Condor Energy Ltd (ASX: CND) (Condor or the Company) is pleased to advise that Quantitative Interpretation (QI) and AVO studies on the legacy 3,800km2 of 3D seismic data covering most of the Company’s Tumbes Technical Evaluation Agreement (TEA or Block) have potentially identified a highly porous sandstone fairway spanning the Raya Prospect, significantly enhancing the probability of success.
Highlights
Figure 1 – Peru TEA with Prospects and areas selected for 3D seismic reprocessing.
The Raya Prospect is defined as a structural high against an east-west fault within the Zorritos Formation, the primary reservoir in the basin, with a combined 46km2 structural and stratigraphic trap with shales overlying the Zorritos Unconformity providing a regional seal1 (Figure 2).
Figure 2 – Raya structure map and illustrative seismic sections.
The Company notes that results from the adjacent Delphin and Barracuda wells confirm the presence of oil charge in the area and, in order to determine resevoir quality, has conducted Quantitative Interpretation (QI) studies of the seismic data covering the Raya prospect.
eSeis Inc., a leading Houston-based QI company, has provided LithSeis and Amplitude Versus Offset (AVO) volumes over the entire 3D data set.
The LithSeis cube, although uncalibrated by well data, is a pre-stack seismic-based petrophysical analysis that yields lithology, porosity, and possible hydrocarbon fill. In the LithSeis section (Figure 3b), yellow colours are interpreted to represent porous sandstones, with red reflectors interpreted to represent very high porosity and/or where hydrocarbons are present. In this case, several layers of high porosity at the top of potential reservoir zones (such as layer SC 1) are evident.
The AVO sections illustrate the responses of seismic reflections to increasing angles of offset and uses a colour bar to differentiate between the five commonly recognised classes of AVO responses; in this area, Class 2 or Class 3 responses are of particular interest as they may be indicative of a hydrocarbon- filled reservoir (either gas or oil).
The highly encouraging culmination of these analyses are the mapped responses of LithSeis and AVO across the SC 1 layer (Figure 4). The strong and consistent LithSeis response suggests the presence of a highly porous sandstone fairway running NE-SW across the Raya prospect, potentially derived from one of the feeder systems identified during field mapping.
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This article includes content from Condor Energy, licensed for the purpose of publishing on Investing News Australia. This article does not constitute financial product advice. It is your responsibility to perform proper due diligence before acting upon any information provided here. Please refer to our full disclaimer here.
Condor Energy (ASX:CND) is an Australia-based oil and gas exploration company focused on developing its recently acquired Tea LXXXVI oil and gas block in Peru, located in the Tumbes basin and near the prolific Talara basin. The project’s hydrocarbon exploration potential leverages Peru’s long history as an oil and gas producer dating back to the late 19th century when the country drilled its first well more than 150 years ago.
Hydrocarbon fields in the Tumbes and Talara basins have contributed over 1.4 billion barrels of domestic oil production and 1.7 trillion cubic feet (TCF) of natural gas production. The Talara basin itself has cumulatively produced more than 1.6 billion barrels of oil and is surrounded by multiple historic and currently producing oil and gas fields.
Condor Energy’s Tea LXXXVI project is the result of a technical evaluation agreement (TEA) with the Peruvian National Agency of Hydrocarbons (Perupetro), which provides Condor Energy and its partner, US-based oil and gas exploration company Jaguar Exploration, the exclusive right for greenfield exploration activities over the TEA area. Condor Energy holds an 80-percent interest in the asset with the remaining 20 percent held by Jaguar.
The project comprises a 4,858-square-kilometer oil and gas block in proven offshore hydrocarbon-bearing basins in Peru, including the prolific Talara basin. Offshore, Peru remains dramatically underexplored and has immense potential for hydrocarbon plays.
Considering the block's potential, Condor Energy has appointed a world-class technical team with more than 200 years of collective experience to develop the TEA LXXXVI asset. Several of the newly appointed team members have previously worked on the area covered by Condor Energy, which should help in fast-tracking the development of the block. The team comprises proven oil finders with collective discoveries of more than 480 million barrels of oil equivalent of 2P reserves and more than 400 million barrels of oil equivalent in contingent resources in Peru and Colombia.
The experience of working in the TEA LXXXVI property and surrounding fields will be vital for Condor Energy to expedite the understanding and evaluation of the asset.
This oil and gas block is located on the northwest coast of Peru in the Tumbes basin, in water depths that range from 100 meters to 1,500 meters. The project spans 4,858 square kilometers and is surrounded by historical and current producing oil and gas fields. The block includes the Corvina oil field which generated past production rates of up to 4,000 barrels of light oil per day. In the south is the Talara basin, which is one of the most productive basins in Peru having produced more than 1.6 billion barrels of oil. To the southeast is the Alto-Pena Negra oil field, one of Peru’s most productive fields, currently producing around 3,000 barrels of oil per day and with a total historical production of more than 143 million barrels of oil.
The project benefits from excellent infrastructure, including a refinery only 70 kilometers away.
Matt Ireland, a partner at Steinepreis Paganin, is a highly experienced corporate and commercial lawyer with extensive experience in corporate governance and compliance matters as well as in mining and oil & gas transactions including joint venture agreements, M&A transactions, capital raisings and asset acquisitions/disposals. Ireland graduated from Murdoch University with a Bachelor of Laws and a Bachelor of Commerce in 2002 and was admitted to the Supreme Court of New South Wales in 2003 and the Supreme Court of Western Australia in 2004.
Serge Hayon is an experienced reservoir engineer and petroleum geologist with broad exposure to working with and managing multi-disciplinary teams primarily focused on South East Asia, the Americas and Australia. Hayon has a Bachelor of Science in Geology (Honours) and an MEngSc in Petroleum Engineering from Curtin University.
Hayon worked for Murphy Oil Corporation for 20 years including most recently as general director / country manager Vietnam during which time he was in charge of the overall management of the Asia business including establishing Murphy’s entry into and securing Final Investment Decision on the Lac Da Vang oilfield, Vietnam. Hayon has delivered projects encompassing the complete lifecycle from exploration, discovery, appraisal to first oil and production of large oil and gas assets.
Scott Macmillan is the managing director and founder of Invictus Energy Limited (ASX:IVZ) which, since listing on the ASX in 2018, has seen Invictus grow substantially in value from a microcap frontier explorer to an emerging oil and gas developer. Invictus Energy is an oil and gas company opening one of the last untested large fronter rift basins in onshore Africa. Macmillan is a reservoir engineer with more than 15 years of experience in oil and gas exploration, field development planning, reserves and resources assessment, reservoir simulation, commercial valuations and business development. Before founding Invictus, Macmillan worked as a senior reservoir engineer at Woodside Energy and AWE, during which time he participated in large offshore oil and gas field operations and the development of the Waitsia Gas Field.
Lloyd Flint, BAcc, FINSIA and MBA is a chartered accountant with over 25 years’ experience in the corporate and financial services arena. He has held a number of management and senior administrative positions as well as providing corporate advisory services as a consultant to corporate clients.
Source Rock Royalties offers investors exposure to oil and gas production without operational costs, providing steady cash flow through its diversified portfolio of royalties and mineral rights.
Source Rock Royalties (TSXV:SRR) is a Calgary, Canada based company exclusively focused on oil & gas royalties in the provinces of Alberta and Saskatchewan. Source Rock's portfolio primarily consists of royalty interests focused on oil, with concentrations in southeast Saskatchewan, central Alberta and west-central Saskatchewan. The portfolio comprises:
Since its inception, Source Rock Royalties has consistently pursued royalty acquisitions, even amidst significant energy market fluctuations. The company has primarily concentrated on non-marketed royalty acquisitions rather than opportunities marketed through formal third-party processes. Leveraging strong relationships within the oil and gas sector in the Western Canadian Sedimentary Basin, Source Rock identifies and accesses niche royalty acquisitions.
Source Rock acquired new royalties worth nearly C$13 million in 2023 and a total of C$16.5 million since its IPO in March 2022. These acquisitions effectively doubled Source Rock’s royalty acreage, significantly enhancing both its current royalty production and its exposure to potential undeveloped drill locations. Source Rock generated C$6.6 million in royalty revenue in 2023, the highest in its 11-year history. Source Rock has generated C$5.8 million royalty revenue for the first nine months of 2024.
Source Rock endeavors to keep costs low, thereby maximizing cash flows. Aside from the CEO and CFO, additional technical oil and gas professionals are engaged by Source Rock as consultants on an as-needed basis. Source Rock Royalties employs only one full-time staff member. The low-cost base ensures consistent cash flows as evidenced by its more than 11+year track record of delivering positive funds from operations.
Strong cash flow allows the company to consistently pay dividends. Source Rock has paid ~$19 million in dividends to shareholders from 2014 to Q4 2024. Source Rock’s per share dividend has increased by 30 percent since March 2023.
The current monthly dividend is $0.0065 and is sustainable given that it can comfortably be funded by current operations even at a lower oil price scenario of ~C$60/bbl (or ~US$50/bbl WTI).
The management and board of directors have a proven track record of creating value in the oil & gas industry. The insiders own 10 percent of Source Rock’s common shares, aligning their interest to that of the shareholders by directly participating in the same financings as outside shareholders since inception. The company has a strong institutional shareholder with CN Rail Pension Fund owning approximately 20 percent of Source Rock’s common shares. Source Rock Royalties has a clean capital structure with only 45.5 million common shares issued and outstanding.
Source Rock focuses on a balanced growth and yield model, limiting volatility in returns for shareholders. Source Rock offers investors a unique opportunity to gain exposure to the oil & gas sector in Canada.
Source Rock's current portfolio comprises royalties primarily focused on oil (95 percent), spread across southeast Saskatchewan, central Alberta and west-central Saskatchewan. The company holds varying gross overriding royalties in more than 150,000 gross acres of land. Additionally, Source Rock owns a production volume royalty in Viking mineral interests situated in lands in east-central Alberta.
The majority of Source Rock's royalties are derived from top-line revenue, resulting in minimal exposure to deductions linked to production costs from wellbores and the sale of various commodities. Also, the majority of its current royalty payors are financially stable and possess robust capabilities to efficiently operate and enhance the value of the lands in which Source Rock holds royalties. Some of the key royalty payors include Whitecap Resources (TSX:WCP), Rubellite Energy (TSX:RBY), Surge Energy (TSX:SGY), Veren (TSX:VRN), Anova Resources (Private), Marling Resources (Private) and Axiom Oil & Gas (Private), among many others.
The company holds gross overriding royalties in approximately 35,000 gross acres of land in southeast Saskatchewan. The key operators include Whitecap Resources, Vermilion Energy (TSX:VET), Anova Resources (Private), Veren (TSX:VRN), Tundra Oil & Gas (Private), ROK Resources (TSXV:ROK), Woodland Development (Private) and Saturn Oil & Gas (TSX:SOIL). Future development activities on gross overriding royalty lands will be focused on the Frobisher Formation. The Frobisher Formation, characterized by shallow depths and conventional light oil, does not necessitate hydraulic fracturing, making it one of Canada's most economically viable light oil plays.
The company holds a gross overriding royalty in approximately 60,000 net acres (95 sections) of largely contiguous land in the Figure Lake area of central Alberta. Rubellite Energy is the operator of gross overriding royalty lands and the production is entirely from the Clearwater Formation. The gross overriding royalty initially carries a royalty rate of 1.5 percent until the cumulative royalty revenue received by Source Rock matches the purchase price. At that point, the royalty rate decreases to 1 percent. The operator has committed to drill 59 horizontal wells on the lands between December 2023 and June 2026.
Source Rock earns a production volume royalty supported by production from Hamilton Lake Unit and Viking lands of Axiom Oil & Gas. Pursuant to the production volume royalty agreement, Source Rock's remaining entitlement to royalty volumes from the Hamilton Lake Unit is as follows:
Source Rock owns varying gross overriding royalties in approximately 60,000 gross acres of land located in west-central Saskatchewan and central Alberta. The west-central Saskatchewan gross overriding royalty lands produce predominantly light oil from the Viking and Mannville formations. The Central Alberta gross overriding royalties produce from various formations and include exposure to several low-decline properties that are under waterflood.
Brad Docherty is the Founder of Source Rock Royalties, and has held the positions of president, chief executive officer and chairman of the company since its incorporation. Previously, he was a corporate finance & securities lawyer at Gowlings and served as the president, CEO and director of Exito Energy and Exitio Energy II, both capital pool companies on the TSXV.
Cheryne Lowe is a seasoned financial professional with extensive experience in companies listed on the Toronto Stock Exchange. She also brings a background in the upstream oil and gas industry and the Canadian capital markets. Her most recent role was interim CFO at AgJunction (TSX:AJX), an agriculture technology company, which was acquired in late 2021. Previously, she served as CFO and corporate secretary at Pine Cliff Energy (TSX:PNE), and as vice-president finance and CFO at Orlen Upstream Canada and its predecessor, TriOil Resources. Lowe began her career with KPMG and later worked as an Institutional Research Associate with Tristone Capital.
John Bell is the president at Kerrobert Fuels and was previously the president and chief financial officer at WCSB Blockchain Infrastructure. Prior to this, he served as the director of finance at Tidewater Midstream and Infrastructure (TSX:TWM).
Dean Potter serves as the executive chairman and CEO of Burgess Creek Exploration. Additionally, he is the president at DPX, a private company engaged in petroleum exploration and development. He is a member of the Saskatchewan oil and gas Hall of Fame and has more than 40 years of geological expertise that has been focused on making discoveries in SE Saskatchewan.
Gary McMurren is the vice-president of engineering at Southern Energy (TSXV:SOU). He was previously the vice-president of engineering at Gulf Pine Energy Partners. Formerly, he held various engineering roles with Athabasca Oil (TSX:ATH).
Shaun Thiessen is vice-president of land and business development at Astara Oil. Prior to this, he held the same title at Astra Oil from inception until its sale. Formerly, he was the director of land at PrairieSky Royalty (TSX:PSK).
Scott Rideout is vice-president of land at Headwater Exploration (TSX:HWX). He was previously vice-president of land at Baytex Energy (TSX:BTE), and prior to that at Raging River Exploration until its sale.
June-Marie Innes is currently CFO at Thread Innovations. She previously held progressively more senior roles at Tamarack Valley Energy (TSX:TVE).
Jordan Kevol is currently COO at Westgate Energy (TSXV:WGT), a private oil and gas producer. Previously, he was the president and CEO of Blackspur Oil.
Trillion Energy International Inc. (" Trillion " or the "Company ") (CSE: TCF) (OTCQB: TRLEF) (Frankfurt: Z62), has reissued its consolidated financial statements for the year ended December 31, 2023 to correct an identified error. As a result, the Company's Net Loss is reduced to $43,842 for the year from the previously reported net loss of $1,102,194.
The error is the result of a foreign exchange loss on intercompany accounts that was recorded in net loss and which should have been recorded in other comprehensive loss. IAS 21, The effects of changes in foreign exchange rates , requires that foreign exchange gains and losses on items that form part of an entity's net investment in a foreign operation, should be recognized in other comprehensive income or loss in the Company's consolidated financial statements.
The following table summarizes the line items impacted in the consolidated statements of financial position:
| As at December 31, 2023 | As previously reported $ | Restatement Adjustment $ | Restated Amount $ |
| Accumulated other comprehensive loss | (12,964,837) | (1,058,352) | (14,023,189) |
| Accumulated deficit | (45,939,198) | 1,058,352 | (44,880,846) |
| Total stockholders' equity | 22,212,572 | - | 22,212,572 |
The following table summarizes the line items impacted in the consolidated statements of income (loss) and comprehensive income (loss):
| For the year ended December 31, 2023 | As previously reported $ | Restatement Adjustment $ | Restated Amount $ |
| Foreign exchange gain (loss) | (10,990,604) | 1,058,352 | (9,932,252) |
| Total other income (expense) | 4,239,593 | 1,058,352 | 5,297,945 |
| Net income (loss) before taxes | 758,132 | 1,058,352 | 1,816,484 |
| Net loss | (1,102,194) | 1,058,352 | (43,842) |
| Other comprehensive loss Foreign currency translation | (8,954,840) | (1,058,352) | (10,013,192) |
| Comprehensive loss | (10,057,034) | - | (10,057,034) |
| Net income (loss) per share – Basic and diluted | (0.01) | 0.01 | (0.00) |
The above changes were adjusted through to the consolidated statements of stockholder' equity, cash flows, and notes to the consolidated financial statements for the year ended December 31, 2023. However, there were no changes to the reported totals of cash flows from (used in) operating, investing and financing activities.
"The Company considers these changes to have a negligible impact on the Company's financial position as there are no cash items impacted" said David Thompson, CFO.
The Company has recently filed its quarterly consolidated financial statements for 30 th September 2024 which are not impacted by the adjustments to the prior year.
About the Company
Trillion Energy International Inc is focused on oil and natural gas production for Europe and Türkiye with natural gas assets in Türkiye. The Company is 49% owner of the SASB natural gas field, a Black Sea natural gas development and a 19.6% (except three wells with 9.8%) interest in the Cendere oil field. More information may be found on www.sedar.com , and our website.
Contact
David Thompson, CFO
1-778-819-1585
E-mail: info@trillionenergy.com
Website: www.trillionenergy.com
Cautionary Statement Regarding Forward-Looking Statements
This news release may contain certain forward-looking information and statements, including without limitation, statements pertaining to the Company's ability to obtain regulatory approval of the executive officer and director appointments. All statements included herein, other than statements of historical fact, are forward-looking information and such information involves various risks and uncertainties. Trillion does not undertake to update any forward-looking information except in accordance with applicable securities laws.
These statements are no guarantee of future performance and are subject to certain risks, uncertainties, delay, change of strategy, and assumptions that are difficult to predict and which may change over time. Accordingly, actual results and strategies could differ materially and adversely from those expressed in any forward-looking statements as a result of various factors. These factors include unforeseen securities regulatory challenges, COVID, oil and gas price fluctuations, operational and geological risks, changes in capital raising strategies, the ability of the Company to raise necessary funds for development; the outcome of commercial negotiations; changes in technical or operating conditions; the cost of extracting gas and oil may increase and be too costly so that it is uneconomic and not profitable to do so and other factors discussed from time to time in the Company's filings on www.sedar.com, including the most recently filed Annual Report on Form 20-F and subsequent filings. For a full summary of our oil and gas reserves information for Turkey, please refer to our Forms F-1,2,3 51-101 filed on www.sedar.com, and or request a copy of our reserves report effective December 31, 2022 and updated January 31 2023.
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Trillion Energy International Inc. (" Trillion " or the "Company ") (CSE: TCF) (OTCQB: TRLEF) (Frankfurt: Z62) is pleased to announce that it has successfully run 2 38 velocity string tubing ("VS") in four existing wells, including three long reach wells on the Akcakoca Platform at the SASB Gas Field, Turkey.
The new tubing operation was conducted to reduce water loading, increase production and overall recovery from the wells. With the new tubing strings, the wells should be able to produce at a lower WHP (well head pressure) for a longer period.
Following the velocity string installation, production from Guluc-2 and West Akcakoca-1 commenced production again and is showing steady improvement, demonstrating the program's initial success in enhancing well performance. Both wells previously experienced production challenges causing down time due to water loading with the previous 4 1/2 tubing. The Akcakoca-3 well continues production with reduced daily water production.
The Company is presently planning the next phase of the operation, which is running the VS on two tripod wells and stimulating all the wells to clean up the producing reservoirs, build pressure and increase production. Choke sizes are being adjusted to minimize water production and maximize gas production. The Company has been injecting nitrogen into wells to flush out water build up as needed.
Winter weather conditions prolonged the operation and necessitated a week's break between the tripods and platform operation, as did the requirement for ordering additional equipment (burst disks) which are expected to arrive later this week.
The Company is confident that these measures will lead to an increase in production for these wells.
About the Company
Trillion Energy International Inc is focused on oil and natural gas production for Europe and Türkiye with natural gas assets in Türkiye. The Company is 49% owner of the SASB natural gas field, a Black Sea natural gas development and a 19.6% (except three wells with 9.8%) interest in the Cendere oil field. More information may be found on www.sedar.com , and our website.
Contact
Arthur Halleran, Chief Executive Officer
Brian Park, Vice President of Finance
1-778-819-1585
E-mail: info@trillionenergy.com ;
Website: www.trillionenergy.com
Cautionary Statement Regarding Forward-Looking Statements
This news release may contain certain forward-looking information and statements, including without limitation, statements pertaining to the Company's ability to obtain regulatory approval of the executive officer and director appointments. All statements included herein, other than statements of historical fact, are forward-looking information and such information involves various risks and uncertainties. Trillion does not undertake to update any forward-looking information except in accordance with applicable securities laws.
These statements are no guarantee of future performance and are subject to certain risks, uncertainties, delay, change of strategy, and assumptions that are difficult to predict and which may change over time. Accordingly, actual results and strategies could differ materially and adversely from those expressed in any forward-looking statements as a result of various factors. These factors include unforeseen securities regulatory challenges, COVID, oil and gas price fluctuations, operational and geological risks, changes in capital raising strategies, the ability of the Company to raise necessary funds for development; the outcome of commercial negotiations; changes in technical or operating conditions; the cost of extracting gas and oil may increase and be too costly so that it is uneconomic and not profitable to do so and other factors discussed from time to time in the Company's filings on www.sedar.com, including the most recently filed Annual Report on Form 20-F and subsequent filings. For a full summary of our oil and gas reserves information for Turkey, please refer to our Forms F-1,2,3 51-101 filed on www.sedar.com, and or request a copy of our reserves report effective December 31, 2022 and updated January 31 2023.
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Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") announces that it has completed and tested 4 additional wells at its Two Rivers East Project including 3 Lower Montney Wells and 1 Upper Montney well on the 5-19 pad.
LOWER MONTNEY
The 3 new Lower Montney wells (F5-19, G5-19, H5-19) were drilled with an average horizontal length of 3,285 metres and completed with approximately 2.5 tons of sand per horizontal metre. The wells were placed on test for clean-up for an average of 7 days until a stabilized rate was achieved. The test rates noted below are based on the final 24 hours of each test.
The average rate achieved for the 3 new Lower Montney wells was 1,624 boepd per well comprised of 989 bbls per day of 41 API light sweet oil and 3.8 mmcf/d of liquids-rich gas. The rates per well are outlined in the table below:
| Well | Oil - bbls/d | Gas - mmcf/d | Total - boe/d | % Light Oil |
| F5-19 | 1,061 | 3.2 | 1,595 | 67 |
| G5-19 | 900 | 4.0 | 1,573 | 57 |
| H5-19 | 1,007 | 4.2 | 1,703 | 59 |
| Average | 989 | 3.8 | 1,624 | 61 |
The overall rates and more specifically the oil rates were materially higher than the previous 3 wells on the pad (C5-19, D5-19 and E5-19) that achieved an average test rate of 1,338 boepd including 729 bbls/d of light oil and 3.7 mmcf/d of gas (see press release dated January 18, 2024 for more information including per well test results and initial production rates). Although the 3 new Lower Montney wells were drilled with slightly longer lateral lengths and the completion design was slightly modified in an attempt to increase the overall oil production, the tests have exceeded expectations.
UPPER MONTNEY
The Upper Montney well (B5-19) was drilled with a horizontal length of 2,647 metres and completed with approximately 2.5 tons of sand per horizontal metre. The well flowed on cleanup for 6 days and achieved a rate of 1,136 boepd comprised of 271 bbls/d of 40 API light oil and 5.2 mmcf/d of liquids-rich gas. In comparison to the Lower Montney Wells noted above, the B5-19 was 20% shorter in horizontal length and had 42% less frac stages leaving room for future optimization.
Management is very pleased with the B5-19 test result particularly the potential impact on Coelacanth's development inventory over its 150-section contiguous Montney land block. The Upper Montney is extensively mapped over Coelacanth's lands, but the impact of this test is amplified given it is a 10-mile step-out from Coelacanth's Two Rivers West project and 5 miles from the nearest competitor well.
INFRASTRUCTURE & TAKEAWAY
As previously disclosed, Coelacanth has secured long-term takeaway and processing for up to 60 mmcf/d of gas and is in process of constructing the required facilities and pipelines to handle the 5-19 and subsequent pads. Initial testing and start-up of the facility is anticipated for late April 2025.
Overall, Coelacanth believes this was a very significant second step in its development that has materially expanded the development fairway of the Upper Montney as well as increased the productivity of the Lower Montney that was already established as productive.
FOR FURTHER INFORMATION PLEASE CONTACT:
Coelacanth Energy Inc.
2110, 530 - 8th Ave SW
Calgary, Alberta T2P 3S8
Phone: 403-705-4525
www.coelacanth.ca
Mr. Robert J. Zakresky
President and Chief Executive Officer
Mr. Nolan Chicoine
Vice President, Finance and Chief Financial Officer
NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS RELEASE.
Oil and Gas Terms
The Company uses the following frequently recurring oil and gas industry terms in the news release:
| Liquids | |
| Bbls | Barrels |
| Bbls/d | Barrels per day |
| NGLs | Natural gas liquids (includes condensate, pentane, butane, propane, and ethane) |
| Natural Gas | |
| Mcf | Thousands of cubic feet |
| Mcf/d | Thousands of cubic feet per day |
| MMcf/d | Millions of cubic feet per day |
| Oil Equivalent | |
| Boe | Barrels of oil equivalent |
| Boe/d | Barrels of oil equivalent per day |
Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent has been used for the calculation of boe amounts in the news release. This boe conversion rate is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Product Types
The Company uses the following references to sales volumes in the news release:
Natural gas refers to shale gas
Oil refers to tight oil
NGLs refers to butane, propane and pentanes combined
Liquids refers to tight oil and NGLs combined
Oil equivalent refers to the total oil equivalent of shale gas, tight oil, and NGLs combined, using the conversion rate of six thousand cubic feet of shale gas to one barrel of oil equivalent as described above.
Forward-Looking Information
This news release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "should", "believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.
More particularly and without limitation, this document contains forward-looking statements and information relating to the Company's oil, NGLs and natural gas production and capital programs. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities and the availability and cost of labor and services.
Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Test Results and Initial Production Rates
The B5-19 Upper Montney well was production tested for 6.3 days and produced at an average rate of 92 bbl/d oil and 2,100 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The F5-19 Lower Montney well was production tested for 4.9 days and produced at an average rate of 728 bbl/d oil and 1,607 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The G5-19 Lower Montney well was production tested for 7.1 days and produced at an average rate of 415 bbl/d oil and 1,489 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The H5-19 Basal Montney well was production tested for 8.1 days and produced at an average rate of 411 bbl/d oil and 1,166 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable and production was starting to decline.
A pressure transient analysis or well-test interpretation has not been carried out on these four wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery.
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/232259
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