CALGARY, Alberta, March 08, 2018 (GLOBE NEWSWIRE) — Touchstone Exploration Inc. (“Touchstone” or the “Company”) (TSX:TXP) (LSE:TXP) announces the results of its independent year-end 2017 reserves evaluation. Reserve numbers provided herein were derived from an independent reserves report (the “Reserves Report”) prepared by GLJ Petroleum Consultants Ltd. (“GLJ”) effective December 31, 2017.
All currency amounts are in Canadian dollars unless otherwise stated. The financial information contained herein is based on the Company’s unaudited expected results for the year ended December 31, 2017 and is subject to change.
The Company expects to release an operational update next week and 2017 year-end results on March 27, 2018.
2017 Year-end Reserve Report Highlights
- The Company increased proved reserves (“1P”) by 20% or 1,756 Mbbl after production and increased proved plus probable reserves (“2P”) by 18% or 2,837 Mbbl after production.
- The increase in reserves replaced production by 450% on a 1P basis and 665% on a 2P basis.
- The Company’s December 31, 2017 net present value of future net revenues before tax (discounted at 10 percent) was $407.9 million ($210.5 million on a 1P basis).
- December 31, 2017 net present value of future net revenues after tax (discounted at 10 percent) was $156.7 million ($83.5 million on a 1P basis).
- Future development costs (“FDC”) associated with a portion of the Company’s internally identified drilling location inventory and portfolio of low risk recompletion projects totaled $57.8 million for 1P and $85.3 million for both 2P.
- Finding and development costs (including changes in FDC) were $7.66 for 1P and $6.33 for 2P. Using the Company’s estimated 2017 operating netback of $24.23 per barrel, the 1P recycle ratio was 3.2 times, and the 2P recycle ratio was 3.8 times.
- The Company’s asset base remains conservatively booked, with 1P assigned 62 drilling locations (30% of the Company’s identified drilling inventory) and 2P assigned 90 drilling locations (43% of the Company’s identified drilling inventory).
2017 Year-end Reserves Summary
Touchstone’s year-end crude 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, 2018. The reserves estimates set forth below are based upon GLJ’s Reserve Report dated March 7, 2018. All values in this press release are based on GLJ’s forecast prices and estimates of future operating and capital costs as at December 31, 2017.
In certain tables set forth below, the columns may not add due to rounding. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
Summary of Gross Oil Reserves as of December 31, 2017 by Product Type(1),(2)
Reserves Category | Light and Medium Oil (Mbbl) |
Heavy Oil (Mbbl) |
Total Oil Equivalent (Mbbl) |
||
Proved | |||||
Developed Producing | 4,017 | 571 | 4,588 | ||
Developed Non-Producing | 781 | 213 | 994 | ||
Undeveloped | 4,594 | 558 | 5,152 | ||
Total Proved | 9,391 | 1,342 | 10,733 | ||
Probable | 7,058 | 744 | 7,802 | ||
Total Proved plus Probable | 16,450 | 2,086 | 18,535 | ||
Possible | 5,297 | 624 | 5,921 | ||
Total Proved plus Probable plus Possible | 21,747 | 2,710 | 24,456 |
Notes: | |
(1) | Gross Reserves are the Company’s working interest share of the remaining reserves before deduction of any royalties. |
(2) | See “Advisories: Oil and Natural Gas Reserves”. |
Summary of Net Present Values of Future Net Revenue as of December 31, 2017(1),(2)
Reserves Category | Net Present Values of Future Net Revenues Before Income Taxes Discounted at (% per year) ($000’s) | |||||||||
0% | 5% | 10% | 15% | 20% | ||||||
Proved | ||||||||||
Developed Producing | 114,771 | 79,682 | 62,994 | 53,032 | 46,294 | |||||
Developed Non-Producing | 53,820 | 44,682 | 37,912 | 32,742 | 28,692 | |||||
Undeveloped | 195,543 | 140,798 | 109,612 | 88,523 | 73,281 | |||||
Total Proved | 364,134 | 265,163 | 210,518 | 174,297 | 148,268 | |||||
Probable | 393,087 | 265,708 | 197,411 | 154,840 | 125,856 | |||||
Total Proved plus Probable | 757,221 | 530,871 | 407,929 | 329,136 | 274,124 | |||||
Possible | 323,132 | 188,257 | 132,408 | 102,272 | 83,287 | |||||
Total Proved plus Probable plus Possible | 1,080,353 | 719,128 | 540,337 | 431,408 | 357,411 |
Reserves Category | Net Present Values of Future Net Revenues After Income Taxes(3) Discounted at (% per year) ($000’s) | |||||||||
0% | 5% | 10% | 15% | 20% | ||||||
Proved | ||||||||||
Developed Producing | 48,259 | 37,339 | 31,670 | 28,047 | 25,452 | |||||
Developed Non-Producing | 19,282 | 16,114 | 13,779 | 12,002 | 10,614 | |||||
Undeveloped | 69,483 | 49,554 | 38,035 | 30,218 | 24,574 | |||||
Total Proved | 137,024 | 103,007 | 83,484 | 70,267 | 60,640 | |||||
Probable | 141,383 | 97,435 | 73,214 | 57,881 | 47,356 | |||||
Total Proved plus Probable | 278,406 | 200,442 | 156,698 | 128,148 | 107,996 | |||||
Possible | 113,175 | 69,477 | 50,329 | 39,691 | 32,888 | |||||
Total Proved plus Probable plus Possible | 391,581 | 269,919 | 207,027 | 167,839 | 140,884 |
Notes: | |
(1) | Based on GLJ’s December 31, 2017 escalated price forecast. See “Summary of Pricing, Inflation and Foreign Exchange Assumptions”. |
(2) | See “Advisories: Oil and Natural Gas Reserves”. |
(3) | Income taxes include all resource income, appropriate income tax calculations per current Republic of Trinidad and Tobago tax regulations and estimated December 31, 2017 consolidated tax pools and non-capital losses. |
Summary of Pricing, Inflation and Foreign Exchange Assumptions
The following table sets forth the benchmark reference prices, inflation and foreign exchange rates reflected in the Reserves Report.
Forecast Year | NYMEX WTI at Cushing, Oklahoma (US$/bbl)(1) |
Brent Blend FOB North Sea (US$/bbl)(1) |
Inflation Rate (%/year)(2) |
US$/C$ Exchange Rate(3) |
||
2018 | 59.00 | 65.50 | 2.0 | 0.79 | ||
2019 | 59.00 | 63.50 | 2.0 | 0.79 | ||
2020 | 60.00 | 63.00 | 2.0 | 0.80 | ||
2021 | 63.00 | 66.00 | 2.0 | 0.81 | ||
2022 | 66.00 | 69.00 | 2.0 | 0.82 | ||
2023 | 69.00 | 72.00 | 2.0 | 0.83 | ||
2024 | 72.00 | 75.00 | 2.0 | 0.83 | ||
2025 | 75.00 | 78.00 | 2.0 | 0.83 | ||
2026 | 77.33 | 80.33 | 2.0 | 0.83 | ||
2027 | 78.88 | 81.88 | 2.0 | 0.83 | ||
Thereafter % change per year | 2.0% | 2.0% | Nil | Nil | ||
Notes: | |
(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 quality differentials and transportation to point of sale. |
(2) | Inflation rates for forecasting pricing and costs. |
(3) | Exchange rates used to generate the benchmark reference prices in this table. |
Reconciliation of Changes in Gross Reserves(1),(2)
Factors | Total Proved Reserves (Mbbl) |
Total Proved plus Probable Reserves (Mbbl) |
|||
December 31, 2016 | 8,977 | 15,698 | |||
Extensions and improved recovery | 1,880 | 3,256 | |||
Technical revisions | 386 | 110 | |||
Economic factors | (8) | (26) | |||
Production | (502) | (502) | |||
December 31, 2017 | 10,733 | 18,535 | |||
Reserves replacement ratio (%)(3) | 450 | 665 |
Notes: | |
(1) | Gross Reserves are the Company’s working interest share of the remaining reserves before deduction of any royalties. |
(2) | See “Advisories: Oil and Natural Gas Reserves”. |
(3) | Reserves replacement ratio is calculated as net increase to reserves divided by 2017 average production of 502 Mbbl. See “Advisories: Oil and Gas Metrics”. |
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 | Total Proved Reserves ($000’s) |
Total Proved plus Probable Reserves ($000’s) |
|
2018 | 10,400 | 13,170 | |
2019 | 18,039 | 23,633 | |
2020 | 18,020 | 25,703 | |
2021 | 11,384 | 22,780 | |
Thereafter | – | – | |
Total undiscounted | 57,842 | 85,287 | |
Total discounted at 10% per year | 47,906 | 69,615 |
Reserve Life Index by Reserves Category(1),(2)
The Company reduced its December 31, 2017 2P reserve life index by 19% from year-end 2016 from 24.0 years to 20.2 years. The following table provides the reserve life index by reserves category as included in the Reserves Report.
Reserves Category | Gross Reserves Volume (Mbbl) |
Reserve Life (years) |
Reserve Life Index (years) |
||
Total Proved | 10,733 | 50.0 | 14.2 | ||
Total Probable | 7,802 | 50.0 | 48.7 | ||
Total Proved plus Probable | 18,535 | 50.0 | 20.2 |
Notes: | |
(1) | Gross Reserves are the Company’s working interest share of the remaining reserves before deduction of any royalties. |
(2) | See “Advisories: Oil and Gas Metrics”. |
Estimated Company Gross Reserve Metrics(1)
Total Proved Reserves |
Total Proved plus Probable Reserves |
|
Exploration capital expenditures ($000’s)(2),(3) | 1,183 | 1,183 |
Development capital expenditures ($000’s)(2),(3) | 6,960 | 6,960 |
Change in future development costs ($000’s) | 9,142 | 12,986 |
Estimated finding and development costs(4) | 17,285 | 21,129 |
Net reserve additions (Mbbl)(4) | 2,258 | 3,339 |
Estimated finding and development costs per barrel ($/bbl)(4) | 7.66 | 6.33 |
Estimated 2017 operating netback ($/bbl)(2),(5) | 24.23 | 24.23 |
Estimated recycle ratio(4) | 3.2x | 3.8x |
Notes: | |
(1) | Gross Reserves are the Company’s working interest share of the remaining reserves before deduction of any royalties. |
(2) | Financial information is based on the Company’s preliminary 2017 unaudited financial statements and is therefore subject to audit. Accordingly, unaudited capital expenditure amounts and operating netbacks used in the calculation of finding and development costs and recycle ratios are Management’s estimate and are subject to change. |
(3) | Exploration and development capital excludes capitalized general and administration costs and corporate asset expenditures. See “Advisories: Oil and Gas Metrics”. |
(4) | See “Advisories: Oil and Natural Gas Reserves” and “Advisories: Oil and Gas Metrics”. |
(5) | See “Non-GAAP Measures”. |