TIDMTXP
RNS Number : 3095R
Touchstone Exploration Inc.
05 March 2021
TOUCHSTONE ANNOUNCES 2020 YEAR- RESERVES AND PROVIDES
OPERATIONAL UPDATE
CALGARY, ALBERTA (March 5, 2021) - Touchstone Exploration Inc.
("Touchstone", "we", "our", "us" or the "Company") (TSX, LSE: TXP)
announces a summary of its 2020 year-end reserves and provides an
operational update.
Our independent reserves evaluation was prepared by GLJ Ltd. ( "
GLJ " ) with an effective date of December 31, 2020 (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, 2020
and is subject to change. Readers are further cautioned to read the
applicable advisories contained herein.
2020 Year-end Reserves Report Highlights
-- Increased 3P net reserves by 236% to 100,150 Mboe, increased
2P net reserves by 194% to 64,947 Mboe and increased 1P net
reserves by 189% to 34,238 Mboe from the prior year.
-- In comparison to 2019, 10% discounted net present value of
future net revenues ("NPV10") on a before tax 3P basis increased by
90% to $1,002.8 million and after tax 3P NPV10 increased by 108% to
$419.4 million.
-- Achieved a before tax 2P NPV10 of $683.1 million,
representing an increase of 72% from $397.9 million reported in
2019 and realized an annual after tax 2P NPV10 increase of 88% to
$289.2 million.
-- Realized before tax 1P NPV10 of $362.9 million, representing
an increase of $160.7 million or 79% from the prior year and
increased after tax 1P NPV10 by 95% from year-end 2019 to $163.0
million.
-- Realized 1P F&D costs of $1.26 per boe, resulting in a
recycle ratio 11.3 times using our unaudited annual estimated 2020
operating netback of $14.29 per boe. Touchstone's low F&D costs
are primarily attributed to our meaningful 2020 reserves growth
from our Cascadura-1ST1 well discovery.
-- Recognized 2P F&D costs of $0.71 per boe, resulting in a
2P recycle ratio of 20.3 times, demonstrating Touchstone's capital
efficient operations in the Ortoire block.
-- FDC associated with only a portion of our internally
identified drilling location inventory and low-risk recompletion
projects totaled $55.9 million for 1P reserves and $83.9 million
for both 2P and 3P reserves.
-- The Cascadura assessment area was assigned gross working
interest 1P reserves of 23,622 Mboe and gross working interest 2P
reserves of 45,030 Mboe with an estimated before tax 2P NPV10 of
$411.8 million.
-- The Reserves Report excluded any potential reserves from the
Company's Chinook-1 and Cascadura Deep-1 wells drilled in the
fourth quarter of 2020.
Paul Baay, President and Chief Executive Officer, commented:
"Our year-end 2020 reserves evaluation provides further
independent confirmation of the significant opportunities that the
Company has in place from our Trinidad assets. Our 1P reserves are
now significantly higher than our 3P reserves at the same time last
year, providing greater operational and financial certainty for
investors, and exclude any potential reserves from the recently
drilled Chinook-1 well or Cascadura Deep-1 wells. We have a lot to
be excited about as we focus on converting our world class reserves
to production during 2021 as well as expanding opportunities
through additional drilling at Ortoire."
Operational Highlights
-- Tested two identified pay zones in the Chinook-1 well, with
both zones encountering potential upside in the form of light sweet
crude oil. One pay zone is currently being configured for an
extended production test.
-- Equipment has arrived in Trinidad to enable testing of the
main gas bearing zones in the Cascadura Deep-1 well, where
significant hydrocarbon accumulations were reported in December
based on drilling and wireline logging data.
-- Testing of the potential gas bearing sands in the Chinook-1
well will commence following the extended crude oil test.
-- We continue to target the second quarter of 2021 for initial
Ortoire gas commercialization, with final regulatory approvals for
the tie-in of our Coho-1 well received and construction
underway.
-- Working with the National Gas Company of Trinidad and Tobago
to commence regulatory applications to tie-in Cascadura and any
potential Chinook production volumes, with the objective of
achieving initial production prior to the end of 2021.
-- The primary access road to the Royston-1 well location has
been cleared, and we have commenced road resurfacing and lease
building operations.
-- Initiated line clearing for the 21-kilometre 2D seismic program in the Royston area.
-- Expected to enter into a minimum three-year drilling services
contract from a Canadian based private company to supply an
ultra-heavy telescopic drilling rig to Trinidad in late 2021, which
will enable us access to three drilling rigs in Trinidad capable of
drilling to depths of 10,000 feet or more.
Operational Update
Well Testing
Touchstone has yet to test the targeted gas bearing zones in the
Chinook-1 and Cascadura Deep-1 exploration wells due to unavoidable
delays associated with third-party equipment including the natural
gas testing unit. However, we are pleased to report that all
required equipment has now been cleared through the various levels
of government organizations in Trinidad and is expected to be on
location within the next ten days.
Touchstone has tested two low resistivity zones in the Chinook-1
well. The first test interval was in the lower sub-thrust sheet,
which was a previously unknown thrust-sheet where we identified 68
net feet of potential pay based on wireline logging data. During
this test, the well recovered trace amounts of 41 degrees API sweet
oil along with significant high pressure and high temperature
water, which was indicative of encountering a fracture at the base
of the formation. With the high volume of water, the zone is
considered uneconomic; however, indications of light oil prove the
concept of hydrocarbons in the sub-thrust sheet. Based on 3D
seismic data, future development locations are anticipated to be
positioned structurally up-dip by as much as 1,000 feet from the
Chinook-1 well to evaluate the sub-thrust sheet in an optimal
structural position. The Company has permanently abandoned this
lowermost zone and completed a second zone in the Herrera formation
which encountered 35 degrees API sweet oil and is currently being
configured for an extended oil production test. We anticipate
conducting the first natural gas test at the Cascadura Deep-1 well
while the Chinook-1 well is on the extended oil production
test.
James Shipka, Chief Operating Officer, commenting on the
Chinook-1 well tests, said:
"This is an encouraging start to the production testing program
as it confirms the presence of hydrocarbons in the sub-thrust sheet
and will allow for further up-dip drilling targets based on
available 3D seismic data. The sub-thrust sheet was not one of the
original Chinook-1 well targets, so the confirmation of
hydrocarbons in the deep section is very positive. Although the
lower zone was considered uneconomic given the high water cuts, the
reservoir displayed potential as fluid flowed to surface at over
2,200 bbls/d. Future targets structurally up-dip from Chinook-1
hold tremendous potential.
The second production test is also very exciting and could
result in numerous development locations. The presence of oil in
the intermediate section reaffirms that the hydrocarbon system in
the Herrera is extensive and variable. Our extended production test
will determine if this zone is commercial in Chinook-1 before we
move up in the wellbore to our next test which we anticipate being
a natural gas zone immediately above the oil. It is unfortunate
that due to third-party issues beyond our control we have had to
wait on the gas test equipment; nevertheless, valuable data has
been collected in the interim period.
The multi-target project at Ortoire is still in the early
stages. The oil discovery at Chinook-1 adds another layer of
opportunity that we have not previously forecasted. For reference,
the offsetting Barrackpore oil pool has over 60 wells that have
produced approximately 18.7 million barrels, averaging 300,000
barrels per well with oil ranging from 27 to 30 degrees API. "
Coho-1 Tie-in
On January 22, 2021, the Company received approval to proceed
with the construction of the Coho-1 tie-in project. Subsequent to
the required initial notification period, construction operations
have commenced. Touchtone is targeting initial gas production from
Coho-1 in the second quarter of 2021. In conjunction with the
project, we have also been working with the Natural Gas Company of
Trinidad and Tobago to survey and commence regulatory applications
to tie-in Cascadura and any potential Chinook production volumes,
with a goal to achieve initial production prior to the end of 2021.
The Company is concurrently applying for two additional surface
locations at both Cascadura and Chinook which will allow for up to
16 development locations.
Royston Drilling Preparations
Touchstone is pleased to report that we have cleared the primary
access road to the Royston-1 drilling location and are currently
surfacing the road and performing lease preparations. The Royston
well will be drilled using Well Services Rig #60 targeting a total
depth of approximately 11,500 feet. The drilling rig is scheduled
to move onto location early in the second quarter of 2021.
Drilling Rig Contract
Given our exploration success, the Company expects to execute a
contract with a Canadian based private company to provide state of
the art drilling equipment commencing in late 2021. The contractor
will deploy a North American based drilling rig equipped for us to
evaluate the deep targets at Royston, Cascadura and Chinook along
with drilling on our legacy crude oil development properties.
Pursuant to the current terms of the drilling contract, Touchstone
must utilize the rig for a minimum of 120 days per year over an
initial three-year term and is obligated to pay for rig
mobilization costs, which are currently estimated to be
approximately $1 million. This arrangement, in combination with our
current drilling services provider, will give the Company access to
three drilling rigs capable of drilling to depths of 10,000 feet or
more on the Ortoire block as well as the Company's legacy oil
development properties.
Seismic Program
Touchstone has initiated surveying and line clearing for our
21-kilometre 2D seismic program. The seismic information will be
used for further delineation of the structure to be drilled at
Royston and adjacent prospects in the Mid Miocene Herrera formation
and is expected to optimize future drilling into the previously
identified Cretaceous exploration target. The program is scheduled
to be completed prior to July 2021.
2020 Year-end Reserves Report Summary
Touchstone's 2020 capital program focused on exploration
activities on our Ortoire property, where we drilled two gross (1.6
net) exploration wells. Similar to 2019, we conducted minimal
capital development activity on our development properties, mainly
performing wellbore recompletions and workover operations to arrest
production declines. The Reserves Report includes those reserves
associated with our legacy development properties and our Coho
natural gas discovery in 2019, as well as new reserves associated
with our Cascadura discovery in 2020. The Reserves Report does not
include any reserves associated with our Chinook-1 and Cascadura
Deep-1 wells drilled in 2020, as production testing operations were
not completed prior to the effective date of the Reserves
Report.
Touchstone's year-end crude oil and natural gas reserves in
Trinidad were evaluated by independent reserves evaluator, GLJ, in
accordance with definitions, standards and procedures contained in
the Canadian Oil and Gas Evaluation Handbook and National
Instrument 51-101 Standards of Disclosure for Oil and Gas
Activities ( " NI 51-101 " ). Additional reserves information as
required under NI 51-101 will be included in the Company's Annual
Information Form, which will be filed on SEDAR on or before March
31, 2021. The reserve estimates set forth below are based upon
GLJ's Reserves Report dated March 4, 2021 with an effective date of
December 31, 2020. All values in this announcement are based on
GLJ's forecast prices and estimates of future operating and capital
costs as at December 31, 2020. In certain tables set forth below,
the columns may not add due to rounding.
Summary of Company Gross Oil and Gas Reserves as of December 31,
2020 by Product Type (1),(2)
Reserves Light and Heavy Oil Conventional Natural Total Oil
Category Medium (Mbbl) Natural Gas Liquids Equivalent
Oil (Mbbl) Gas (MMcf) (Mbbl) (Mboe)
--------------- -------------------- ------------------------- ------------------------- ------------------------- --------------------
Proved
Developed
Producing 3,470 175 - - 3,644
Developed
Non-Producing 1,717 367 48,708 1,061 11,264
Undeveloped 3,703 - 81,313 2,074 19,329
--------------- -------------------- ------------------------- ------------------------- ------------------------- --------------------
Total Proved 8,890 542 130,021 3,136 34,238
Probable 6,562 469 125,022 2,842 30,709
Total Proved
plus
Probable 15,452 1,010 255,043 5,977 64,947
--------------- -------------------- ------------------------- ------------------------- ------------------------- --------------------
Possible 4,873 362 157,386 3,738 35,203
--------------- -------------------- ------------------------- ------------------------- ------------------------- --------------------
Total Proved
plus
Probable plus
Possible 20,325 1,372 412,429 9,715 100,150
--------------- -------------------- ------------------------- ------------------------- ------------------------- --------------------
Notes:
(1) Gross reserves are the Company's working interest share of
the remaining reserves before deduction of any royalties.
(2) See " Advisories: Reserves Advisory ".
Summary of Net Present Values of Future Net Revenues Before Tax
as of December 31, 2020 (1),(2)
Reserves Category Net Present Values of Future Net Revenues
Before Income Taxes Discounted at (%
per year) ($000's)
---------------------------- ------------------------------------------------------
0% 5% 10% 15% 20%
---------------------------- ---------- ---------- ---------- -------- --------
Proved
Developed Producing 61,934 45,680 37,399 32,106 28,344
Developed Non-Producing 207,971 162,378 133,400 112,822 97,384
Undeveloped 351,317 255,396 192,092 148,557 117,550
---------------------------- ---------- ---------- ---------- -------- --------
Total Proved 621,222 463,454 362,891 293,485 243,278
Probable 646,336 439,959 320,192 243,712 191,811
---------------------------- ---------- ---------- ---------- -------- --------
Total Proved plus Probable 1,267,557 903,413 683,084 537,197 435,089
Possible 737,859 463,396 319,751 234,400 179,349
---------------------------- ---------- ---------- ---------- -------- --------
Total Proved plus Probable
plus Possible 2,005,416 1,366,809 1,002,835 771,597 614,438
---------------------------- ---------- ---------- ---------- -------- --------
Notes:
(1) Based on GLJ's December 31, 2020 escalated price forecast.
See " Summary of Pricing and Inflation Rate Assumptions " .
(2) See " Advisories: Reserves Advisory " .
Summary of Net Present Values of Future Net Revenues After Tax
as of December 31, 2020 (1),(2), (3)
Reserves Category Net Present Values of Future Net Revenues
After Income Taxes Discounted at (%
per year) ($000's)
---------------------------- --------------------------------------------------
0% 5% 10% 15% 20%
---------------------------- --------- --------- -------- -------- --------
Proved
Developed Producing 35,991 29,848 26,081 23,358 21,259
Developed Non-Producing 90,946 74,294 62,920 54,527 48,055
Undeveloped 140,503 100,506 74,021 55,827 42,929
---------------------------- --------- --------- -------- -------- --------
Total Proved 267,440 204,648 163,022 133,712 112,242
---------------------------- --------- --------- -------- -------- --------
Probable 254,214 173,852 126,150 95,476 74,642
---------------------------- --------- --------- -------- -------- --------
Total Proved plus Probable 521,655 378,501 289,172 229,188 186,884
Possible 294,079 187,684 130,262 95,795 73,487
---------------------------- --------- --------- -------- -------- --------
Total Proved plus Probable
plus Possible 815,734 566,185 419,434 324,983 260,371
---------------------------- --------- --------- -------- -------- --------
Notes:
(1) Based on GLJ's December 31, 2020 escalated price forecast.
See " Summary of Pricing and Inflation Rate Assumptions " .
(2) See " Advisories: Reserves Advisory " .
(3) Income taxes include all resource income, appropriate income
tax calculations per current Republic of Trinidad and Tobago tax
regulations and estimated unaudited December 31, 2020 consolidated
tax pools and non-capital losses. See "Advisories: Unaudited
Financial Information".
Reconciliation of Changes in Gross Reserves by Product Type
(1),(2)
Reserves Light and Heavy Crude Conventional Natural Total Oil
Category Medium Crude Oil (Mbbl) Natural Gas Liquids Equivalent
and Factors Oil (Mbbl) Gas (MMcf) (Mbbl) (Mboe)
------------- ------------------------- ------------------------- ------------------------- ------------------------- ------------------------
Total Proved
December 31,
2019(3) 9,590 1,103 6,888 - 11,840
Exploration
discoveries - - 122,916 3,136 23,622
Technical
revisions (196) (516) 218 - (675)
Economic
factors (33) (12) - - (45)
Production (471) (33) - - (504)
------------- ------------------------- ------------------------- ------------------------- ------------------------- ------------------------
December 31,
2020 8,890 542 130,021 3,136 34,238
------------- ------------------------- ------------------------- ------------------------- ------------------------- ------------------------
Total Proved
plus
Probable
December 31,
2019(3) 16,906 1,801 20,091 - 22,056
Exploration
discoveries - - 234,318 5,977 45,030
Technical
revisions (934) (743) 634 - (1,571)
Economic
factors (50) (15) - - (65)
Production (471) (33) - - (504)
------------- ------------------------- ------------------------- ------------------------- ------------------------- ------------------------
December 31,
2020 15,452 1,010 255,043 5,977 64,947
------------- ------------------------- ------------------------- ------------------------- ------------------------- ------------------------
Notes:
(1) Gross reserves are the Company's working interest share of
the remaining reserves before deduction of any royalties.
(2) See " Advisories: Reserves Advisory " .
(3) Prior year reserve estimates per GLJ's independent reserves
evaluation dated March 4, 2020 with an effective date of December
31, 2019.
In comparison to December 31, 2019 on a 2P reserve basis, light
and medium crude oil reserves decreased 984 Mbbl from technical
revisions and economic factors in 2020. Approximately 597 Mbbl of
this change reflected decreased well performance from the Company's
Coora, WD-8 and WD-4 blocks. In addition, the removal of future
development locations on the Company's Barrackpore and San
Francique properties decreased 2P reserves by approximately 387
Mbbl.
Heavy crude oil was attributed combined downward technical
revisions and economic factors of 758 Mbbl as of December 31, 2020,
primarily reflecting a decrease in future development locations on
Touchstone's Fyzabad and New Dome properties based on decreased
future planned activity and expenditures.
Upward technical revisions of approximately 106 Mboe were
reflective of reduced surface loss estimates related to the Coho
natural gas discovery in 2019. The Company's successful
Cascadura-1ST1 well drilled and tested on our Ortoire property led
to a 45,030 Mboe increase in conventional natural gas and natural
gas liquids 2P reserves in 2020.
Future Development Costs
The following table provides information regarding the future
development costs deducted in the estimation of the Company's
future net revenue using forecast prices and costs as included in
the Reserves Report.
Year Proved Reserves Proved plus Proved plus
($000's) Probable Reserves Probable plus
($000's) Possible Reserves
($000's)
------------------------- ---------------- ------------------- -------------------
2021 9,530 11,360 11,360
2022 16,236 23,397 23,397
2023 12,584 16,787 16,787
2024 8,906 17,759 17,759
2025 8,666 14,625 14,625
Thereafter - - -
------------------------- ---------------- ------------------- -------------------
Total undiscounted 55,920 83,927 83,927
Total discounted at 10%
per year 45,098 66,584 66,584
------------------------- ---------------- ------------------- -------------------
The following table sets forth the changes in undiscounted
future development costs included in the Reserves Report against
such costs included in the December 31, 2019 reserves report.
($000's unless otherwise Proved Reserves Proved plus Proved plus
stated) Probable Reserves Probable plus
Possible Reserves
--------------------------- ---------------- ------------------- -------------------
Increase in forecasted
capital costs 1,645 1,976 1,976
Decrease in development
locations (6,905) (10,158) (10,158)
Cascadura discovery 15,805 20,428 20,428
--------------------------- ---------------- ------------------- -------------------
Total undiscounted change 10,545 12,246 12,246
Total undiscounted change
(%) 19 15 15
--------------------------- ---------------- ------------------- -------------------
Summary of Pricing and Inflation Rate Assumptions
The following table sets forth benchmark reference pricing and
inflation rates reflected in the Reserves Report.
Forecast Year Brent Spot NYMEX Henry Conway Condensate Inflation Rates
Crude Oil Hub ($/bbl)(1) (% per year)(2)
($/bbl)(1) Natural Gas
($/MMBtu)(1)
--------------- ------------- -------------- ------------------ -----------------
2021 50.75 2.75 43.20 0.0
2022 55.00 2.80 46.35 1.0
2023 58.50 2.85 49.05 2.0
2024 61.79 2.90 52.01 2.0
2025 62.95 2.95 53.06 2.0
2026 64.13 3.01 54.12 2.0
2027 65.33 3.07 55.20 2.0
2028 66.56 3.13 56.30 2.0
2029 67.81 3.19 57.43 2.0
2030 69.17 3.25 58.58 2.0
Thereafter +2.0% / year +2.0% / year +2.0% / year 2.0
Notes:
(1) This summary table identifies benchmark reference pricing
schedules that might apply to a reporting issuer. Product sales
prices will reflect these reference prices with further adjustments
for marketing arrangements, quality differentials and
transportation to point of sale.
(2) Inflation rates for forecasting pricing and costs.
Estimated Company Capital Program Efficiency
Proved Reserves Proved plus
Probable Reserves
-------------------------------------------- --------------------- ---------------------
Estimated capital expenditures ($000's)
(1) 18,349 18,349
Change in FDC required to develop reserves
($000's) 10,545 12,246
-------------------------------------------- --------------------- ---------------------
Estimated F&D costs ($000's) (2) 28,894 30,595
-------------------------------------------- --------------------- ---------------------
Gross reserve additions (Mboe) (2),
( (3) 22,902 43,395
Estimated F&D costs per boe ($/boe)
(2) 1.26 0.71
-------------------------------------------- --------------------- ---------------------
Estimated 2020 operating netback ($/boe)
(1),(4) 14.29 14.29
Estimated 2020 recycle ratio (2) 11.3x 20.3x
-------------------------------------------- --------------------- ---------------------
Notes:
(1) Financial information is based on the Company's preliminary
2020 unaudited financial statements and is therefore subject to
audit. See "Advisories: Unaudited Financial Information".
(2) See "Advisories: Reserves Advisory" and "Advisories: Oil and Gas Metrics".
(3) Gross reserves are the Company's working interest share of
the remaining reserves before deduction of any royalties.
(4) See "Non-GAAP Measures".
Advisories
Forward-Looking Statements
Certain information provided in this 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 estimated crude oil and
natural gas reserves and the net present values of future net
revenue therefrom, the forecasted future production, commodity
prices, inflation rates and all future costs used by GLJ in their
evaluation, the potential undertaking, timing, locations and costs
of future well testing, well drilling, well tie-in and seismic
operations, the expected timing of initial production from
exploration wells and the expected execution of a drilling rig
contract, including drilling rig mobilization timing and costs.
Although the Company believes that the expectations and assumptions
on which the forward-looking statements are based are reasonable,
undue reliance should not be placed on the forward-looking
statements because the Company can give no assurance that they will
prove to be correct. Since forward-looking statements address
future events and conditions, by their very nature they involve
inherent risks and uncertainties. Actual results could differ
materially from those currently anticipated due to a number of
factors and risks. Certain of these risks are set out in more
detail in the Company's 2019 Annual Information Form dated March
25, 2020 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, 2020 will
be contained in the Company's Annual Information Form for the year
ended December 31, 2020 which will be filed on SEDAR on or before
March 31, 2021.
The recovery and reserve estimates of crude oil and natural gas
reserves provided herein are estimates only, and there is no
guarantee that the estimated reserves will be recovered. Actual
crude oil and natural gas reserves may eventually prove to be
greater than or less than the estimates provided herein. This
announcement summarizes the crude oil and natural gas reserves of
the Company and the net present values of future net revenue for
such reserves using forecast prices and costs as at December 31,
2020 prior to provision for interest and finance costs, general and
administration expenses, the impact of any financial derivatives or
liabilities associated with the abandonment and reclamation of
certain facilities and wells. It should not be assumed that the
present worth of estimated future net revenues presented in the
tables above represent the fair market value of the reserves. There
is no assurance that the forecast prices and costs assumptions will
be attained, and variances could be material.
"Proved Developed Producing Reserves" are those reserves that
are expected to be recovered from completion intervals open at the
time of the estimate. These reserves may be currently producing, or
if shut-in, they must have previously been on production, and the
date of resumption of production must be known with reasonable
certainty.
"Proved Developed Non-Producing Reserves" are those reserves
that either have not been on production or have previously been on
production but are shut-in, and the date of resumption of
production is unknown.
"Proved Undeveloped Reserves" are those reserves expected to be
recovered from known accumulations where a significant expenditure
(e.g., when compared to the cost of drilling a well) is required to
render them capable of production. They must fully meet the
requirements of the reserves category (proved, probable, possible)
to which they are assigned.
"Proved" reserves are those reserves that can be estimated with
a high degree of certainty to be recoverable. It is likely that the
actual remaining quantities recovered will exceed the estimated
proved reserves.
"Probable" reserves are those additional reserves that are less
certain to be recovered than proved reserves. It is equally likely
that the actual remaining quantities recovered will be greater or
less than the sum of the estimated proved plus probable
reserves.
"Possible" reserves are those additional reserves that are less
certain to be recovered than probable reserves. There is a 10%
probability that the quantities actually recovered will equal or
exceed the sum of proved plus probable plus possible reserves. It
is unlikely that the actual remaining quantities recovered will
exceed the sum of the estimated proved plus probable plus possible
reserves.
In the Reserves Report, GLJ forecasted reserve volumes and
future cash flows based upon current and historical well
performance through to the economic production limit of individual
wells. Notwithstanding established precedence and contractual
options for the continuation and renewal of the Company's existing
licence, sub-licence and marketing agreements , in many cases the
forecasted economic limit of individual wells is beyond the current
term of the relevant agreements. There is no certainty as to any
renewal of the Company's existing exploration, production, and
marketing arrangements.
Oil and Gas Measures
Where applicable, natural gas has been converted to barrels of
oil equivalent based on six thousand cubic feet to one barrel of
oil. The barrel of oil equivalent rate is based on an energy
equivalent conversion method primarily applicable at the burner
tip, and given that the value ratio based on the current price of
crude oil as compared to natural gas is significantly different
than the energy equivalency of the 6:1 conversion ratio, utilizing
the 6:1 conversion ratio may be misleading as an indication of
value.
Oil and Gas Metrics
This announcement contains several oil and gas metrics that are
commonly used in the oil and gas industry such as reserves
additions, finding and development costs, and recycle ratio. These
metrics have been prepared by Management and do not have
standardized meanings or standardized methods of calculation, and
therefore such measures may not be comparable to similar measures
presented by other companies and should not be used to make
comparisons. Such metrics have been included herein to provide
readers with additional measures to evaluate the Company's
performance; however, such measures are not reliable indicators of
the future performance of the Company, and future performance may
not compare to the performance in prior periods, and therefore such
metrics should not be unduly relied upon. The Company uses these
oil and gas metrics for its own performance measurements and to
provide shareholders with measures to compare the Company's
operations over time. Readers are cautioned that the information
provided by these metrics, or that can be derived from the metrics
presented in this announcement, should not be relied upon for
investment purposes.
Net reserve additions are calculated as the change in reserves
from the beginning to the end of the applicable period excluding
period production. Management uses this measure to determine the
relative change of its reserves base over a period of time.
F&D costs represent the costs of exploration and development
incurred. Specifically, F&D is calculated as the sum of
exploration and development capital expenditures incurred in the
period and the change in future development costs required to
develop those reserves. The Company's annual audit of its December
31, 2020 consolidated financial statements is not complete.
Accordingly, unaudited capital expenditure amounts used in the
calculation of F&D costs are Management's estimates and are
subject to change. F&D costs per barrel is determined by
dividing current period net reserve additions to the corresponding
period's F&D cost. Readers are cautioned that the aggregate of
capital expenditures incurred in the most recent financial year and
the change during that year in estimated FDC generally will not
reflect total F&D costs related to net reserves additions for
that year. Management uses F&D costs as a measure of its
ability to execute its capital program, the success in doing so,
and of the Company's asset quality.
Recycle ratio is a measure used by Management to evaluate the
effectiveness of its capital reinvestment program and is calculated
by dividing the annual F&D costs per barrel to operating
netback per barrel prior to realized gains or losses on commodity
derivative contracts in the corresponding period (see "Non-GAAP
Measures"). The Company's annual audit of its December 31, 2020
consolidated financial statements is not complete. Accordingly,
unaudited operating netbacks used in calculations of recycle ratios
are Management's estimates and are subject to change. The recycle
ratio compares netbacks from existing reserves to the cost of
finding new reserves and may not accurately indicate the investment
success unless the replacement of reserves are of equivalent
quality as the produced reserves.
Unaudited Financial Information
Certain annual 2020 financial information disclosed herein
including capital expenditures and operating netback are based on
unaudited estimated results and are subject to the same limitations
as discussed in Forward-Looking Statements set out above. These
estimated results are subject to change upon completion of the
Company's audited financial statements for the year ended December
31, 2020, and changes could be material. Touchstone anticipates
filing its audited consolidated financial statements and related
management's discussion and analysis for the year ended December
31, 2020 on SEDAR on March 26, 2021.
Non-GAAP Measures
The Company uses operating netback as a key performance
indicator of field results. Operating netback is presented on a
total and per barrel basis and is calculated by deducting royalties
and operating expenses from petroleum sales. Operating netback is
presented herein prior to realized gains or losses on commodity
derivative contracts. Operating netback does not have a
standardized meaning under Generally Accepted Accounting Principles
and therefore may not be comparable with the calculation of similar
measures by other companies. The Company considers operating
netback to be a key measure as it demonstrates Touchstone's
profitability relative to current commodity prices. This
measurement assists Management and investors in evaluating
operating results on a historical basis.
Abbreviations
bbl(s) barrel(s)
bbls/d barrels per day
Mbbl thousand barrels
Mcf thousand cubic feet
MMcf million cubic feet
Bcf billion cubic feet
MMBtu million British Thermal Units
boe barrels of oil equivalent
Mboe thousand barrels of oil equivalent
API American Petroleum Institute gravity
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.
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:
Touchstone Exploration Inc.
Mr. Paul Baay, President and Chief Executive Officer Tel: +1
(403) 750 4487
Mr. James Shipka, Chief Operating Officer
Shore Capital (Nominated Advisor and Joint Broker)
Nominated Advisor: Edward Mansfield / Daniel Bush / Michael
McGloin Tel: +44 (0) 207 408 4090
Corporate Broking: Jerry Keen
Canaccord Genuity (Joint Broker)
Adam James / Henry Fitzgerald O'Connor / Thomas Diehl Tel: +44
(0) 207 523 8000
Camarco (Financial PR)
Nick Hennis / Billy Clegg Tel: +44 (0) 203 781 8330
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END
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(END) Dow Jones Newswires
March 05, 2021 02:00 ET (07:00 GMT)
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