CALGARY, ALBERTA–(Marketwired – March 20, 2017) – Touchstone Exploration Inc. (“Touchstone” or the “Company”) (TSX:TXP) announces the results of the independent December 31, 2016 reserve evaluation (the “Reserves Report”) with respect to the Company’s crude oil reserves in the Republic of Trinidad and Tobago (“Trinidad”). Amounts herein are in Canadian dollars unless otherwise stated.
Touchstone’s year-end reserves were evaluated by independent reserves evaluator GLJ Petroleum Consultants Ltd. (“GLJ”) in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation (“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 on or before March 31, 2017. The reserves estimates set forth below are based upon GLJ’s Reserve Report dated March 17, 2017. 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, 2016. All financial information presented in this press release are based on estimates and are unaudited.
In 2016 Touchstone remained sensitive to the low commodity price environment and continued to follow a strategy of conservatively deploying exploration and development capital. The Company focused on operations directly related to maintaining production from the Company’s core assets and arresting base declines through low cost recompletion projects. Touchstone recompleted a total of nine wells and stimulated two wells as part of an evaluation project but deployed no drilling capital during the fiscal year. Notwithstanding the Company’s minimal capital investment in 2016, annual crude oil production was 476,057 barrels, representing an average of 1,301 barrels per day. The Company was able to organically grow reserves as a result of better than previously forecasted well performance and the effectiveness of the recompletion program.
2016 Reserve Report Highlights
• | Proved developed producing reserves (“PDP”): | ||
– | Decreased 6% to 4,606 Mbbl, replacing 40% of 2016 production. | ||
– | Reserve life index of 9.9 years based on forecast 2017 PDP production of 1,277 bbls/d. | ||
– | PDP comprise 51% of 1P and 29% of 2P. | ||
• | Proved reserves (“1P”): | ||
– | Increased 2% to 8,977 Mbbl, replacing 134% of 2016 production. | ||
– | Reserve life index of 15.1 years based on forecast 2017 1P production of 1,628 bbls/d. | ||
– | 1P comprise 57% of 2P. | ||
• | Proved plus probable reserves (“2P”): | ||
– | Increased 2% to 15,698 Mbbl, replacing 149% of 2016 production. | ||
– | Reserve life index of 24.0 years based on forecast 2017 2P production of 1,790 bbls/d. | ||
• | Total 2P net present value of future net revenues before tax (10 percent discount rate) of $324.9 million ($161.1 million on a 1P basis). | ||
• | Total 2P net present value of future net revenues after tax (10 percent discount rate) of $130.7 million, which excluding net debt equated to a net asset value of $1.57 per basic common share ($72.7 million or $0.87 per basic common share on a 1P basis). | ||
• | Total future development costs (“FDC”) of $48.7 million for 1P and $72.3 million for 2P. | ||
• | Finding and development costs (including changes in FDC) were $7.35 for 1P and $6.00 for 2P. Using the Company’s estimated operating netback before hedging of $15.08 per barrel, the 1P recycle ratio was 2.05 times and the 2P recycle ratio was 2.51 times. |
Future development costs are associated with a portion of the Company’s internally identified drilling location inventory and the Company’s estimated portfolio of low cost, low risk recompletion projects.
• | 1P have been assigned for 52 drilling locations (25% of the Company’s identified drilling inventory) and 64 recompletions (19% of the Company’s identified recompletion projects). | |
• | 2P have been assigned to 78 drilling locations (38% of the Company’s identified drilling inventory) and 122 recompletions (36% of the Company’s identified recompletion projects). |
The Company’s total inventory of 208 drilling locations and 338 recompletion or workover projects are based upon current Management estimates. The Company currently operates 1,133 wells in Trinidad, 410 of which had associated production in 2016.
GLJ has forecast reserve volumes and future cash flows based upon current and historical well performance through to the economic production limit of individual wells. Notwithstanding established precedence and contractual options for the continuation and renewal of the Company’s existing operating agreements, in many cases the forecast economic limit of individual wells are beyond the current term of the relevant operating agreements.
2016 Year-end Reserves Summary
The tables below disclose the following in relation to the Company’s development properties, which as of December 31, 2016 are all located onshore within Trinidad. The figures in the following tables have been prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in NI 51-101. In certain tables set forth below, the columns may not add due to rounding. All dollar amounts are reported in thousands of Canadian dollars unless otherwise indicated.
December 31, 2016 Gross Reserves(1),(2)
Light and Medium Oil (Mbbl) |
Heavy Oil (Mbbl) |
Total Oil Equivalent (Mbbl) |
||
Proved | ||||
Proved producing | 3,955 | 651 | 4,606 | |
Proved non-producing | 735 | 213 | 948 | |
Proved undeveloped | 2,890 | 533 | 3,423 | |
Total proved | 7,580 | 1,397 | 8,977 | |
Probable | 5,914 | 808 | 6,722 | |
Total proved plus probable | 13,494 | 2,205 | 15,698 | |
(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“. | ||||
Reconciliation of Changes in Gross Reserves(1),(2)
Proved (Mbbl) |
Proved Plus Probable(Mbbl) |
||
December 31, 2015 | 8,815 | 15,465 | |
Extensions and improved recovery | 481 | 466 | |
Technical revisions | 190 | 276 | |
Economic factors | (33) | (33) | |
Production | (476) | (476) | |
December 31, 2016 | 8,977 | 15,698 | |
Reserves replacement ratio (%)(3) | 134 | 149 | |
(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 increase to reserves divided by 2016 average production of 476 Mbbl. See “Advisories – Oil and Gas Metrics“. | |||
Net Present Values of Future Net Revenue as of December 31, 2016(1),(2)
Net Present Values of Future Net Revenues Before Income Taxes Discounted at (% per year) ($000’s) | ||||||
0% | 5% | 10% | 15% | 20% | ||
Proved | ||||||
Proved producing | 135,098 | 83,260 | 62,240 | 50,732 | 43,305 | |
Proved non-producing | 49,825 | 41,109 | 34,654 | 29,732 | 25,887 | |
Proved undeveloped | 112,953 | 83,755 | 64,199 | 50,503 | 40,562 | |
Total proved | 297,876 | 208,125 | 161,093 | 130,967 | 109,753 | |
Probable | 327,003 | 220,407 | 163,770 | 128,052 | 103,516 | |
Total proved plus probable | 624,878 | 428,551 | 324,863 | 259,018 | 213,269 | |
Net Present Values of Future Net Revenues After Income Taxes(3)Discounted at (% per year) ($000’s) | ||||||
0% | 5% | 10% | 15% | 20% | ||
Proved | ||||||
Proved producing | 65,425 | 46,613 | 38,095 | 32,990 | 29,449 | |
Proved non-producing | 18,099 | 15,447 | 13,486 | 11,982 | 10,795 | |
Proved undeveloped | 39,408 | 28,407 | 21,088 | 15,985 | 12,301 | |
Total proved | 122,931 | 90,466 | 72,668 | 60,958 | 52,546 | |
Probable | 114,765 | 77,910 | 58,072 | 45,426 | 36,686 | |
Total proved plus probable | 237,696 | 168,376 | 130,740 | 106,383 | 89,233 | |
(1) Based on GLJ’s December 31, 2016 escalated price forecast. See “Pricing and Foreign Exchange Assumptions“. | ||||||
(2) See “Advisories: Oil and Natural Gas Reserves“. | ||||||
(3) Income taxes include all resource income, appropriate income tax calculations per current Trinidad tax regulations and estimated December 31, 2016 tax pools and non-capital losses. |
Pricing and Foreign Exchange Assumptions
The following table sets forth the benchmark reference prices reflected in the Reserves Report. This price forecast was GLJ’s standard price forecast effective January 1, 2017.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS AS OF JANUARY 1, 2017(1) | |||||
Forecast Year |
Inflation Rate (%/year) |
US$/Cdn$ Exchange Rate |
WTI Cushing Oklahoma (US$/bbl) |
Brent Blend Crude Oil FOB North Sea (US$/bbl) |
Edmonton Par Price 40 API Light Sweet Crude Oil (Cdn$/bbl) |
2017 | 2.0 | 0.750 | 55.00 | 57.00 | 69.33 |
2018 | 2.0 | 0.775 | 59.00 | 61.00 | 72.26 |
2019 | 2.0 | 0.800 | 64.00 | 66.00 | 75.00 |
2020 | 2.0 | 0.825 | 67.00 | 70.00 | 76.36 |
2021 | 2.0 | 0.850 | 71.00 | 74.00 | 78.82 |
2022 | 2.0 | 0.850 | 74.00 | 77.00 | 82.35 |
2023 | 2.0 | 0.850 | 77.00 | 80.00 | 85.88 |
2024 | 2.0 | 0.850 | 80.00 | 83.00 | 89.41 |
2025 | 2.0 | 0.850 | 83.00 | 86.00 | 92.94 |
2026 | 2.0 | 0.850 | 86.05 | 89.64 | 95.61 |
Thereafter | 2.0 | 0.850 | +2.0%/year | +2.0%/year | +2.0%/year |
(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. |
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 Incurred | For Proved Reserves ($000’s) |
For Proved Plus Probable Reserves ($000’s) |
2017 | 5,980 | 5,980 |
2018 | 13,617 | 19,181 |
2019 | 21,897 | 33,742 |
2020 | 7,206 | 13,398 |
Thereafter | – | – |
Total undiscounted | 48,700 | 72,301 |
Total discounted at 10% per year | 39,921 | 58,513 |
Estimated Finding and Development Costs Including FDC
For Proved Reserves |
For Proved Plus Probable Reserves |
|
Exploration capital expenditures (000’s)(1),(2) | 1,823 | 1,823 |
Development capital expenditures (000’s)(1),(2) | 842 | 842 |
Change in future development costs ($000’s) | 2,022 | 1,592 |
Estimated Finding and development costs ($000’s)(3) | 4,687 | 4,257 |
Net reserve additions (Mbbl)(3) | 638 | 709 |
Estimated finding and development costs per barrel ($/bbl)(3) | 7.35 | 6.00 |
(1) Financial information is based on the Company’s preliminary 2016 unaudited financial statements and is therefore subject to audit. Accordingly, unaudited capital expenditure amounts used in the calculation of finding and development costs are management’s estimate and are subject to change. | ||
(2) Exploration and development capital excludes capitalized general and administration costs. See “Advisories – Oil and Gas Metrics“. | ||
(3) See “Advisories: Oil and Natural Gas Reserves” and “Advisories – Oil and Gas Metrics“. |