Touchstone Exploration Inc. (TSX, LON:TXP) has announced 2022 year-end reserves.
Our independent reserves evaluation was prepared by GLJ Ltd. (“GLJ”) with an effective date of December 31, 2022 (the “Reserves Report”). 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. All finding and development (“F&D”) costs below include changes in future development capital (“FDC”). 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, 2022 and is subject to change. Readers are further cautioned to read the applicable advisories contained herein.
Touchstone’s 2022 year-end reserves reflect the sustainability of our low decline asset base, as our 2022 capital program focused on exploration activities on our Ortoire property, where we completed construction of the Coho natural gas facility and continued construction operations of the Cascadura natural gas and liquids facility. Touchstone did not drill any development or exploration wells in the 2022 year.
In 2022 we achieved initial production from our Coho-1 well, which produced net volumes of 5.7 MMcf/d (approximately 955 boe/d) in the fourth quarter of 2022 contributing to average quarterly production volumes of 2,229 boe/d and average 2022 annual production volumes of 1,581 boe/d.
2022 Year-end Reserves Report Highlights
· Relative to year-end 2021 and after 2022 production, we increased PDP gross reserves by 33% to 4,843 Mboe, decreased 1P gross reserves by 0.7% to 38,463 Mboe, decreased 2P gross reserves by 0.6% to 75,074 Mboe and decreased 3P gross reserves by 0.6% to 120,594 Mboe in 2022.
· PDP reserves replaced 2022 annual production by 308%, reflecting forecasted Coho-1 natural gas volumes that were brought online in 2022.
· Our net present value of future net revenues discounted at 10% (“NPV10”) on a before tax PDP basis increased by 21% to $62.6 million, increased by 12% to $530.3 million on a 1P basis, increased by 13% to $993.7 million on a 2P basis, and increased by 12% to $1.47 billion on a 3P basis from the prior year.
· Realized after tax PDP NPV10 of $51.8 million representing an increase of 45% from the prior year, after tax 1P NPV10 increased by 22% from year-end 2021 to $256.6 million, after tax 2P NPV10 increased by 24% from the prior year to $450.6 million and after tax 3P NPV10 increased by 22% from 2021 to $654.9 million.
· Limited development operations and a focus on investing in our natural gas facilities led to a 1P recycle ratio of 0.6 times and a 2P recycle ratio of 0.2 times.
· We continue to maintain a long producing reserve life index (“RLI”) of 5.8 years PDP and 13.1 years 1P reflecting the low decline nature of our asset base.
2022 Year-end Reserves Report Summary
Touchstone’s year-end crude oil, natural gas and NGL 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 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 on or before March 31, 2023.
The reserve estimates set forth below are based upon GLJ’s Reserves Report dated March 3, 2023 with an effective date of December 31, 2022. 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.). 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, 2022.
2022 Reserves Summary by Category
| PDP | 1P | 2P | 3P | |
| Total gross reserves(1) (Mboe) | 4,843 | 38,463 | 75,074 | 120,594 |
| Reserve additions (reductions)(2) (Mboe) | 1,769 | 306 | 101 | (164) |
| NPV10 before income tax(3) ($000’s) | 62,561 | 530,264 | 993,714 | 1,473,380 |
| NPV10 after income tax(3) ($000’s) | 51,770 | 256,623 | 450,624 | 654,913 |
Notes:
(1) Gross reserves are the Company’s working interest share before deduction of royalties.
(2) Reserve additions exclude period production. See “Advisories: Oil and Gas Metrics“.
(3) Based on the three Consultants’ average December 31, 2022 forecast prices and costs. See “Forecast prices and costs“.
Year-Over-Year Reserves Data
| December 31, 2022 | December 31, 2021(1) | % Change | |
| PDP gross reserves(2) (Mboe) | 4,843 | 3,648 | 33 |
| 1P gross reserves(2) (Mboe) | 38,463 | 38,731 | (1) |
| 2P gross reserves(2) (Mboe) | 75,074 | 75,547 | (1) |
| 3P gross reserves(2) (Mboe) | 120,594 | 121,332 | (1) |
| PDP NPV10 before income tax(3) ($000’s) | 62,561 | 51,737 | 21 |
| 1P NPV10 before income tax(3) ($000’s) | 530,264 | 474,922 | 12 |
| 2P NPV10 before income tax(3) ($000’s) | 993,714 | 881,753 | 13 |
| 3P NPV10 before income tax(3) ($000’s) | 1,473,380 | 1,313,006 | 12 |
| PDP NPV10 after income tax(3) ($000’s) | 51,770 | 35,781 | 45 |
| 1P NPV10 after income tax(3) ($000’s) | 256,623 | 210,036 | 22 |
| 2P NPV10 after income tax(3) ($000’s) | 450,624 | 363,068 | 24 |
| 3P NPV10 after income tax(3) ($000’s) | 654,913 | 535,613 | 22 |
Notes:
(1) Prior year reserve estimates per GLJ’s independent reserves evaluation dated March 4, 2022 with an effective date of December 31, 2021.
(2) Gross reserves are the Company’s working interest share before deduction of royalties.
(3) Based on the three Consultants’ average December 31, 2022 forecast prices and costs. See “Forecast prices and costs“.
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 | 3,470 | 258 | 6,690 | – | 4,843 |
| Developed Non-Producing | 1,529 | 210 | 86,146 | 2,198 | 18,294 |
| Undeveloped | 4,979 | – | 53,841 | 1,373 | 15,326 |
| Total 1P | 9,977 | 468 | 146,677 | 3,571 | 38,463 |
| Probable | 8,711 | 416 | 144,850 | 3,342 | 36,611 |
| Total 2P | 18,688 | 884 | 291,527 | 6,913 | 75,074 |
| Possible | 5,902 | 332 | 205,894 | 4,972 | 45,520 |
| Total 3P | 24,590 | 1,216 | 497,421 | 11,885 | 120,594 |
| 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 | 2,091 | 230 | 5,854 | – | 3,296 |
| Developed Non-Producing | 965 | 187 | 75,378 | 1,923 | 15,638 |
| Undeveloped | 3,658 | – | 47,111 | 1,202 | 12,712 |
| Total 1P | 6,714 | 417 | 128,343 | 3,125 | 31,646 |
| Probable | 6,540 | 370 | 126,744 | 2,925 | 30,959 |
| Total 2P | 13,254 | 787 | 255,086 | 6,049 | 62,605 |
| Possible | 4,342 | 295 | 180,157 | 4,350 | 39,013 |
| Total 3P | 17,596 | 1,082 | 435,243 | 10,399 | 101,618 |
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(1)
| Net Present Values Before Income Taxes ($000’s) | Undiscounted | Discounted at 5% | Discounted at 10% | Discounted at 15% | Discounted at 20% |
| Proved | |||||
| Developed Producing | 84,121 | 71,897 | 62,561 | 55,515 | 50,081 |
| Developed Non-Producing | 373,318 | 303,750 | 256,815 | 222,221 | 195,600 |
| Undeveloped | 349,815 | 268,045 | 210,888 | 169,542 | 138,744 |
| Total 1P | 807,254 | 643,692 | 530,264 | 447,278 | 384,425 |
| Probable | 929,042 | 634,858 | 463,450 | 354,683 | 281,289 |
| Total 2P | 1,736,296 | 1,278,550 | 993,714 | 810,961 | 665,714 |
| Possible | 1,162,845 | 706,880 | 479,666 | 350,833 | 270,402 |
| Total 3P | 2,899,141 | 1,985,430 | 1,473,380 | 1,152,794 | 936,116 |
| Net Present Values After Income Taxes(2) ($000’s) | Undiscounted | Discounted at 5% | Discounted at 10% | Discounted at 15% | Discounted at 20% |
| Proved | |||||
| Developed Producing | 59,691 | 56,612 | 51,770 | 47,274 | 43,432 |
| Developed Non-Producing | 159,207 | 134,649 | 117,278 | 104,014 | 93,519 |
| Undeveloped | 153,285 | 114,778 | 87,576 | 67,879 | 53,270 |
| Total 1P | 372,183 | 306,039 | 256,623 | 219,166 | 190,222 |
| Probable | 383,287 | 265,306 | 194,000 | 148,011 | 116,700 |
| Total 2P | 755,470 | 571,344 | 450,624 | 367,177 | 306,922 |
| Possible | 474,034 | 296,499 | 204,289 | 150,949 | 117,211 |
| Total 3P | 1,229,504 | 867,843 | 654,913 | 518,126 | 424,133 |
Notes:
(1) Based on the three Consultants’ average December 31, 2022 forecast prices and costs. See “Forecast prices and costs“.
(2) The after-tax net present values prepared by GLJ in the evaluation of the Company’s crude oil 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, 2022. 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 total gross proved plus probable reserves as of December 31, 2022 by product type against such reserves as at December 31, 2021 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, 2021(2) | 10,174 | 471 | 147,093 | 3,571 | 38,731 |
| Extensions and improved recovery(3) | 94 | – | – | – | 94 |
| Technical revisions(4) | 169 | 23 | 111 | – | 211 |
| Production | (460) | (27) | (527) | – | (574) |
| December 31, 2022 | 9,977 | 468 | 146,677 | 3,571 | 38,463 |
| Total Probable | |||||
| December 31, 2021(2) | 8,908 | 458 | 144,642 | 3,342 | 36,815 |
| Technical revisions(4) | (201) | (42) | 208 | – | (208) |
| Economic factors(5) | 3 | – | – | – | 3 |
| December 31, 2022 | 8,711 | 416 | 144,850 | 3,342 | 36,611 |
| Total Proved plus Probable | |||||
| December 31, 2021(2) | 19,082 | 929 | 291,735 | 6,914 | 75,547 |
| Extensions and improved recovery(3) | 94 | – | – | – | 94 |
| Technical revisions(4) | (31) | (18) | 320 | – | 4 |
| Economic factors(5) | 3 | – | – | – | 3 |
| Production | (460) | (27) | (527) | – | (574) |
| December 31, 2022 | 18,688 | 884 | 291,527 | 6,913 | 75,074 |
Notes:
(1) NGLs are comprised of 100 percent condensate.
(2) Prior year reserve estimates per GLJ’s independent reserves evaluation dated March 4, 2022 with an effective date of December 31, 2021.
(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.
In comparison to December 31, 2021 on a proved plus probable reserve basis, 2022 light and medium crude oil reserves declined 394 Mbbl. Improved recovery attributed to well recompletions was offset by 2022 annual production. 2022 proved plus probable heavy crude oil reserves decreased by 45 Mbbl from the prior year due to downward technical revisions of 18 Mbbl associated with reduced well performance at our Fyzabad block, combined with 27 Mbbl of production. Proved plus probable conventional natural gas reserves decreased by 208 MMcf relative to December 31, 2021, as an increase from reduced surface loss estimates related to Coho was offset by 2022 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 |
| 2023 | 190 | 23,648 | 26,938 | 26,938 |
| 2024 | – | 31,810 | 45,006 | 45,006 |
| 2025 | – | 8,841 | 38,067 | 38,067 |
| 2026 | – | 11,232 | 15,885 | 15,885 |
| 2027 | – | 11,213 | 15,470 | 15,470 |
| Thereafter | – | – | – | – |
| Total undiscounted | 190 | 86,744 | 141,366 | 141,366 |
| Total discounted at 10% per year | 181 | 72,435 | 116,145 | 116,145 |
The following table sets forth the changes in undiscounted future development costs included in the Reserves Report against such costs in our December 31, 2021 reserves report prepared by GLJ dated March 4, 2022.
| ($000’s unless otherwise stated) | PDP | 1P | 2P | 3P |
| (Decrease) / increase in forecasted capital costs | (110) | 3,450 | 5,685 | 5,685 |
| Increase in forecasted wells | – | 4,757 | 4,720 | 4,720 |
| Decrease in forecasted facility and pipeline costs | – | (1,477) | (2,613) | (2,613) |
| Total (decrease) / increase in FDC from 2021 | (110) | 6,730 | 7,792 | 7,792 |
| Total (decrease) / increase in FDC from 2021 (%) | (37) | 8 | 6 | 6 |
Forecast Pricing and Costs
Forecast pricing and costs are prices and costs that are generally acceptable, in the opinion of GLJ, as being a reasonable outlook of the future as of the evaluation effective date. The forecast cost assumptions consider inflation with respect to future operating and capital costs. The following table sets forth the benchmark reference prices and inflation rates reflected in the Reserves Data as of December 31, 2022. These price assumptions were provided to the Company by GLJ and represented the average price forecast of the three Consultants as of the date of the Reserves Report.
| Consultants Average Price Forecast | |||
| Forecast Year | Brent Spot Crude Oil(1)($/bbl) | Henry Hub Natural Gas(1)($/MMBtu) | Inflation Rate(% per year) |
| 2023 | 84.67 | 4.74 | 0.0 |
| 2024 | 82.69 | 4.50 | 2.3 |
| 2025 | 81.03 | 4.31 | 2.0 |
| 2026 | 81.39 | 4.40 | 2.0 |
| 2027 | 82.65 | 4.49 | 2.0 |
| 2028 | 84.29 | 4.58 | 2.0 |
| 2029 | 85.98 | 4.67 | 2.0 |
| 2030 | 87.70 | 4.76 | 2.0 |
| 2031 | 89.46 | 4.86 | 2.0 |
| 2032 | 91.25 | 4.95 | 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
| 2022 | ||||
| 2022 – 2020 Total | ||||
| 1P | 2P | 1P | 2P | |
| Estimated capital expenditures(1),(4) ($000’s) | 11,330 | 11,330 | 57,763 | 57,763 |
| Change in FDC ($000’s) | 6,730 | 7,792 | 41,369 | 69,685 |
| F&D costs(2),(4) ($000’s) | 18,060 | 19,122 | 99,132 | 127,448 |
| Reserve additions(2),(3) (Mboe) | 306 | 101 | 28,193 | 54,588 |
| F&D costs per boe(2),(4) ($/boe) | 59.02 | 189.33 | 3.52 | 2.33 |
| Estimated operating netback(1),(4) ($/boe) | 33.42 | 33.42 | 25.16 | 25.16 |
| Recycle ratio(2),(4) | 0.6x | 0.2x | 7.2x | 10.8x |
Notes:
(1) Financial information is based on the Company’s preliminary 2022 unaudited financial statements and is therefore subject to change. See “Advisories: Unaudited Financial Information“.
(2) See “Advisories: Reserves Advisory” and “Advisories: Oil and Gas Metrics“.
(3) Based on gross reserves, which are the Company’s working interest share before deduction of royalties.
(4) Non-GAAP financial measure. See “Advisories: Non-GAAP Financial Measures “.
