Our independent reserves evaluation was prepared by
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.
"Our year-end 2020 reserves evaluation provides further independent confirmation of the significant opportunities that the Company has in place from our
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 ofTrinidad 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 inTrinidad 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
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.
"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
Royston Drilling Preparations
Touchstone is pleased to report that we have cleared the primary access road to the
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
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
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
Summary of Company Gross Oil and Gas Reserves as of
Reserves Category | Light and | Heavy Oil | Conventional | Natural Gas | Total Oil (Mboe) |
Proved | |||||
Developed Producing | 3,470 | 175 | - | - | 3,644 |
Developed Non-Producing | 1,717 | 367 | 48,708 | 1,061 | 11,264 |
Undeveloped | 3,703 | - | 81,313 | 2,074 | 19,329 |
Total Proved | 8,890 | 542 | 130,021 | 3,136 | 34,238 |
Probable | 6,562 | 469 | 125,022 | 2,842 | 30,709 |
Total Proved plus Probable | 15,452 | 1,010 | 255,043 | 5,977 | 64,947 |
Possible | 4,873 | 362 | 157,386 | 3,738 | 35,203 |
Total Proved plus Probable plus Possible | 20,325 | 1,372 | 412,429 | 9,715 | 100,150 |
Notes: | |
(1) | Gross reserves are the Company's working interest share of the remaining reserves before deduction of any royalties. |
(2) | See "Advisories: Reserves Advisory". |
Summary of Net Present Values of Future Net Revenues Before Tax as of
Reserves Category | Net Present Values of Future Net Revenues Before Income | ||||
0% | 5% | 10% | 15% | 20% | |
Proved | |||||
Developed Producing | 61,934 | 45,680 | 37,399 | 32,106 | 28,344 |
Developed Non-Producing | 207,971 | 162,378 | 133,400 | 112,822 | 97,384 |
Undeveloped | 351,317 | 255,396 | 192,092 | 148,557 | 117,550 |
Total Proved | 621,222 | 463,454 | 362,891 | 293,485 | 243,278 |
Probable | 646,336 | 439,959 | 320,192 | 243,712 | 191,811 |
Total Proved plus Probable | 1,267,557 | 903,413 | 683,084 | 537,197 | 435,089 |
Possible | 737,859 | 463,396 | 319,751 | 234,400 | 179,349 |
Total Proved plus Probable plus Possible | 2,005,416 | 1,366,809 | 1,002,835 | 771,597 | 614,438 |
Notes: | |
(1) | Based on GLJ's |
(2) | See "Advisories: Reserves Advisory". |
Summary of Net Present Values of Future Net Revenues After Tax as of
Reserves Category | Net Present Values of Future Net Revenues After Income | ||||
0% | 5% | 10% | 15% | 20% | |
Proved | |||||
Developed Producing | 35,991 | 29,848 | 26,081 | 23,358 | 21,259 |
Developed Non-Producing | 90,946 | 74,294 | 62,920 | 54,527 | 48,055 |
Undeveloped | 140,503 | 100,506 | 74,021 | 55,827 | 42,929 |
Total Proved | 267,440 | 204,648 | 163,022 | 133,712 | 112,242 |
Probable | 254,214 | 173,852 | 126,150 | 95,476 | 74,642 |
Total Proved plus Probable | 521,655 | 378,501 | 289,172 | 229,188 | 186,884 |
Possible | 294,079 | 187,684 | 130,262 | 95,795 | 73,487 |
Total Proved plus Probable plus Possible | 815,734 | 566,185 | 419,434 | 324,983 | 260,371 |
Notes: | |
(1) | Based on GLJ's |
(2) | See "Advisories: Reserves Advisory". |
(3) | Income taxes include all resource income, appropriate income tax calculations per current |
Reconciliation of Changes in Gross Reserves by Product Type(1),(2)
Reserves Category and Factors | Light and | Heavy Crude | Conventional | Natural Gas | Total Oil (Mboe) |
Total Proved | |||||
9,590 | 1,103 | 6,888 | - | 11,840 | |
Exploration discoveries | - | - | 122,916 | 3,136 | 23,622 |
Technical revisions | (196) | (516) | 218 | - | (675) |
Economic factors | (33) | (12) | - | - | (45) |
Production | (471) | (33) | - | - | (504) |
8,890 | 542 | 130,021 | 3,136 | 34,238 | |
Total Proved plus Probable | |||||
16,906 | 1,801 | 20,091 | - | 22,056 | |
Exploration discoveries | - | - | 234,318 | 5,977 | 45,030 |
Technical revisions | (934) | (743) | 634 | - | (1,571) |
Economic factors | (50) | (15) | - | - | (65) |
Production | (471) | (33) | - | - | (504) |
15,452 | 1,010 | 255,043 | 5,977 | 64,947 |
Notes: | |
(1) | Gross reserves are the Company's working interest share of the remaining reserves before deduction of any royalties. |
(2) | See "Advisories: Reserves Advisory". |
(3) | Prior year reserve estimates per GLJ's independent reserves evaluation dated |
In comparison to
Heavy crude oil was attributed combined downward technical revisions and economic factors of 758 Mbbl as of
Upward technical revisions of approximately 106 Mboe were reflective of reduced surface loss estimates related to the Coho natural gas discovery in 2019. The Company's successful Cascadura-1ST1 well drilled and tested on our Ortoire property led to a 45,030 Mboe increase in conventional natural gas and natural gas liquids 2P reserves in 2020.
Future Development Costs
The following table provides information regarding the future 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 | Proved plus | Proved plus |
2021 | 9,530 | 11,360 | 11,360 |
2022 | 16,236 | 23,397 | 23,397 |
2023 | 12,584 | 16,787 | 16,787 |
2024 | 8,906 | 17,759 | 17,759 |
2025 | 8,666 | 14,625 | 14,625 |
Thereafter | - | - | - |
Total undiscounted | 55,920 | 83,927 | 83,927 |
Total discounted at 10% per year | 45,098 | 66,584 | 66,584 |
The following table sets forth the changes in undiscounted future development costs included in the Reserves Report against such costs included in the
( | Proved Reserves | Proved plus | Proved plus |
Increase in forecasted capital costs | 1,645 | 1,976 | 1,976 |
Decrease in development locations | (6,905) | (10,158) | (10,158) |
Cascadura discovery | 15,805 | 20,428 | 20,428 |
Total undiscounted change | 10,545 | 12,246 | 12,246 |
Total undiscounted change (%) | 19 | 15 | 15 |
Summary of Pricing and Inflation Rate Assumptions
The following table sets forth benchmark reference pricing and inflation rates reflected in the Reserves Report.
Forecast Year | Brent Spot Crude Oil ($/bbl)(1) | NYMEX Henry Hub Natural Gas ($/MMBtu)(1) |
($/bbl)(1) | Inflation Rates (% per year)(2) |
2021 | 50.75 | 2.75 | 43.20 | 0.0 |
2022 | 55.00 | 2.80 | 46.35 | 1.0 |
2023 | 58.50 | 2.85 | 49.05 | 2.0 |
2024 | 61.79 | 2.90 | 52.01 | 2.0 |
2025 | 62.95 | 2.95 | 53.06 | 2.0 |
2026 | 64.13 | 3.01 | 54.12 | 2.0 |
2027 | 65.33 | 3.07 | 55.20 | 2.0 |
2028 | 66.56 | 3.13 | 56.30 | 2.0 |
2029 | 67.81 | 3.19 | 57.43 | 2.0 |
2030 | 69.17 | 3.25 | 58.58 | 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 marketing arrangements, quality differentials and transportation to point of sale. |
(2) | Inflation rates for forecasting pricing and costs. |
Estimated Company Capital Program Efficiency
Proved Reserves | Proved plus | |
Estimated capital expenditures ( | 18,349 | 18,349 |
Change in FDC required to develop reserves ( | 10,545 | 12,246 |
Estimated F&D costs ( | 28,894 | 30,595 |
Gross reserve additions (Mboe)(2),(3) | 22,902 | 43,395 |
Estimated F&D costs per boe ($/boe)(2) | 1.26 | 0.71 |
Estimated 2020 operating netback ($/boe)(1),(4) | 14.29 | 14.29 |
Estimated 2020 recycle ratio(2) | 11.3x | 20.3x |
Notes: | |
(1) | Financial information is based on the Company's preliminary 2020 unaudited financial statements and is therefore subject to audit. See "Advisories: Unaudited Financial Information". |
(2) | See "Advisories: Reserves Advisory" and "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 "Non-GAAP Measures". |
Advisories
Forward-Looking Statements
Certain information provided in this news release may constitute forward-looking statements and information (collectively, "forward-looking statements") within the meaning of applicable securities laws. Such forward-looking statements include, without limitation, forecasts, estimates, expectations and objectives for future operations that are subject to assumptions, risks and uncertainties, many of which are beyond the control of the Company. Forward-looking statements are statements that are not historical facts and are generally, but not always, identified by the words "expects", "plans", "anticipates", "believes", "intends", "estimates", "projects", "potential" and similar expressions, or are events or conditions that "will", "would", "may", "could" or "should" occur or be achieved.
Forward-looking statements in this news release 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, the forecasted future production, commodity prices, inflation rates and all future costs used by GLJ in their evaluation, the potential undertaking, timing, locations and costs of future well testing, well drilling, well tie-in and seismic operations, the expected timing of initial production from exploration wells and the expected execution of a drilling rig contract, including drilling rig mobilization timing and costs. 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 2019 Annual Information Form dated
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.
Reserves Advisory
The disclosure in this news 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
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 news release 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
"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 news release 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 news 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. 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
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
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
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.
Abbreviations | |
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 |
SOURCE
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