Touchstone Exploration Inc (LON:TXP) today announced highlights of our independent reserves evaluation prepared by GLJ Petroleum Consultants Ltd. with an effective date of December 31, 2019.
Highlights of our total proved (“1P”), total proved plus probable (“2P”) and total proved plus probable plus possible reserves from the Reserves Report are provided below. All finding, development and acquisition (“FD&A”) costs below include changes in future development capital (“FDC”). Unless otherwise stated, all financial amounts herein are rounded to thousands of United States dollars. The financial information contained herein is based on the Company’s unaudited expected results for the year ended December 31, 2019 and is subject to change.
Touchstone’s 2019 capital program focused on exploration activities on our Ortoire property, where we drilled two gross (1.6 net) exploration wells. We conducted minimal capital development activity on our development properties, mainly performing wellbore recompletions to arrest production declines. The Reserves Report included those reserves associated with our development properties as well as new reserves associated with our Coho natural gas discovery in 2019. The Reserves Report does not include any reserves associated with the Cascadura discovery given well testing commenced subsequent to the effective date of the report.
2019 Year-end Reserves Report Highlights
· Increased 1P reserves by 6% to 11,840 Mboe and increased 2P reserves by 14% to 22,056 Mboe from the prior year.
· Replaced 2019 annual production by 193% on a 1P reserves basis and 519% on a 2P reserves basis.
· Realized after tax 1P 10% discounted net present value of future net revenues (“NPV10”) of $83.7 million, representing an increase of $4.0 million or 5% from the prior year.
· Achieved an after tax 2P NPV10 of $153.9 million, an increase of 6% from $145.4 million in 2018.
· Realized 1P FD&A costs of $7.75 per boe, resulting in a recycle ratio 3.4 times using our unaudited annual 2019 operating netback of $26.62 per boe.
· Achieved 2P FD&A costs of $3.95 per boe, resulting in a 2P recycle ratio of 6.7 times.
· FDC associated with only a portion of our internally identified drilling location inventory and portfolio of low risk recompletion projects totaled $45.4 million for 1P reserves and $71.7 million for 2P reserves.
· Coho was assigned gross working interest 1P reserves of 1,148 Mboe and gross working interest 2P reserves of 3,349 Mboe with a 2P NPV10 of $27.5 million before taxes.
James Shipka, Chief Operating Officer, commented:
“The Company’s independent 2019 reserves evaluation reflected the strong performance of our base production and included the first reserves associated with our discoveries on the Ortoire exploration block. With gross working interest 2P reserves of over 20 Bcf (approximately 3.4 million boe) assigned at Coho, the Company has exceeded the best estimates of the recoverable gas in the pool compared to the independent evaluation report prepared for the Company in the prior year. With the second stage of the production test at Cascadura-1ST1 expected to commence this weekend, we look forward to updating our shareholders on this material discovery and the impact it will have on corporate reserves.”
2019 Year-end Reserves Report Summary
Touchstone’s year-end crude oil and natural gas 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 30, 2020. The reserve estimates set forth below are based upon GLJ’s Reserves Report dated March 4, 2020 with an effective date of December 31, 2019. All values in this announcement are based on GLJ’s forecast prices and estimates of future operating and capital costs as at December 31, 2019. In certain tables set forth below, the columns may not add due to rounding.
Summary of Net Present Values of Future Net Revenues as of December 31, 2019(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 | 101,871 | 74,072 | 60,187 | 51,683 | 45,800 |
| Developed Non-Producing | 96,266 | 75,368 | 62,537 | 53,439 | 46,563 |
| Undeveloped | 137,702 | 102,837 | 79,500 | 63,128 | 51,196 |
| Total Proved | 335,839 | 252,276 | 202,224 | 168,250 | 143,559 |
| Probable | 390,549 | 262,615 | 195,689 | 153,716 | 124,875 |
| Total Proved plus Probable | 726,388 | 514,891 | 397,913 | 321,966 | 268,434 |
| Possible | 310,663 | 184,353 | 129,718 | 99,472 | 80,216 |
| Total Proved plus Probable plus Possible | 1,037,051 | 699,244 | 527,631 | 421,438 | 348,650 |
| Reserves Category | Net Present Values of Future Net Revenues After Income Taxes(3) Discounted at (% per year) ($000’s) | ||||
| 0% | 5% | 10% | 15% | 20% | |
| Proved | |||||
| Developed Producing | 47,867 | 38,463 | 33,156 | 29,569 | 26,893 |
| Developed Non-Producing | 35,676 | 28,865 | 24,651 | 21,648 | 19,360 |
| Undeveloped | 49,677 | 35,447 | 25,933 | 19,293 | 14,503 |
| Total Proved | 133,220 | 102,775 | 83,740 | 70,510 | 60,756 |
| Probable | 139,212 | 94,523 | 70,164 | 54,647 | 43,946 |
| Total Proved plus Probable | 272,431 | 197,297 | 153,904 | 125,157 | 104,702 |
| Possible | 108,046 | 66,699 | 47,646 | 36,801 | 29,817 |
| Total Proved plus Probable plus Possible | 380,477 | 263,996 | 201,550 | 161,958 | 134,519 |
Notes:
(1) Based on GLJ’s December 31, 2019 escalated price forecast. See “Summary of Pricing and Inflation Assumptions“.
(2) See “Advisories: Reserve Advisory“.
(3) Income taxes include all resource income, appropriate income tax calculations per current Republic of Trinidad and Tobago tax regulations and estimated unaudited December 31, 2019 consolidated tax pools and non-capital losses.
Summary of Pricing and Inflation Assumptions
The following table sets forth benchmark reference pricing and inflation rates reflected in the Reserves Report.
| Forecast Year | WTI Crude Oil Cushing, Oklahoma ($/bbl)(1) | Brent Spot Crude Oil ($/bbl)(1) | Henry HubNatural Gas($/MMBtu)(1) | Inflation Rates (%/year)(2) |
| 2020 | 61.00 | 67.00 | 2.42 | 0.0 |
| 2021 | 63.00 | 68.00 | 2.75 | 2.0 |
| 2022 | 66.00 | 71.00 | 2.90 | 2.0 |
| 2023 | 68.00 | 73.00 | 3.00 | 2.0 |
| 2024 | 70.00 | 75.00 | 3.10 | 2.0 |
| 2025 | 72.00 | 76.00 | 3.20 | 2.0 |
| 2026 | 74.00 | 78.00 | 3.27 | 2.0 |
| 2027 | 75.81 | 79.81 | 3.33 | 2.0 |
| 2028 | 77.33 | 81.33 | 3.40 | 2.0 |
| 2029 | 78.88 | 82.88 | 3.47 | 2.0 |
| Thereafter | +2.0% / year | +2.0% / year | +2.0% / year | 2.0 |
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.
Reconciliation of Changes in Gross Reserves(1),(2)
| Factors | Total Proved Reserves (Mboe) | Total Proved plus Probable Reserves (Mboe) |
| December 31, 2018 | 11,222 | 19,275 |
| Infill drilling | 52 | 64 |
| Technical revisions | 69 | 15 |
| Exploration discoveries | 1,148 | 3,349 |
| Improved recovery | 12 | 17 |
| Production | (663) | (663) |
| December 31, 2019 | 11,840 | 22,056 |
| Reserves replacement ratio (%)(3) | 193 | 519 |
Notes:
(1) Gross Reserves are the Company’s working interest share of the remaining reserves before deduction of any royalties.
(2) See “Advisories: Reserve Advisory“.
(3) Reserves replacement ratio is calculated as net increase to reserves divided by 2019 average production of 663 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 | Proved Reserves ($000’s) | Proved plus Probable Reserves ($000’s) |
| 2020 | 9,367 | 12,324 |
| 2021 | 15,939 | 19,192 |
| 2022 | 13,564 | 22,277 |
| 2023 | 6,506 | 17,888 |
| Thereafter | – | – |
| Total undiscounted | 45,375 | 71,681 |
| Total discounted at 10% per year | 38,095 | 58,753 |
Estimated Company Capital Program Efficiency
| ($000’s unless otherwise stated) | Total Proved Reserves | Total Proved plus Probable Reserves |
| Exploration capital expenditures(1),(2) | 9,858 | 9,858 |
| Development capital expenditures (1),(2) | 696 | 696 |
| Change in future development costs | (624) | 3,039 |
| Estimated FD&A costs(4) | 9,930 | 13,593 |
| Gross reserve additions (Mboe)(3),(4) | 1,281 | 3,444 |
| Estimated FD&A costs per boe ($/boe)(4) | 7.75 | 3.95 |
| Estimated 2019 operating netback ($/boe)(1),(5) | 26.62 | 26.62 |
| Estimated 2019 recycle ratio(4) | 3.4x | 6.7x |
Notes:
(1) Financial information is based on the Company’s preliminary 2019 unaudited financial statements and is therefore subject to audit. See “Advisories: Unaudited Financial Information“.
(2) Exploration and development capital exclude capitalized general and administration costs and corporate asset expenditures. See “Advisories: Oil and Gas Metrics“.
(3) Gross Reserves are the Company’s working interest share of the remaining reserves before deduction of any royalties.
(4) See “Advisories: Reserve Advisory” and “Advisories: Oil and Gas Metrics“.
(5) See “Non-GAAP Measures“.
Touchstone Exploration Inc.
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”. For further information about Touchstone, please visit our website at www.touchstoneexploration.com or contact:
Reserve Advisory
The disclosure in this announcement 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, 2019 will be contained in the Company’s Annual Information Form for the year ended December 31, 2019 which will be filed on SEDAR on or before March 30, 2020.
The recovery and reserve estimates of crude oil and natural gas reserves provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil and natural gas reserves may eventually prove to be greater than or less than the estimates provided herein. This announcement summarizes the crude oil and natural gas reserves of the Company and the net present values of future net revenue for such reserves using forecast prices and costs as at December 31, 2019 prior to provision for interest, general and administrative expenses, the impact of any financial derivatives or liabilities associated with the abandonment and reclamation of certain facilities and wells. 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.
“Proved Developed Producing Reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing, or if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
“Proved Developed Non-Producing Reserves” are those reserves that either have not been on production or have previously been on production but are shut-in, and the date of resumption of production is unknown.
“Proved Undeveloped Reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
“Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
“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. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
In the Reserves Report, GLJ forecasted 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 forecasted economic limit of individual wells is beyond the current term of the relevant operating agreements.
Oil and Gas Measures
Where applicable, natural gas has been converted to barrels of oil equivalent based on six thousand cubic feet to one barrel of oil. The barrel of oil equivalent rate is based on an energy equivalent conversion method primarily applicable at the burner tip, and given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
Oil and Gas Metrics
This announcement contains several oil and gas metrics that are commonly used in the oil and gas industry such as reserves additions, reserves replacement ratio, finding, development and acquisition costs, and recycle ratio. These metrics have been prepared by Management and 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 and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures 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 announcement, 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.
FD&A costs represent the costs of net property acquisitions and dispositions, exploration, and development incurred. Specifically, FD&A is calculated as the sum of net acquisition costs less proceeds of dispositions, 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, 2019 consolidated financial statements is not complete. Accordingly, unaudited capital expenditure amounts used in the calculation of FD&A costs are Management’s estimate and are subject to change. FD&A costs per barrel is determined by dividing current period net reserve additions to the corresponding period’s FD&A 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 annual FD&A costs per barrel to operating netback per barrel 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, 2019 consolidated financial statements is not complete. Accordingly, unaudited operating netbacks used in calculations of recycle ratios 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.
Unaudited Financial Information
Certain annual 2019 financial information disclosed herein including capital expenditures and operating netback are based on unaudited estimated results. These estimated results are subject to change upon completion of the Company’s audited financial statements for the year ended December 31, 2019, and changes could be material.
Non-GAAP Measures
The Company uses operating netback as a key performance indicator of field results. Operating netback is presented on a total and per barrel basis and is calculated by deducting royalties and operating expenses from petroleum sales. Operating netback is presented herein prior to realized gains or losses on commodity derivative contracts. Operating netback does not have a standardized meaning under Generally Accepted Accounting Principles and therefore may not be comparable with the calculation of similar measures by other companies. The Company considers operating netback to be a key measure as it demonstrates Touchstone’s profitability relative to current commodity prices. This measurement assists Management and investors in evaluating operating results on a historical basis.
Forward-Looking Statements
Certain information provided in this announcement may constitute forward-looking statements within the meaning of applicable securities laws. Forward-looking information in this announcement may include, but is not limited to, statements relating to estimated crude oil and natural gas reserves and the net present values of future net revenue therefrom, future development costs associated with crude oil and natural gas reserves, the potential undertaking, timing, locations and costs of future well testing, well drilling, and the sufficiency of resources and available financing to fund future development and exploration 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. Since 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 2018 Annual Information Form dated March 26, 2019 which has been filed on SEDAR and can be accessed at www.sedar.com. The forward-looking statements contained in this announcement 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.
In addition, 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 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.
Abbreviations
bbl(s) barrel(s)
Mbbl thousand barrels
Mcf thousand cubic feet
MMcf million cubic feet
Bcf billion cubic feet
MMBtu million British Thermal Units
boe barrels of oil equivalent
Mboe thousand barrels of oil equivalent
Competent Persons Statement
In accordance with the AIM Rules for Companies, the technical information contained in this announcement has been reviewed and approved by James Shipka, Chief Operating Officer of Touchstone Exploration Inc. Mr. Shipka is a qualified person as defined in the London Stock Exchange’s Guidance Note for Mining and Oil and Gas Companies and is a Fellow of the Geological Society of London (BGS) as well as a member of the Canadian Society of Petroleum Geologists and the Geological Society of Trinidad and Tobago. Mr. Shipka has a Bachelor of Science in Geology from the University of Calgary and has over 30 years of oil and gas exploration and development experience.
