Touchstone Exploration Inc (LON:TXP) has announced its 2023 year-end reserves.
Touchstone’s independent reserves evaluation was prepared by GLJ Ltd. with an effective date of December 31, 2023. Highlights of our total proved developed producing (PDP), total proved (1P), total proved plus probable (2P) and total proved plus probable plus possible (3P) reserves from the Reserves Report are provided below. Unless otherwise stated, all financial amounts referenced herein are stated in United States dollars. Financial information contained herein is based on the Company’s unaudited results for the year ended December 31, 2023 and is subject to change. Readers are further cautioned to read the applicable advisories contained herein.
Touchstone’s 2023 year-end reserves reflect the initial transition of our Cascadura production base into the PDP reserves category as we brought onstream the first two Cascadura wells, Cascadura-1ST1 and Cascadura Deep-1. In addition to successfully constructing and commissioning the Cascadura natural gas and liquids facility in 2023, we also prepared for our Cascadura C delineation and development program.
In 2023 we achieved initial production from our Cascadura field which produced net volumes of 37.4 MMcf/d of natural gas and 622 bbls/d of natural gas liquids in the fourth quarter of 2023, contributing to corporate average quarterly net production volumes of 8,504 boe/d and average 2023 annual net production volumes of 3,981 boe/d.
2023 Year-end Reserves Report Highlights
· Relative to year-end 2022 and after 2023 production, we increased gross PDP reserves by 180 percent to 13,547 Mboe, decreased gross 1P reserves by 12 percent to 33,696 Mboe, decreased gross 2P reserves by 10 percent to 67,379 Mboe and decreased gross 3P reserves by 10 percent to 108,859 Mboe in 2023.
· PDP reserves replaced 2023 annual production by 699 percent, reflecting Cascadura-1ST1 and Cascadura Deep-1 natural gas and associated liquids volumes that were brought online in 2023.
· With the addition of Cascadura property reserves, PDP reserves represent 40 percent of 1P reserves, reflecting an attractive ratio of base production to low risk proved undeveloped (“PUD”) drilling targets.
· Reductions in our 1P, 2P, and 3P year-end reserves balances from 2022 reflected the removal of eight PUD locations on our non-core legacy crude oil blocks and Royston, technical revisions to the natural gas liquids yields at Cascadura, increased annual production volumes in 2023 and a limited 2023 development capital program.
· Our net present value of future net revenues discounted at 10 percent (“NPV10”) on a before tax PDP basis increased by 142 percent to $151.4 million, decreased by 30 percent to $372.5 million on a 1P basis, decreased by 27 percent to $730.1 million on a 2P basis, and decreased by 29 percent to $1.05 billion on a 3P basis from the prior year.
· Realized after tax PDP NPV10 of $99.8 million representing an increase of 93 percent from the prior year, after tax 1P NPV10 decreased by 25 percent from year-end 2022 to $191.4 million, after tax 2P NPV10 decreased by 24 percent from the prior year to $342.5 million and after tax 3P NPV10 decreased by 26 percent from 2022 to $482.6 million.
· We continue to maintain a long producing reserve life index of 7.9 years 1P and 14.4 years 2P, reflecting the low decline nature of our asset base.
· The Cascadura-2 well was drilled subsequent to the effective date of the Reserves Report and will be reflected in our future reserve evaluations.
2023 Year-end Reserves Report Summary
Touchstone’s year-end light and medium crude oil, heavy crude oil, conventional natural gas and natural gas liquid reserves in Trinidad were evaluated by independent reserves evaluator, GLJ, in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserves information as required under NI 51-101 will be included in the Company’s Annual Information Form, which will be filed on SEDAR+ (www.sedarplus.ca) on or before March 30, 2024.
The reserve estimates set forth below are based upon GLJ’s Reserves Report dated February 29, 2024 with an effective date of December 31, 2023. The Reserves Report uses the average price forecasts of the three leading Canadian oil and gas evaluation consultants (GLJ, McDaniel & Associates Consultants Ltd. and Sproule Associates Ltd. (collectively, the “Consultants”)). All values in this announcement are based on the three Consultants’ average forecast pricing and GLJ’s estimates of future operating and capital costs as of December 31, 2023. Please refer to “Advisories: Reserves Disclosure” for further information. In certain tables set forth below, the columns may not add due to rounding.
2023 Reserves Summary by Category
| PDP | 1P | 2P | 3P | |
| Total gross reserves(1) (Mboe) | 13,547 | 33,696 | 67,379 | 108,859 |
| Reserve additions (reductions)(2) (Mboe) | 10,158 | (3,313) | (6,241) | (10,281) |
| NPV10 before income tax(3) ($000’s) | 151,433 | 372,547 | 730,065 | 1,052,803 |
| NPV10 after income tax(3) ($000’s) | 99,791 | 191,466 | 342,527 | 482,575 |
Notes:
(1) Gross reserves are the Company’s working interest share before deduction of royalties.
(2) Reserve additions (reductions) exclude 2023 annual production. See “Advisories: Oil and Gas Metrics“.
(3) Based on the Consultants’ average December 31, 2023 forecast prices and costs. See “Forecast prices and costs” herein.
Year-Over-Year Reserves Data
| December 31, 2023 | December 31, 2022(1) | % Change | |
| PDP gross reserves(2) (Mboe) | 13,547 | 4,843 | 180 |
| 1P gross reserves(2) (Mboe) | 33,696 | 38,463 | (12) |
| 2P gross reserves(2) (Mboe) | 67,379 | 75,074 | (10) |
| 3P gross reserves(2) (Mboe) | 108,859 | 120,594 | (10) |
| PDP NPV10 before income tax(3) ($000’s) | 151,433 | 62,561 | 142 |
| 1P NPV10 before income tax(3) ($000’s) | 372,547 | 530,264 | (30) |
| 2P NPV10 before income tax(3) ($000’s) | 730,065 | 993,714 | (27) |
| 3P NPV10 before income tax(3) ($000’s) | 1,052,803 | 1,473,380 | (29) |
| PDP NPV10 after income tax(3) ($000’s) | 99,791 | 51,770 | 93 |
| 1P NPV10 after income tax(3) ($000’s) | 191,446 | 256,623 | (25) |
| 2P NPV10 after income tax(3) ($000’s) | 342,527 | 450,624 | (24) |
| 3P NPV10 after income tax(3) ($000’s) | 482,575 | 654,913 | (26) |
Notes:
(1) Prior year reserve estimates per GLJ’s independent reserves evaluation dated March 3, 2023 with an effective date of December 31, 2022.
(2) Gross reserves are the Company’s working interest share before deduction of royalties.
(3) Based on the three Consultants’ average December 31, 2023 forecast prices and costs. See “Forecast prices and costs” herein.
Summary of Crude Oil and Natural Gas Reserves by Product Type
| Company Gross(1) Reserves | Light and Medium Crude Oil (Mbbl) | Heavy Crude Oil(Mbbl) | Conventional Natural Gas (MMcf) | Natural Gas Liquids (Mbbl)(2) | Total Oil Equivalent (Mboe) |
| Proved | |||||
| Developed producing | 3,360 | 224 | 56,296 | 580 | 13,547 |
| Developed non-producing | 1,331 | 10 | 4,020 | 37 | 2,048 |
| Undeveloped | 3,846 | 0 | 80,427 | 849 | 18,100 |
| Total 1P | 8,538 | 234 | 140,743 | 1,467 | 33,696 |
| Probable | 8,084 | 58 | 145,180 | 1,344 | 33,683 |
| Total 2P | 16,622 | 292 | 285,923 | 2,811 | 67,379 |
| Possible | 5,141 | 87 | 205,911 | 1,933 | 41,480 |
| Total 3P | 21,763 | 379 | 491,834 | 4,744 | 108,859 |
| Company Net(3) Reserves | Light and Medium Crude Oil (Mbbl) | Heavy Crude Oil(Mbbl) | Conventional Natural Gas (MMcf) | Natural Gas Liquids (Mbbl)(2) | Total Oil Equivalent (Mboe) |
| Proved | |||||
| Developed producing | 2,022 | 199 | 49,259 | 508 | 10,939 |
| Developed non-producing | 856 | 9 | 3,518 | 32 | 1,484 |
| Undeveloped | 2,786 | 0 | 70,374 | 743 | 15,258 |
| Total 1P | 5,664 | 209 | 123,150 | 1,283 | 27,681 |
| Probable | 6,056 | 51 | 127,032 | 1,176 | 28,456 |
| Total 2P | 11,720 | 260 | 250,183 | 2,460 | 56,137 |
| Possible | 3,780 | 78 | 180,171 | 1,691 | 35,578 |
| Total 3P | 15,500 | 338 | 430,354 | 4,151 | 91,715 |
Notes:
(1) Gross reserves are the Company’s working interest share before deduction of royalties.
(2) NGLs are comprised of 100% condensate.
(3) Net reserves are the Company’s working interest share after the deduction of royalty obligations.
Summary of Net Present Values of Future Net Revenues
| Net Present Values Before Income Taxes(1) ($000’s) | Undiscounted | Discounted at 5% | Discounted at 10% | Discounted at 15% | Discounted at 20% |
| Proved | |||||
| Developed producing | 203,893 | 173,513 | 151,433 | 134,704 | 121,630 |
| Developed non-producing | 41,188 | 32,603 | 27,853 | 24,538 | 21,988 |
| Undeveloped | 316,080 | 243,189 | 193,262 | 157,745 | 131,632 |
| Total 1P | 561,162 | 449,304 | 372,547 | 316,987 | 275,251 |
| Probable | 708,321 | 487,694 | 357,518 | 274,398 | 218,055 |
| Total 2P | 1,269,483 | 936,998 | 730,065 | 591,386 | 493,306 |
| Possible | 920,790 | 504,989 | 322,738 | 228,824 | 173,899 |
| Total 3P | 2,190,273 | 1,441,987 | 1,052,803 | 820,210 | 667,205 |
Note:
(1) Based on the three Consultants’ average December 31, 2023 forecast prices and costs. See “Forecast prices and costs” herein.
| Net Present Values After Income Taxes(1)(2) ($000’s) | Undiscounted | Discounted at 5% | Discounted at 10% | Discounted at 15% | Discounted at 20% |
| Proved | |||||
| Developed producing | 118,430 | 109,202 | 99,791 | 91,684 | 84,890 |
| Developed non-producing | 14,408 | 13,126 | 11,716 | 10,546 | 9,583 |
| Undeveloped | 137,087 | 103,315 | 79,938 | 63,308 | 51,161 |
| Total 1P | 269,925 | 225,643 | 191,446 | 165,539 | 145,633 |
| Probable | 296,550 | 207,139 | 151,082 | 114,601 | 89,695 |
| Total 2P | 566,475 | 432,782 | 342,527 | 280,140 | 235,328 |
| Possible | 386,142 | 216,473 | 140,048 | 100,088 | 76,482 |
| Total 3P | 952,617 | 649,255 | 482,575 | 380,228 | 311,810 |
Notes:
(1) Based on the three Consultants’ average December 31, 2023 forecast prices and costs. See “Forecast prices and costs” herein.
(2) The after-tax net present values prepared by GLJ in the evaluation of the Company’s petroleum and natural gas assets presented herein are calculated by considering current Trinidad tax regulations and are based on the Company’s estimated tax pools and non-capital losses as of December 31, 2023. The values reflect the expected income tax burden on the assets on a consolidated basis. Values do not represent an estimate of the value at the business entity level or consider tax planning, which may be significantly different. See “Advisories: Unaudited Financial Information“.
Reconciliation of Gross Reserves by Product Type
The following table sets forth a reconciliation of the Company’s total gross proved, gross probable and gross proved plus probable reserves as of December 31, 2023 by product type against such reserves as at December 31, 2022 based on forecast prices and cost assumptions.
| Reserves Category and Factors | Light and Medium Crude Oil (Mbbl) | Heavy Crude Oil(Mbbl) | Conventional Natural Gas (MMcf) | Natural Gas Liquids (Mbbl)(1) | Total Oil Equivalent (Mboe) |
| Total Proved | |||||
| December 31, 2022(2) | 9,977 | 468 | 146,677 | 3,571 | 38,463 |
| Extensions and improved recovery(3) | 327 | – | – | – | 327 |
| Technical revisions(4) | (1,359) | (209) | (242) | (2,030) | (3,638) |
| Economic factors(5) | (2) | – | – | – | (2) |
| Production | (406) | (25) | (5,692) | (74) | (1,454) |
| December 31, 2023 | 8,538 | 234 | 140,743 | 1,467 | 33,696 |
| Total Probable | |||||
| December 31, 2022(2) | 8,711 | 416 | 144,850 | 3,342 | 36,611 |
| Extensions and improved recovery(3) | 82 | – | – | – | 82 |
| Technical revisions(4) | (702) | (359) | 330 | (1,998) | (3,003) |
| Economic factors(5) | (7) | – | – | – | (7) |
| Production | – | – | – | – | – |
| December 31, 2023 | 8,084 | 58 | 145,180 | 1,344 | 33,683 |
| Total Proved plus Probable | |||||
| December 31, 2022(2) | 18,688 | 884 | 291,527 | 6,913 | 75,074 |
| Extensions and improved recovery(3) | 409 | – | – | – | 409 |
| Technical revisions(4) | (2,061) | (567) | 87 | (4,028) | (6,641) |
| Economic factors(5) | (9) | – | – | – | (9) |
| Production | (406) | (25) | (5,692) | (74) | (1,454) |
| December 31, 2023 | 16,622 | 292 | 285,923 | 2,811 | 67,379 |
Notes:
(1) NGLs are comprised of 100 percent condensate.
(2) Prior year reserve estimates per GLJ’s independent reserves evaluation dated March 3, 2023 with an effective date of December 31, 2022.
(3) Reserve amounts for Infill Drilling, Extensions and Improved Recovery are combined and reported as “Extensions and Improved Recovery”.
(4) Technical revisions factor includes all changes in reserves due to well performance and previously booked wells which were drilled in the year.
(5) Economic factors are the change in reserves exclusively due to changes in pricing.
December 31, 2023 gross proved plus probable reserves were 67,379 Mboe, representing a 7,695 Mboe or 10 percent decrease from the 75,074 Mboe reported in the prior year. Relative to December 31, 2022, light and medium crude oil reserves decreased by 2,006 Mbbl. The annual decline predominately reflected a combination of annual production, the removal of two proved undeveloped drilling locations at Royston and six proved undeveloped drilling locations at our CO-2 field, partially offset by two new proved undeveloped drilling locations at our CO-1 property and improved recovery from well recompletions at our WD-4 field. Proved plus probable heavy crude oil reserves decreased by 592 Mbbl from the prior year, reflecting the removal of all future recompletion activity at our Fyzabad property and 2023 production. Proved plus probable conventional natural gas reserves decreased by 5,604 MMcf relative to December 31, 2022, mainly attributed to annual Cascadura and Coho field production. Proved plus probable natural gas liquids reserves decreased by 4,102 Mbbl in comparison to December 31, 2022, reflecting a reduction in forecasted Cascadura natural gas liquids yields and 2023 annual production.
Future Development Costs
The following table provides information regarding the development costs deducted in the estimation of the Company’s future net revenue using forecast prices and costs as included in the Reserves Report.
| Year ($000’s) | PDP | 1P | 2P | 3P |
| 2024 | 50 | 19,270 | 28,260 | 28,260 |
| 2025 | – | 12,143 | 24,786 | 24,786 |
| 2026 | – | 21,505 | 28,236 | 28,236 |
| 2027 | – | 11,493 | 40,857 | 40,857 |
| 2028 | – | 12,995 | 18,537 | 18,537 |
| Thereafter | – | – | – | – |
| Total undiscounted | 50 | 77,406 | 140,676 | 140,676 |
| Total discounted at 10% per year | 48 | 62,540 | 112,018 | 112,018 |
The following table sets forth the changes in undiscounted future development costs (“FDC”) included in the Reserves Report against such costs in our December 31, 2022 reserves report prepared by GLJ dated March 3, 2023.
| ($000’s unless otherwise stated) | PDP | 1P | 2P | 3P |
| (Decrease) increase in forecasted well costs | (140) | 11,692 | 19,414 | 19,414 |
| Decrease in forecasted well locations | – | (15,630) | (15,481) | (15,481) |
| Decrease in forecasted facility and pipeline costs | – | (5,400) | (4,623) | (4,623) |
| Total decrease in FDC from 2022 | (140) | (9,338) | (690) | (690) |
| Total decrease in FDC from 2022 (%) | (74) | (11) | – | – |
Forecast Pricing and Costs
Forecast pricing and costs are prices and costs that are generally acceptable, in the opinion of GLJ, as being a reasonable outlook of the future as of the evaluation effective date. The forecast cost assumptions consider inflation with respect to future operating and capital costs. The following table sets forth the benchmark reference commodity prices and inflation rates reflected in the Reserves Data as of December 31, 2023. These price assumptions were provided to the Touchstone Exploration by GLJ and represented the average price forecast of the three Consultants as of the date of the Reserves Report.
| Consultants Average Price Forecast | |||
| Forecast Year | Brent Spot Crude Oil(1)($/bbl) | Henry Hub Natural Gas(1)($/MMBtu) | Inflation Rate(% per year) |
| 2024 | 78.00 | 2.75 | 0.0 |
| 2025 | 79.18 | 3.64 | 2.0 |
| 2026 | 80.36 | 4.02 | 2.0 |
| 2027 | 81.79 | 4.10 | 2.0 |
| 2028 | 83.41 | 4.18 | 2.0 |
| 2029 | 85.09 | 4.27 | 2.0 |
| 2030 | 86.79 | 4.35 | 2.0 |
| 2031 | 88.52 | 4.44 | 2.0 |
| 2032 | 90.29 | 4.53 | 2.0 |
| 2033 | 92.10 | 4.62 | 2.0 |
| Thereafter | +2.0% / year | +2.0% / year | 2.0 |
Note:
(1) This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer. Product sales prices will reflect these reference prices with further adjustments for specific marketing arrangements, quality differentials and transportation to point of sale.
Capital Program Efficiency
| 2023 | 2023 – 2019 Total | |||
| 1P | 2P | 1P | 2P | |
| Estimated capital expenditures(1)(2) ($000’s) | 18,949 | 18,949 | 88,213 | 88,213 |
| Change in FDC ($000’s) | (9,338) | (690) | 31,407 | 72,034 |
| Finding and development (“F&D”) costs(2)(3) ($000’s) | 9,611 | 18,259 | 119,620 | 160,247 |
| Reserve (reductions) additions(3)(4) (Mboe) | (3,313) | (6,241) | 26,161 | 51,791 |
| F&D costs per boe(2)(3) ($/boe) | n/a | n/a | 4.57 | 3.09 |
| Estimated operating netback(1)(2) ($/boe) | 18.04 | 18.04 | 22.62 | 22.62 |
| Recycle ratio(2)(3) | n/a | n/a | 4.9x | 7.3x |
Notes:
(1) Financial information is based on the Company’s preliminary 2023 unaudited financial statements and is therefore subject to change. See “Advisories: Unaudited Financial Information“.
(2) Non-GAAP financial measure. See “Advisories: Non-GAAP Financial Measures“.
(3) See “Advisories: Reserves Disclosure” and “Advisories: Oil and Gas Metrics“.
(4) Based on gross reserves, which are the Company’s working interest share before deduction of royalties.
January 2024 Sales Volumes and Realized Prices
In January 2024, we achieved average net sales volumes of 7,436 boe/d as follows:
· Cascadura contributed net sales volumes of 5,799 boe/d consisting of:
– net natural gas sales volumes of 32.8 MMcf/d or 5,460 boe/d with a realized price of $2.47 per Mcf; and
– net natural gas liquids volumes of 339 bbls/d with an average realized price of $68.15 per barrel;
· Coho field net average natural gas sales volumes were 2.8 MMcf/d or 467 boe/d at a realized price of $2.28 per Mcf (excluding third party processing fees); and
· average net daily crude oil sales volumes were 1,170 bbls/d per day with an average realized price of $68.15 per barrel.
January 2024 production decreased by approximately 11 percent from December 2023, attributed to natural declines and the Cascadura Deep-1 well being shut in for four days in the month.
