# Touchstone Exploration year end reserves increased and operational update

- Link: https://www.directorstalkinterviews.com/touchstone-exploration-year-end-reserves-increased-and-operational-update/4121055789
- Published: 2022-03-07T07:42:55+00:00
- Author: Giles

**[Touchstone Exploration](https://www.directorstalkinterviews.com/company/touchstone-exploration-inc/txp.l)
Inc.** (TSX, [LON:TXP](https://www.directorstalkinterviews.com/company/touchstone-exploration-inc/txp.l))
has announced a summary of its 2021 year-end reserves and an operational update.

Our independent reserves evaluation was prepared by GLJ Ltd. with an effective date
of December 31, 2021. 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 costs below include changes
in future development capital. 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, Touchstone Exploration President and Chief Executive Officer, commented:**
> “Our 2021 independent reserves evaluation confirms the significant opportunities
> at our Ortoire property and the profitability of all of our assets in Trinidad.
> The estimated additions of both future net revenues and reserves at the newly 
> discovered Royston light oil pool are reflective of our successful drilling activities
> in 2021 and the considerable size of the prospect in the Herrera Formation. The
> initial Royston reserves evaluation was conservative, given only one well was 
> drilled to date and no reserves were assigned to the subthrust sheet. We have 
> two exciting opportunities to substantially increase reserves in the area with
> the Royston Deep well intended to evaluate the subthrust sheet of the Herrera 
> Formation and the Kraken well targeting the deeper Cretaceous Formation.
> We are proceeding with the final step to bring the Coho gas field online with 
> anticipated first natural gas production in May 2022, which will represent a milestone
> for Touchstone and Trinidad. We also remain on track with our operations at Cascadura,
> as we have submitted the required regulatory applications and procured the long
> lead items for the surface facility, providing visibility to estimated completion
> in September 2022.
> Our focus is to convert our extensive Trinidad resource base to cash flows while
> continuing to target further exploration opportunities across our licence areas.
> It is an exciting time for Touchstone, as it is rare to have a combination of 
> solid low decline base production, a near-term step change in production, a multi-
> year development drilling program and extensive exploration opportunities. I would
> encourage anyone requiring additional information to view the updated corporate
> presentation available on our website.”

**Operational Highlights**

·      With all relevant agreements executed, pipeline tie-in operations for the
Coho-1 well are proceeding with anticipated first gas in May 2022 subject to weather
conditions.

·      The Company is currently awaiting regulatory approvals to commence constructing
the Cascadura natural gas facility, with equipment procurement and delivery of pressure
vessels on track for facility completion in September 2022 assuming timely receipt
of required regulatory approvals.

·      The extended flow test at Royston has confirmed the well is capable of over
675 bbls/d of light, sweet oil production from a combination of the overthrust and
intermediate sheets of the Herrera Formation.

·      The three development wells drilled on our legacy crude oil blocks in the
fourth quarter of 2021 have produced a field estimated 210 bbls/d since coming on
production, contributing to our current field estimated aggregate net base production
of approximately 1,449 bbls/d, excluding production testing volumes from Royston-
1.

**Operational Update**

**Coho**

All of the required agreements with our third-party partners to allow for the final
tie-in of the Coho gas field on the Ortoire block have been executed. Pipeline installation
operations have commenced with first gas anticipated in May 2022 subject to weather
delays that may hinder trenching and welding operations. Following testing and purging
of the pipeline, we are anticipating natural gas production to increase over time
to a gross target of 10 MMcf/d (8 MMcf/d net, representing approximately 1,333 boe/
d net production).

**Cascadura**

The Cascadura facility is proceeding with the major facility components nearing 
completion for transportation to Trinidad. The components will be delivered on skids
and will be assembled in the field by local contractors. In parallel with the facilities
procurement and construction, we have submitted the required regulatory application
and expect to receive a response on or before mid-May 2022. Upon approval, we will
proceed with four distinct projects at Cascadura: road construction, condensate 
pipeline construction, facility construction and construction of future development
drilling locations.

**Royston**

We commenced a long-term production test of the uppermost 84 feet of the Herrera
overthrust section in January 2022 with the goal of evaluating different flowing
regimes and possible pump configurations to maximize oil production. While conducting
the test, approximately 2,200 feet of pipe and perforating guns were stuck in the
bottom portion of the well, not allowing any further testing of the deeper zones.
However, with these constraints, the well has continued to deliver both pumping 
and flowing volumes from the uppermost 84 feet.

Combined with the previous test in the intermediate zone, the well has shown that
the completed intervals are capable of producing over 675 bbls/d of oil. Produced
oil is being sold at our Barrackpore sales facility, and all associated water has
been separated on-site and reinjected at our water disposal facility. We anticipate
production testing continuing until the commencement of future drilling operations
at Royston.

**Legacy Wells**

The three development wells drilled by the Company in the fourth quarter of 2021
are on production. Since being brought onstream, they have contributed an aggregate
average of 210 bbls of net oil per day. We have prepared the next location on our
Coora-1 block where we plan to drill two commitment infill wells targeting the Forest
and Cruse Formations.

> **James Shipka, Chief Operating Officer, commenting on the Royston-1 well test,
> said:**
> “Testing of the Royston-1 exploration well resumed in early January with the well
> initially flowing at rates of over 250 barrels of oil per day from the uppermost
> 84 feet of the overthrust reservoir. Over the course of flow testing and, as anticipated,
> production rates gradually declined due to liquid loading in the wellbore and 
> we subsequently moved a service rig to the location to install a pump to increase
> production. While attempting to raise the downhole assembly, we discovered an 
> issue with the casing at approximately 7,250 feet that prevented us to run the
> optimized downhole pumping assembly. The wellbore could not be cleared, and we
> ultimately severed the existing tubing string at approximately 7,200 feet. In 
> early February, we ran a downhole pump above the pre-existing tubing string, and
> we are currently working on optimizing production in this restricted configuration.
> Despite these mechanical challenges, our testing program at Royston-1 has confirmed
> that the Royston structure will be a core oil development property for Touchstone.
> The light oil discoveries in the intermediate and overthrust sheets have displayed
> production rates in excess of 675 barrels of oil per day from the structure. With
> an independent estimate of up to 212 million barrels of total petroleum initially-
> in-place in the high case, including upside potential from the upper two sheets,
> Royston will be an exciting long-term project. Our 2021 reserves bookings reflect
> Royston’s initial development stage, and we look forward to our future exploration
> wells which will further delineate and expand our understanding of the structure.
> Until then, we will continue our testing program at Royston to gather additional
> information and refine our model of the reservoir. The similarities between Royston
> and the Penal-Barrackpore fields are significant and have given us confidence 
> in our understanding of how the different thrust sheets may contribute to the 
> ultimate recovery of the field.”

**2021 Year-end Reserves Report Summary**

Touchstone’s 2021 capital program focused on exploration activities on our Ortoire
property, where we conducted production testing operations on the Cascadura Deep-
1 well drilled in the fourth quarter of 2020, completed the Royston area 22-kilometre
seismic program, and drilled and tested the Royston-1 exploration well. In addition,
we drilled three gross and net wells on our legacy oil properties representing our
first infill drilling since 2019. The Reserves Report includes those reserves associated
with our legacy development properties, our Coho natural gas discovery in 2019, 
our Cascadura discovery in 2020, as well as additions relating to the Cascadura 
Deep-1 and Royston-1 wells.

Touchstone’s year-end crude oil, natural gas and NGL reserves in Trinidad were evaluated
by independent reserves evaluator, GLJ, in accordance with definitions, standards
and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National
Instrument 51-101 _Standards of Disclosure for Oil and Gas Activities_ (“NI 51-101”).
Additional reserves information as required under NI 51-101 will be included in 
the Company’s Annual Information Form, which will be filed on SEDAR on or before
March 31, 2022. The reserve estimates set forth below are based upon GLJ’s Reserves
Report dated March 4, 2022 with an effective date of December 31, 2021. All values
in this announcement are based on GLJ’s forecast prices and estimates of future 
operating and capital costs as of December 31, 2021. Please refer to “_Advisories:
Reserves Advisories_” for further information. In certain tables set forth below,
the columns may not add due to rounding.

**2021 Reserves Summary by Category**

|  | 1P | 2P | 3P | 
|  |  |  |  | 
| Total gross reserves^((1)) (Mboe) | 38,731 | 75,547 | 121,332 | 
| Reserve additions^((2)) (Mboe) | 4,985 | 11,092 | 21,674 | 
| NPV10 before income tax^((3)) ($000’s) | 474,922 | 881,753 | 1,313,006 | 
| NPV10 after income tax^((3)) ($000’s) | 210,036 | 363,068 | 535,613 | 
|  |  |  |  |

Notes:

(1)    Gross reserves are the Company’s working interest share before deduction 
of royalties.

(2)    See “_Advisories: Oil and Gas Metrics_“.

(3)    Based on GLJ’s December 31, 2021 forecast prices and costs. See “_Forecast
prices and costs_“.

**Year-Over-Year Reserves Data**

|  | December 31, 2021 | December 31, 2020^((1)) | % Change | 
|  |  |  |  | 
| 1P gross reserves^((2)) (Mboe) | 38,731 | 34,238 | 13 | 
| 2P gross reserves^((2)) (Mboe) | 75,547 | 64,947 | 16 | 
| 3P gross reserves^((2)) (Mboe) | 121,332 | 100,150 | 21 | 
|  |  |  |  | 
| 1P NPV10 before income tax^((3)) ($000’s) | 474,922 | 362,891 | 31 | 
| 2P NPV10 before income tax^((3)) ($000’s) | 881,753 | 683,084 | 29 | 
| 3P NPV10 before income tax^((3)) ($000’s) | 1,313,006 | 1,002,835 | 31 | 
|  |  |  |  | 
| 1P NPV10 after income tax^((3)) ($000’s) | 210,036 | 163,022 | 29 | 
| 2P NPV10 after income tax^((3)) ($000’s) | 363,068 | 289,172 | 26 | 
| 3P NPV10 after income tax^((3)) ($000’s) | 535,613 | 419,434 | 28 | 
|  |  |  |  |

Notes:

(1)    Prior year reserve estimates per GLJ’s independent reserves evaluation dated
March 4, 2021 with an effective date of December 31, 2020.

(2)    Gross reserves are the Company’s working interest share before deduction 
of royalties.

(3)    Based on GLJ’s December 31, 2021 forecast prices and costs. See “_Forecast
prices and costs_“.

**Summary of Crude Oil and Natural Gas Reserves by Product Type**

| **Company Gross**^((1))** Reserves** | Light and Medium Crude Oil (Mbbl) | Heavy Crude Oil(Mbbl) | **Conventional ****Natural Gas (MMcf)** | **Natural Gas Liquids (Mbbl)**^((2)) | Total Oil Equivalent (Mboe) | 
|  |  |  |  |  |  | 
| Proved |  |  |  |  |  | 
| Developed Producing | 3,387 | 261 | – | – | 3,648 | 
| Developed Non-Producing | 2,148 | 210 | 93,252 | 2,198 | 20,098 | 
| Undeveloped | 4,638 | – | 53,841 | 1,374 | 14,985 | 
| Total Proved | 10,174 | 471 | 147,093 | 3,571 | 38,731 | 
|  |  |  |  |  |  | 
| Probable | 8,908 | 458 | 144,642 | 3,342 | 36,815 | 
| Total Proved plus Probable | 19,082 | 929 | 291,735 | 6,913 | 75,547 | 
|  |  |  |  |  |  | 
| Possible | 6,186 | 340 | 205,727 | 4,972 | 45,785 | 
| Total Proved plus Probable plus Possible | 25,268 | 1,269 | 497,462 | 11,885 | 121,332 |

Notes:

(1)    Gross reserves are the Company’s working interest share before deduction 
of royalties.

(2)    NGLs are comprised of 100% condensate.

| **Company Net**^((1))** Reserves** | Light and Medium Crude Oil (Mbbl) | Heavy Crude Oil(Mbbl) | **Conventional ****Natural Gas (MMcf)** | **Natural Gas Liquids (Mbbl)**^((2)) | Total Oil Equivalent (Mboe) | 
|  |  |  |  |  |  | 
| Proved |  |  |  |  |  | 
| Developed Producing | 2,119 | 232 | – | – | 2,352 | 
| Developed Non-Producing | 1,599 | 187 | 81,595 | 1,923 | 17,308 | 
| Undeveloped | 3,285 | – | 47,111 | 1,202 | 12,339 | 
| Total Proved | 7,003 | 419 | 128,706 | 3,125 | 31,999 | 
|  |  |  |  |  |  | 
| Probable | 6,719 | 407 | 126,561 | 2,925 | 31,145 | 
| Total Proved plus Probable | 13,723 | 827 | 255,268 | 6,049 | 63,143 | 
|  |  |  |  |  |  | 
| Possible | 4,581 | 302 | 180,011 | 4,350 | 39,236 | 
| Total Proved plus Probable plus Possible | 18,304 | 1,129 | 435,279 | 10,399 | 102,379 |

Notes:

(1)    Net reserves are the Company’s working interest share after the deduction
of royalty obligations.

(2)    NGLs are comprised of 100% condensate.

**_Summary of Net Present Values of Future Net Revenues_**^((1))

| Net Present Values Before Income Taxes ($000’s) | Undiscounted | Discounted at 5% | Discounted at 10% | Discounted at 15% | Discounted at 20% | 
|  |  |  |  |  |  | 
| Proved |  |  |  |  |  | 
| Developed Producing | 70,586 | 59,730 | 51,737 | 45,799 | 41,267 | 
| Developed Non-Producing | 375,339 | 302,251 | 253,336 | 217,580 | 190,218 | 
| Undeveloped | 285,210 | 217,561 | 169,849 | 135,347 | 109,717 | 
| Total Proved | 731,135 | 579,541 | 474,922 | 398,726 | 341,202 | 
|  |  |  |  |  |  | 
| Probable | 827,687 | 559,969 | 406,831 | 310,348 | 245,521 | 
| Total Proved plus Probable | 1,558,822 | 1,139,510 | 881,753 | 709,074 | 586,723 | 
|  |  |  |  |  |  | 
| Possible | 1,050,052 | 636,255 | 431,253 | 315,331 | 243,050 | 
| Total Proved plus Probable plus Possible | 2,608,874 | 1,775,765 | 1,313,006 | 1,024,405 | 829,773 | 
|  |  |  |  |  |  | 
| **Net Present Values After Income Taxes**^((2))** ($000’s)** | Undiscounted | Discounted at 5% | Discounted at 10% | Discounted at 15% | Discounted at 20% | 
|  |  |  |  |  |  | 
| Proved |  |  |  |  |  | 
| Developed Producing | 40,461 | 38,818 | 35,781 | 32,906 | 30,445 | 
| Developed Non-Producing | 93,106 | 77,056 | 66,818 | 59,345 | 53,537 | 
| Undeveloped | 178,040 | 136,986 | 107,437 | 85,756 | 69,482 | 
| Total Proved | 311,607 | 252,860 | 210,036 | 178,006 | 153,464 | 
|  |  |  |  |  |  | 
| Probable | 317,593 | 213,545 | 153,032 | 114,800 | 89,205 | 
| Total Proved plus Probable | 629,200 | 466,405 | 363,068 | 292,806 | 242,669 | 
|  |  |  |  |  |  | 
| Possible | 413,968 | 254,122 | 172,545 | 126,103 | 97,118 | 
| Total Proved plus Probable plus Possible | 1,043,168 | 720,527 | 535,613 | 418,909 | 339,787 |

Notes:

(1)    Based on GLJ’s December 31, 2021 forecast prices and costs. See “_Forecast
prices and costs_“.

(2)    The after-tax net present values prepared by GLJ in the evaluation of the
Company’s crude oil and natural gas assets presented herein are calculated by considering
current Trinidad tax regulations and are based on the Company’s estimated tax pools
and non-capital losses as of December 31, 2021. The values reflect the expected 
income tax burden on the assets on a consolidated basis. Values do not represent
an estimate of the value at the business entity level or consider tax planning, 
which may be significantly different. See “_Advisories: Unaudited Financial Information_“.

**Reconciliation of Gross Reserves by Product Type**

The following table sets forth a reconciliation of the Company’s total gross proved,
gross probable and total gross proved plus probable reserves as of December 31, 
2021 by product type against such reserves as at December 31, 2020 based on forecast
prices and cost assumptions.

| Reserves Category and Factors | Light and Medium Crude Oil (Mbbl) | Heavy Crude Oil(Mbbl) | **Conventional ****Natural Gas (MMcf)** | **Natural Gas Liquids (Mbbl)**^((1)) | Total Oil Equivalent (Mboe) | 
|  |  |  |  |  |  | 
| Total Proved |  |  |  |  |  | 
| December 31, 2020^((2)) | 8,890 | 542 | 130,021 | 3,136 | 34,238 | 
| Exploration discoveries^((3)) | 1,280 | – | – | – | 1,280 | 
| Extensions and improved recovery^((4)) | 244 | – | 17,072 | 436 | 3,525 | 
| Technical revisions^((5)) | 195 | (16) | – | – | 179 | 
| Dispositions^((6)) | – | (11) | – | – | (11) | 
| Economic factors^((7)) | 13 | – | – | – | 13 | 
| Production | (449) | (43) | – | – | (492) | 
| December 31, 2021 | 10,174 | 471 | 147,093 | 3,571 | 38,731 | 
|  |  |  |  |  |  | 
| Total Probable |  |  |  |  |  | 
| December 31, 2020^((2)) | 6,562 | 469 | 125,022 | 2,842 | 30,709 | 
| Exploration discoveries^((3)) | 2,240 | – | – | – | 2,240 | 
| Extensions and improved recovery^((4)) | 72 | – | 19,620 | 500 | 3,842 | 
| Technical revisions^((5)) | 28 | (6) | – | – | 22 | 
| Dispositions^((6)) | – | (5) | – | – | (5) | 
| Economic factors^((7)) | 7 | – | – | – | 7 | 
| Production | – | – | – | – | – | 
| December 31, 2021 | 8,908 | 458 | 144,642 | 3,342 | 36,815 | 
|  |  |  |  |  |  | 
| Total Proved plus Probable |  |  |  |  |  | 
| December 31, 2020^((2)) | 15,452 | 1,010 | 255,043 | 5,977 | 64,947 | 
| Exploration discoveries^((3)) | 3,520 | – | – | – | 3,520 | 
| Extensions and improved recovery^((4)) | 316 | – | 36,691 | 936 | 7,367 | 
| Technical revisions^((5)) | 222 | (21) | – | – | 201 | 
| Dispositions^((6)) | – | (16) | – | – | (16) | 
| Economic factors^((7)) | 20 | – | – | – | 20 | 
| Production | (449) | (43) | – | – | (492) | 
| December 31, 2021 | 19,082 | 929 | 291,735 | 6,914 | 75,547 |

Notes:

(1)    NGLs are comprised of 100 percent condensate.

(2)    Prior year reserve estimates per GLJ’s independent reserves evaluation dated
March 4, 2021 with an effective date of December 31, 2020.

(3)    Discoveries are associated with the evaluation of the Royston area discovery
on the Ortoire block.

(4)    Reserve amounts for Infill Drilling, Extensions and Improved Recovery are
combined and reported as “Extensions and Improved Recovery”.

(5)    Technical revisions factor includes all changes in reserves due to well performance
and previously booked wells which were drilled in the year.

(6)    The assets associated with three non-core properties were classified as held
for sale with an effective date of December 31, 2021. The Company is currently awaiting
regulatory approvals to close the asset dispositions.

(7)    Economic factors are the change in reserves exclusively due to changes in
pricing.

In comparison to December 31, 2020 on a proved plus probable reserve basis, light
and medium crude oil reserves increased 558 Mbbl from technical revisions, economic
factors and drilling extensions in 2021. 222 Mbbl of the annual increase reflected
improved well performance from our Coora, WD-4, WD-8, San Francique and Barrackpore
blocks, and 316 Mbbl of this change was based on our 2021 drilling campaign at WD-
4 and WD-8 resulting in drilling extension reserve additions. In addition, heavy
crude oil was attributed downward technical revisions and economic factors of 21
Mbbl as of December 31, 2021, primarily due to reduced well performance at our Fyzabad
block. Effective December 31, 2021, we sold our non-core New Dome, South Palo Seco,
and Palo Seco properties, resulting in an aggregate decrease of 16 Mbbl.

Our successful Royston-1 exploration well drilled in 2021 on the Ortoire block led
to a proved plus probable exploration discovery of 3,520 Mbbl of light and medium
crude oil reserves in 2021. In addition, our Cascadura Deep-1 well which was tested
in the first quarter of 2021 led to a 7,051 Mboe increase in proved plus probable
conventional natural gas and NGL reserves as of December 31, 2021.

**Future Development Costs**

The following table provides information regarding the development costs deducted
in the estimation of the Company’s future net revenue using forecast prices and 
costs as included in the Reserves Report.

| Year ($000’s) | 1P | 2P | 3P | 
|  |  |  |  | 
| 2022 | 27,708 | 31,098 | 31,098 | 
| 2023 | 23,700 | 37,353 | 37,353 | 
| 2024 | 8,126 | 36,650 | 36,650 | 
| 2025 | 10,341 | 14,542 | 14,542 | 
| 2026 | 10,138 | 13,931 | 13,931 | 
| Thereafter | – | – | – | 
| Total undiscounted | 80,014 | 133,574 | 133,574 | 
| Total discounted at 10% per year | 67,375 | 110,397 | 110,397 |

The following table sets forth the changes in undiscounted future development costs
included in the Reserves Report against such costs in our December 31, 2020 reserves
report prepared by GLJ dated March 4, 2021.

| ($000’s unless otherwise stated) | 1P | 2P | 3P | 
|  |  |  |  | 
| Increase in forecasted well costs | 1,859 | 3,154 | 3,154 | 
| Increase in forecasted facility and pipeline costs | 3,867 | 4,707 | 4,707 | 
| Royston exploration discovery development costs | 18,368 | 41,786 | 41,786 | 
| Total increase in future development costs from 2020 | 24,094 | 49,647 | 49,647 | 
| Total increase in future development costs from 2020 (%) | 43 | 59 | 59 |

**Forecast Pricing and Costs**

Forecast pricing and costs are prices and costs that are generally acceptable, in
the opinion of GLJ, as being a reasonable outlook of the future as of the evaluation
effective date. The forecast cost assumptions consider inflation with respect to
future operating and capital costs. The following table sets forth the benchmark
reference prices and inflation rates reflected in the Reserves Data as of December
31, 2021. These price assumptions were provided to the Company by GLJ and were GLJ’s
then current forecast as of the date of the Reserves Report.

**Summary of GLJ January 1, 2022 Forecast Prices and Inflation Rate Assumptions**

| Forecast Year | **Brent Spot Crude Oil**^((1))($/bbl) | **Henry Hub Natural Gas**^((1))($/MMBtu) | **Conway Condensate**^((1))($/bbl) | Inflation Rate(% per year) | 
|  |  |  |  |  | 
| 2022 | 76.00 | 3.80 | 67.16 | 0.0 | 
| 2023 | 72.51 | 3.50 | 63.49 | 3.0 | 
| 2024 | 71.24 | 3.15 | 61.86 | 2.0 | 
| 2025 | 72.66 | 3.21 | 63.09 | 2.0 | 
| 2026 | 74.12 | 3.28 | 64.36 | 2.0 | 
| 2027 | 75.59 | 3.34 | 65.64 | 2.0 | 
| 2028 | 77.11 | 3.41 | 66.96 | 2.0 | 
| 2029 | 78.66 | 3.48 | 68.30 | 2.0 | 
| 2030 | 80.22 | 3.55 | 69.66 | 2.0 | 
| 2031 | 81.83 | 3.62 | 71.06 | 2.0 | 
| Thereafter | +2.0% / year | +2.0% / year | +2.0% / year | 2.0 | 
|  |  |  |  |  |

Note:

(1)    This summary table identifies benchmark reference pricing schedules that 
might apply to a reporting issuer. Product sales prices will reflect these reference
prices with further adjustments for specific marketing arrangements, quality differentials
and transportation to point of sale.

**Capital Program Efficiency**

|   | 2021 |   | 2021 – 2019 Total | 
|   | 1P | 2P | 1P | 2P | 
|  |  |   |  |  | 
| Estimated exploration and development capital expenditures^((1)) ($000’s) | 27,546 | 27,546 | 57,617 | 57,617 | 
| Change in FDC ($000’s) | 24,094 | 49,647 | 34,015 | 64,932 | 
| F&D costs^((2),(4) )($000’s) | 51,640 | 77,193 | 91,632 | 122,549 | 
|  |  |   |  |  | 
| Reserve additions^((2),(3)) (Mboe) | 4,985 | 11,092 | 29,168 | 57,931 | 
|  |  |   |  |  | 
| F&D costs per boe^((2),(4)) ($/boe) | 10.36 | 6.96 | 3.14 | 2.12 | 
|  |  |   |  |  | 
| Estimated operating netback^((1),(4)) ($/boe) | 26.55 | 26.55 | 22.88 | 22.88 | 
|  |  |   |  |  | 
| Recycle ratio^((2),(4)) | 2.6x | 3.8x | 7.3x | 10.8x |

Notes:

(1)    Financial information is based on the Company’s preliminary 2021 unaudited
financial statements and is therefore subject to change. See “_Advisories: Unaudited
Financial Information_“.

(2)    See “_Advisories: Reserves Advisory_” and “_Advisories: Oil and Gas Metrics_“.

(3)    Based on gross reserves, which are the Company’s working interest share before
deduction of royalties.

(4)    Non-GAAP financial measure or ratio. See “_Advisories:_ _Non-GAAP Financial
Measures and Ratios_“.

**Touchstone Exploration Inc.**

Touchstone Exploration Inc. is a Calgary, Alberta based company engaged in the business
of acquiring interests in petroleum and natural gas rights and the exploration, 
development, production and sale of petroleum and natural gas. Touchstone is currently
active in onshore properties located in the Republic of Trinidad and Tobago. The
Company’s common shares are traded on the Toronto Stock Exchange and the AIM market
of the London Stock Exchange under the symbol “TXP”.

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