2021 YEAR-END RESERVES AND OPERATIONAL UPDATE
2021 YEAR-END RESERVES AND OPERATIONAL UPDATE
CALGARY, ALBERTA (March 7, 2022) - Touchstone Exploration Inc. ("Touchstone", "we", "our", "us" or the "Company") (TSX, LSE: TXP) is pleased to announce a summary of our 2021 year-end reserves and an operational update.
Our independent reserves evaluation was prepared by GLJ Ltd. ( " GLJ " ) with an effective date of December 31, 2021 (the " Reserves Report " ). Highlights of our total proved ("1P"), total proved plus probable ("2P") and total proved plus probable plus possible ("3P") reserves from the Reserves Report are provided below. All finding and development ("F&D") costs below include changes in future development capital ("FDC"). 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, 2021 and is subject to change. Readers are further cautioned to read the applicable advisories contained herein.
2021 Year-end Reserves Report Highlights
· Relative to year-end 2020, increased 3P gross reserves by 21% to 121,332 Mboe, increased 2P gross reserves by 16% to 75,547 Mboe and increased 1P gross reserves by 13% to 38,731 Mboe in 2021.
· Touchstone's net present value of future net revenues discounted at 10% ("NPV10") on a before tax 3P basis increased by 31% to $1.31 billion, before tax 2P NPV10 increased by 29% to $881.8 million and before tax 1P NPV10 increased by 31% to $474.9 million from the prior year.
· Realized after tax 3P NPV10 of $535.6 million, representing an increase of 28% from the prior year, after tax 2P NPV10 increased by 26% from year-end 2020 to $363.1 million and after tax 1P NPV10 increased by 29% from the prior year to $210 million.
· Achieved 1P F&D costs of $10.36 per boe, resulting in a recycle ratio of 2.6 times using our unaudited annual estimated 2021 operating netback of $26.55 per boe.
· Realized 2P F&D costs of $6.96 per boe, resulting in a 2P recycle ratio of 3.8 times, demonstrating our capital efficient operations on the Ortoire block.
· Relative to year-end 2020, increased Cascadura 1P reserves by 14% to 26,902 Mboe and 2P total reserves by 16% to 52,082 Mboe following our successful Cascadura Deep-1 well tested in 2021.
· The Royston exploration discovery was assigned gross working interest 3P reserves of 4,800 Mboe, gross working interest 2P reserves of 3,520 Mboe and gross working interest 1P reserves of 1,280 Mboe.
· Our independent reserves evaluator estimates that the Royston structure has a low estimate of 128.3 MMbbl, a best estimate of 165.7 MMbbl and a high estimate of 211.7 MMbbl of total petroleum initially-in-place from the overthrust and intermediate sheets of the Herrera Formation, with no estimate provided in the subthrust sheet.
Paul Baay, President and Chief Executive Officer, commented:
"Our 2021 independent reserves evaluation confirms the significant opportunities at our Ortoire property and the profitability of all of our assets in Trinidad. The estimated additions of both future net revenues and reserves at the newly discovered Royston light oil pool are reflective of our successful drilling activities in 2021 and the considerable size of the prospect in the Herrera Formation. The initial Royston reserves evaluation was conservative, given only one well was drilled to date and no reserves were assigned to the subthrust sheet. We have two exciting opportunities to substantially increase reserves in the area with the Royston Deep well intended to evaluate the subthrust sheet of the Herrera Formation and the Kraken well targeting the deeper Cretaceous Formation.
We are proceeding with the final step to bring the Coho gas field online with anticipated first natural gas production in May 2022, which will represent a milestone for Touchstone and Trinidad. We also remain on track with our operations at Cascadura, as we have submitted the required regulatory applications and procured the long lead items for the surface facility, providing visibility to estimated completion in September 2022.
Our focus is to convert our extensive Trinidad resource base to cash flows while continuing to target further exploration opportunities across our licence areas. It is an exciting time for Touchstone, as it is rare to have a combination of solid low decline base production, a near-term step change in production, a multi-year development drilling program and extensive exploration opportunities. I would encourage anyone requiring additional information to view the updated corporate presentation available on our website. "
Operational Highlights
· With all relevant agreements executed, pipeline tie-in operations for the Coho-1 well are proceeding with anticipated first gas in May 2022 subject to weather conditions.
· The Company is currently awaiting regulatory approvals to commence constructing the Cascadura natural gas facility, with equipment procurement and delivery of pressure vessels on track for facility completion in September 2022 assuming timely receipt of required regulatory approvals.
· The extended flow test at Royston has confirmed the well is capable of over 675 bbls/d of light, sweet oil production from a combination of the overthrust and intermediate sheets of the Herrera Formation.
· The three development wells drilled on our legacy crude oil blocks in the fourth quarter of 2021 have produced a field estimated 210 bbls/d since coming on production, contributing to our current field estimated aggregate net base production of approximately 1,449 bbls/d, excluding production testing volumes from Royston-1.
Operational Update
Coho
All of the required agreements with our third-party partners to allow for the final tie-in of the Coho gas field on the Ortoire block have been executed. Pipeline installation operations have commenced with first gas anticipated in May 2022 subject to weather delays that may hinder trenching and welding operations. Following testing and purging of the pipeline, we are anticipating natural gas production to increase over time to a gross target of 10 MMcf/d (8 MMcf/d net, representing approximately 1,333 boe/d net production).
Cascadura
The Cascadura facility is proceeding with the major facility components nearing completion for transportation to Trinidad. The components will be delivered on skids and will be assembled in the field by local contractors. In parallel with the facilities procurement and construction, we have submitted the required regulatory application and expect to receive a response on or before mid-May 2022. Upon approval, we will proceed with four distinct projects at Cascadura: road construction, condensate pipeline construction, facility construction and construction of future development drilling locations.
Royston
We commenced a long-term production test of the uppermost 84 feet of the Herrera overthrust section in January 2022 with the goal of evaluating different flowing regimes and possible pump configurations to maximize oil production. While conducting the test, approximately 2,200 feet of pipe and perforating guns were stuck in the bottom portion of the well, not allowing any further testing of the deeper zones. However, with these constraints, the well has continued to deliver both pumping and flowing volumes from the uppermost 84 feet.
Combined with the previous test in the intermediate zone, the well has shown that the completed intervals are capable of producing over 675 bbls/d of oil. Produced oil is being sold at our Barrackpore sales facility, and all associated water has been separated on-site and reinjected at our water disposal facility. We anticipate production testing continuing until the commencement of future drilling operations at Royston.
Legacy Wells
The three development wells drilled by the Company in the fourth quarter of 2021 are on production. Since being brought onstream, they have contributed an aggregate average of 210 bbls of net oil per day. We have prepared the next location on our Coora-1 block where we plan to drill two commitment infill wells targeting the Forest and Cruse Formations.
James Shipka, Chief Operating Officer, commenting on the Royston-1 well test, said:
"Testing of the Royston-1 exploration well resumed in early January with the well initially flowing at rates of over 250 barrels of oil per day from the uppermost 84 feet of the overthrust reservoir. Over the course of flow testing and, as anticipated, production rates gradually declined due to liquid loading in the wellbore and we subsequently moved a service rig to the location to install a pump to increase production. While attempting to raise the downhole assembly, we discovered an issue with the casing at approximately 7,250 feet that prevented us to run the optimized downhole pumping assembly. The wellbore could not be cleared, and we ultimately severed the existing tubing string at approximately 7,200 feet. In early February, we ran a downhole pump above the pre-existing tubing string, and we are currently working on optimizing production in this restricted configuration.
Despite these mechanical challenges, our testing program at Royston-1 has confirmed that the Royston structure will be a core oil development property for Touchstone. The light oil discoveries in the intermediate and overthrust sheets have displayed production rates in excess of 675 barrels of oil per day from the structure. With an independent estimate of up to 212 million barrels of total petroleum initially-in-place in the high case, including upside potential from the upper two sheets, Royston will be an exciting long-term project. Our 2021 reserves bookings reflect Royston's initial development stage, and we look forward to our future exploration wells which will further delineate and expand our understanding of the structure. Until then, we will continue our testing program at Royston to gather additional information and refine our model of the reservoir. The similarities between Royston and the Penal-Barrackpore fields are significant and have given us confidence in our understanding of how the different thrust sheets may contribute to the ultimate recovery of the field."
2021 Year-end Reserves Report Summary
Touchstone's 2021 capital program focused on exploration activities on our Ortoire property, where we conducted production testing operations on the Cascadura Deep-1 well drilled in the fourth quarter of 2020, completed the Royston area 22-kilometre seismic program, and drilled and tested the Royston-1 exploration well. In addition, we drilled three gross and net wells on our legacy oil properties representing our first infill drilling since 2019. The Reserves Report includes those reserves associated with our legacy development properties, our Coho natural gas discovery in 2019, our Cascadura discovery in 2020, as well as additions relating to the Cascadura Deep-1 and Royston-1 wells.
Touchstone's year-end crude oil, natural gas and NGL 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, 2022. The reserve estimates set forth below are based upon GLJ's Reserves Report dated March 4, 2022 with an effective date of December 31, 2021. All values in this announcement are based on GLJ's forecast prices and estimates of future operating and capital costs as of December 31, 2021. Please refer to "Advisories: Reserves Advisories" for further information. In certain tables set forth below, the columns may not add due to rounding.
2021 Reserves Summary by Category
|
|
1P |
2P |
3P |
|
|
|
|
|
|
Total gross reserves(1) (Mboe) |
38,731 |
75,547 |
121,332 |
|
Reserve additions(2) (Mboe) |
4,985 |
11,092 |
21,674 |
|
NPV10 before income tax(3) ($000's) |
474,922 |
881,753 |
1,313,006 |
|
NPV10 after income tax(3) ($000's) |
210,036 |
363,068 |
535,613 |
|
|
|
|
|
Notes:
(1) Gross reserves are the Company's working interest share before deduction of royalties.
(2) See "Advisories: Oil and Gas Metrics".
(3) Based on GLJ's December 31, 2021 forecast prices and costs. See " Forecast prices and costs " .
Year-Over-Year Reserves Data
|
|
December 31, 2021 |
December 31, 2020(1) |
% Change |
|
|
|
|
|
|
1P gross reserves(2) (Mboe) |
38,731 |
34,238 |
13 |
|
2P gross reserves(2) (Mboe) |
75,547 |
64,947 |
16 |
|
3P gross reserves(2) (Mboe) |
121,332 |
100,150 |
21 |
|
|
|
|
|
|
1P NPV10 before income tax(3) ($000's) |
474,922 |
362,891 |
31 |
|
2P NPV10 before income tax(3) ($000's) |
881,753 |
683,084 |
29 |
|
3P NPV10 before income tax(3) ($000's) |
1,313,006 |
1,002,835 |
31 |
|
|
|
|
|
|
1P NPV10 after income tax(3) ($000's) |
210,036 |
163,022 |
29 |
|
2P NPV10 after income tax(3) ($000's) |
363,068 |
289,172 |
26 |
|
3P NPV10 after income tax(3) ($000's) |
535,613 |
419,434 |
28 |
|
|
|
|
|
Notes:
(1) Prior year reserve estimates per GLJ's independent reserves evaluation dated March 4, 2021 with an effective date of December 31, 2020.
(2) Gross reserves are the Company's working interest share before deduction of royalties.
(3) Based on GLJ's December 31, 2021 forecast prices and costs. See " Forecast prices and costs " .
Summary of Crude Oil and Natural Gas Reserves by Product Type
|
Company Gross (1) Reserves |
Light and Medium Crude Oil (Mbbl) |
Heavy Crude Oil (Mbbl) |
Conventional Natural Gas (MMcf) |
Natural Gas Liquids (Mbbl) (2) |
Total Oil Equivalent (Mboe) |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
Developed Producing |
3,387 |
261 |
- |
- |
3,648 |
|
Developed Non-Producing |
2,148 |
210 |
93,252 |
2,198 |
20,098 |
|
Undeveloped |
4,638 |
- |
53,841 |
1,374 |
14,985 |
|
Total Proved |
10,174 |
471 |
147,093 |
3,571 |
38,731 |
|
|
|
|
|
|
|
|
Probable |
8,908 |
458 |
144,642 |
3,342 |
36,815 |
|
Total Proved plus Probable |
19,082 |
929 |
291,735 |
6,913 |
75,547 |
|
|
|
|
|
|
|
|
Possible |
6,186 |
340 |
205,727 |
4,972 |
45,785 |
|
Total Proved plus Probable plus Possible |
25,268 |
1,269 |
497,462 |
11,885 |
121,332 |
Notes:
(1) Gross reserves are the Company's working interest share before deduction of royalties.
(2) NGLs are comprised of 100% condensate.
|
Company Net (1) Reserves |
Light and Medium Crude Oil (Mbbl) |
Heavy Crude Oil (Mbbl) |
Conventional Natural Gas (MMcf) |
Natural Gas Liquids (Mbbl) (2) |
Total Oil Equivalent (Mboe) |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
Developed Producing |
2,119 |
232 |
- |
- |
2,352 |
|
Developed Non-Producing |
1,599 |
187 |
81,595 |
1,923 |
17,308 |
|
Undeveloped |
3,285 |
- |
47,111 |
1,202 |
12,339 |
|
Total Proved |
7,003 |
419 |
128,706 |
3,125 |
31,999 |
|
|
|
|
|
|
|
|
Probable |
6,719 |
407 |
126,561 |
2,925 |
31,145 |
|
Total Proved plus Probable |
13,723 |
827 |
255,268 |
6,049 |
63,143 |
|
|
|
|
|
|
|
|
Possible |
4,581 |
302 |
180,011 |
4,350 |
39,236 |
|
Total Proved plus Probable plus Possible |
18,304 |
1,129 |
435,279 |
10,399 |
102,379 |
Notes:
(1) Net reserves are the Company's working interest share after the deduction of royalty obligations.
(2) NGLs are comprised of 100% condensate.
Summary of Net Present Values of Future Net Revenues (1)
|
Net Present Values Before Income Taxes ($000's) |
Undiscounted |
Discounted at 5% |
Discounted at 10% |
Discounted at 15% |
Discounted at 20% |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
Developed Producing |
70,586 |
59,730 |
51,737 |
45,799 |
41,267 |
|
Developed Non-Producing |
375,339 |
302,251 |
253,336 |
217,580 |
190,218 |
|
Undeveloped |
285,210 |
217,561 |
169,849 |
135,347 |
109,717 |
|
Total Proved |
731,135 |
579,541 |
474,922 |
398,726 |
341,202 |
|
|
|
|
|
|
|
|
Probable |
827,687 |
559,969 |
406,831 |
310,348 |
245,521 |
|
Total Proved plus Probable |
1,558,822 |
1,139,510 |
881,753 |
709,074 |
586,723 |
|
|
|
|
|
|
|
|
Possible |
1,050,052 |
636,255 |
431,253 |
315,331 |
243,050 |
|
Total Proved plus Probable plus Possible |
2,608,874 |
1,775,765 |
1,313,006 |
1,024,405 |
829,773 |
|
|
|
|
|
|
|
|
Net Present Values After Income Taxes (2) ($000's) |
Undiscounted |
Discounted at 5% |
Discounted at 10% |
Discounted at 15% |
Discounted at 20% |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
Developed Producing |
40,461 |
38,818 |
35,781 |
32,906 |
30,445 |
|
Developed Non-Producing |
93,106 |
77,056 |
66,818 |
59,345 |
53,537 |
|
Undeveloped |
178,040 |
136,986 |
107,437 |
85,756 |
69,482 |
|
Total Proved |
311,607 |
252,860 |
210,036 |
178,006 |
153,464 |
|
|
|
|
|
|
|
|
Probable |
317,593 |
213,545 |
153,032 |
114,800 |
89,205 |
|
Total Proved plus Probable |
629,200 |
466,405 |
363,068 |
292,806 |
242,669 |
|
|
|
|
|
|
|
|
Possible |
413,968 |
254,122 |
172,545 |
126,103 |
97,118 |
|
Total Proved plus Probable plus Possible |
1,043,168 |
720,527 |
535,613 |
418,909 |
339,787 |
Notes:
(1) Based on GLJ's December 31, 2021 forecast prices and costs. See " Forecast prices and costs " .
(2) The after-tax net present values prepared by GLJ in the evaluation of the Company's crude oil and natural gas assets presented herein are calculated by considering current Trinidad tax regulations and are based on the Company's estimated tax pools and non-capital losses as of December 31, 2021. The values reflect the expected income tax burden on the assets on a consolidated basis. Values do not represent an estimate of the value at the business entity level or consider tax planning, which may be significantly different. See "Advisories: Unaudited Financial Information".
Reconciliation of Gross Reserves by Product Type
The following table sets forth a reconciliation of the Company's total gross proved, gross probable and total gross proved plus probable reserves as of December 31, 2021 by product type against such reserves as at December 31, 2020 based on forecast prices and cost assumptions.
|
Reserves Category and Factors |
Light and Medium Crude Oil (Mbbl) |
Heavy Crude Oil (Mbbl) |
Conventional Natural Gas (MMcf) |
Natural Gas Liquids (Mbbl) (1) |
Total Oil Equivalent (Mboe) |
|
|
|
|
|
|
|
|
Total Proved |
|
|
|
|
|
|
December 31, 2020 (2) |
8,890 |
542 |
130,021 |
3,136 |
34,238 |
|
Exploration discoveries(3) |
1,280 |
- |
- |
- |
1,280 |
|
Extensions and improved recovery(4) |
244 |
- |
17,072 |
436 |
3,525 |
|
Technical revisions(5) |
195 |
(16) |
- |
- |
179 |
|
Dispositions(6) |
- |
(11) |
- |
- |
(11) |
|
Economic factors(7) |
13 |
- |
- |
- |
13 |
|
Production |
(449) |
(43) |
- |
- |
(492) |
|
December 31, 2021 |
10,174 |
471 |
147,093 |
3,571 |
38,731 |
|
|
|
|
|
|
|
|
Total Probable |
|
|
|
|
|
|
December 31, 2020 (2) |
6,562 |
469 |
125,022 |
2,842 |
30,709 |
|
Exploration discoveries(3) |
2,240 |
- |
- |
- |
2,240 |
|
Extensions and improved recovery(4) |
72 |
- |
19,620 |
500 |
3,842 |
|
Technical revisions(5) |
28 |
(6) |
- |
- |
22 |
|
Dispositions(6) |
- |
(5) |
- |
- |
(5) |
|
Economic factors(7) |
7 |
- |
- |
- |
7 |
|
Production |
- |
- |
- |
- |
- |
|
December 31, 2021 |
8,908 |
458 |
144,642 |
3,342 |
36,815 |
|
|
|
|
|
|
|
|
Total Proved plus Probable |
|
|
|
|
|
|
December 31, 2020 (2) |
15,452 |
1,010 |
255,043 |
5,977 |
64,947 |
|
Exploration discoveries(3) |
3,520 |
- |
- |
- |
3,520 |
|
Extensions and improved recovery(4) |
316 |
- |
36,691 |
936 |
7,367 |
|
Technical revisions(5) |
222 |
(21) |
- |
- |
201 |
|
Dispositions(6) |
- |
(16) |
- |
- |
(16) |
|
Economic factors(7) |
20 |
- |
- |
- |
20 |
|
Production |
(449) |
(43) |
- |
- |
(492) |
|
December 31, 2021 |
19,082 |
929 |
291,735 |
6,914 |
75,547 |
Notes:
(1) NGLs are comprised of 100 percent condensate.
(2) Prior year reserve estimates per GLJ's independent reserves evaluation dated March 4, 2021 with an effective date of December 31, 2020.
(3) Discoveries are associated with the evaluation of the Royston area discovery on the Ortoire block.
(4) Reserve amounts for Infill Drilling, Extensions and Improved Recovery are combined and reported as "Extensions and Improved Recovery".
(5) Technical revisions factor includes all changes in reserves due to well performance and previously booked wells which were drilled in the year.
(6) The assets associated with three non-core properties were classified as held for sale with an effective date of December 31, 2021. The Company is currently awaiting regulatory approvals to close the asset dispositions.
(7) Economic factors are the change in reserves exclusively due to changes in pricing.
In comparison to December 31, 2020 on a proved plus probable reserve basis, light and medium crude oil reserves increased 558 Mbbl from technical revisions, economic factors and drilling extensions in 2021. 222 Mbbl of the annual increase reflected improved well performance from our Coora, WD-4, WD-8, San Francique and Barrackpore blocks, and 316 Mbbl of this change was based on our 2021 drilling campaign at WD-4 and WD-8 resulting in drilling extension reserve additions. In addition, heavy crude oil was attributed downward technical revisions and economic factors of 21 Mbbl as of December 31, 2021, primarily due to reduced well performance at our Fyzabad block. Effective December 31, 2021, we sold our non-core New Dome, South Palo Seco, and Palo Seco properties, resulting in an aggregate decrease of 16 Mbbl.
Our successful Royston-1 exploration well drilled in 2021 on the Ortoire block led to a proved plus probable exploration discovery of 3,520 Mbbl of light and medium crude oil reserves in 2021. In addition, our Cascadura Deep-1 well which was tested in the first quarter of 2021 led to a 7,051 Mboe increase in proved plus probable conventional natural gas and NGL reserves as of December 31, 2021.
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 ($000's) |
1P |
2P |
3P |
|
|
|
|
|
|
2022 |
27,708 |
31,098 |
31,098 |
|
2023 |
23,700 |
37,353 |
37,353 |
|
2024 |
8,126 |
36,650 |
36,650 |
|
2025 |
10,341 |
14,542 |
14,542 |
|
2026 |
10,138 |
13,931 |
13,931 |
|
Thereafter |
- |
- |
- |
|
Total undiscounted |
80,014 |
133,574 |
133,574 |
|
Total discounted at 10% per year |
67,375 |
110,397 |
110,397 |
The following table sets forth the changes in undiscounted future development costs included in the Reserves Report against such costs in our December 31, 2020 reserves report prepared by GLJ dated March 4, 2021.
|
($000's unless otherwise stated) |
1P |
2P |
3P |
|
|
|
|
|
|
Increase in forecasted well costs |
1,859 |
3,154 |
3,154 |
|
Increase in forecasted facility and pipeline costs |
3,867 |
4,707 |
4,707 |
|
Royston exploration discovery development costs |
18,368 |
41,786 |
41,786 |
|
Total increase in future development costs from 2020 |
24,094 |
49,647 |
49,647 |
|
Total increase in future development costs from 2020 (%) |
43 |
59 |
59 |
Forecast Pricing and Costs
Forecast pricing and costs are prices and costs that are generally acceptable, in the opinion of GLJ, as being a reasonable outlook of the future as of the evaluation effective date. The forecast cost assumptions consider inflation with respect to future operating and capital costs. The following table sets forth the benchmark reference prices and inflation rates reflected in the Reserves Data as of December 31, 2021. These price assumptions were provided to the Company by GLJ and were GLJ's then current forecast as of the date of the Reserves Report.
Summary of GLJ January 1, 2022 Forecast Prices and Inflation Rate Assumptions
|
Forecast Year |
Brent Spot Crude Oil (1) ($/bbl) |
Henry Hub Natural Gas (1) ($/MMBtu) |
Conway Condensate (1) ($/bbl) |
Inflation Rate (% per year) |
|
|
|
|
|
|
|
2022 |
76.00 |
3.80 |
67.16 |
0.0 |
|
2023 |
72.51 |
3.50 |
63.49 |
3.0 |
|
2024 |
71.24 |
3.15 |
61.86 |
2.0 |
|
2025 |
72.66 |
3.21 |
63.09 |
2.0 |
|
2026 |
74.12 |
3.28 |
64.36 |
2.0 |
|
2027 |
75.59 |
3.34 |
65.64 |
2.0 |
|
2028 |
77.11 |
3.41 |
66.96 |
2.0 |
|
2029 |
78.66 |
3.48 |
68.30 |
2.0 |
|
2030 |
80.22 |
3.55 |
69.66 |
2.0 |
|
2031 |
81.83 |
3.62 |
71.06 |
2.0 |
|
Thereafter |
+2.0% / year |
+2.0% / year |
+2.0% / year |
2.0 |
|
|
|
|
|
|
Note:
(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 specific marketing arrangements, quality differentials and transportation to point of sale.
Capital Program Efficiency
|
|
2021 |
2021 - 2019 Total |
||
|
1P |
2P |
1P |
2P |
|
|
|
|
|
|
|
|
Estimated exploration and development capital expenditures(1) ($000's) |
27,546 |
27,546 |
57,617 |
57,617 |
|
Change in FDC ($000's) |
24,094 |
49,647 |
34,015 |
64,932 |
|
F&D costs (2),(4) ($000's) |
51,640 |
77,193 |
91,632 |
122,549 |
|
|
|
|
|
|
|
Reserve additions (2),(3) (Mboe) |
4,985 |
11,092 |
29,168 |
57,931 |
|
|
|
|
|
|
|
F&D costs per boe (2),(4) ($/boe) |
10.36 |
6.96 |
3.14 |
2.12 |
|
|
|
|
|
|
|
Estimated operating netback (1),(4) ($/boe) |
26.55 |
26.55 |
22.88 |
22.88 |
|
|
|
|
|
|
|
Recycle ratio (2),(4) |
2.6x |
3.8x |
7.3x |
10.8x |
Notes:
(1) Financial information is based on the Company's preliminary 2021 unaudited financial statements and is therefore subject to change. See "Advisories: Unaudited Financial Information".
(2) See "Advisories: Reserves Advisory" and "Advisories: Oil and Gas Metrics".
(3) Based on gross reserves, which are the Company's working interest share before deduction of royalties.
(4) Non-GAAP financial measure or ratio. See "Advisories:Non-GAAP Financial Measures and Ratios".
Touchstone Exploration Inc.
Touchstone Exploration Inc. is a Calgary, Alberta 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:
Mr. Paul Baay, President and Chief Executive Officer Tel: +1 (403) 750-4487
Mr. James Shipka, Chief Operating Officer
Mr. Scott Budau, Chief Financial Officer
Shore Capital (Nominated Advisor and Joint Broker)
Daniel Bush / Toby Gibbs / Michael McGloin Tel: +44 (0) 207 408 4090
Canaccord Genuity (Joint Broker)
Adam James / Henry Fitzgerald O'Connor / Thomas Diehl Tel: +44 (0) 207 523 8000
Camarco (Financial PR)
Billy Clegg / Emily Hall / Lily Pettifar Tel: +44 (0) 203 781 8330
Advisories
Forward-Looking Statements
Certain information provided in this announcement 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 announcement may include, but is not limited to, statements relating to Touchstone's near-term priorities, Touchstone's exploration opportunities, Royston-1 well potential production capability and the field becoming a future core development property, estimated crude oil, natural gas and NGL reserves and the net present values of future net revenue therefrom, total petroleum-initially-in-place estimated by GLJ, the forecasted future production, commodity prices, inflation rates and all future costs used by GLJ in their evaluation, field estimated production, the Company's exploration plans and strategies, including anticipated future exploration well drilling, production testing operations, pipeline installation operations, ultimate natural gas production and targeted production rates from the Coho-1 well, receipt of regulatory approvals, anticipated completion of the Cascadura natural gas facility, and the expected timing thereof . 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 2020 Annual Information Form dated March 25, 2021 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.
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, 2021 will be contained in the Company's Annual Information Form for the year ended December 31, 2021 which will be filed on SEDAR on or before March 31, 2022.
The recovery and reserve estimates of crude oil, natural gas and NGL reserves provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than or less than the estimates provided herein. This announcement summarizes the crude oil, natural gas and NGL 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, 2021 prior to provision for interest and finance costs, general and administration expenses, and the impact of any financial derivatives. 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.
"Undeveloped Reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, 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.
This announcement uses the term "total petroleum initially-in-place", which means the quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. In their evaluation of the Royston structure, GLJ estimated that the overthrust and intermediate sheet structures in the Royston area contained a low estimate of 128.3 MMbbl, a best estimate of 165.7 MMbbl and a high estimate of 211.7 MMbbl of total petroleum initially-in-place.
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.
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, 2021 consolidated financial statements is not complete. Accordingly, unaudited exploration and development 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 reserve additions to the corresponding period's F&D costs. 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 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 "Advisories:Non-GAAP Financial Measures and Ratios"). The Company's annual audit of its December 31, 2021 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 2021 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 the forward-looking statements advisory disclosed herein. These estimated results are subject to change upon completion of the Company's audited financial statements for the year ended December 31, 2021, 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, 2021 on SEDAR on March 28, 2022.
Non-GAAP Financial Measures and Ratios
Certain financial measures and ratios included herein do not have a standardized meaning as prescribed by International Financial Reporting Standards and therefore are considered non-GAAP financial measures and ratios. These measures and ratios may not be comparable to similar measures and ratios presented by other issuers. These measures and ratios are commonly used in the crude oil and natural gas industry and by the Company to provide shareholders and potential investors with additional information regarding the Company's performance and capital efficiency. Non-GAAP financial measures and ratios include operating netback, F&D costs and recycle ratio.
The Company uses operating netback as a key performance indicator of field results. The Company considers operating netback to be a key measure as it demonstrates Touchstone's profitability relative to current commodity prices and assists Management and investors with evaluating operating results on a historical basis. Operating netback is calculated by deducting royalties and operating expenses from petroleum sales. Operating netback per barrel is calculated by dividing the operating netback by production volumes for the period. Operating netback is presented herein prior to realized gains or losses on commodity derivative contracts.
The following table presents the computation of estimated operating netback disclosed herein, using unaudited financial information for the year ended December 31, 2021 in both periods.
|
($000's unless otherwise stated) |
|
|
Year ended December 31, 2021 |
Three years ended December 31, 2021 |
|
|
|
|
|
|
|
Petroleum sales |
|
|
29,568 |
87,814 |
|
Royalties |
|
|
(9,251) |
(25,725) |
|
Operating expenses |
|
|
(7,286) |
(23,920) |
|
Estimated operating netback |
|
|
13,031 |
38,169 |
|
Production (bbls) |
|
|
490,741 |
1,668,065 |
|
Estimated operating netback ($/bbl) |
|
|
26.55 |
22.88 |
Refer to "Advisories: Oil and Gas Metrics" regarding F&D costs and recycle ratio.
Abbreviations
bbl(s) barrel(s)
bbls/d barrels per day
Mbbl thousand barrels
MMbbl million barrels
Mcf thousand cubic feet
MMcf million cubic feet
MMBtu million British Thermal Units
NGL(s) natural gas liquid(s)
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.
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