REG - Touchstone Explrtn. - 2021 YEAR-END RESERVES AND OPERATIONAL UPDATE
07/03/2022 07:00
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RNS Number : 7773D Touchstone Exploration Inc. 07 March 2022
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 Conventional Natural Gas (MMcf) Natural Gas Liquids (Mbbl)((2)) Total Oil Equivalent (Mboe)
(Mbbl)
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 Conventional Natural Gas (MMcf) Natural Gas Liquids (Mbbl)((2)) Total Oil Equivalent (Mboe)
(Mbbl)
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 Conventional Natural Gas (MMcf) Natural Gas Liquids (Mbbl)((1)) Total Oil Equivalent (Mboe)
(Mbbl)
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.
($000's unless otherwise stated) 1P 2P 3P
Increase in forecasted well costs 1,859 3,154 3,154
Increase in forecasted facility and pipeline costs 3,867 4,707 4,707
Royston exploration discovery development costs 18,368 41,786 41,786
Total increase in future development costs from 2020 24,094 49,647 49,647
Total increase in future development costs from 2020 (%) 43 59 59
Forecast Pricing and Costs
Forecast pricing and costs are prices and costs that are generally acceptable,
in the opinion of GLJ, as being a reasonable outlook of the future as of the
evaluation effective date. The forecast cost assumptions consider inflation
with respect to future operating and capital costs. The following table sets
forth the benchmark reference prices and inflation rates reflected in the
Reserves Data as of December 31, 2021. These price assumptions were provided
to the Company by GLJ and were GLJ's then current forecast as of the date of
the Reserves Report.
Summary of GLJ January 1, 2022 Forecast Prices and Inflation Rate Assumptions
Forecast Year Brent Spot Crude Oil((1)) Henry Hub Natural Gas((1)) Conway Condensate((1)) Inflation Rate
($/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 (http://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 (http://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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