TIDMTXP
RNS Number : 7773D
Touchstone Exploration Inc.
07 March 2022
2021 YEAR- 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 December % Change
31, 2021 31, 2020(1)
---------------------------------------- ---------- ------------- ---------
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 Heavy Conventional Natural Total
and Medium Crude Natural Gas Liquids Oil Equivalent
Crude Oil Gas (MMcf) (Mbbl) (Mboe)
Oil (Mbbl) (Mbbl) (2)
---------------------------- ------------ -------- ------------- ------------- ----------------
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 Heavy Conventional Natural Total
and Medium Crude Natural Gas Liquids Oil Equivalent
Crude Oil Gas (MMcf) (Mbbl) (Mboe)
Oil (Mbbl) (Mbbl) (2)
---------------------------- ------------ -------- ------------- ------------- ----------------
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 Undiscounted Discounted Discounted Discounted Discounted
Income Taxes ($000's) at 5% at 10% at 15% 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 Undiscounted Discounted Discounted Discounted Discounted
After Income Taxes (2) at 5% at 10% at 15% at 20%
($000's)
---------------------------- ------------- ----------- ----------- ----------- -----------
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 Light Heavy Conventional Natural Total
Factors and Medium Crude Natural Gas Liquids Oil Equivalent
Crude Oil Gas (MMcf) (Mbbl) (Mboe)
Oil (Mbbl) (Mbbl) (1)
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.
($000's unless otherwise stated) 1P 2P 3P
------------------------------------------- ------- ------- -------
Increase in forecasted well costs 1,859 3,154 3,154
Increase in forecasted facility
and pipeline costs 3,867 4,707 4,707
Royston exploration discovery development
costs 18,368 41,786 41,786
------------------------------------------- ------- ------- -------
Total increase in future development
costs from 2020 24,094 49,647 49,647
Total increase in future development
costs from 2020 (%) 43 59 59
------------------------------------------- ------- ------- -------
Forecast Pricing and Costs
Forecast pricing and costs are prices and costs that are
generally acceptable, in the opinion of GLJ, as being a reasonable
outlook of the future as of the evaluation effective date. The
forecast cost assumptions consider inflation with respect to future
operating and capital costs. The following table sets forth the
benchmark reference prices and inflation rates reflected in the
Reserves Data as of December 31, 2021. These price assumptions were
provided to the Company by GLJ and were GLJ's then current forecast
as of the date of the Reserves Report.
Summary of GLJ January 1, 2022 Forecast Prices and Inflation
Rate Assumptions
Forecast Year Brent Spot Henry Hub Conway Condensate Inflation
Crude Oil Natural Gas (1) Rate
(1) (1)
($/bbl) ($/MMBtu) ($/bbl) (% 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.
($000's unless otherwise Year ended Three years
stated) December ended December
31, 2021 31, 2021
----------------------------- ----------- ----------------
Petroleum sales 29,568 87,814
Royalties (9,251) (25,725)
Operating expenses (7,286) (23,920)
------------------------------- ----------- ----------------
Estimated operating netback 13,031 38,169
------------------------------- ----------- ----------------
Production (bbls) 490,741 1,668,065
Estimated operating netback
($/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.
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
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END
MSCFLFLAVAIRIIF
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March 07, 2022 02:00 ET (07:00 GMT)
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