| 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
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Primera to drill three wells at Rio Claro license Block onshore Trinidad
oilnow.gy
GLTA ! |
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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
|
| | Canadian Oil & Gas Companies | Stock Discussion ForumsShare | RecommendKeepReplyMark as Last ReadRead Replies (1) |
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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.
LC |
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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
GLTA ! |
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| From: LoneClone | 11/14/2024 2:35:11 PM | | | | | | Crown Point Announces Operating and Financial Results for the Three and Nine Months Ended September 30, 2024
ca.finance.yahoo.com
Crown Point Energy Inc.
Mon, November 11, 2024 at 2:31 p.m. PST 9 min read
CWVLF
0.00%
Crown Point Energy Inc. CALGARY, Alberta, Nov. 11, 2024 (GLOBE NEWSWIRE) -- TSX-V: CWV: Crown Point Energy Inc. (“Crown Point”, the “Company” or "we") today announced its financial and operating results for the three and nine months ended September 30, 2024.
Selected information is outlined below and should be read in conjunction with the Company’s September 30, 2024 unaudited condensed interim consolidated financial statements and management’s discussion and analysis (“MD&A”) that are being filed with Canadian securities regulatory authorities and will be made available under the Company’s profile at www.sedarplus.ca and on the Company’s website at www.crownpointenergy.com. All dollar figures are expressed in United States dollars ("USD") unless otherwise stated.
In the following discussion, the three months ended September 30, 2024 may be referred to as “Q3 2024”. The comparative three months ended September 30, 2023, may be referred to as “Q3 2023”.
Q3 2024 SUMMARY
During Q3 2024, the Company:
- Reported net cash used in operating activities of $1.8 million and funds flow used in operating activities of $1.2 million;
- Earned $5.6 million of oil and natural gas sales revenue on total average daily sales volumes of 1,410 BOE per day, lower than $7.4 million of oil and natural gas sales revenue earned on total average daily sales volumes of 1,502 BOE per day in Q3 2023 due to lower oil sales volumes in the Mendoza Concessions;
- Received an average of $3.48 per mcf for natural gas and $66.19 per bbl for oil;
- Reported an operating netback of $(3.02) per BOE 1 mainly due to the increase in operating expense in Mendoza Concessions combined with a decrease in natural gas and oil prices in TDF Concessions;
- Obtained $2.5 million of working capital and overdraft loans, issued $7.18 million principal amount of unsecured fixed-rate Series V Notes and repaid $2.1 million of notes payable and $3.5 million of working capital and export financing loans;
- Reported a loss before taxes of $3.5 million and a net loss of $2.1 million;
- Reported a working capital deficit2 of $29.7 million; and
- Entered into an agreement to acquire a 16.9972% non-operating participating interest in the TDF Concessions for $0.7 million cash ($0.3 million of which was paid as a deposit), subject to customary closing adjustments. Completion of the acquisition is subject to the receipt of all necessary regulatory, stock exchange and Provincial approvals, the waiver or expiration of applicable rights of first refusal, and other customary closing conditions.
_______________________________
1 Non-IFRS financial ratio. See "Non-IFRS and Other Financial Measures".
2 Capital management measure. See "Non-IFRS and Other Financial Measures".
SUBSEQUENT EVENTS
Subsequent to September 30, 2024 the Company:
- Obtained working capital and overdraft loans for a total amount of $5.76 million and repaid $0.64 million on working capital loans.
- Repaid the first $3.4 million principal installment on the Series IV Notes.
- Issued a total of $22 million principal amount of secured fixed-rate Series VI Notes for cash consideration, which are denominated in USD and payable in USD. The principal amount of the Series VI Notes is repayable in three equal installments, starting on October 30, 2026 and ending on October 30, 2027. The Series VI Notes accrue interest at a fixed rate of 9.5% per annum, payable every six months in arrears from the issue date. The Series VI Notes are secured with a pledge on crude oil sales collections from the Santa Cruz Concessions.
- On October 31, 2024, the Company completed the acquisition of a 100% operating interest in the Piedra Clavada and Koluel Kaike hydrocarbon exploitation concessions ("Santa Cruz Concessions"). On the closing date, the Company paid $9.6 million in cash, which corresponds to the remaining balance of the $12 million base consideration (a $2.4 million advance was previously paid). Additionally, non-cash consideration was agreed to be paid over a 15-year period from the closing date, under which the Company will deliver to the Seller a monthly quantity of oil produced in the Santa Cruz Concessions, ranging from 0 to 600 barrels of oil per day, subject to the market price of oil determined for each month.
Additionally, the Company paid in cash: i) $11.3 million for the crude oil inventories and consumables, ii) $5.3 million for the capitalizable investments and iii) $4.6 million for the corresponding taxes, less the estimated net income from the Santa Cruz Concessions as of October 31, 2024, which was $3.2 million. The total amount disbursed, on October 31, 2024, was $27.6 million and the total amount paid for the Santa Cruz Concessions (including the $2.4 million advance) was $30 million, including taxes.
The purchase price was financed through the proceeds from the issuance of the Series VI Notes for $22 million, plus debt financing obtained with the backing of the Company's controlling shareholders. The amount paid is subject to the final review by the parties involved.
OPERATIONAL UPDATE
Tierra del Fuego Concessions ("TDF" or "TDF Concessions")
During Q3 2024, San Martin oil production averaged 453 (net 157) bbls of oil per day; Las Violetas concession natural gas production averaged 8,960 (net 3,112) mcf per day and oil production averaged 218 (net 76) bbls of oil per day.
Mendoza Concessions
During Q3 2024, the UTE carried out one workover on an oil well in the the Chañares Herrados concession. Oil production for Q3 2024 averaged 812 (net 406) bbls of oil per day from the Chañares Herrados concession and 140 (net 70) bbls of oil per day from the Puesto Pozo Cercado Oriental concession.
OUTLOOK
- The Company’s capital spending on developed and producing assets for fiscal 2024 is budgeted at approximately $3.6 million of which $0.8 million is for improvements to facilities in the TDF Concessions and $2.8 million is for well workovers, facilities improvements and optimization in the Mendoza Concessions. During the nine months ended September 30, 2024, the Company incurred $1.8 million of capital expenditures in the Mendoza and TDF Concessions.
SUMMARY OF FINANCIAL INFORMATION
(expressed in $, except shares outstanding)
| September 30
2024
| December 31
2023
| Current assets
| 5,492,636
|
| 7,636,408
|
| Current liabilities
| (35,165,540
| )
| (19,422,342
| )
| Working capital(1)
| (29,672,904
| )
| (11,785,934
| )
| Exploration and evaluation assets
| 14,094,575
|
| 14,103,353
|
| Property and equipment
| 41,925,646
|
| 45,834,731
|
| Total assets
| 66,215,433
|
| 67,785,665
|
| Non-current financial liabilities(1)
| 8,993,076
|
| 18,317,856
|
| Share capital
| 56,456,328
|
| 56,456,328
|
| Total common shares outstanding
| 72,903,038
|
| 72,903,038
|
|
(expressed in $, except shares outstanding)
| Three months ended
| Nine months ended
|
| September 30
| September 30
|
| 2024
|
| 2023
|
| 2024
|
| 2023
|
| Oil and natural gas sales revenue
| 5,560,809
|
| 7,400,992
|
| 17,246,209
|
| 21,235,332
|
| Loss before taxes
| (3,490,096
| )
| (2,084,976
| )
| (9,966,566
| )
| (7,751,038
| )
| Net loss
| (2,063,972
| )
| (2,027,637
| )
| (6,024,390
| )
| (6,031,549
| )
| Net loss per share(2)
| (0.03
| )
| (0.03
| )
| (0.08
| )
| (0.08
| )
| Net cash (used) provided by operating activities
| (1,793,711
| )
| 2,144,720
|
| (2,861,420
| )
| 2,453,571
|
| Net cash per share – operating activities(1)(2)
| (0.02
| )
| 0.03
|
| (0.04
| )
| 0.03
|
| Funds flow (used) provided by operating activities
| (1,201,259
|
| 622,333
|
| (2,085,892
| )
| (501,188
| )
| Funds flow per share – operating activities(1)(2)
| (0.02
| )
| 0.01
|
| (0.03
| )
| (0.01
| )
| Weighted average number of shares – basic -diluted
| 72,903,038
|
| 72,903,038
|
| 72,903,038
|
| 72,903,038
|
|
(1) We adhere to International Financial Reporting Standards (“IFRS”), however the Company also employs certain non-IFRS measures to analyze financial performance, financial position, and cash flow. “Working capital” is a capital management measure. “Non-current financial liabilities” is a supplemental financial measure. "Net cash per share – operating activities" is a supplemental financial measure. "Funds flow per share – operating activities" is a supplemental financial measure. See "Non-IFRS and Other Financial Measures".
(2) All per share figures are the same for the basic and diluted weighted average number of shares outstanding in the periods. The effect of options is anti-dilutive in loss periods. Per share amounts may not add due to rounding.
Sales Volumes
| Three months ended
| Nine months ended
|
| September 30
| September 30
|
| 2024
|
| 2023
|
| 2024
|
| 2023
|
| Total sales volumes (BOE)
| 129,807
|
| 138,243
|
| 370,183
|
| 407,863
|
| Light oil bbls per day
| 679
|
| 962
|
| 768
|
| 941
|
| NGL bbls per day
| 15
|
| 19
|
| 18
|
| 18
|
| Natural gas mcf per day
| 4,298
|
| 3,128
|
| 3,392
|
| 3,213
|
| Total BOE per day
| 1,410
|
| 1,502
|
| 1,351
|
| 1,495
|
|
Operating Netback (1)
| Three months ended
| Nine months ended
|
| September 30
| September 30
|
| 2024
| 2023
| 2024
| 2023
|
|
| Per BOE
|
| Per BOE
|
| Per BOE
|
| Per BOE
| Oil and natural gas sales revenue ($)
| 5,560,809
|
| 42.84
|
| 7,400,992
|
| 53.54
|
| 17,246,209
|
| 46.59
|
| 21,235,332
|
| 52.06
|
| Export tax ($)
| (76,514
| )
| (0.59
| )
| (139,494
| )
| (1.01
| )
| (309,309
| )
| (0.84
| )
| (377,964
| )
| (0.93
| )
| Royalties and turnover tax ($)
| (999,926
| )
| (7.70
| )
| (1,299,685
| )
| (9.40
| )
| (3,045,017
| )
| (8.23
| )
| (3,557,850
| )
| (8.72
| )
| Operating costs ($)
| (4,877,196
| )
| (37.57
| )
| (4,793,415
| )
| (34.67
| )
| (14,118,773
| )
| (38.14
| )
| (15,048,736
| )
| (36.90
| )
| Operating netback(1)($)
| (392,827
| )
| (3.02
| )
| 1,168,398
|
| 8.46
|
| (226,890
| )
| (0.62
| )
| 2,250,782
|
| 5.51
|
|
|
|
|
|
|
|
|
|
|
(1) "Operating netback" is a non-IFRS measure. “Operating netback per BOE” is a non-IFRS ratio. See "Non-IFRS and Other Financial Measures".
About Crown Point
Crown Point Energy Inc. is an international oil and gas exploration and development company headquartered in Calgary, Canada, incorporated in 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 Golfo San Jorge basin in the Province of Santa Cruz, the Austral basin in the province of Tierra del Fuego, and the Neuquén and Cuyo (or Cuyana) basins in the province of Mendoza. 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.
Advisory
Non-IFRS and Other Financial Measures: Throughout this press release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position, and cash flow. These non-IFRS and other financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures provided by other issuers. The non-IFRS and other financial measures should not be considered to be more meaningful than financial measures which are determined in accordance with IFRS, such as net income (loss), oil and natural gas sales revenue and net cash (used) provided by operating activities as indicators of our performance.
"Funds flow per share – operating activities" is a supplemental financial measure. Funds flow per share – operating activities is comprised of funds flow provided (used) by operating activities divided by the basic and diluted weighted average number of common shares outstanding for the period. See “Summary of Financial Information”.
"Net cash per share – operating activities" is a supplemental financial measure. Net cash per share – operating activities is comprised of net cash provided (used) by operating activities divided by the basic and diluted weighted average number of common shares outstanding for the period. See “Summary of Financial Information”.
"Non-current financial liabilities" is a supplemental financial measure. Non-current financial liabilities is comprised of the non-current portions of trade and other payables, notes payable and lease liabilities as presented in the Company’s consolidated statements of financial position. See “Summary of Financial Information”.
"Operating Netback" is a non-IFRS measure. Operating netback is comprised of oil and natural gas sales revenue less export tax, royalties and turnover tax and operating costs. Management believes this measure is a useful supplemental measure of the Company’s profitability relative to commodity prices. See “Operating Netback” for a reconciliation of operating netback to oil and natural gas sales revenue, being our nearest measure prescribed by IFRS.
"Operating netback per BOE" is a non-IFRS ratio. Operating netback per BOE is comprised of operating netback divided by total BOE sales volumes in the period. Management believes this measure is a useful supplemental measure of the Company’s profitability relative to commodity prices. In addition, management believes that operating netback per BOE is a key industry performance measure of operational efficiency and provide investors with information that is also commonly presented by other crude oil and natural gas producers. Operating netback is a non-IFRS measure. See "Operating Netback" for the calculation of operating netback per BOE.
"Working capital" is a capital management measure. Working capital is comprised of current assets less current liabilities. Management believes that working capital is a useful measure to assess the Company's capital position and its ability to execute its existing exploration commitments and its share of any development programs. See “Summary of Financial Information” for a reconciliation of working capital to current assets and current liabilities, being our nearest measures prescribed by IFRS.
Abbreviations and BOE Presentation: "bbl" means barrel; "bbls" means barrels; "BOE" means barrels of oil equivalent; "mcf” means thousand cubic feet; "mmcf" means million cubic feet, "NGL" means natural gas liquids; "UTE" means Union Transitoria de Empresas, which is a registered joint venture contract established under the laws of Argentina; "WI" means working interest. All BOE conversions in this press release are derived by converting natural gas to oil in the ratio of six mcf of gas to one bbl of oil. BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of six mcf of gas to one bbl of oil (6 mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the price of crude oil as compared to natural gas in Argentina from time to time may be different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Forward-looking Information: This document contains forward-looking information. This information relates to future events and the Company’s future performance. All information and statements contained herein that are not clearly historical in nature constitute forward-looking information. Such information represents the Company’s internal projections, estimates, expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. This information involves known or unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. In addition, this document may contain forward-looking information attributed to third party industry sources. Crown Point believes that the expectations reflected in this forward-looking information are reasonable; however, undue reliance should not be placed on this forward-looking information, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. This press release contains forward-looking information concerning, among other things, the following: under "Q3 2024 Summary", the Company’s expectations regarding the terms, conditions and timing for closing the proposed TDF acquisition, including the potential exercise of any ROFR; under "Outlook", our estimated capital expenditure budget for fiscal 2024, and the capital expenditures that we intend to make in our concessions during such period; under "About Crown Point", all elements of the Company’s business strategy and focus. The reader is cautioned that such information, although considered reasonable by the Company, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided in this document as a result of numerous known and unknown risks and uncertainties and other factors. A number of risks and other factors could cause actual results to differ materially from those expressed in the forward-looking information contained in this document including, but not limited to, the following: that the Company is unable to truck oil to the Enap refinery and/or the Rio Cullen marine terminal and/or that the cost to do so rises and/or becomes uneconomic; that the price received by the Company for its oil is at a substantial discount to the Brent oil price; that the Company is not able to meet its obligations as they become due and continue as a going concern; that the Company is unable to complete the proposed acquisition of the additional interest in the TDF Concessions on the terms described herein or at all, whether due to the inability of the Company to obtain financing to fund the cash portion of the purchase price, obtain requisite regulatory approvals, satisfy applicable conditions precedent, the exercise of rights of first refusal, or otherwise; risks associated with the insolvency and/or bankruptcy of our joint venture partners and/or the operators of the concessions in which we have an interest, including the risk that any such insolvency and/or bankruptcy has an adverse effect on one of our UTEs, one of our concessions and/or the Company; and the risks and other factors described under “Business Risks and Uncertainties” in our MD&A and under “Risk Factors” in the Company’s most recently filed Annual Information Form, which is available for viewing on SEDAR+ at www.sedarplus.ca. With respect to forward-looking information contained in this document, the Company has made assumptions regarding, among other things: that the Company will complete the proposed acquisition of the additional interest in the TDF Concessions on the terms described herein on a timely basis, including the ability of the Company to obtain the requisite financing to fund the cash portion of the purchase price on acceptable terms, obtain all requisite regulatory approvals and satisfy all applicable conditions precedent; trucking costs; the ability and willingness of OPEC+ nations and other major producers of crude oil to balance crude oil production levels and thereby sustain higher global crude oil prices; that our joint venture partners and the operators of our concessions that we do not operate will honour their contractual commitments in a timely fashion and will not become insolvent or bankrupt; the impact of inflation rates in Argentina and the devaluation of the Argentine peso against the USD on the Company; the impact of increasing competition; the general stability of the economic and political environment in which the Company operates (including in relation to the newly elected President and Vice-President of Argentina and their administration), including operating under a consistent regulatory and legal framework in Argentina; future oil, natural gas and NGL prices (including the effects of governmental incentive programs and government price controls thereon); the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the costs of obtaining equipment and personnel to complete the Company’s capital expenditure program; the ability to operate the projects in which the Company has an interest in a safe, efficient and effective manner; that the Company will not pay dividends for the foreseeable future; the ability of the Company to obtain financing on acceptable terms when and if needed and continue as a going concern; the ability of the Company to service its debt repayments when required; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration activities; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; currency, exchange, inflation and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in Argentina; and the ability of the Company to successfully market its oil and natural gas products. Management of Crown Point has included the above summary of assumptions and risks related to forward-looking information included in this document in order to provide investors with a more complete perspective on the Company’s future operations. Readers are cautioned that this information may not be appropriate for other purposes. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking information contained in this document are expressly qualified by this cautionary statement. The forward-looking information contained herein is made as of the date of this document and the Company disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable Canadian securities laws.
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.
CONTACT: For inquiries please contact: 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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| To: LoneClone who wrote (24734) | 11/14/2024 2:37:15 PM | | From: LoneClone | | | | QIMC Reports Major Advancements in Ville Marie Geophysical Surveys for Natural Hydrogen Discovery and Launches Underwater Hydrogen Exploration and Sampling
newsfilecorp.com
November 14, 2024 8:00 AM EST | Source: Quebec Innovative Materials Corp.
Lachute, Quebec--(Newsfile Corp. - November 14, 2024) - Quebec Innovative Materials Corp. (CSE: QIMC) (FSE: 7FJ) (OTC Pink: QIMCF) ("QI Materials", "QIMC" or the "Company"), QIMC is pleased to share a major advancement in our geophysical and gravimetric surveys for the Ville Marie Natural Hydrogen discovery, further demonstrating our dedication to our precise and data-driven hydrogen exploration. This recent survey encompassed over 1,000 gravimetric measurements, carefully conducted at 50-meter intervals across an expansive 80-square-kilometer area in the St-Bruno-de-Guigues region. These efforts are critical in evaluating the thickness of sedimentary rock layers that overlay the Archean volcano-plutonic greenstone belt, providing essential insights into the conditions for hydrogen formation and migration.
Our team is now performing advanced 2D and 3D inversion analysis on this comprehensive gravimetric dataset. These analyses will enable us to create detailed gravimetric models for St-Bruno-de-Guigues, which will integrate seamlessly with data from the central and southern areas to establish a district-scale gravity model. This model will further enhance our geological understanding and help identify prime locations for the hydrogen and helium conduits.
We are also optimizing parameters for an upcoming electromagnetic survey (TDEM), scheduled for winter 2024 into early 2025. QIMC's proprietary TDEM system, designed specifically for hydrogen and helium prospecting, is a cutting-edge ground-based system that provides high-resolution electrical resistivity and chargeability profiles. With penetration depths of 100-200 meters and horizontal resolutions as fine as 15 centimeters, this system is vital for identifying key hydrogen conduits and mapping bedrock fracture networks hidden beneath layers of glaciolacustrine sediments. The resulting structural insights will be instrumental in guiding soil-gas prospecting and drilling efforts to pinpoint natural hydrogen dominant advective conduits.
Hydrogen and Helium model
Following a successful hydrogen prospecting season in summer 2024-where our dedicated field team collected 1,100 samples, exceeding our original targets by double-we are setting ambitious goals for helium prospecting, with a comprehensive soil sampling program planned for 2025.
"As our geological model suggests, helium and hydrogen in this area appear to be generated through similar geological processes," notes Professor Marc Richer-Laflèche. "This model reveals a distinct distribution pattern: a helium-hydrogen mix towards the west, influenced by the Cobalt Group's arkosic rocks, which are rich in potassium and actinides, and a hydrogen-rich concentration towards the east, associated with the Baby Group's Iron Greenstone belt, where rocks are comparatively lower in potassium and actinides," states Professor Laflèche.
"This insight aligns with our strategy to efficiently explore and develop both helium and hydrogen along our Ville-Marie district," said John Karagiannidis, CEO of QIMC.
Underwater Hydrogen surveys
QIMC and INRS team will be deploying an aquatic probe specifically designed to measure dissolved hydrogen concentrations in the waters of Lake Témiscamingue. "By analogy with the detection of hydrogen in soils (Soil Gas), the possibility of quantitatively measuring hydrogen concentrations in water will contribute to our model of hydrogen transfer mechanisms in the structures of the Lake Témiscamingue Graben," notes John Karagiannidis, CEO of QIMC. These structures have been well documented by Sonar and CHIRP imagery and by seismic reflection surveys carried out by the Geological Survey of Canada.
The approach adopted by QIMC and INRS is based on techniques for detecting methane in aquatic environments and oceanographic techniques for detecting hydrothermal vents on mid-ocean ridges. The proprietary probe used can measure hydrogen and other important parameters such as bathymetry, water temperature, and pH and identify the advective conduits/chimneys.
The probe will be deployed in the winter of 2024 and early 2025 using holes drilled in the frozen surface of Lake Témiscamingue. For each hole, measurements will be taken at varying depths, producing kilometre-long sections of dissolved hydrogen concentrations in the lake. Among other things, the team will be paying particular attention to faulted sectors in the deepest parts of Lake Témiscamingue.
The winter survey will be followed by aquatic acquisitions using a boat and small craft capable of navigating Lake Témiscamingue and the Rivière à la Loutre (St-Bruno-de-Guigues), the Petite Rivière Blanche (Duhamel-Ouest) and the Rivière Blanche (Notre-Dame-du-Nord sector). These rivers flow through areas of sedimentary rock in the Témiscamingue graben.
"Lac Kipawa is a demonstration that regional seismicity causes an ascent of gas towards the subsurface. This is a demonstration on a human scale of the fast and dynamic gas transfer process in the Temiscamingue graben," states Professor Laflèche. "What is interesting is that Lake Kipawa is to the south of our property and Notre-Dame-du-Nord to the north St-Bruno. Between the two we have our hydrogen-rich and HE/hydrogen rich sector," further notes Professor Laflèche.
QIMC to exhibit at Reuters Live Energy Conference in Houston
QIMC is pleased to announce our participation in the upcoming Reuters Events: Hydrogen North America 2024 in Houston on December 4th and 5th. We are excited to showcase our innovative solutions and projects in the rapidly evolving hydrogen sector. You can find us at Booth #315 in the Hydrogen section, where our team will be available to discuss our ongoing efforts and future initiatives aimed at driving sustainable growth and decarbonization in the energy industry. We look forward to connecting with industry leaders and exploring opportunities for collaboration as we work towards a cleaner and more resilient energy future.
QIMC is committed to leveraging proprietary state-of-the-art geophysical technologies and methodologies to responsibly unlock the natural hydrogen potential in Témiscamingue, supporting a sustainable, cleaner energy future. We look forward to sharing further updates on our progress and insights from these advanced surveys.
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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