Touchstone Exploration year-end 2020 reserves evaluation confirms significant opportunities from Trinidad assets

Touchstone Exploration Inc (LON:TXP) has announced a summary of its 2020 year-end reserves and provides an operational update.

Our independent reserves evaluation was prepared by GLJ Ltd. with an effective date of December 31, 2020. Highlights of our total proved, total proved plus probable and total proved plus probable plus possible reserves from the Reserves Report are provided below. All finding and development costs below include changes in future development capital. 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, 2020 and is subject to change. Readers are further cautioned to read the applicable advisories contained herein.

2020 Year-end Reserves Report Highlights

·      Increased 3P net reserves by 236% to 100,150 Mboe, increased 2P net reserves by 194% to 64,947 Mboe and increased 1P net reserves by 189% to 34,238 Mboe from the prior year.

·      In comparison to 2019, 10% discounted net present value of future net revenues (“NPV10”) on a before tax 3P basis increased by 90% to $1,002.8 million and after tax 3P NPV10 increased by 108% to $419.4 million.

·    Achieved a before tax 2P NPV10 of $683.1 million, representing an increase of 72% from $397.9 million reported in 2019 and realized an annual after tax 2P NPV10 increase of 88% to $289.2 million.

·      Realized before tax 1P NPV10 of $362.9 million, representing an increase of $160.7 million or 79% from the prior year and increased after tax 1P NPV10 by 95% from year-end 2019 to $163.0 million.

·    Realized 1P F&D costs of $1.26 per boe, resulting in a recycle ratio 11.3 times using our unaudited annual estimated 2020 operating netback of $14.29 per boe. Touchstone’s low F&D costs are primarily attributed to our meaningful 2020 reserves growth from our Cascadura-1ST1 well discovery.

·   Recognized 2P F&D costs of $0.71 per boe, resulting in a 2P recycle ratio of 20.3 times, demonstrating Touchstone’s capital efficient operations in the Ortoire block.

·  FDC associated with only a portion of our internally identified drilling location inventory and low-risk recompletion projects totaled $55.9 million for 1P reserves and $83.9 million for both 2P and 3P reserves.

·    The Cascadura assessment area was assigned gross working interest 1P reserves of 23,622 Mboe and gross working interest 2P reserves of 45,030 Mboe with an estimated before tax 2P NPV10 of $411.8 million.

·      The Reserves Report excluded any potential reserves from the Company’s Chinook-1 and Cascadura Deep-1 wells drilled in the fourth quarter of 2020.

Paul Baay, President and Chief Executive Officer, commented:

“Our year-end 2020 reserves evaluation provides further independent confirmation of the significant opportunities that the Company has in place from our Trinidad assets. Our 1P reserves are now significantly higher than our 3P reserves at the same time last year, providing greater operational and financial certainty for investors, and exclude any potential reserves from the recently drilled Chinook-1 well or Cascadura Deep-1 wells. We have a lot to be excited about as we focus on converting our world class reserves to production during 2021 as well as expanding opportunities through additional drilling at Ortoire.”

Operational Highlights

·   Tested two identified pay zones in the Chinook-1 well, with both zones encountering potential upside in the form of light sweet crude oil. One pay zone is currently being configured for an extended production test.

·    Equipment has arrived in Trinidad to enable testing of the main gas bearing zones in the Cascadura Deep-1 well, where significant hydrocarbon accumulations were reported in December based on drilling and wireline logging data.

·      Testing of the potential gas bearing sands in the Chinook-1 well will commence following the extended crude oil test.

·    We continue to target the second quarter of 2021 for initial Ortoire gas commercialization, with final regulatory approvals for the tie-in of our Coho-1 well received and construction underway.

·      Working with the National Gas Company of Trinidad and Tobago to commence regulatory applications to tie-in Cascadura and any potential Chinook production volumes, with the objective of achieving initial production prior to the end of 2021.

·   The primary access road to the Royston-1 well location has been cleared, and we have commenced road resurfacing and lease building operations.

·      Initiated line clearing for the 21-kilometre 2D seismic program in the Royston area.

·   Expected to enter into a minimum three-year drilling services contract from a Canadian based private company to supply an ultra-heavy telescopic drilling rig to Trinidad in late 2021, which will enable us access to three drilling rigs in Trinidad capable of drilling to depths of 10,000 feet or more.

Operational Update

Well Testing

Touchstone has yet to test the targeted gas bearing zones in the Chinook-1 and Cascadura Deep-1 exploration wells due to unavoidable delays associated with third-party equipment including the natural gas testing unit. However, we are pleased to report that all required equipment has now been cleared through the various levels of government organizations in Trinidad and is expected to be on location within the next ten days.

Touchstone has tested two low resistivity zones in the Chinook-1 well. The first test interval was in the lower sub-thrust sheet, which was a previously unknown thrust-sheet where we identified 68 net feet of potential pay based on wireline logging data. During this test, the well recovered trace amounts of 41 degrees API sweet oil along with significant high pressure and high temperature water, which was indicative of encountering a fracture at the base of the formation. With the high volume of water, the zone is considered uneconomic; however, indications of light oil prove the concept of hydrocarbons in the sub-thrust sheet. Based on 3D seismic data, future development locations are anticipated to be positioned structurally up-dip by as much as 1,000 feet from the Chinook-1 well to evaluate the sub-thrust sheet in an optimal structural position. The Company has permanently abandoned this lowermost zone and completed a second zone in the Herrera formation which encountered 35 degrees API sweet oil and is currently being configured for an extended oil production test. We anticipate conducting the first natural gas test at the Cascadura Deep-1 well while the Chinook-1 well is on the extended oil production test.

James Shipka, Chief Operating Officer, commenting on the Chinook-1 well tests, said:

“This is an encouraging start to the production testing program as it confirms the presence of hydrocarbons in the sub-thrust sheet and will allow for further up-dip drilling targets based on available 3D seismic data. The sub-thrust sheet was not one of the original Chinook-1 well targets, so the confirmation of hydrocarbons in the deep section is very positive. Although the lower zone was considered uneconomic given the high water cuts, the reservoir displayed potential as fluid flowed to surface at over 2,200 bbls/d. Future targets structurally up-dip from Chinook-1 hold tremendous potential.

The second production test is also very exciting and could result in numerous development locations. The presence of oil in the intermediate section reaffirms that the hydrocarbon system in the Herrera is extensive and variable. Our extended production test will determine if this zone is commercial in Chinook-1 before we move up in the wellbore to our next test which we anticipate being a natural gas zone immediately above the oil. It is unfortunate that due to third-party issues beyond our control we have had to wait on the gas test equipment; nevertheless, valuable data has been collected in the interim period.

The multi-target project at Ortoire is still in the early stages. The oil discovery at Chinook-1 adds another layer of opportunity that we have not previously forecasted. For reference, the offsetting Barrackpore oil pool has over 60 wells that have produced approximately 18.7 million barrels, averaging 300,000 barrels per well with oil ranging from 27 to 30 degrees API.”

Coho-1 Tie-in

On January 22, 2021, the Company received approval to proceed with the construction of the Coho-1 tie-in project. Subsequent to the required initial notification period, construction operations have commenced. Touchtone is targeting initial gas production from Coho-1 in the second quarter of 2021. In conjunction with the project, we have also been working with the Natural Gas Company of Trinidad and Tobago to survey and commence regulatory applications to tie-in Cascadura and any potential Chinook production volumes, with a goal to achieve initial production prior to the end of 2021. The Company is concurrently applying for two additional surface locations at both Cascadura and Chinook which will allow for up to 16 development locations.

Royston Drilling Preparations

Touchstone is pleased to report that we have cleared the primary access road to the Royston-1 drilling location and are currently surfacing the road and performing lease preparations. The Royston well will be drilled using Well Services Rig #60 targeting a total depth of approximately 11,500 feet. The drilling rig is scheduled to move onto location early in the second quarter of 2021. 

Drilling Rig Contract

Given our exploration success, the Company expects to execute a contract with a Canadian based private company to provide state of the art drilling equipment commencing in late 2021. The contractor will deploy a North American based drilling rig equipped for us to evaluate the deep targets at Royston, Cascadura and Chinook along with drilling on our legacy crude oil development properties. Pursuant to the current terms of the drilling contract, Touchstone must utilize the rig for a minimum of 120 days per year over an initial three-year term and is obligated to pay for rig mobilization costs, which are currently estimated to be approximately $1 million. This arrangement, in combination with our current drilling services provider, will give the Company access to three drilling rigs capable of drilling to depths of 10,000 feet or more on the Ortoire block as well as the Company’s legacy oil development properties.

Seismic Program

Touchstone has initiated surveying and line clearing for our 21-kilometre 2D seismic program. The seismic information will be used for further delineation of the structure to be drilled at Royston and adjacent prospects in the Mid Miocene Herrera formation and is expected to optimize future drilling into the previously identified Cretaceous exploration target. The program is scheduled to be completed prior to July 2021. 

2020 Year-end Reserves Report Summary

Touchstone’s 2020 capital program focused on exploration activities on our Ortoire property, where we drilled two gross (1.6 net) exploration wells. Similar to 2019, we conducted minimal capital development activity on our development properties, mainly performing wellbore recompletions and workover operations to arrest production declines. The Reserves Report includes those reserves associated with our legacy development properties and our Coho natural gas discovery in 2019, as well as new reserves associated with our Cascadura discovery in 2020. The Reserves Report does not include any reserves associated with our Chinook-1 and Cascadura Deep-1 wells drilled in 2020, as production testing operations were not completed prior to the effective date of the Reserves Report. 

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 31, 2021. The reserve estimates set forth below are based upon GLJ’s Reserves Report dated March 4, 2021 with an effective date of December 31, 2020. All values in this announcement are based on GLJ’s forecast prices and estimates of future operating and capital costs as at December 31, 2020. In certain tables set forth below, the columns may not add due to rounding.

Reserves 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, 2020 will be contained in the Company’s Annual Information Form for the year ended December 31, 2020 which will be filed on SEDAR on or before March 31, 2021.

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, 2020 prior to provision for interest and finance costs, general and administration 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% 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 licence, sub-licence and marketing agreements, in many cases the forecasted economic limit of individual wells is beyond the current term of the relevant agreements. There is no certainty as to any renewal of the Company’s existing exploration, production, and marketing arrangements.

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, finding and development 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. Management uses this measure to determine the relative change of its reserves base over a period of time.

F&D costs represent the costs of exploration and development incurred. Specifically, F&D is calculated as the sum of exploration and development 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, 2020 consolidated financial statements is not complete. Accordingly, unaudited capital expenditure amounts used in the calculation of F&D costs are Management’s estimates and are subject to change. F&D costs per barrel is determined by dividing current period net reserve additions to the corresponding period’s F&D cost. Readers are cautioned that the aggregate of capital expenditures incurred in the most recent financial year and the change during that year in estimated FDC generally will not reflect total F&D costs related to net reserves additions for that year. Management uses F&D costs as a measure of its ability to execute its capital program, the success in doing so, and of the Company’s asset quality.

Recycle ratio is a measure used by Management to evaluate the effectiveness of its capital reinvestment program and is calculated by dividing the annual F&D 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, 2020 consolidated financial statements is not complete. Accordingly, unaudited operating netbacks used in calculations of recycle ratios are Management’s estimates 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 2020 financial information disclosed herein including capital expenditures and operating netback are based on unaudited estimated results and are subject to the same limitations as discussed in Forward-Looking Statements set out above. These estimated results are subject to change upon completion of the Company’s audited financial statements for the year ended December 31, 2020, and changes could be material. Touchstone anticipates filing its audited consolidated financial statements and related management’s discussion and analysis for the year ended December 31, 2020 on SEDAR on March 26, 2021.

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.


bbl(s)                barrel(s)

bbls/d               barrels per day

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

API                   American Petroleum Institute gravity

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