road (line 1: rte du 4ième rang) in St-Bruno-de-Guigues. B) Contrast enhancement by scaling electrical resistivity values. Modeling and 2D data inversion: M.R. LaFlèche).
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Section along line 1 (rte du quatrième rang): This survey was carried out in the area of the first hydrogen anomaly discoveries (July 2024) in the northern part of St-Bruno-de-Guigues. The section clarifies the contact between bedrock (between I and II) and the Quaternary sequence, comprising some 5 units (II: sand and gravels; III: clays; IV: sands; V: clays and silty sands at the top)(Fig. 2 a). "The imagery obtained along line 1 also shows significant heterogeneity, particularly affecting horizon III, which according to our model would be a low-permeability clay-rich horizon (Fig. 2b)" notes Professor Richer-Laflèche. "Despite the absence of drilling in this area, we believe that this anomalous domain marks a break in the tightness of a clay horizon", continues Professor Richer-Laflèche, "allowing gases such as hydrogen to ascend to the sub-surface and soils."
Section north of line 3E
This 1500m-long section was laid parallel to line 3E to avoid electrical interference associated with a transmission line located along chemin du Quai (line 3E). Note that the Soil-Gas survey for line 3E reported very strong hydrogen anomalies that could not be explained by surface observations.
"The section shows a more complex geological and topographical context than line 1 (Fig. 3a). In the central part, the bedrock becomes sub-outcropping sub-flush (I) (Lorrain Fm sandstone) and shows more conductive sub-vertical anisotropies, which we interpret as major fractures that could be important in the process of hydrogen transfer to the surface(VI and VII)" states Professor Richer-Laflèche. "Note that these fractures (or faults) affect sub-horizontally dipping sedimentary rocks. As with the Line 1 section, it shows the presence of sandy-gravelly (III and IV) and silty-clay (V) sediments (Fig. 3a), which also appear disturbed in sectors VIII and IX (Fig. 3b and C). Despite the absence of drilling data at present, we interpret these disturbances as electrical resistivity anomalies related to the probable presence of gas in the sediments, as they are located in an area characterized by strong hydrogen anomalies in the soils (ref. Soil-Gas survey on line 3 East)."
Figure 3. A) High-resolution geoelectric tomographic imagery calculated from data collected along a section located north of Chemin du Quai (line 3E)in St-Bruno-de-Guigues. B and C) Contrast enhancement by scaling electrical resistivity values. Modeling and 2D data inversion: M.R. LaFlèche.
To view an enhanced version of this graphic, please visit:
images.newsfilecorp.com
Probable origin of disturbances observed in high-resolution ERT imagery
The presence of sub-vertical electrical resistivity anisotropies, affecting glaciolacustrine sediments, could be explained by different geological processes. Given the seismic context of the region, the increase in electrical resistivity values in silty clays could be explained, among other things, by the emplacement of non-cohesive sand dykes in cohesive silty-clay sediments. In fact, an earthquake-related sand eruption was observed in the Témiscamingue graben Northeast of New Liskeard (Doughty et al., 2010). "We believe that the presence of sub-vertical sandy dykes (more porous and permeable) could promote the ascent of hydrogen through the clay-silt cover (impermeable) and thus produce hydrogen anomalies in the soils." states Professor Richer-Lafèche. "Also, locally, if the gas flow is significant (advective flux sectors), subvertical resistive anomalies could be linked to the presence of significant quantities of gas, thus explaining a localized increase in electrical resistivity values." This will be further confirmed by geotechnical drilling planned for Spring 2025.
"Deeper data, located in the sandstone horizon of the Lorrain Formation (Cobalt Gp), suggest that despite the sub horizontal nature of the stratification of the sandstone units, these rocks appear fractured and probably faulted," notes Professor Richer-Laflèche. "This is underlined by a sharp drop in electrical resistivity values. This type of rock discontinuity could be an exploration vector for advective gas flow zones in Proterozoic, Ordovician and Silurian sedimentary rocks of the Témiscamingue graben."
"The successful results of these surveys mark a significant step forward in QIMC's efforts to explore and harness Ville Marie's natural hydrogen resources in a responsible and sustainable manner." continues John Karagiannidis, president of QIMC. The data collected from the geophysical surveys will be further analyzed and integrated into QIMC's ongoing exploration strategy for the region, ensuring that future developments are grounded in sound geological understanding.
QIMC will continue to engage with local stakeholders and provide updates as the project progresses. The company is committed to maintaining transparency and fostering positive relationships with the community throughout this process.
Reference:
Doughty, M., Eyles N., and Daurio, L., 2010. Ongoing Neotectonic Activity in the Timiskaming - Kipawa Area of Ontario and Québec. Geoscience Canada, Volume 37, Number 3, September 2010, pp.95-146
About the INRS and Pr. Marc Richer-LaFlèche, P.Geo.
The Institut National de la Recherche Scientifique ("INRS") is a high-level research and training institute. Pr. Richer-LaFlèche's team has exceptional geological, geochemical and geophysical experience specifically in the regions of QIMC's newly acquired claims. They have carried out over six years of geophysical and geochemical work and collected thousands of C1-C4 Soil-Gas analyses.
M. Richer-LaFlèche also holds an FRQNT grant, in partnership with Quebec MRN and the mining industry, to develop and optimize a Soil-Gas method for the direct detection of mineralized bodies and faults under Quaternary cover. In addition to sulphide gases, hydrogen was systematically analyzed in the numerous surveys carried out in 2023 in Abitibi, Témiscamingue and also in the Quebec Appachian. M. Richer-LaFlèche is the Qualified Person responsible for the technical information contained in this news release and has read the information contained herein.
In addition, the INRS team has several portable gas spectrometers and the sampling equipment and logistics necessary for taking gas samples and geophysical measurements on the ground or in the aquatic environment. He is a professional geologist registered with the Ordre des géologues du Québec and is the Qualified Person responsible for the technical information contained in this news release and has read and approved the information contained herein.
For more information about Quebec Innovative Materials Corp. and its products, please visit www.qimaterials.com
About Québec Innovative Materials Corp.
Québec Innovative Materials Corp. is a mineral exploration, and development company dedicated to exploring and harnessing the potential of Canada's abundant resources. With properties in Ontario and Québec, QIMC is focused on specializing in the exploration of white (natural) hydrogen and high-grade silica deposits, QIMC is committed to sustainable practices and innovation. With a focus on environmental stewardship and cutting-edge extraction technology, we aim to unlock the full potential of these materials to drive forward clean energy solutions to power the AI and carbon-neutral economy and contribute to a more sustainable future.
QUÉBEC INNOVATIVE MATERIALS CORP.
John Karagiannidis
Chief Executive Officer
Tel: +1 438-401-8271
For further information, please contact:
Email: info@qimaterials.com
Neither the Canadian Securities Exchange nor its Regulation Services Provider (as that term is defined in the CSE policies) accepts responsibility for the adequacy or accuracy of this news release and has neither approved nor disapproved the contents of this news release.
Forward-Looking Statements
This news release contains statements that constitute "forward-looking statements". Such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause Québec Innovative Materials' actual results, performance or achievements, or developments in the industry to differ materially from the anticipated results, performance or achievements expressed or implied by such forward-looking statements. Forward-looking statements are statements that are not historical facts and are generally, but not always, identified by the words "expects," "plans," "anticipates," "believes," "intends," "estimates," "projects," "potential" and similar expressions, or that events or conditions "will," "would," "may," "could" or "should" occur.
Although Québec Innovative Materials believes the forward-looking information contained in this news release is reasonable based on information available on the date hereof, by their nature, forward-looking statements involve assumptions, known and unknown risks, uncertainties and other factors which may cause our actual results, performance or achievements, or other future events, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.
Examples of such assumptions, risks and uncertainties include, without limitation, assumptions, risks and uncertainties associated with general economic conditions; adverse industry events; future legislative and regulatory developments in the mining sector; the Company's ability to access sufficient capital from internal and external sources, and/or inability to access sufficient capital on favorable terms; mining industry and markets in Canada and generally; the ability of Québec Innovative Materials Corp. to implement its business strategies; competition; and other assumptions, risks and uncertainties.
The forward-looking information contained in this news release represents the expectations of the Company as of the date of this news release and, accordingly, is subject to change after such date. Readers should not place undue importance on forward-looking information and should not rely upon this information as of any other date. While the Company may elect to, it does not undertake to update this information at any particular time except as required in accordance with applicable laws.
 SOURCE: Quebec Innovative Materials Corp. |
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| From: LoneClone | 11/1/2024 12:15:45 PM | | | | | | Gran Tierra Energy: Scheme of Arrangement for Acquisition of i3 Energy Becomes Effective
ca.finance.yahoo.com
Gran Tierra Energy Inc.
Thu, October 31, 2024 at 12:30 a.m. PDT 20 min read
GTE
-0.16%
Gran Tierra Energy Inc. NOT FOR RELEASE, PUBLICATION OR DISTRIBUTION IN WHOLE OR IN PART, DIRECTLY OR INDIRECTLY IN, INTO OR FROM ANY JURISDICTION WHERE TO DO SO WOULD CONSTITUTE A VIOLATION OF THE RELEVANT LAWS OR REGULATIONS OF SUCH JURISDICTION
CALGARY, Alberta, Oct. 31, 2024 (GLOBE NEWSWIRE) --
31 October 2024
RECOMMENDED AND FINAL CASH AND SHARE ACQUISITION
for
i3 Energy plc ("i3 Energy")
by
Gran Tierra Energy Inc. ("Gran Tierra")
to be implemented by way of a scheme of arrangement under Part 26 of the Companies Act 2006
SCHEME OF ARRANGEMENT BECOMES EFFECTIVE
On 19 August 2024, the boards of directors of i3 Energy and Gran Tierra announced that they had reached agreement on the terms of a recommended and final cash and share acquisition of the entire issued, and to be issued, share capital of i3 Energy (the "Acquisition"). The Acquisition is being implemented by means of a Court-sanctioned scheme of arrangement under Part 26 of the Companies Act 2006.
i3 Energy published a circular in relation to the Scheme dated 29 August 2024 (the "Scheme Document").
On 29 October 2024, i3 Energy announced that the Court had sanctioned the Scheme at the Sanction Hearing held on 29 October 2024.
i3 Energy and Gran Tierra are pleased to announce that, following delivery of the Court Order to the Registrar of Companies and satisfaction or waiver of all of the conditions set out in the Scheme Document, the Scheme has now become Effective in accordance with its terms and, pursuant to the Scheme, the entire issued and to be issued share capital of i3 Energy is now owned by Gran Tierra.
Consideration
A Scheme Shareholder on the register of members of i3 Energy at the Scheme Record Time, being 6.00 p.m. on 30 October 2024, will be entitled to receive one New Gran Tierra Share per every 207 i3 Energy Shares held and 10.43 pence cash per i3 Energy Share subject to any adjustments to such consideration resulting from valid Elections made under the Mix and Match Facility. For Scheme Shareholders holding Scheme Shares in certificated form, settlement of the consideration will be effected by electronic payment or (for those Scheme Shareholders who have not set up an electronic payment mandate) by the despatch of cheques. For Scheme Shareholders holding Scheme Shares in uncertificated form, settlement of consideration will be effected by the crediting of CREST or CDS accounts, as applicable. In each case settlement of consideration will occur as soon as practicable and in any event not later than 14 days after the date of this announcement, being 14 November 2024.
Further to the announcement on 7 October 2024, i3 Energy confirms that, the Scheme having become Effective, the Acquisition Dividend totalling £3,084,278 will be paid as follows:
| Dividend:
| 0.2565 pence / i3 Energy Share
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| Record Date:
| 6.00 p.m. on 30 October 2024
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|
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| Payment date:
| by 13 November 2024
|
|
|
|
i3 Energy admission to listing on AIM
An application was made for the suspension of admission to trading in i3 Energy Shares on the London Stock Exchange's AIM Market ("AIM") and such suspension has taken effect from 7.30 a.m. today. The cancellation of the admission to trading of the i3 Energy Shares on AIM has been applied for and is expected to take place by 8.00 a.m. on 1 November 2024. The delisting of the i3 Energy Shares on the Toronto Stock Exchange has been applied for and is expected to take place at the close of markets on 1 November 2024.
Gran Tierra admission of shares to listing
An application has been made for the admission of 5,808,925 new shares (the "Consideration Shares") of common stock of par value USD0.001 per share in Gran Tierra. Gran Tierra has applied for the Consideration Shares to be admitted to the Equity Shares (International Commercial Companies Secondary Listing) Category of the Official List of the Financial Conduct Authority and to trading on the main market of the London Stock Exchange PLC (together, "Admission").
Gran Tierra expects Admission of the Consideration Shares to occur at 8.00 a.m. on 1 November 2024. The Consideration Shares will rank pari passu in all respects with Gran Tierra's existing shares of common stock of par value USD0.001 per share.
Total Voting Rights
Following Admission, Gran Tierra will have total issued share capital of 36,460,141 common shares, and holds no common shares in treasury. Gran Tierra Shareholders may use the figure of 36,460,141 as the denominator in calculations to determine if they are required to notify Gran Tierra of their interest in, or a change to their interest in Gran Tierra under the Financial Conduct Authority's Disclosure Guidance and Transparency Rules.
Cancellation of the Trafigura Loan Facility
Gran Tierra also announces that the Loan Facility entered into on 19 August 2024 with Trafigura has today been cancelled. As announced on 18 September 2024, Gran Tierra completed an offering of an additional US$ 150 million aggregate principal amount of its 9.500% Senior Secured Amortizing Notes due 2029, the net proceeds of which are being applied to satisfy the cash consideration payable to i3 Energy Shareholders in place of the term loan facility available to Gran Tierra pursuant to the terms of the Loan Facility.
Board and constitutional changes
Each of the i3 Energy Directors has resigned as a director of i3 Energy with effect from the Scheme becoming Effective.
Pedro Zutara, Adam Hewitson and Amy Lister have been appointed as directors of i3 Energy with effect from the Scheme becoming Effective.
i3 Energy will in due course submit an application to cease to be a reporting issuer in each of the provinces of Canada under National Policy 11-206 – Process for Cease to be a Reporting Issuer Applications. i3 Energy is expected to be converted to a private limited company and its name changed to Gran Tierra UK Limited. As disclosed in the Scheme Document, i3 Energy Shares are expected to be transferred to a wholly-owned subsidiary of Gran Tierra following completion of the re-registration.
Full details of the Acquisition are set out in the Scheme Document. Defined terms used but not defined in this announcement have the meanings set out in the Scheme Document. All references to times in this announcement are to London time.
Enquiries:
Gran Tierra
Gary Guidry
Ryan Ellson
| Tel: +1 (403) 265 3221
|
|
| i3 Energy
Majid Shafiq (CEO)
| c/o Camarco
Tel: +44 (0) 203 757 4980
|
|
| Stifel Nicolaus Europe Limited (Joint Financial Adviser to Gran Tierra)
Callum Stewart
Simon Mensley
| Tel: +44 (0) 20 7710 7600
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| Eight Capital (Joint Financial Adviser to Gran Tierra)
Tony P. Loria
Matthew Halasz
| Tel: +1 (587) 893 6835
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| Zeus Capital Limited (Rule 3 Financial Adviser, Nomad and Joint Broker to i3 Energy)
James Joyce, Darshan Patel, Isaac Hooper
|
Tel: +44 (0) 203 829 5000
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| Tudor, Pickering, Holt & Co. Securities - Canada, ULC (Financial Adviser to i3 Energy)
Brendan Lines
|
Tel: +1 (403) 705 7830
|
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| National Bank Financial Inc. (Financial Adviser to i3 Energy)
Tarek Brahim Arun Chandrasekaran
|
Tel: +1 (403) 410 7749
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| Camarco
Georgia Edmonds, Violet Wilson, Sam Morris
|
Tel: +44 (0) 203 757 4980
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No increase statement
The financial terms of the Acquisition will not be increased save that Gran Tierra reserves the right to revise the financial terms of the Acquisition in the event: (i) a third party, other than Gran Tierra, announces a firm intention to make an offer for i3 Energy on more favourable terms than Gran Tierra's Acquisition; or (ii) the Panel otherwise provides its consent.
Notices relating to financial advisers
Stifel Nicolaus Europe Limited ("Stifel"), which is authorised and regulated by the FCA in the UK, is acting as financial adviser exclusively for Gran Tierra and no one else in connection with the matters referred to in this announcement and will not be responsible to anyone other than Gran Tierra for providing the protections afforded to its clients or for providing advice in relation to matters referred to in this announcement. Neither Stifel, nor any of its affiliates, owes or accepts any duty, liability or responsibility whatsoever (whether direct or indirect, whether in contract, in tort, under statute or otherwise) to any person who is not a client of Stifel in connection with this announcement, any statement contained herein or otherwise.
Eight Capital ("Eight Capital"), which is authorised and regulated by the Canadian Investment Regulatory Organization in Canada, is acting exclusively for Gran Tierra and for no one else in connection with the subject matter of this announcement and will not be responsible to anyone other than Gran Tierra for providing the protections afforded to its clients or for providing advice in connection with the subject matter of this announcement.
Zeus Capital Limited ("Zeus"), which is authorised and regulated by the FCA in the United Kingdom, is acting exclusively for i3 Energy as financial adviser, nominated adviser and joint broker and no one else in connection with the matters referred to in this announcement and will not be responsible to anyone other than i3 Energy for providing the protections afforded to clients of Zeus, or for providing advice in relation to matters referred to in this announcement. Neither Zeus nor any of its affiliates owes or accepts any duty, liability or responsibility whatsoever (whether direct or indirect, whether in contract, in tort, under statute or otherwise) to any person who is not a client of Zeus in connection with the matters referred to in this announcement, any statement contained herein or otherwise.
Tudor, Pickering, Holt & Co. Securities - Canada, ULC ("TPH&Co."), which is regulated by the Canadian Investment Regulatory Organization and a member of the Canadian Investor Protection Fund, is acting exclusively for i3 Energy by way of its engagement with i3 Energy Canada Ltd., a wholly owned subsidiary of i3 Energy, in connection with the matters referred to in this announcement and for no one else, and will not be responsible to anyone other than i3 Energy for providing the protections afforded to its clients nor for providing advice in relation to the matters set out in this announcement. Neither TPH&Co. nor any of its subsidiaries, branches or affiliates and their respective directors, officers, employees or agents, owes or accepts any duty, liability or responsibility whatsoever (whether direct or indirect, whether in contract, in tort, under statute or otherwise) to any person who is not a client of TPH&Co. in connection with this announcement, any statement contained herein or otherwise.
National Bank Financial Inc. ("NBF"), which is regulated by the Canadian Investment Regulatory Organization and a member of the Canadian Investor Protection Fund, is acting as financial adviser to i3 Energy Canada Ltd., a wholly-owned subsidiary of i3 Energy plc, in connection with the subject matter of this announcement. Neither NBF, nor any of its subsidiaries, branches or affiliates and their respective directors, officers, employees or agents, owes or accepts any duty, liability or responsibility whatsoever (whether direct or indirect, whether in contract, in tort, under statute or otherwise) to any person who is not a client of NBF in connection with this announcement, any statement contained herein or otherwise.
Additional Information
This announcement is for information purposes only. It is not intended to, and does not, constitute or form part of any offer, offer to acquire, invitation or the solicitation of an offer to purchase, or an offer to acquire, subscribe for, sell or otherwise dispose of, any securities or the solicitation of any vote or approval in any jurisdiction, pursuant to this announcement or otherwise \ nor shall there be any sale, issuance or transfer of securities of Gran Tierra or i3 Energy pursuant to the Acquisition in any jurisdiction in contravention of applicable laws.
This announcement is not an offer of securities for sale in the United States or in any other jurisdiction. No offer of securities shall be made in the United States absent registration under the U.S. Securities Act of 1933, as amended (the “U.S. Securities Act”), or pursuant to an exemption from, or in a transaction not subject to, such registration requirements. Any securities issued as part of the Acquisition are anticipated to be issued in reliance upon available exemption from such registration requirements pursuant to Section 3(a)(10) of the U.S. Securities Act. Any New Gran Tierra Shares to be issued in connection with the Acquisition are expected to be issued in reliance upon the prospectus exemption provided by Section 2.11 or Section 2.16, as applicable, of National Instrument 45-106 – Prospectus Exemptions of the Canadian Securities Administrators and in compliance with the provincial securities laws of Canada.
This announcement has been prepared in accordance with the laws of England and Wales, the Code, the AIM Rules for Companies and the Disclosure Guidance and Transparency Rules and the information disclosed may not be the same as that which would have been prepared in accordance with the laws of jurisdictions outside England and Wales.
This announcement does not constitute a prospectus or circular or prospectus exempted document.
Overseas Shareholders
The availability of the Acquisition to i3 Energy Shareholders who are not resident in the United Kingdom may be affected by the laws of the relevant jurisdictions in which they are resident. Any person outside the United Kingdom or who are subject to the laws and/regulations of another jurisdiction should inform themselves of, and should observe, any applicable legal and/or regulatory requirements. Any failure to comply with the restrictions may constitute a violation of the securities laws of any such jurisdiction.
The release, publication or distribution of this announcement in or into or from jurisdictions other than the United Kingdom may be restricted by law and therefore any persons who are subject to the laws of any jurisdiction other than the United Kingdom should inform themselves about, and observe, such restrictions. Any failure to comply with the applicable restrictions may constitute a violation of the securities laws of such jurisdiction. To the fullest extent permitted by applicable law, the companies and persons involved in the Acquisition disclaim any responsibility or liability for the violation of such restrictions by any person.
Unless otherwise determined by Gran Tierra or required by the Code and permitted by applicable law and regulation, the Acquisition will not be made available, directly or indirectly, in, into or from a Restricted Jurisdiction where to do so would violate the laws in that jurisdiction and no person may vote in favour of the Acquisition by any such use, means, instrumentality or form (including, without limitation, facsimile, email or other electronic transmission, telex or telephone) within any Restricted Jurisdiction or any other jurisdiction if to do so would constitute a violation of the laws of that jurisdiction. Accordingly, copies of this announcement and all documents relating to the Acquisition are not being, and must not be, directly or indirectly, mailed or otherwise forwarded, distributed or sent in, into or from a Restricted Jurisdiction where to do so would violate the laws in that jurisdiction, and persons receiving this document and all documents relating to the Acquisition (including custodians, nominees and trustees) must observe these restrictions and must not mail or otherwise distribute or send them in, into or from such jurisdictions where to do so would violate the laws in that jurisdiction. Doing so may render invalid any purported vote in respect of the Acquisition.
Dealing and Opening Position Disclosure Requirements
Under Rule 8.3(a) of the Takeover Code, any person who is interested in one per cent. or more of any class of relevant securities of an offeree company or of any securities exchange offeror (being any offeror other than an offeror in respect of which it has been announced that its offer is, or is likely to be, solely in cash) must make an Opening Position Disclosure following the commencement of the Offer Period and, if later, following the announcement in which any securities exchange offeror is first identified.
An Opening Position Disclosure must contain details of the person's interests and short positions in, and rights to subscribe for, any relevant securities of each of (i) the offeree company and (ii) any securities exchange offeror(s). An Opening Position Disclosure by a person to whom Rule 8.3(a) applies must be made by no later than 3.30 p.m. (London time) on the 10th Business Day following the commencement of the Offer Period and, if appropriate, by no later than 3.30 p.m. (London time) on the 10th Business Day following the announcement in which any securities exchange offeror is first identified. Relevant persons who deal in the relevant securities of the offeree company or of a securities exchange offeror prior to the deadline for making an Opening Position Disclosure must instead make a Dealing Disclosure.
Under Rule 8.3(b) of the Takeover Code, any person who is, or becomes, interested in one per cent. or more of any class of relevant securities of the offeree company or of any securities exchange offeror must make a Dealing Disclosure if the person deals in any relevant securities of the offeree company or of any securities exchange offeror. A Dealing Disclosure must contain details of the dealing concerned and of the person's interests and short positions in, and rights to subscribe for, any relevant securities of each of (i) the offeree company and (ii) any securities exchange offeror(s), save to the extent that these details have previously been disclosed under Rule 8. A Dealing Disclosure by a person to whom Rule 8.3(b) applies must be made by no later than 3.30 p.m. (London time) on the Business Day following the date of the relevant dealing. If two or more persons act together pursuant to an agreement or understanding, whether formal or informal, to acquire or control an interest in relevant securities of an offeree company or a securities exchange offeror, they will be deemed to be a single person for the purpose of Rule 8.3.
Opening Position Disclosures must also be made by the offeree company and by any offeror and Dealing Disclosures must also be made by the offeree company, by any offeror and by any persons acting in concert with any of them (see Rules 8.1, 8.2 and 8.4). Details of the offeree and offeror companies in respect of whose relevant securities Opening Position Disclosures and Dealing Disclosures must be made can be found in the Disclosure Table on the Panel's website at www.thetakeoverpanel.org.uk, including details of the number of relevant securities in issue, when the Offer Period commenced and when any offeror was first identified. You should contact the Panel's Market Surveillance Unit on +44 20 7638 0129 if you are in any doubt as to whether you are required to make an Opening Position Disclosure or a Dealing Disclosure.
Publication on website and availability of hard copies
In accordance with Rule 26.1 of the Code, a copy of this announcement is and will be available free of charge, subject to certain restrictions relating to persons resident in Restricted Jurisdictions, for inspection on i3 Energy 's website i3.energy and on Gran Tierra's website grantierra.com by no later than 12 noon (London time) on the Business Day following this announcement. For the avoidance of doubt, the contents of the website referred to in this announcement are not incorporated into and do not form part of this announcement.
Forward Looking Statements
This announcement (including information incorporated by reference into this announcement), oral statements regarding the Acquisition and other information published by Gran Tierra and i3 Energy contain certain forward-looking statements with respect to the financial condition, strategies, objectives, results of operations and businesses of Gran Tierra and i3 Energy and their respective groups and certain plans and objectives with respect to the Combined Group. These forward-looking statements can be identified by the fact that they do not relate only to historical or current facts. Forward looking statements are prospective in nature and are not based on historical facts, but rather on current expectations and projections of the management of Gran Tierra and i3 Energy about future events, and are therefore subject to risks and uncertainties which could cause actual results to differ materially from the future results expressed or implied by the forward-looking statements. The forward looking statements contained in this announcement include, without limitation, statements relating to the expected effects of the Acquisition on Gran Tierra and i3 Energy, the expected timing and method of completion, and scope of the Acquisition, the expected actions of i3 Energy and Gran Tierra upon completion of the Acquisition and other statements other than historical facts. Forward looking statements often use words such as "anticipate", "target", "expect", "estimate", "intend", "plan", "strategy", "focus", "envision", "goal", "believe", "hope", "aims", "continue", "will", "may", "should", "would", "could", or other words of similar meaning. These statements are based on assumptions and assessments made by Gran Tierra, and/or i3 Energy in light of their experience and their perception of historical trends, current conditions, future developments and other factors they believe appropriate. By their nature, forward looking statements involve risk and uncertainty, because they relate to events and depend on circumstances that will occur in the future and the factors described in the context of such forward looking statements in this announcement could cause actual results and developments to differ materially from those expressed in or implied by such forward looking statements. Although it is believed that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to have been correct and readers are therefore cautioned not to place undue reliance on these forward-looking statements. Actual results may vary from the forward-looking statements.
There are several factors which could cause actual results to differ materially from those expressed or implied in forward looking statements. Among the factors that could cause actual results to differ materially from those described in the forward-looking statements are changes in the global, political, economic, business, competitive, market and regulatory forces, future exchange and interest rates, changes in tax rates and future business acquisitions or dispositions.
Each forward-looking statement speaks only as at the date of this announcement. Neither Gran Tierra nor i3 Energy, nor their respective groups assume any obligation to update or correct the information contained in this announcement (whether as a result of new information, future events or otherwise), except as required by applicable law or by the rules of any competent regulatory authority.
Early Warning Reporting Provisions of Canadian Securities Laws
Certain of the information in this announcement is being issued under the early warning reporting provisions of Canadian securities laws. An early warning report with additional information in respect of the foregoing matters will be filed and made available under the SEDAR profile of i3 Energy at www.sedarplus.ca. The purpose of the Scheme was to enable Gran Tierra to acquire 100% of the share capital of i3 Energy. Immediately prior to the completion of the Scheme, Gran Tierra did not own, directly or indirectly, any securities of i3 Energy. To obtain a copy of the early warning report, you may also contact Phillip Abraham, Vice President, Legal & Business Development at 403-698-7918. Gran Tierra is an oil and gas company subsisting under the laws of Delaware, United States and its head office is located at 500 Centre Street SE, Calgary, Alberta T2P 1A6 and i3 Energy's head office is located at 500, 207 – 9 Ave SW, Calgary, Alberta T2P 1K3. |
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| To: LoneClone who wrote (24725) | 11/1/2024 12:17:42 PM | | From: LoneClone | | | | Crown Point Announces Closing of Strategic Acquisition of Exploitation Concessions in Santa Cruz, Argentina
newswire.ca
News provided by Crown Point Energy Inc. Oct 31, 2024, 17:13 ET
CWV: TSX.V
CALGARY, AB, Oct. 31, 2024 /CNW/ - Crown Point Energy Inc. (TSXV: CWV) ("Crown Point" or the "Company") is pleased to announce that it has closed the previously announced acquisition of a 100% operating interest in the Piedra Clavada and Koluel Kaike hydrocarbon exploitation concessions (the "Santa Cruz Concessions") from PAN AMERICAN ENERGY S.L., SUCURSAL ARGENTINA (the "Seller"). The Santa Cruz Concessions are located in the Santa Cruz Province, on the southern flank of Golfo San Jorge basin, approximately 200 km southwest of Comodoro Rivadavia.
The Santa Cruz Concessions, comprising a total of 71,593 acres, include Company owned extensive infrastructure in place capable of handling larger than current production volumes, which averaged production of 3,223 barrels per day ("bbl/d") during the first half of 2024.
The purchase price payable by Crown Point to the Seller was US$12,000,000 cash base consideration, subject to closing adjustments, plus certain contingent in-kind consideration that is payable throughout a fifteen-year period following the closing date. With respect to the in-kind consideration, Crown Point will deliver to the Seller a monthly quantity of oil produced from the Santa Cruz Concessions that may range from zero up to 600 bbl/d, subject to the oil market price so determined for each month. The effective date of the acquisition is January 1, 2024.
Crown Point funded the base cash portion of the purchase price using its existing cash resources, operating cash flows, and proceeds from the previously announced debt financing that closed on October 30.
For further information regarding the Santa Cruz Concessions, include reserves information, see the press release issued by the Company on April 15, 2024.
About Crown Point
Crown Point is an international oil and gas exploration and development company incorporated in Alberta, Canada, trading on the TSX Venture Exchange and operating in Argentina. Crown Point's exploration and development activities are focused in four producing basins in Argentina, the Austral basin in the province of Tierra del Fuego, the Neuquén and Cuyano basins in the province of Mendoza, and the Golfo San Jorge basin in the province of Santa Cruz. Crown Point has a strategy that focuses on establishing a portfolio of producing properties, plus production enhancement and exploration opportunities to provide a basis for future growth.
Neither 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.
SOURCE Crown Point Energy Inc.
 Gabriel Obrador, President & CEO, Ph: (403) 232-1150, Crown Point Energy Inc., gobrador@crownpointenergy.com; Marisa Tormakh, Vice-President, Finance & CFO, Ph: (403) 232-1150, Crown Point Energy Inc., mtormakh@crownpointenergy.com
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| From: pstad60 | 11/4/2024 9:17:01 AM | | | | | | Touchstone Exploration Announces Initial Production from Cascadura C
accesswire.com
CALGARY, AB / ACCESSWIRE / November 4, 2024 / Touchstone Exploration Inc. ("Touchstone", "we", "our" or the "Company") (TSX:TXP)(LSE:TXP) announces initial production from the Cascadura C well pad.
Touchstone has safely commissioned the flowline connecting our Cascadura C surface location to the Cascadura natural gas processing plant, which ties in our Cascadura-2ST1 and Cascadura-3ST1 wells. Additionally, a new natural gas separator has been installed and brought online, expanding the plant's gross natural gas processing capacity to approximately 140 million cubic feet per day.
We are currently conducting production testing operations on the Cascadura-2ST1 well and expect to advance to the Cascadura-3ST1 well thereafter. Isochronal tests will be performed on both wells to evaluate their production capacity and refine future production models. These tests involve flowing each well at various choke sizes to measure flow rates and pressures, followed by pressure buildup periods to assess reservoir performance. During this testing phase, all produced gas will be processed and sold. We expect to complete testing operations within the next two weeks, after which both the Cascadura-2ST1 and Cascadura-3ST1 wells will enter continuous production. Touchstone will provide additional flow rate details once testing concludes.
Paul R. Baay, President and Chief Executive Officer, commented:
"We are excited to announce the commencement of production from the Cascadura C pad, marking a significant milestone as tested volumes from these wells begin generating revenue. Following these well tests, our focus will be on determining optimal production levels to maximize recovery from this portion of the structure. Positioned at the boundary of our reserves booking, these wells offer an exciting opportunity to expand our reserves potential across the field as we continue to evaluate the Cascadura structure to the east.
With the recent flowline installation and facility expansions, we have established strategic infrastructure throughout the Cascadura field, creating efficiencies that are expected to greatly reduce future cycle times from drilling to production."
Touchstone Exploration Inc.
Touchstone Exploration Inc. is a Calgary, Alberta based company engaged in the business of acquiring interests in petroleum and natural gas rights and the exploration, development, production and sale of petroleum and natural gas. Touchstone is currently active in onshore properties located in the Republic of Trinidad and Tobago. The Company's common shares are traded on the Toronto Stock Exchange and the AIM market of the London Stock Exchange under the symbol "TXP". For further information about Touchstone, please visit our website at www.touchstoneexploration.com or contact:
Mr. Paul Baay, President and Chief Executive Officer
Mr. Brian Hollingshead, Executive Vice President Engineering and Business Development
Tel: +1 (403) 750-4405
Advisories
Working Interest
Touchstone has an 80 percent operating working interest in the Cascadura field, which is located on the Ortoire block onshore in the Republic of Trinidad and Tobago. Heritage Petroleum Company Limited holds the remaining 20 percent working interest.
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Decent increase in share price on London AIM market today with this news release.
Should be a steady flow of news and updates for the next few months.
GLTA ! |
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| From: LoneClone | 11/5/2024 1:34:30 PM | | | | | | Gran Tierra Energy Reports Third Quarter 2024 Results and Announces its Sixth Consecutive Ecuador Oil Discovery from the Charapa-B7 Well
- Gran Tierra Announces its Sixth Consecutive Ecuador Oil Discovery from the Charapa-B7 Well and Has Achieved Cumulative Production of Over 1 Million Barrels of Oil in Ecuador
- Gran Tierra Achieved $1 Million in Net Income and Generated $60 Million in Funds Flow from Operations(2), an Increase of 31% from Prior Quarter
- Third Quarter 2024 Total Average WI Production of 32,764 BOPD
- Operating Netback of $101 Million and Adjusted EBITDA of $93 Million(1)(4)
- Exited the Quarter with $278 Million in Cash
- Entered into new credit facility for further liquidity which is currently undrawn
ca.finance.yahoo.com
Gran Tierra Energy Inc.
Mon, November 4, 2024 at 3:15 a.m. PST 39 min read
GTE
-1.08%
CALGARY, Alberta, Nov. 04, 2024 (GLOBE NEWSWIRE) -- Gran Tierra Energy Inc. (“Gran Tierra” or the “Company”) (NYSE American:GTE) (TSX:GTE) (LSE:GTE) announced the Company’s financial and operating results for the quarter ended September 30, 2024 (“the Quarter”). All dollar amounts are in United States dollars, and production amounts are on an average working interest (“WI”) before royalties basis unless otherwise indicated. Per barrel (“bbl”) and bbl per day (“BOPD”) amounts are based on WI sales before royalties. For per bbl amounts based on net after royalty (“NAR”) production, see Gran Tierra’s Quarterly Report on Form 10-Q filed November 4, 2024.
Message to Shareholders
“On October 31, 2024 we were excited to have announced the close of our acquisition of i3 Energy plc (“i3 Energy”). We believe the purchase of i3 Energy uniquely positions Gran Tierra as a premier diversified oil and gas company with assets in Canada, Colombia, and Ecuador. The i3 Energy acquisition has diversified Gran Tierra into Canada and has added 253 net booked drilling locations(1), 77% operated production totaling approximately 18,000 bbls of oil equivalent per day, almost 1.2 million acres (0.6 million acres net) including 53 gross sections in the Montney and 144 gross sections in the Clearwater, two of the most prolific plays in North America. The i3 Energy acquisition has increased Gran Tierra’s PDP reserves(1) by 42 million bbls of oil equivalent (“MMBOE”) or 96%, 1P(1) by 88 MMBOE an increase of 97%, and 2P(1) by 174 MMBOE an increase of 119%. We believe the currently depressed natural gas pricing we see in Western Canada will be alleviated as major Liquified Natural Gas projects including LNG Canada are brought online. In the short term, Gran Tierra will focus on developing the significant oil weighted assets in its Canadian and South American portfolio.
We would like to take this opportunity to welcome our new shareholders in Gran Tierra and look forward to engaging with, and updating them on the Company's strategy in the coming months. We look forward to the integration of our teams and are confident the combined company will have top tier technical and operational skill sets across a broad portfolio. We are eager to implement industry leading technology currently used in Canada in both our Ecuador and Colombia operations, and are equally looking forward to bringing our reservoir modeling, exploration knowledge and asset management expertise into Canada. Combined we are a much stronger company.
Additionally, having our six consecutive discovery in Ecuador and reaching the milestone of 1 million cumulative bbls of oil produced from our operations in Ecuador is a significant achievement for Gran Tierra, highlighting our strong presence and success in the region. The productivity of the Ecuador wells is a testament to the geology in the Oriente and Putumayo Basins, and underpins a key pillar of growth going forward. We remain excited about the potential of the Arawana-Bocachico play, and the two remaining Zabaleta wells to be drilled by the end of the year that will provide essential insights into the size and scope of this promising opportunity”, commented Gary Guidry, President and Chief Executive Officer of Gran Tierra.
Operational Update:
- Acquisition of i3 Energy
- On October 31, 2024, Gran Tierra completed its acquisition of i3 Energy. Gran Tierra is integrating the Canadian operations and are forecasting an active Q4 2024, including drilling 19 gross wells (8.4 net), targeting each of its core operating areas in Central AB, Simonette, Clearwater and Wapiti.
- The Company drilled 2 gross (2 net) horizontal Dunvegan oil wells at Simonette. These high-impact 2-mile wells are currently being stimulated and are expected to be brought on stream in late November. With success, Gran Tierra can drill 2 additional Dunvegan development wells in 2025.
- Clearwater activity commenced in mid-October with the Company’s first operated Clearwater multilateral well at Dawson (100% working interest). The 8-leg multilateral horizontal well (11,870 m of total lateral length) was a follow-up to the Company’s initial 6-leg (7,500 m of total lateral length) discovery at Dawson. The 8-leg well follow-up multilateral was located structurally up-dip of the discovery well and encountered high quality reservoir throughout while drilling. The well will be placed on production imminently as the rig has skidded to and spud the third Clearwater well from the same pad. The Company has been working to secure multiple pad sites at East Dawson to facilitate future expansion of the field, upon further operational success. Following these two wells the rig will move to Walrus and drill 2 prospective Falher sands.
- In addition to the operated capital program, Gran Tierra plans to participate in 10 gross (1.67 net) non-operated partner horizontal wells across its land base.
- In connection with i3 Energy acquisition closing on October 31, 2024, the Company amended and restated the existing revolving credit facility agreement of i3 Energy Canada Ltd. (“i3 Energy Canada”) with National Bank of Canada dated March 22, 2024. As a result of the amendment and restatement, among other things, the borrowing base was revised to C$100.0 million (US$74.1 million) with available commitment of a C$50.0 million (US$37.0 million) revolving credit facility comprised of C$35.0 million (US$25.9 million) syndicated facility and C$15.0 million (US$11.1 million) of operating facility. Subject to the next borrowing base redetermination which will occur on or before June 30, 2025, the revolving credit facility is available until October 31, 2025 with a repayment date of October 31, 2026, which may be extended by further periods of up to 364 days, subject to lender approval. The facility is undrawn.
- Exploration
- Gran Tierra has successfully drilled its sixth consecutive oil discovery in Ecuador, the Charapa-B7 well. The wells drilled in Ecuador continue to yield strong results producing over 1 million cumulative bbls of oil to date which highlights the exceptional potential of the Oriente and Putumayo basins.
Well
| Zone
| Onstream
Date
| IP30
(BOPD)1
| IP90
(BOPD)2
| IP30
BS&W3
| API
| GOR
(scf/stb)4
| Cumulative
Production to
Date (Mbbl)5
| Charapa-B5
| Hollin
| 11/9/2022
| 1,092
| 910
| 2%
| 28
| 160
| 307
| Bocachico-J1
| Basal Tena
| 5/30/2023
| 1,296
| 1,146
| <1%
| 20
| 204
| 449
| Arawana-J1
| Basal Tena
| 5/17/2024
| 1,182
| 970
| <1%
| 20
| 264
| 131
| Bocachico Norte-J1
| T-Sand
| 8/1/2024
| 833
| 519
| 3%
| 35
| 361
| 47
| Charapa-B6
| Hollin
| 8/7/2024
| 1,645
| -
| 21%
| 28
| 49
| 77
| Charapa-B7
| Basal Tena
| 8/30/2024
| 2,043
| -
| <1%
| 25
| 153
| 112
|
1. Average initial 30-day production per well.
2. Average initial 90-day production per well.
3. Percentage of basic sediment and water in the initial 30-day production.
4. Gas-oil ratio and standard cubic feet per stock tank barrel.
5. Thousand bbls of oil and based on production up to November 1, 2024.
- The drilling rig has been moved from the Charapa Block and mobilized to the Chanangue Block to drill two wells - the Zabaleta-K1 and Zabaleta Oeste-K1 exploration wells. The Zabaleta-K1 well is located four kilometers (“km”) to the east of the Arawana-J1 well drilled earlier this year and is 200 feet up structure. The well spud on October 22 2024, and we have currently drilled to 9,488 feet. Both wells will target the Basal Tena formation as well as assess potential in the T-Sand, U-Sand and B-Limestone.
- During the Quarter, the 238 km2 3D seismic program of the Charapa Block was completed, the data has been processed and is currently being interpreted. Preliminary interpretations of the high-quality 3D data confirm potential prospectivity and additional areas of interest identified on seismic, including better definition over the Charapa structure. The 3D data will further delineate reserves, underpin future drilling locations scheduled for 2025 and support future development planning.
- Development
- The planning, civil works, and facility construction at Cohembi in the Suroriente Block are progressing, paving the way for drilling operations to commence in late Q4 2024.
- Acordionero water treatment facilities expansion is expected to be completed mid-December which will result in an addition of 21,500 bbls of water handling per day which represents a 35% increase in water treatment capacity. This will allow for further well optimizations to increase injection and associated oil production. Gran Tierra continues to steadily increased total fluid production and water injection by ~18% per year to continue growing and maintaining oil production while improving sweep efficiencies and recoveries.
Key Highlights of the Quarter:
- Production: Gran Tierra’s total average WI production, which is before the i3 acquisition that has an effective date of October 31, 2024, was 32,764 BOPD, which was consistent with the second quarter 2024 (“the Prior Quarter”). During the Quarter the Company had lower volumes in the Acordionero field caused by downtime related to workovers, partially offset by higher production in the Costayaco field in Colombia, and increased production from the Chanangue and Charapa Blocks in Ecuador as a result of a successful exploration drilling campaign.
- Net Income: Gran Tierra incurred net income of $1 million, compared to a net income of $36.4 million in the Prior Quarter and a net income of $7 million in the third quarter of 2023.
- Adjusted EBITDA(2): Adjusted EBITDA(2) was $93 million compared to $103 million in the Prior Quarter and $119 million in the third quarter of 2023. Twelve month trailing Net Debt(2) to Adjusted EBITDA(2) was 1.3 times and the Company continues to have a long term target of 1.0 times.
- Funds Flow from Operations(2): Funds flow from operations(2) was $60 million ($1.96 per share), up 31% from the Prior Quarter and down 24% from the third quarter of 2023.
- Cash and Debt: As of September 30, 2024, the Company had a cash balance of $278 million, total debt of $787 million and net debt(2) of $509 million. During the Quarter, the Company issued additional $150 million of 9.50% Senior Notes due October 2029 and received cash proceeds of $140 million. Of the total amount of proceeds received, $100 million has been used for financing the purchase price and transaction costs related to the i3 Energy acquisition with the remainder to be used for general corporate purposes.
- Share Buybacks: As a result of the i3 Energy acquisition announced on August 19, 2024, Gran Tierra was required to pause its share buyback program resulting in only 371,130 shares repurchased during the Quarter. From January 1, 2023 to September 30, 2024, the Company repurchased approximately 4.0 million shares, or 12% of shares issued and outstanding at January 1, 2023, from free cash flow(2).
- Return on Average Capital Employed(2): The Company achieved return on average capital employed(2) of 17% during the Quarter and 16% over the trailing 12 months.
Additional Key Financial Metrics:
- Capital Expenditures: Capital expenditures of $53 million were lower than the $61 million in the Prior Quarter due to only operating one drilling rig during the Quarter compared to two in the Prior Quarter. Capital expenditures were up from $43 million compared to the third quarter of 2023 as a result of a more active exploration program in the Quarter when compared to the third quarter of 2023.
- Oil Sales: Gran Tierra generated oil sales of $151 million, down 16% from the third quarter of 2023 as a result of weaker Brent pricing, higher Castilla, Vasconia and Oriente oil differentials and 4% lower sales volumes as a result of lower production. Oil sales decreased 9% from the Prior Quarter primarily due to a 7% decrease in Brent price and higher Castilla, Oriente, and Vasconia oil differentials offset by 1% higher sales volumes.
- Quality and Transportation Discounts: The Company’s quality and transportation discounts per bbl were higher during the Quarter at $14.10, compared to $12.79 in the Prior Quarter and $11.83 in the third quarter of 2023. The Castilla oil differential per bbl widened to $8.83 from $8.21 in the Prior Quarter and from $6.64 in the third quarter of 2023 (Castilla is the benchmark for the Company’s Middle Magdalena Valley Basin oil production). The Vasconia differential per bbl widened to $5.07 from $4.00 in the Prior Quarter, and from $3.59 in the third quarter of 2023. Finally, the Ecuadorian benchmark, Oriente, per bbl was $9.15, up from $8.38 in the Prior Quarter, and up from $7.69 one year ago. The current(3) Castilla differential is approximately $8.50 per bbl, the Vasconia differential is approximately $5.00 per bbl and the Oriente differential is approximately $9.20 per bbl.
- Operating Expenses: Gran Tierra’s operating expenses decreased by 2% to $46 million, compared to the Prior Quarter primarily due to lower workover costs, offset by higher lifting costs primarily associated with inventory fluctuations in Ecuador. Compared to the third quarter of 2023, operating expenses decreased by 7% from $49 million, primarily due to lower lifting costs associated with power generation, equipment rental and road maintenance, partially offset by higher workover activities. On a per bbl basis, operating expense decreased by 2% when compared to the third quarter of 2023 and decreased by 4% when compared to the Prior Quarter.
- Transportation Expenses: The Company’s transportation expenses decreased by 31% to $4 million, compared to the Prior Quarter of $6 million and increased by 2% from the third quarter of 2023. Transportation expenses were higher than the same period in 2023 as a result of increases in trucking tariffs for Acordionero volumes and higher sales volumes transported in Ecuador during the Quarter. Transportation expenses, when compared to the Prior Quarter, were lower due to the utilization of shorter distance delivery points in the Quarter.
- Operating Netback(2)(4): The Company’s operating netback(2)(4) was $34.18 per bbl, down 12% from the Prior Quarter and down 16% from the third quarter of 2023 commensurate with the decrease in Brent Price and higher differentials.
- General and Administrative (“G&A”) Expenses: G&A expenses before stock-based compensation were $3.20 per bbl, down from $3.77 per bbl in the Prior Quarter due to lower consulting, business development and travel expenses and up from $2.68 per bbl, when compared to the third quarter of 2023.
- Cash Netback(2): Cash netback(2) per bbl was $20.34, compared to $15.85 in the Prior Quarter primarily as a result of lower current tax expenses of $5.13 per bbl compared to a current tax expense of $14.54 per bbl in the Prior Quarter as a result of a one time tax adjustment incurred in the Prior Quarter. Compared to one year ago, cash netback(2) per bbl decreased by $5.14 from $25.48 per bbl as a result of lower operating netback primarily due to lower Brent pricing and higher differentials.
Financial and Operational Highlights (all amounts in $000s, except per share and bbl amounts)
| Three Months Ended
September 30,
|
| Three
Months
Ended
June 30,
|
| Nine Months Ended
September 30,
|
| 2024
| 2023
|
| 2024
|
| 2024
| 2023
|
|
|
|
|
|
|
|
| Net Income (Loss)
| $1,133
| $6,527
|
| $36,371
|
| $37,426
| $(13,998)
| Per Share - Basic and Diluted(5)
| $0.04
| $0.20
|
| $1.16
|
| $1.20
| $(0.42)
|
|
|
|
|
|
|
|
| Oil Sales
| $151,373
| $179,921
|
| $165,609
|
| $474,559
| $482,013
| Operating Expenses
| (46,060)
| (49,367)
|
| (47,035)
|
| (141,561)
| (139,227)
| Transportation Expenses
| (3,911)
| (3,842)
|
| (5,690)
|
| (14,185)
| (10,599)
| Operating Netback(2)(4)
| $101,402
| $126,712
|
| $112,884
|
| $318,813
| $332,187
|
|
|
|
|
|
|
|
| G&A Expenses Before Stock-Based Compensation
| $9,491
| $8,307
|
| $10,967
|
| $31,240
| $29,052
| G&A Stock-Based Compensation (Recovery) Expense
| (3,145)
| 1,931
|
| 6,160
|
| 6,376
| 3,748
| G&A Expenses, Including Stock Based Compensation
| $6,346
| $10,238
|
| $17,127
|
| $37,616
| $32,800
|
|
|
|
|
|
|
|
| Adjusted EBITDA(2)
| $92,794
| $119,235
|
| $103,004
|
| $290,590
| $306,391
|
|
|
|
|
|
|
|
| EBITDA(2)
| $97,365
| $115,382
|
| $101,187
|
| $290,443
| $294,391
|
|
|
|
|
|
|
|
| Net Cash Provided by Operating Activities
| $78,654
| $70,381
|
| $73,233
|
| $212,714
| $157,511
|
|
|
|
|
|
|
|
| Funds Flow from Operations(2)
| $60,338
| $79,000
|
| $46,167
|
| $180,812
| $192,122
|
|
|
|
|
|
|
|
| Capital Expenditures
| $52,921
| $43,080
|
| $61,273
|
| $169,525
| $179,707
|
|
|
|
|
|
|
|
| Free Cash Flow(2)
| $7,417
| $35,920
|
| $(15,106)
|
| $11,287
| $12,415
|
|
|
|
|
|
|
|
| Average Daily Volumes (BOPD)
|
|
|
|
|
|
|
| WI Production Before Royalties
| 32,764
| 33,940
|
| 32,776
|
| 32,595
| 33,098
| Royalties
| (6,776)
| (7,164)
|
| (6,774)
|
| (6,650)
| (6,592)
| Production NAR
| 25,988
| 26,776
|
| 26,002
|
| 25,945
| 26,506
| (Increase) Decrease in Inventory
| (524)
| (380)
|
| (811)
|
| (367)
| (222)
| Sales
| 25,464
| 26,396
|
| 25,191
|
| 25,578
| 26,284
| Royalties, % of WI Production Before Royalties
| 21%
| 21%
|
| 21%
|
| 20%
| 20%
|
|
|
|
|
|
|
|
| Per bbl
|
|
|
|
|
|
|
| Brent
| $78.71
| $85.92
|
| $85.03
|
| $81.82
| $81.94
| Quality and Transportation Discount
| (14.10)
| (11.83)
|
| (12.79)
|
| (14.11)
| (14.76)
| Royalties
| (13.58)
| (16.06)
|
| (15.31)
|
| (13.97)
| (13.58)
| Average Realized Price
| 51.03
| 58.03
|
| 56.93
|
| 53.74
| 53.60
| Transportation Expenses
| (1.32)
| (1.24)
|
| (1.96)
|
| (1.61)
| (1.18)
| Average Realized Price Net of Transportation Expenses
| 49.71
| 56.79
|
| 54.97
|
| 52.13
| 52.42
| Operating Expenses
| (15.53)
| (15.92)
|
| (16.17)
|
| (16.03)
| (15.48)
| Operating Netback(2)(4)
| 34.18
| 40.87
|
| 38.80
|
| 36.10
| 36.94
| G&A Expenses Before Stock-Based Compensation
| (3.20)
| (2.68)
|
| (3.77)
|
| (3.54)
| (3.23)
| Transaction Costs
| (0.49)
| —
|
| —
|
| (0.17)
| —
| Realized Foreign Exchange Gain (Loss)
| 0.34
| (0.64)
|
| 0.37
|
| 0.07
| (1.77)
| Interest Expense, Excluding Amortization of Debt Issuance Costs
| (5.66)
| (3.84)
|
| (5.38)
|
| (5.38)
| (3.85)
| Interest Income
| 0.23
| 0.09
|
| 0.35
|
| 0.27
| 0.19
| Net Lease Payments
| 0.07
| 0.18
|
| 0.02
|
| 0.07
| 0.17
| Current Income Tax Expense
| (5.13)
| (8.50)
|
| (14.54)
|
| (6.96)
| (7.08)
| Cash Netback(2)
| $20.34
| $25.48
|
| $15.85
|
| $20.46
| $21.37
|
|
|
|
|
|
|
|
| Share Information (000s)
|
|
|
|
|
|
|
| Common Stock Outstanding, End of Period(5)
| 30,651
| 33,288
|
| 31,022
|
| 30,651
| 33,288
| Weighted Average Number of Shares of Common Stock Outstanding - Basic(5)
| 30,733
| 33,287
|
| 31,282
|
| 31,274
| 33,675
| Weighted Average Number of Shares of Common Stock Outstanding - Diluted(5)
| 30,733
| 33,350
|
| 31,282
|
| 31,274
| 33,675
|
(1) Based on the i3 Energy GLJ Report report dated July 31, 2024. See “Presentation of Oil and Gas Information”.
(2) Funds flow from operations, operating netback, net debt, cash netback, return on average capital employed, earnings before interest, taxes and depletion, depreciation and accretion (“DD&A”) (“EBITDA”) and EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense, other gains or losses, transaction costs and financial instruments gains or losses (“Adjusted EBITDA”), cash flow and free cash flow are non-GAAP measures and do not have standardized meanings under generally accepted accounting principles in the United States of America (“GAAP”). Cash flow refers to funds flow from operations. Free cash flow refers to funds flow from operations less capital expenditures. Refer to “Non-GAAP Measures” in this press release for descriptions of these non-GAAP measures and, where applicable, reconciliations to the most directly comparable measures calculated and presented in accordance with GAAP.
(3) Gran Tierra’s fourth quarter-to-date 2024 total average differentials are for the period from October 1 to October 31, 2024.
(4) Operating netback as presented is defined as oil sales less operating and transportation expenses. See the table titled Financial and Operational Highlights above for the components of consolidated operating netback and corresponding reconciliation.
(5) Reflects our 1-for-10 reverse stock split that became effective May 5, 2023 and not inclusive of shares of common stock issued in connection with the i3 Energy acquisition on October 31, 2024.
Conference Call Information:
Gran Tierra will host its third quarter 2024 results conference call on Monday, November 4, 2024, at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time. Interested parties may access the conference call by registering at the following link: https://https://register.vevent.com/register/BIc9cc718f582741cbbf0eb2cfe5a231b1. The call will also be available via webcast at www.grantierra.com.
Corporate Presentation:
Gran Tierra’s Corporate Presentation has been updated and is available on the Company website at www.grantierra.com.
Contact Information
For investor and media inquiries please contact:
Gary Guidry
President & Chief Executive Officer
Ryan Ellson
Executive Vice President & Chief Financial Officer
+1-403-265-3221
info@grantierra.com
About Gran Tierra Energy Inc.
Gran Tierra Energy Inc. together with its subsidiaries is an independent international energy company currently focused on oil and natural gas exploration and production in Canada, Colombia and Ecuador. The Company is currently developing its existing portfolio of assets in Canada, Colombia and Ecuador and will continue to pursue additional new growth opportunities that would further strengthen the Company’s portfolio. The Company’s common stock trades on the NYSE American, the Toronto Stock Exchange and the London Stock Exchange under the ticker symbol GTE. Additional information concerning Gran Tierra is available at www.grantierra.com. Except to the extent expressly stated otherwise, information on the Company’s website or accessible from our website or any other website is not incorporated by reference into and should not be considered part of this press release. Investor inquiries may be directed to info@grantierra.com or (403) 265-3221.
Gran Tierra’s Securities and Exchange Commission (the “SEC”) filings are available on the SEC website at sec.gov. The Company’s Canadian securities regulatory filings are available on SEDAR+ at sedarplus.ca and UK regulatory filings are available on the National Storage Mechanism website at data.fca.org.uk.
Forward Looking Statements and Legal Advisories:
This press release contains opinions, forecasts, projections, and other statements about future events or results that constitute forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, and financial outlook and forward looking information within the meaning of applicable Canadian securities laws (collectively, “forward-looking statements”). All statements other than statements of historical facts included in this press release regarding our business strategy, plans and objectives of our management for future operations, capital spending plans and benefits of the changes in our capital program or expenditures, our liquidity and financial condition, and those statements preceded by, followed by or that otherwise include the words “expect,” “plan,” “can,” “will,” “should,” “guidance,” “forecast,” “budget,” “estimate,” “signal,” “progress” and “believes,” derivations thereof and similar terms identify forward-looking statements. In particular, but without limiting the foregoing, this press release contains forward-looking statements regarding: the Company’s leverage ratio target, the Company’s plans regarding strategic investments, acquisitions, including the anticipated benefits and operating synergies expected from the acquisition of i3 Energy, and growth, the Company’s drilling program and capital expenditures and the Company’s expectations of commodity prices, including future gas pricing in Canada, exploration and production trends and its positioning for 2024. The forward-looking statements contained in this press release reflect several material factors and expectations and assumptions of Gran Tierra including, without limitation, that Gran Tierra will continue to conduct its operations in a manner consistent with its current expectations, pricing and cost estimates (including with respect to commodity pricing and exchange rates), the ability of Gran Tierra to successfully integrate the assets and operations of i3 Energy or realize the anticipated benefits and operating synergies expected from the acquisition of i3 Energy, the general continuance of assumed operational, regulatory and industry conditions in Canada, Colombia and Ecuador, and the ability of Gran Tierra to execute its business and operational plans in the manner currently planned.
Among the important factors that could cause our actual results to differ materially from the forward-looking statements in this press release include, but are not limited to: certain of our operations are located in South America and unexpected problems can arise due to guerilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events; global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including inflation and changes resulting from a global health crisis, geopolitical events, including the conflicts in Ukraine and the Gaza region, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries and the resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a prolonged decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict. which could cause further modification of our strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to execute our business plan, which may include acquisitions, and realize expected benefits from current or future initiatives; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of waterflood and multi-stage fracture stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that we do not receive the anticipated benefits of government programs, including government tax refunds; our ability to access debt or equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt; our ability to comply with financial covenants in our indentures and make borrowings under any future credit agreement; and the risk factors detailed from time to time in Gran Tierra’s periodic reports filed with the Securities and Exchange Commission, including, without limitation, under the caption “Risk Factors” in Gran Tierra’s Annual Report on Form 10-K for the year ended December 31, 2023 filed February 20, 2024 and its other filings with the SEC. These filings are available on the SEC website at sec.gov and on SEDAR+ at www.sedarplus.ca.
The forward-looking statements contained in this press release are based on certain assumptions made by Gran Tierra based on management’s experience and other factors believed to be appropriate. Gran Tierra believes these assumptions to be reasonable at this time, but the forward-looking statements are subject to risk and uncertainties, many of which are beyond Gran Tierra’s control, which may cause actual results to differ materially from those implied or expressed by the forward looking statements. The risk that the assumptions on which the 2024 outlook are based prove incorrect may increase the later the period to which the outlook relates. All forward-looking statements are made as of the date of this press release and the fact that this press release remains available does not constitute a representation by Gran Tierra that Gran Tierra believes these forward-looking statements continue to be true as of any subsequent date. Actual results may vary materially from the expected results expressed in forward-looking statements. Gran Tierra disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by applicable law. In addition, historical, current and forward-looking sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future.
Following Gran Tierra’s acquisition of i3 Energy, investors should not rely on Gran Tierra’s previously issued financial and production guidance for 2024, which is no longer applicable on a combined company basis.
Non-GAAP Measures
This press release includes non-GAAP financial measures as further described herein. These non-GAAP measures do not have a standardized meaning under GAAP. Investors are cautioned that these measures should not be construed as alternatives to net income or loss, cash flow from operating activities or other measures of financial performance as determined in accordance with GAAP. Gran Tierra’s method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to similar measures used by other companies. Each non-GAAP financial measure is presented along with the corresponding GAAP measure so as to not imply that more emphasis should be placed on the non-GAAP measure.
Operating netback, as presented, is defined as oil sales less operating and transportation expenses. See the table entitled Financial and Operational Highlights above for the components of consolidated operating netback and corresponding reconciliation.
Return on average capital employed as presented is defined as earnings before interest and taxes ("EBIT"; annualized, if the period is other than one year) divided by average capital employed (total assets minus cash and current liabilities; average of the opening and closing balances for the period).
|
| Three Months Ended
September 30,
|
| Twelve Month Trailing
September 30,
|
| As at September 30,
| Return on Average Capital Employed - (Non-GAAP) Measure ($000s)
|
|
| 2024
|
|
|
| 2024
|
|
|
| 2024
|
| Net Income
|
| $
| 1,133
|
|
| $
| 45,137
|
|
|
| Adjustments to reconcile net income to EBIT:
|
|
|
|
|
|
| Interest Expense
|
|
| 19,892
|
|
|
| 74,503
|
|
|
| Income Tax Expense
|
|
| 20,767
|
|
|
| 34,589
|
|
|
| EBIT
|
| $
| 41,792
|
|
| $
| 154,229
|
|
|
|
|
|
|
|
|
|
| Total Assets
|
|
|
|
|
| $
| 1,533,378
|
| Less Current Liabilities
|
|
|
|
|
|
| 263,492
|
| Less Cash and Cash Equivalents
|
|
|
|
|
|
| 277,645
|
| Capital Employed
|
|
|
|
|
| $
| 992,241
|
|
|
|
|
|
|
|
| Annualized EBIT*
|
| $
| 167,168
|
|
|
|
|
| Divided by Average Capital Employed
|
|
| 992,241
|
|
|
| 992,241
|
|
|
| Return on Average Capital Employed
|
|
| 17
| %
|
|
| 16
| %
|
|
|
*Annualized EBIT was calculated for the three months ended September 30, 2024, by multiplying the quarter-to-date EBIT by 4.
Cash netback as presented is defined as net income or loss adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss and other gain or loss. Management believes that operating netback and cash netback are useful supplemental measures for investors to analyze financial performance and provide an indication of the results generated by Gran Tierra’s principal business activities prior to the consideration of other income and expenses. A reconciliation from net income or loss to cash netback is as follows:
| Three Months Ended
September 30,
|
| Three
Months
Ended
June 30,
|
| Nine Months Ended
September 30,
| Cash Netback - (Non-GAAP) Measure ($000s)
|
| 2024
|
|
| 2023
|
|
|
| 2024
|
|
|
| 2024
|
|
| 2023
|
| Net Income (Loss)
| $
| 1,133
|
| $
| 6,527
|
|
| $
| 36,371
|
|
| $
| 37,426
|
| $
| (13,998
| )
| Adjustments to reconcile net income (loss) to cash netback
|
|
|
|
|
|
|
| DD&A expenses
|
| 55,573
|
|
| 55,019
|
|
|
| 55,490
|
|
|
| 167,213
|
|
| 163,424
|
| Deferred tax expense (recovery)
|
| 5,550
|
|
| 13,990
|
|
|
| (51,361
| )
|
|
| (32,332
| )
|
| 43,242
|
| Stock-based compensation (recovery) expense
|
| (3,145
| )
|
| 1,931
|
|
|
| 6,160
|
|
|
| 6,376
|
|
| 3,748
|
| Amortization of debt issuance costs
|
| 3,109
|
|
| 1,594
|
|
|
| 2,760
|
|
|
| 9,175
|
|
| 3,394
|
| Non-cash lease expense
|
| 1,370
|
|
| 1,235
|
|
|
| 1,381
|
|
|
| 4,164
|
|
| 3,488
|
| Lease payments
|
| (1,171
| )
|
| (676
| )
|
|
| (1,311
| )
|
|
| (3,540
| )
|
| (1,918
| )
| Unrealized foreign exchange gain
|
| (2,081
| )
|
| (266
| )
|
|
| (3,323
| )
|
|
| (7,670
| )
|
| (7,814
| )
| Other gain
|
| —
|
|
| (354
| )
|
|
| —
|
|
|
| —
|
|
| (1,444
| )
| Cash netback
| $
| 60,338
|
| $
| 79,000
|
|
| $
| 46,167
|
|
| $
| 180,812
|
| $
| 192,122
|
|
EBITDA, as presented, is defined as net income or loss adjusted for DD&A expenses, interest expense and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gain or loss, stock-based compensation expense, transaction costs and other gain or loss. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net income or loss to EBITDA and adjusted EBITDA is as follows:
| Three Months Ended
September 30,
|
| Three
Months
Ended
June 30,
|
| Nine Months Ended
September 30,
| EBITDA - (Non-GAAP) Measure ($000s)
|
| 2024
|
|
| 2023
|
|
|
| 2024
|
|
|
| 2024
|
|
| 2023
|
| Net Income (Loss)
| $
| 1,133
|
| $
| 6,527
|
|
| $
| 36,371
|
|
| $
| 37,426
|
| $
| (13,998
| )
| Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA
|
|
|
|
|
|
|
| DD&A expenses
|
| 55,573
|
|
| 55,019
|
|
|
| 55,490
|
|
|
| 167,213
|
|
| 163,424
|
| Interest expense
|
| 19,892
|
|
| 13,503
|
|
|
| 18,398
|
|
|
| 56,714
|
|
| 38,017
|
| Income tax expense (recovery)
|
| 20,767
|
|
| 40,333
|
|
|
| (9,072
| )
|
|
| 29,090
|
|
| 106,948
|
| EBITDA
| $
| 97,365
|
| $
| 115,382
|
|
| $
| 101,187
|
|
| $
| 290,443
|
| $
| 294,391
|
| Non-cash lease expense
|
| 1,370
|
|
| 1,235
|
|
|
| 1,381
|
|
|
| 4,164
|
|
| 3,488
|
| Lease payments
|
| (1,171
| )
|
| (676
| )
|
|
| (1,311
| )
|
|
| (3,540
| )
|
| (1,918
| )
| Foreign exchange (gain) loss
|
| (3,084
| )
|
| 1,717
|
|
|
| (4,413
| )
|
|
| (8,312
| )
|
| 8,126
|
| Stock-based compensation expense
|
| (3,145
| )
|
| 1,931
|
|
|
| 6,160
|
|
|
| 6,376
|
|
| 3,748
|
| Transaction costs
|
| 1,459
|
|
| —
|
|
|
| —
|
|
|
| 1,459
|
|
| —
|
| Other loss (gain)
|
| —
|
|
| (354
| )
|
|
| —
|
|
|
| —
|
|
| (1,444
| )
| Adjusted EBITDA
| $
| 92,794
|
| $
| 119,235
|
|
| $
| 103,004
|
|
| $
| 290,590
|
| $
| 306,391
|
|
Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain, and other gain or loss. Management uses this financial measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. Free cash flow, as presented, is defined as funds flow from operations adjusted for capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net income or loss to both funds flow from operations and free cash flow is as follows:
| Three Months Ended
September 30,
|
| Three
Months
Ended
June 30,
|
| Nine Months Ended
September 30,
| Funds Flow From Operations -
(Non-GAAP) Measure ($000s)
|
| 2024
|
|
| 2023
|
|
|
| 2024
|
|
|
| 2024
|
|
| 2023
|
| Net Income (Loss)
| $
| 1,133
|
| $
| 6,527
|
|
| $
| 36,371
|
|
| $
| 37,426
|
| $
| (13,998
| )
| Adjustments to reconcile net income (loss) to funds flow from operations
|
|
|
|
|
|
|
| DD&A expenses
|
| 55,573
|
|
| 55,019
|
|
|
| 55,490
|
|
|
| 167,213
|
|
| 163,424
|
| Deferred tax expense (recovery)
|
| 5,550
|
|
| 13,990
|
|
|
| (51,361
| )
|
|
| (32,332
| )
|
| 43,242
|
| Stock-based compensation (recovery) expense
|
| (3,145
| )
|
| 1,931
|
|
|
| 6,160
|
|
|
| 6,376
|
|
| 3,748
|
| Amortization of debt issuance costs
|
| 3,109
|
|
| 1,594
|
|
|
| 2,760
|
|
|
| 9,175
|
|
| 3,394
|
| Non-cash lease expense
|
| 1,370
|
|
| 1,235
|
|
|
| 1,381
|
|
|
| 4,164
|
|
| 3,488
|
| Lease payments
|
| (1,171
| )
|
| (676
| )
|
|
| (1,311
| )
|
|
| (3,540
| )
|
| (1,918
| )
| Unrealized foreign exchange gain
|
| (2,081
| )
|
| (266
| )
|
|
| (3,323
| )
|
|
| (7,670
| )
|
| (7,814
| )
| Other loss (gain)
|
| —
|
|
| (354
| )
|
|
| —
|
|
|
| —
|
|
| (1,444
| )
| Funds flow from operations
| $
| 60,338
|
| $
| 79,000
|
|
| $
| 46,167
|
|
| $
| 180,812
|
| $
| 192,122
|
| Capital expenditures
| $
| 52,921
|
| $
| 43,080
|
|
| $
| 61,273
|
|
| $
| 169,525
|
| $
| 179,707
|
| Free cash flow
| $
| 7,417
|
| $
| 35,920
|
|
| $
| (15,106
| )
|
| $
| 11,287
|
| $
| 12,415
|
|
Net debt as of September 30, 2024, was $509 million, calculated using the sum of the aggregate principal amount of 6.25% Senior Notes, 7.75% Senior Notes, and 9.50% Senior Notes outstanding, excluding deferred financing fees, totaling $787 million, less cash and cash equivalents of $278 million.
Presentation of Oil and Gas Information
All reserves value and ancillary information contained in this press release regarding Gran Tierra (not including reserves value and ancillary information regarding i3 Energy) have been prepared by the Company’s independent qualified reserves evaluator McDaniel & Associates Consultants Ltd. (“McDaniel”) in a report with an effective date of December 31, 2023 (the “Gran Tierra McDaniel Reserves Report”) and calculated in compliance with Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”), unless otherwise expressly stated. All reserves value and ancillary information contained in this press release regarding i3 Energy have been prepared by i3 Energy’s independent qualified reserves evaluator GLJ Ltd. (“GLJ”) in a fair market value report with an effective date of July 31, 2024 (the “i3 Energy GLJ Report”) and calculated in compliance with NI 51-101 and COGEH, unless otherwise expressly stated.
Barrel of oil equivalents (“boe”) have been converted on the basis of six thousand cubic feet (“Mcf”) natural gas to 1 bbl of oil. Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of oil as compared with natural gas is significantly different from the energy equivalent of six to one, utilizing a boe conversion ratio of 6 Mcf: 1 bbl would be misleading as an indication of value.
The following reserves categories are discussed in this press release: Proved (“1P”), 1P plus Probable (“2P”) and 2P plus Possible (“3P”) and Proved Developed Producing (“PDP”). Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. Proved developed producing reserves are those proved reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. Certain terms used in this press release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 – Revised Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities (“CSA Staff Notice 51-324”) and/or the COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the case may be.
Estimates of reserves for individual properties may not reflect the same level of confidence as estimates of reserves for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by McDaniel or GLJ in evaluating Gran Tierra’s or i3 Energy’s reserves, respectively, will be attained and variances could be material. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. The reserves information set forth in the Gran Tierra McDaniel Reserves Report and the i3 Energy GLJ Report are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided therein. All reserves assigned in the Gran Tierra McDaniel Reserves Report are located in Colombia and Ecuador and presented on a consolidated basis by foreign geographic area.
Booked drilling locations of i3 Energy disclosed herein are derived from the i3 Energy GLJ Report and account for drilling locations that have associated 2P reserves.
References to a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume. Gran Tierra’s reported production is a mix of light crude oil and medium and heavy crude oil for which there is not a precise breakdown since the Company’s oil sales volumes typically represent blends of more than one type of crude oil. Well test results should be considered as preliminary and not necessarily indicative of long-term performance or of ultimate recovery. Well log interpretations indicating oil and gas accumulations are not necessarily indicative of future production or ultimate recovery. If it is indicated that a pressure transient analysis or well-test interpretation has not been carried out, any data disclosed in that respect should be considered preliminary until such analysis has been completed. References to thickness of “oil pay” or of a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume.
This press release contains certain oil and gas metrics, including operating netback and cash netback, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. These metrics are calculated as described in this press release and management believes that they are useful supplemental measures for the reasons described in this press release.
Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.
References in this press release to IP30, IP90 and other short-term production rates of Gran Tierra are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Gran Tierra. Gran Tierra cautions that such results should be considered to be preliminary.
Disclosure of Reserve Information and Cautionary Note to U.S. Investors
Unless expressly stated otherwise, all estimates of proved, probable and possible reserves and related future net revenue disclosed in this press release have been prepared in accordance with NI 51-101. Estimates of reserves and future net revenue made in accordance with NI 51-101 will differ from corresponding estimates prepared in accordance with applicable SEC rules and disclosure requirements of the U.S. Financial Accounting Standards Board (“FASB”), and those differences may be material. NI 51-101, for example, requires disclosure of reserves and related future net revenue estimates based on forecast prices and costs, whereas SEC and FASB standards require that reserves and related future net revenue be estimated using average prices for the previous 12 months. In addition, NI 51-101 permits the presentation of reserves estimates on a “company gross” basis, representing Gran Tierra's working interest share before deduction of royalties, whereas SEC and FASB standards require the presentation of net reserve estimates after the deduction of royalties and similar payments. There are also differences in the technical reserves estimation standards applicable under NI 51-101 and, pursuant thereto, the COGEH, and those applicable under SEC and FASB requirements.
In addition to being a reporting issuer in certain Canadian jurisdictions, Gran Tierra is a registrant with the SEC and subject to domestic issuer reporting requirements under U.S. federal securities law, including with respect to the disclosure of reserves and other oil and gas information in accordance with U.S. federal securities law and applicable SEC rules and regulations (collectively, “SEC requirements”). Disclosure of such information in accordance with SEC requirements is included in the Company's Annual Report on Form 10-K and in other reports and materials filed with or furnished to the SEC and, as applicable, Canadian securities regulatory authorities. The SEC permits oil and gas companies that are subject to domestic issuer reporting requirements under U.S. federal securities law, in their filings with the SEC, to disclose only estimated proved, probable and possible reserves that meet the SEC's definitions of such terms. Gran Tierra has disclosed estimated proved, probable and possible reserves in its filings with the SEC. In addition, Gran Tierra prepares its financial statements in accordance with United States generally accepted accounting principles, which require that the notes to its annual financial statements include supplementary disclosure in respect of the Company's oil and gas activities, including estimates of its proved oil and gas reserves and a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. This supplementary financial statement disclosure is presented in accordance with FASB requirements, which align with corresponding SEC requirements concerning reserves estimation and reporting. |
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| From: pstad60 | 11/6/2024 5:52:54 PM | | | | | | OilNow articles on recent Touchstone Exploration developments
.
.
Touchstone achieves initial production at Cascadura C well pad in Trinidad
oilnow.gy
.
Primera to drill three wells at Rio Claro license Block onshore Trinidad
oilnow.gy
GLTA ! |
| | Canadian Oil & Gas Companies | Stock Discussion ForumsShare | RecommendKeepReplyMark as Last Read |
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| From: LoneClone | 11/8/2024 2:16:20 PM | | | | | | HEADWATER EXPLORATION ANNOUNCES THIRD QUARTER OPERATING AND FINANCIAL RESULTS, DECLARATION OF QUARTERLY DIVIDEND AND UPDATE TO 2024 GUIDANCE
newswire.ca
News provided by Headwater Exploration Inc. Nov 07, 2024, 17:00 ET
CALGARY, AB, Nov. 7, 2024 /CNW/ - Headwater Exploration Inc. (the "Company" or "Headwater") (TSX: HWX) is pleased to announce its operating and financial results for the three and nine months ended September 30, 2024, declaration of quarterly dividend and update to 2024 guidance. Selected financial and operational information is outlined below and should be read in conjunction with the unaudited condensed interim financial statements and the related management's discussion and analysis ("MD&A"). These filings will be available at www.sedarplus.ca and the Company's website at www.headwaterexp.com.
Financial and Operating Highlights
| Three months ended
September 30,
| Percent
Change
| Nine months ended
September 30,
| Percent
Change
|
| 2024
| 2023
| 2024
| 2023
| Financial (thousands of dollars except share data)
|
|
|
|
|
|
| Sales, net of blending (1) (4)
| 151,740
| 144,003
| 5
| 436,163
| 351,133
| 24
| Adjusted funds flow from operations (2)
| 84,185
| 80,887
| 4
| 248,654
| 206,279
| 21
| Per share - basic (3)
| 0.35
| 0.34
| 3
| 1.05
| 0.88
| 19
| - diluted (3)
| 0.35
| 0.34
| 3
| 1.04
| 0.87
| 20
| Cash flows provided by operating activities
| 95,272
| 85,568
| 11
| 240,721
| 212,626
| 13
| Per share - basic
| 0.40
| 0.36
| 11
| 1.02
| 0.90
| 13
| - diluted
| 0.40
| 0.36
| 11
| 1.01
| 0.90
| 12
| Net income
| 47,634
| 49,677
| (4)
| 139,121
| 110,603
| 26
| Per share - basic
| 0.20
| 0.21
| (5)
| 0.59
| 0.47
| 26
| - diluted
| 0.20
| 0.21
| (5)
| 0.58
| 0.47
| 23
| Capital expenditures (1)
| 58,196
| 70,208
| (17)
| 174,180
| 203,796
| (15)
| Adjusted working capital (2)
|
|
|
| 64,411
| 35,921
| 79
| Shareholders' equity
|
|
|
| 684,486
| 587,380
| 17
| Dividends declared
| 23,767
| 23,638
| 1
| 71,261
| 70,763
| 1
| Per share
| 0.10
| 0.10
| -
| 0.30
| 0.30
| -
| Weighted average shares (thousands)
|
|
|
|
|
|
| Basic
| 237,484
| 236,191
| 1
| 236,285
| 235,305
| -
| Diluted
| 239,735
| 239,167
| -
| 238,427
| 237,683
| -
| Shares outstanding, end of period (thousands)
|
|
|
|
|
|
| Basic
|
|
|
| 237,665
| 236,384
| 1
| Diluted (5)
|
|
|
| 241,115
| 241,175
| -
| Operating (6:1 boe conversion)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Average daily production
|
|
|
|
|
|
| Heavy crude oil (bbls/d)
| 19,718
| 16,902
| 17
| 18,689
| 15,775
| 18
| Natural gas (mmcf/d)
| 3.4
| 6.1
| (44)
| 6.8
| 9.1
| (25)
| Natural gas liquids (bbl/d)
| 64
| 103
| (38)
| 72
| 100
| (28)
| Barrels of oil equivalent (9) (boe/d)
| 20,342
| 18,027
| 13
| 19,890
| 17,398
| 14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Average daily sales (6) (boe/d)
| 20,329
| 17,862
| 14
| 19,850
| 17,331
| 15
|
|
|
|
|
|
|
| Netbacks ($/boe) (3) (7)
|
|
|
|
|
|
| Operating
|
|
|
|
|
|
| Sales, net of blending (4)
| 81.13
| 87.63
| (7)
| 80.19
| 74.22
| 8
| Royalties
| (15.74)
| (16.26)
| (3)
| (14.88)
| (13.06)
| 14
| Transportation
| (5.90)
| (5.32)
| 11
| (5.60)
| (5.43)
| 3
| Production expenses
| (7.46)
| (7.43)
| -
| (7.25)
| (7.11)
| 2
|
|
|
|
|
|
|
|
| Operating netback (3)
| 52.03
| 58.62
| (11)
| 52.46
| 48.62
| 8
| Realized gains on financial derivatives
| 0.18
| 0.18
| -
| 1.04
| 1.66
| (37)
| Operating netback, including financial derivatives (3)
| 52.21
| 58.80
| (11)
| 53.50
| 50.28
| 6
| General and administrative expense
| (1.42)
| (1.52)
| (7)
| (1.46)
| (1.46)
| -
| Interest income and other (8)
| 0.76
| 0.85
| (11)
| 0.84
| 0.98
| (14)
| Current tax expense
| (6.54)
| (8.91)
| (27)
| (7.14)
| (6.20)
| 15
| Settlement of decommissioning liability
| -
| -
| -
| (0.02)
| -
| 100
| Adjusted funds flow netback (3)
| 45.01
| 49.22
| (9)
| 45.72
| 43.60
| 5
|
(1)
| Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
| (2)
| Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
| (3)
| Non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" within this press release.
| (4)
| Total sales are netted with blending expense to compare the realized price to benchmark pricing while transportation expense is shown separately. In the interim financial statements blending expense is recorded within blending and transportation expense.
| (5)
| In-the-money dilutive instruments as at September 30, 2024 includes 0.5 million stock options with a weighted average exercise price of $4.49 and 3.0 million performance share units ("PSU's"). The number of outstanding PSUs has been adjusted for dividends. Restricted Share Units have been excluded as the Company intends to cash settle these awards.
| (6)
| Includes sales of unblended heavy crude oil, natural gas and natural gas liquids. The Company's heavy crude oil sales volumes and production volumes differ due to changes in inventory.
| (7)
| Netbacks are calculated using average sales volumes. For the three months ended September 30, 2024, sales volumes comprised of 19,706 bbs/d of heavy oil, 3.4 mmcf/d of natural gas and 64 bbls/d of natural gas liquids (2023- 16,738 bbls/d, 6.1 mmcf/d and 103 bbls/d). For the nine months ended September 30, 2024, sales volumes comprised of 18,648 bbls/d of heavy oil, 6.8 mmcf/d of natural gas and 72 bbls/d of natural gas liquids (2023- 15,709 bbls/d, 9.1 mmcf/d and 100 bbls/d).
| (8)
| Excludes unrealized foreign exchange gains/losses, accretion on decommissioning liabilities, interest on lease liability and interest on repayable contribution.
| (9)
| See "Barrels of Oil Equivalent".
|
HIGHLIGHTS FOR THREE MONTHS ENDED SEPTEMBER 30, 2024
- Achieved record production averaging 20,342 boe/d (consisting of 19,718 bbls/d heavy oil, 3.4 mmcf/d natural gas and 64 bbls/d natural gas liquids), representing an increase of 13% from the third quarter of 2023.
- Realized adjusted funds flow from operations (1) of $84.2 million ($0.35 per share basic (2)) and cash flows from operating activities of $95.3 million ($0.40 per share basic).
- Achieved an operating netback, including financial derivatives (2) of $52.21/boe and an adjusted funds flow netback (2) of $45.01/boe.
- Achieved net income of $47.6 million ($0.20 per share basic) equating to $25.47/boe.
- Executed a $58.2 million capital expenditure (3) program drilling 18 multi-lateral crude oil wells and 2 injection wells in Marten Hills West and multi-lateral exploration tests in both Little Horse and Clay at a 100% success rate.
- Generated free cash flow (3) of $26.0 million.
- Returned $23.8 million, or $0.10/common share, to shareholders through Headwater's quarterly dividend.
- As at September 30, 2024, Headwater had adjusted working capital (1) of $64.4 million, working capital of $74.9 million and no outstanding bank debt.
(1)
| Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
| (2)
| Non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" within this press release.
| (3)
| Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
|
OPERATIONS UPDATE
Marten Hills West
In the third quarter of 2024, Headwater drilled 18 successful multi-lateral wells in Marten Hills West.
The Clearwater E pool was discovered with our first test in January 2024. Inclusive of three pool extension wells drilled in the third quarter of 2024, production associated with the Clearwater E pool has risen from zero in January 2024 to current rates exceeding 750 bbls/d. The six producing wells have tested the regional extent of the pool which is now estimated to exist on over 50 sections of Headwater lands.
Select results from the recently drilled Clearwater E wells include the 00/13-07-075-01W5 well, the most southern Clearwater E extension well which achieved a 30-day initial production rate of 240 bbls/d of 21 API oil. The 04/16-13-075-02W5 well, the most western Clearwater E extension well achieved a 30-day initial production rate of 209 bbls/d of 21 API oil and the 00/13-16-075-01W5 well, our most eastern Clearwater E extension well provided strong reservoir indications while drilling and is currently recovering load fluid.
Reservoir and oil quality from the Clearwater E creates a highly amenable environment for secondary recovery. As a result, Headwater has initiated two secondary recovery pilots. The 03/16-07-075-01W5 well has been on injection for 60 days at strong injection rates and the 05/16-07-075-01W5 well was commissioned for injection late in October. Both of these waterfloods are designed as lateral waterfloods similar to those initiated by our peers in the Nipisi area. Expansion of the waterflood in the Clearwater E is expected to occur concurrently with the development of the pool.
The Clearwater sandstone, the primary producing zone in Marten Hills West, continues to produce at rates in excess of 11,000 bbls/d. The third quarter was also characterized by additional successful step outs in this zone. The 02/12-18-075-01W5 well achieved a 30-day initial production rate of 300 bbls/d and the 00/11-10-075-01W5 well achieved a 15-day initial production rate of 250 bbls/d, providing further validation of the Clearwater sandstone eastern boundary expansion.
Results from the Marten Hills West first full section secondary recovery pilot continues to show strong initial performance. Injection rates were increased from 300 bbls/d in March 2024 to the current rates of approximately 900 bbls/d resulting in an immediate response in the gas oil ratio which have decreased by over 50% in the last seven months. Oil rates within the pilot continue to be stable at 260 bbls/d, with early indications of improving oil rates in some wells within the pilot. Headwater has initiated the drilling of our second full section secondary recovery pilot at 22-75-02W5, which is expected to be commissioned later in the fourth quarter of 2024.
Marten Hills Core
Secondary recovery in the Marten Hills Core continues to show tremendous results. Despite the decline associated with currently unsupported sections, the core area's production has remained flat at rates in excess of 7,000 bbls/d for the last 11 months. Headwater is currently in the process of converting two additional sections to secondary recovery. By year-end, 8 of the 9 sections will be supported by injection.
To date, it is estimated that the implementation of secondary recovery has reduced our corporate decline rates by approximately 5% and maintenance capital requirements by approximately $25 million per year.
Greater Nipisi
Headwater is excited to report results from our first exploration well targeting the Bluesky formation on the 49 section Little Horse area of Greater Nipisi. The 00/16-29-076-14W5 well, a 12-leg multi-lateral, has achieved a 30-day initial production rate of 205 bbls/d of 15 API oil. This successful exploration test validates a new Bluesky pool estimated to be 15-20 sections in size. A follow-up exploration well will test an additional identified Bluesky prospect on the 20 section northern block in the first quarter of 2025.
Handel Saskatchewan
Headwater is currently conducting a 3D seismic shoot over the Handel lands which is anticipated to finish prior to year-end. Data will be processed in the first quarter of 2025, establishing the next multi-lateral targets expected to be drilled in the second half of 2025.
Clay
At Clay, in the greater Bonnyville area, Headwater drilled and recently brought on production a 7-leg multi-lateral well targeting the McLaren formation. The 00/04-15-059-13W4 well achieved a 30-day initial production rate of 205 bbls/d of 16 API oil.
Exploration and Land Update
With the addition of 10.9 net sections of Clearwater land in the third quarter, Headwater now has a total of 539 sections in the Clearwater fairway. Additionally, we have 192.5 net sections of land in oil prospective fairways outside of the Clearwater fairway.
McCully Update
McCully is scheduled to be placed back on production at the beginning of December. We have hedged approximately 83% of McCully's estimated December 2024 to April 2025 production at a price of Cdn$11.58/mmbtu. The aggressive hedging profile used at McCully provides consistency in the free cash flow (1) which is expected to be approximately $12 million over this winter season (2).
(1)
| Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
| (2)
| McCully's winter season is estimated to be December 2024 to April 2025.
|
2024 GUIDANCE UPDATE
Headwater has increased its 2024 annual average production guidance from 20,000 to 20,250 boe/d. Given strong results over the past 2 years, the Board of Directors has approved a $20 million increase to the Company's 2024 capital expenditures to accelerate secondary recovery projects in Marten Hills West. This capital will continue to stabilize and add duration to corporate cash flows. The Company intends to release its 2025 capital budget in December.
|
| 2024 Guidance as
released on March 9, 2024
| Updated 2024
Guidance
|
|
|
|
| 2024 annual average production (boe/d)
Fourth Quarter daily production
|
| 20,000
21,500
| 20,250
21,500
| Capital expenditures (1)
|
| $200 million
| $220 million
| Comprised of:
|
|
|
| Development capital
|
| $135 million
| $135 million
| Land
|
| $20 million
| $25 million
| Exploration and enhanced oil recovery
|
| $45 million
| $60 million
| WTI
|
| US$76.25/bbl
| US$75.33/bbl
| WCS
|
| Cdn$83.88/bbl
| Cdn$82.98/bbl
| Adjusted funds flow from operations (2)
|
| $319 million
| $326 million
| Exit adjusted working capital (2)(3)
|
| $86 million
| $60 million
| Quarterly dividend
|
| $0.10/common share
| $0.10/common share
|
(1)
| Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
| (2)
| Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
| (3)
| Reflects the Board approved change to cash settle the Company's outstanding performance share units.
| (4)
| For assumptions utilized in the above guidance see "Future Oriented Financial Information" within this press release.
|
FOURTH QUARTER DIVIDEND
The Board of Directors of Headwater has declared a quarterly cash dividend to shareholders of $0.10 per common share payable on January 15, 2025, to shareholders of record at the close of business on December 31, 2024. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
Headwater remains committed to delivering long term top quartile returns through growth and return of capital. Additional corporate information can be found in the Company's corporate presentation and on Headwater's website at www.headwaterexp.com.
FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. The use of any of the words "guidance", "initial", "anticipate", "scheduled", "can", "will", "prior to", "estimate", "believe", "potential", "should", "unaudited", "forecast", "future", "continue", "may", "expect", "project", and similar expressions are intended to identify forward-looking statements. The forward-looking statements contained herein, include, without limitation: expectations that the Company will cash settle its restricted share units; the Company's 2024 guidance related to expected annual average production, fourth quarter daily production; capital expenditures and the breakdown thereof and the expectation that this capital will continue to stabilize and add duration to corporate cash flows, adjusted funds flow from operations, dividends and exit adjusted working capital and the expectation to cash settle its performance share units, and the expectation that the increased capital expenditures will be used to accelerate the implementation of additional secondary recovery; the estimated size of certain of the Company's pools; the expectation that the expansion of the waterflood in the Clearwater E is expected to occur concurrently with the development of the pool; the expectation that the secondary pilot of 22-75-02W5 will be commissioned later in the fourth quarter of 2024; the expectation that the Company's 2025 budget will be released in December; the expectation that secondary development will continue to decrease corporate decline rates and maintenance capital requirements; anticipated reductions in decline rates and maintenance capital requirements as a result of the implementation of secondary recovery at Marten Hills Core; the expectation that a follow-up exploration well will test an additional identified Bluesky prospect on the 20 section northern block in the first quarter of 2025; the expectation that the Company will complete a 3D seismic shoot in Handel Saskatchewan prior to year-end and that data will be processed in the first quarter of 2025, establishing the next multi-lateral targets expected to be drilled in the second half of 2025; the expectation around timing of the McCully startup and the expectation that it will generate $12 million of free cash flow over the winter season; the anticipated terms of the Company's quarterly dividend, including its expectation that it will be designated as an "eligible dividend"; and the expectation that Headwater is committed to delivering long term top quartile returns through growth and return of capital. The forward-looking statements contained herein are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning the success of optimization and efficiency improvement projects, the availability of capital, current legislation, receipt of required regulatory approvals, the success of future drilling, development and waterflooding activities, the performance of existing wells, the performance of new wells, Headwater's growth strategy, general economic conditions, availability of required equipment and services, prevailing equipment and services costs, prevailing commodity prices. Although the Company 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 the Company 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; risks associated with wildfires in areas in which the Company operates including safety of personnel, asset integrity and potential disruption of operations which could affect the Company's results, business, financial conditions or liquidity; disruptions to the Canadian and global economy resulting from major public health events, the Russian-Ukrainian war and the middle-eastern conflict involving various nations and the impact on the global economy and commodity prices; the impacts of inflation and supply chain issues and steps taken by central banks to curb inflation; pandemics, war, terrorist events, political upheavals and other similar events; events impacting the supply and demand for oil and gas including actions taken by the OPEC + group; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks); commodity price and exchange rate fluctuations; changes in legislation affecting the oil and gas industry; uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the risk that Headwater's 2024 operating and financial results may not be consistent with its expectations; the risk that Headwater may not be opportunistic in future accretive acquisitions, land expansion and exploration; the risk that Headwater may not deliver long term top quartile returns through growth and return of capital; the risk that the Company's additional secondary recovery may not lead to the benefits anticipated; and the risk that the Company's pools may be smaller than anticipated. Refer to Headwater's most recent Annual Information Form dated March 7, 2024, on SEDAR+ at www.sedarplus.ca, and the risk factors contained therein.
FUTURE ORIENTED FINANCIAL INFORMATION: This press release contains information that may be considered a financial outlook or future-oriented financial information under applicable securities laws including: the Company's 2024 guidance related to capital expenditures and the breakdown thereof, adjusted funds flow from operations, dividends and exit adjusted working capital; the expectation that the McCully startup will generate $12 million of free cash flow over the winter season; and the anticipated terms of the Company's quarterly dividend, including its expectation that it will be designated as an "eligible dividend". Any financial outlook or future oriented financial information in this press release, as defined by applicable securities legislation, has been approved by management of the Company as of the date hereof. Readers are cautioned that any such future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information as to the anticipated results of its proposed business activities for 2024 has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. The assumptions used in the 2024 guidance include: annual average production of 20,250 boe/d, WTI of US$75.33/bbl, WCS of Cdn$82.98/bbl, AGT US$4.60/mmbtu, AECO of Cdn$1.46/GJ, foreign exchange rate of Cdn$/US$ of 0.73, blending expense of WCS less $2.20, royalty rate of 19.0%, operating and transportation costs of $13.45/boe, G&A and interest income and other expense of $1.30/boe and cash taxes of $6.85/boe. The AGT price is the average price for the winter producing months in the McCully field which include January to April and November to December. Q4 2024 production guidance comprised of: 20,250 bbls/d of heavy oil, 40 bbls/d of natural gas liquids and 7.3 mmcf/d of natural gas. 2024 annual production guidance comprised of: 19,051 bbls/d of heavy oil, 64 bbls/d of natural gas liquids and 7.1 mmcf/d of natural gas.
DIVIDEND POLICY: The amount of future cash dividends paid by the Company, if any, will be subject to the discretion of the Board of Directors of the Company and may vary depending on a variety of factors and conditions existing from time to time, including, among other things, adjusted funds flow from operations, fluctuations in commodity prices, production levels, capital expenditure requirements, acquisitions, debt service requirements and debt levels, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends. Depending on these and various other factors, many of which will be beyond the control of the Company, the Board will adjust the Company's dividend policy from time to time and, as a result, future cash dividends could be reduced or suspended entirely.
BARRELS OF OIL AND CUBIC FEET OF NATURAL GAS EQUIVALENT: The term "boe" (or barrels of oil equivalent) and "Mcf" (or thousand cubic feet of natural gas equivalent) may be misleading, particularly if used in isolation. A boe and Mcf conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (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. Additionally, 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 ratio of 6:1 may be misleading as an indication of value.
INITIAL PRODUCTION RATES: References in this press release to IP rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. All IP rates presented herein represent the results from wells after all "load" fluids (used in well completion stimulation) have been recovered. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary.
NON-GAAP AND OTHER FINANCIAL MEASURES
In this press release, we use various non-GAAP and other financial measures to analyze operating performance and financial position. These non-GAAP and other financial measures do not have standardized meanings prescribed under IFRS and therefore may not be comparable to similar measures presented by other issuers. The term cash flow in this press release is equivalent to adjusted funds flow from operations.
Non-GAAP Financial Measures
Total sales, net of blending
Management utilizes total sales, net of blending expense to compare realized pricing to benchmark pricing. It is calculated by deducting the Company's blending expense from total sales. In the interim financial statements blending expense is recorded within blending and transportation expense.
| Three months ended
September 30,
| Nine months ended
September 30,
|
| 2024
| 2023
| 2024
| 2023
|
| (thousands of dollars)
| (thousands of dollars)
| Total sales
| 158,382
| 149,632
| 456,697
| 372,808
| Blending expense
| (6,642)
| (5,629)
| (20,534)
| (21,675)
| Total sales, net of blending expense
| 151,740
| 144,003
| 436,163
| 351,133
|
Capital expenditures
Management utilizes capital expenditures to measure total cash capital expenditures incurred in the period. Capital expenditures represents capital expenditures – exploration and evaluation and capital expenditures – property, plant and equipment in the statement of cash flows in the Company's interim financial statements.
| Three months ended
September 30,
| Nine months ended
September 30,
|
| 2024
| 2023
| 2024
| 2023
|
| (thousands of dollars)
| (thousands of dollars)
| Cash flows used in investing activities
| 63,136
| 62,030
| 180,920
| 188,998
| Proceeds from government grant
| -
| -
| 354
| -
| Change in non-cash working capital
| (4,940)
| 8,178
| (7,094)
| 14,798
| Capital expenditures
| 58,196
| 70,208
| 174,180
| 203,796
|
Free cash flow
Management utilizes free cash flow to assess the amount of funds available for future capital allocation decisions. It is calculated as adjusted funds flow from operations net of capital expenditures before dividends.
| Three months ended
September 30,
|
| Nine months ended
September 30,
|
| 2024
| 2023
|
| 2024
| 2023
|
| (thousands of dollars)
|
| (thousands of dollars)
| Adjusted funds flow from operations
| 84,185
| 80,887
|
| 248,654
| 206,279
| Capital expenditures
| (58,196)
| (70,208)
|
| (174,180)
| (203,796)
| Free cash flow
| 25,989
| 10,679
|
| 74,474
| 2,483
|
Capital Management Measures
Adjusted funds flow from operations
Management considers adjusted funds flow from operations to be a key measure to assess the Company's management of capital. Adjusted funds flow from operations is an indicator as to whether adjustments are necessary to the level of capital expenditures. For example, in periods where adjusted funds flow from operations is negatively impacted by reduced commodity pricing, capital expenditures may need to be reduced or curtailed to preserve the Company's capital and dividend policy. Management believes that by excluding the impact of changes in non-cash working capital and adjusting for current income taxes in the period, adjusted funds flow from operations provides a useful measure of Headwater's ability to generate the funds necessary to manage the capital needs of the Company.
| Three months ended
September 30,
| Nine months ended
September 30,
|
| 2024
| 2023
| 2024
| 2023
|
| (thousands of dollars)
| (thousands of dollars)
| Cash flows provided by operating activities
| 95,272
| 85,568
| 240,721
| 212,626
| Changes in non–cash working capital
| (9,092)
| 5,618
| (2,678)
| (1,663)
| Current income taxes
| (12,223)
| (14,647)
| (38,848)
| (29,322)
| Current income taxes paid
| 10,228
| 4,348
| 49,459
| 24,638
| Adjusted funds flow from operations
| 84,185
| 80,887
| 248,654
| 206,279
|
Adjusted working capital
Adjusted working capital is a capital management measure which management uses to assess the Company's liquidity. Financial derivative receivable/liability have been excluded as these contracts are subject to a high degree of volatility prior to settlement and relate to future production periods. Financial derivative receivable/liability are included in adjusted funds flow from operations when the contracts are ultimately realized. Management has included the effects of the repayable contribution to provide a better indication of Headwater's net financing obligations.
|
|
| As at
September 30, 2024
| As at
December 31, 2023
|
|
|
|
|
| (thousands of dollars)
| Working capital
|
|
| 74,925
| 78,610
| Repayable contribution
|
|
| (10,713)
| (11,405)
| Financial derivative receivable
|
|
| (921)
| (3,758)
| Financial derivative liability
|
|
| 1,120
| 79
| Adjusted working capital
|
|
| 64,411
| 63,526
|
Non-GAAP Ratios
Adjusted funds flow netback, operating netback and operating netback, including financial derivatives
Adjusted funds flow netback, operating netback and operating netback, including financial derivatives are non-GAAP ratios and are used by management to better analyze the Company's performance against prior periods on a more comparable basis.
Adjusted funds flow netback is defined as adjusted funds flow from operations divided by sales volumes in the period.
Operating netback is defined as sales less royalties, transportation and blending costs and production expense divided by sales volumes in the period. Sales volumes exclude the impact of purchased condensate and butane. Operating netback, including financial derivatives is defined as operating netback plus realized gains (losses) on financial derivatives.
Adjusted funds flow from operations per share
Adjusted funds flow from operations per share is a non-GAAP ratio and is used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow per share is calculated as adjusted funds flow from operations divided by weighted average shares outstanding on a basic or diluted basis.
Supplementary Financial Measures
Per boe numbers
This press release represents various results on a per boe basis including sales, net of blending boe, realized gains (losses) on financial derivatives per boe, royalty expense per boe, transportation expense per boe, production expense per boe, general and administrative expenses per boe, interest income and other expense per boe, current taxes per boe, settlement of decommissioning liability expense per boe and net income per boe. These figures are calculated using sales volumes.
SOURCE Headwater Exploration Inc.
 FOR FURTHER INFORMATION PLEASE CONTACT: HEADWATER EXPLORATION INC.: Mr. Neil Roszell, P. Eng., Executive Chairman; HEADWATER EXPLORATION INC.: Mr. Jason Jaskela, P.Eng., President and Chief Executive Officer; HEADWATER EXPLORATION INC.: Ms. Ali Horvath, CPA, CA, Chief Financial Officer, info@headwaterexp.com, (587) 391-3680
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| To: LoneClone who wrote (24730) | 11/8/2024 2:29:07 PM | | From: LoneClone | | | | In response to HWX's quarterlies, BMO released a new analyst report that frequently used the word 'encouraging' but kept them at Outperform with a target of $10.
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| To: pstad60 who wrote (24727) | 11/11/2024 10:29:56 AM | | From: pstad60 | | | | Touchstone Exploration Announces Cascadura Well Test Results
CALGARY, AB / ACCESSWIRE / November 11, 2024 / Touchstone Exploration Inc. ("Touchstone", "we", "our" or the "Company") (TSX:TXP)(LSE:TXP) announces the completion of Cascadura-2ST1 and Cascadura-3ST1 well testing.
Highlights
- Cascadura-2ST1 Well: during an extended 48-hour test, Cascadura-2ST1 produced an average rate of approximately 4,950 boe/d, consisting of 26.4 MMcf/d of natural gas and 547 bbls/d of NGLs.
- Fluid Analysis for Cascadura-2ST1: initial field analysis shows the presence of liquids-rich natural gas with no produced water, similar to the characteristics of the Cascadura-1ST1 well.
- Cascadura-3ST1 Well: over a 68-hour testing period, Cascadura-3ST1 achieved an average production rate of approximately 1,100 boe/d, including 786 bbls/d of crude oil and 1.9 MMcf/d of natural gas.
- Fluid Analysis for Cascadura-3ST1: field assessments indicate medium API gravity crude oil with a 2 percent water cut, along with liquids-rich natural gas.
Production Status: the Cascadura-2ST1 well is currently on continuous production to the Cascadura natural gas processing facility, and the Cascadura-3ST1 well is scheduled to commence permanent production within the next two days.
Paul R. Baay, President and Chief Executive Officer, commented:
"These encouraging well test results not only validate our geological models but also underscore the potential of the Cascadura field. With critical infrastructure in place between the wells, we are well-positioned to drill additional wells to further develop the field.
The Cascadura-2ST1 well test results are similar to those of Cascadura-1ST1, and the well is located at the boundary of our reserves booking. The Cascadura-3ST1 well test results are exceptionally promising, as they unlock a new oil and natural gas play on the eastern side of Fault C, extending into the recently acquired Rio Claro block. On a per barrel equivalent basis, oil currently generates nearly five times the revenue of natural gas, and with a 12.5 percent royalty on the block and anticipated operating expenses below our corporate average, the play offers strong cash flow generating capabilities.
Together, these wells represent a material increase to our base production, reinforce our development strategy and open the door to a new oil play."
Cascadura-2ST1 Testing
Cascadura-2ST1 production testing commenced on November 2, 2024, with flow tests spanning a total of 82 hours, comprised of an initial clean-up flow period, followed by an initial shut-in period and a four-step rate test, including a 48-hour extended flow test. All production accumulated during well testing was processed for sales at the Cascadura natural gas processing facility.
During the 48-hour extended portion of the flow test, the well produced at an average rate of approximately 4,950 boe/d (89 percent natural gas), including 26.4 MMcf/d of natural gas and an estimated 547 bbls/d of NGLs. The bottom hole flowing pressure of the well during this stage of testing averaged 3,497 psi through a 64 percent choke, representing a 15 percent reservoir pressure drawdown.
During testing, Cascadura-2ST1 yielded 44-degree API gravity NGLs at an average ratio of approximately 21 barrels of NGLs per MMcf of natural gas produced. Field analysis of the produced gas indicated liquids rich natural gas. Additional testing of fluid samples will be conducted to accurately assess the natural gas and associated liquids composition as well as the phase behaviour of the fluids within the reservoir.
The well was shut-in for a pressure build-up survey between November 6, 2024 and November 9, 2024 with further analysis to be conducted in identifying reservoir continuity.
On November 9, 2024 the Cascadura-2ST1 well was placed on continuous production at a choke restricted initial natural gas rate of approximately 20 MMcf/d and associated NGLs. This initial choke setting was selected based on well test analysis and is designed to maximize the ultimate recovery of both natural gas and NGLs from this section of the reservoir, ensuring optimal long-term performance.
Cascadura-3ST1 Testing
Cascadura-3ST1 flow testing commenced on November 6, 2024, with all production accumulated during testing processed for sales at the Cascadura natural gas processing facility.
During the 68-hour flow test, the well produced at an average rate of approximately 1,100 boe/d (71 percent oil), including an estimated 786 bbls/d of oil and 1.9 MMcf/d of natural gas. The wellhead flowing pressure during the flow test averaged 1,122 psi through choke settings of 25 percent to 35 percent, representing a 65 percent wellhead pressure drawdown.
During testing, Cascadura-3ST1 yielded 29-degree API gravity oil with a 2 percent water cut, as well as liquids rich natural gas. Additional testing of fluid samples will be conducted to accurately assess the liquids and natural gas compositions.
The well is currently shut-in for a pressure build-up survey with further analysis to be conducted in identifying reservoir parameters and bottom hole reservoir performance. Touchstone intends to place the Cascadura-3ST1 on continuous production over the next two days at a choke restricted initial rate of approximately 600 to 700 bbls/d of oil in order to optimize the well's long-term production potential.
Cascadura-3ST1 openhole wireline logs also indicate an additional unperforated sand with over 24 feet of net hydrocarbon pay. This sand is located at depths between 5,816 to 5,840 feet in the well, uphole of the current production zone. Given the strong flow test results from the well, this interval offers a potential future development opportunity for the Company to pursue.
Touchstone Exploration Inc.
Touchstone Exploration Inc. is a Calgary, Alberta based company engaged in the business of acquiring interests in petroleum and natural gas rights and the exploration, development, production and sale of petroleum and natural gas. Touchstone is currently active in onshore properties located in the Republic of Trinidad and Tobago. The Company's common shares are traded on the Toronto Stock Exchange and the AIM market of the London Stock Exchange under the symbol "TXP". For further information about Touchstone, please visit our website at www.touchstoneexploration.com or contact:
Mr. Paul Baay, President and Chief Executive Officer
Mr. Brian Hollingshead, Executive Vice President Engineering and Business Development
Tel: +1 (403) 750-4405
Advisories
Working Interest
Touchstone has an 80 percent operating working interest in the Cascadura field, which is located on the Ortoire block onshore in the Republic of Trinidad and Tobago. Heritage Petroleum Company Limited holds the remaining 20 percent working interest. All production figures disclosed herein are gross volumes.
Forward-Looking Statements
The information provided in this news release contains certain forward-looking statements and information (collectively, "forward-looking statements") within the meaning of applicable securities laws. Such forward-looking statements include, without limitation, forecasts, estimates, expectations and objectives for future operations that are subject to assumptions, risks and uncertainties, many of which are beyond the control of the Company. Forward-looking statements are statements that are not historical facts and are generally, but not always, identified by the words "expect", "believe", "intend", "estimate", "potential", "growth", "long-term", "anticipate", "forecast" and similar expressions, or are events or conditions that "will", "would", "could" or "should" occur or be achieved. The forward-looking statements contained in this news release speak only as of the date hereof and are expressly qualified by this cautionary statement.
Specifically, this news release includes, but is not limited to, forward-looking statements relating to the Company's business plans, strategies, priorities and development plans; expectations of future production rates from the Cascadura-2ST1 and Cascadura-3ST1 wells and the timing thereof; the quality and quantity of prospective hydrocarbon accumulations based on openhole wireline logs, including the potential uphole zone in Cascadura-3ST1; the Company's expectation of drilling additional wells in the Casacdura field, including the locations and timing thereof; anticipated liquids operating expenses from Cascadura-3ST1; and the Company's expectation of a new oil play, including its ability to generate future cash flows. The Company's actual decisions, activities, results, performance, or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Touchstone will derive from them.
Although the Company 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 the Company 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. Certain of these risks are set out in more detail in the Company's 2023 Annual Information Form dated March 20, 2024 which is available under the Company's profile on SEDAR+ ( www.sedarplus.ca) and on the Company's website ( www.touchstoneexploration.com). The forward-looking statements contained in this news release are made as of the date hereof, and except as may be required by applicable securities laws, the Company assumes no obligation or intent to update publicly or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.
Oil and Natural Gas Measures
Where applicable, natural gas has been converted to barrels of oil equivalent (boe) based on six thousand cubic feet (Mcf) to one barrel (bbl) of oil. The barrel of oil equivalent rate is based on an energy equivalent conversion method primarily applicable at the burner tip and given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. This conversion factor is an industry accepted norm and is not based on either energy content or prices.
Abbreviations
bbls(s) barrel(s)
NGL(s) natural gas liquid(s)
bbls/d barrels per day
psi pounds per square inch
boe barrels of oil equivalent
API American Petroleum Institute
boe/d barrels of oil equivalent per day
MMcf million cubic feet
MMcf/d million cubic feet per day
Source: accesswire.com
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