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”. |
Advisories
Forward-Looking Statements
Certain information provided in this press release may constitute forward-looking statements within the meaning of applicable securities laws. Forward-looking information in this press release may include, but is not limited to, statements relating to estimated crude oil reserves, current field estimated production, the potential undertaking, timing, locations and costs of future well drilling, the quality and quantity of prospective hydrocarbon accumulations as indicated by wireline logs, drilling location inventory, future development costs associated with crude oil reserves, and sufficiency of resources to fund operations. 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. Because 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 Annual Information Form dated March 21, 2017 which has been filed on SEDAR and can be accessed at www.sedar.com. The forward-looking statements contained in this press release are made as of the date hereof; and except as may be required by applicable securities laws, the Company assumes no obligation to update publicly or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.
Statements relating to reserves are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. The recovery and reserve estimates of Touchstone’s reserves provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered. Consequently, actual results may differ materially from those anticipated in the forward-looking statements.
Oil and Natural Gas Reserves
The disclosure in this press release summarizes certain information contained in the Reserves Report but represents only a portion of the disclosure required under NI 51-101. Full disclosure with respect to the Company’s reserves as at December 31, 2017 will be contained in the Company’s Annual Information Form for the year ended December 31, 2017 which will be filed on SEDAR on or before March 31, 2018. All evaluations and reviews of future net revenues are stated prior to any provision for finance expenses or general and administrative costs and after the deduction of estimated future capital expenditures and estimated future well abandonment costs. It should not be assumed that the present worth of estimated future net revenues presented in the tables above represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserves estimates of crude oil provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil reserves may be greater than or less than the estimates provided herein.
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 is beyond the current term of the relevant operating agreements.
Oil and Gas Metrics
This press release contains certain oil and gas metrics that are commonly used in the oil and gas industry such as reserves additions, reserves replacement ratio, reserve life index, finding and development costs, and recycle ratio. These metrics do not have standardized meanings or standardized methods of calculation and therefore such measures may not be comparable to similar measures presented by other companies. Such metrics have been included herein to provide readers with additional metrics 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 prior periods and therefore such metrics should not be unduly relied upon. The Company uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment purposes.
Net reserve additions are calculated as the change in reserves from the beginning to the end of the applicable period excluding period production. Reserves replacement ratio is calculated as period net reserve additions divided by period production. Reserve life index is calculated as total Company gross reserves divided by annual production.
Finding and development costs are the sum of capital expenditures excluding capitalized general and administrative costs and corporate capital expenditures incurred in the period and the change in future development costs required to develop those reserves. The Company’s annual audit of its December 31, 2017 consolidated financial statements is not complete. Accordingly, unaudited capital expenditure amounts used in the calculation of finding and development costs are Management’s estimate and are subject to change. Finding and development costs per barrel is determined by dividing current period net reserve additions to the corresponding period’s finding and development cost. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
Recycle ratios are calculated by dividing the current period finding and development costs per barrel to operating netbacks prior to realized gains or losses on commodity derivative contracts in the corresponding period (see “Non-GAAP Measures”). The Company’s annual audit of its December 31, 2017 consolidated financial statements is not complete. Accordingly, unaudited operating netbacks used in the calculation of recycle ratio are Management’s estimate and are subject to change. The recycle ratio compares netbacks from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement of reserves are of equivalent quality as the produced reserves.
Drilling Locations
This press release discloses drilling locations in three categories: (i)1P locations; (ii) 2P locations; and (iii) unbooked locations.1P locations and 2P locations are derived from the Reserves Report and account for locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the prospective acreage associated with the Company’s assets and an assumption as to the number of wells that can be drilled based on industry practice and internal review. Unbooked locations do not have attributed reserves. Of the approximately 208 (net) drilling locations identified herein, 62 (net) are 1P locations; 28 (net) are 2P locations; and the remaining are unbooked locations. Unbooked locations have been identified by Management as an estimation of the Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked locations, and if drilled there is no certainty that such locations will result in additional oil and gas reserves or production. The locations on which the Company will actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, crude oil prices, costs, actual drilling results, additional reservoir information that can be obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where Management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations, and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production.
Non-GAAP Measures
The Company uses operating netback as a key performance indicator of field results. Operating netback does not have a standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures by other companies. Operating netback is presented on a per barrel basis and is calculated by deducting royalties and operating expenses from petroleum revenue. Operating netback is presented herein prior to realized gains or losses on commodity derivative contracts. The Company’s annual audit of its December 31, 2017 consolidated financial statements is not complete. Accordingly, unaudited figures used in the calculation of operating netback and recycle ratios are Management’s estimate and are subject to change. The Company considers operating netbacks to be a key measure as they demonstrate Touchstone’s profitability relative to current commodity prices. This measurement assists Management and investors in evaluating operating results on a per barrel basis to analyze performance on a historical basis.
Crude Oil Abbreviations
| bbl(s) | barrel(s) | |
| bbls/d | barrels per day | |
| Mbbl | one thousand barrels |
About Touchstone
Touchstone Exploration Inc. is a Calgary 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”.
Contact
Mr. Paul Baay, President and Chief Executive Officer; or
Mr. James Shipka, Chief Operating Officer
Telephone: 403.750.4487
www.touchstoneexploration.com