Touchstone Exploration Announces 2023 Year-End Reserves

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CALGARY, AB / ACCESSWIRE / March 1, 2024 / Touchstone Exploration Inc. ("Touchstone", "we", "our" or the "Company") (TSX, LSE:TXP) announces 2023 year-end reserves.

Touchstone's independent reserves evaluation was prepared by GLJ Ltd. ("GLJ") with an effective date of December 31, 2023 (the "Reserves Report"). Highlights of our total proved developed producing ("PDP"), total proved ("1P"), total proved plus probable ("2P") and total proved plus probable plus possible ("3P") reserves from the Reserves Report are provided below. 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, 2023 and is subject to change. Readers are further cautioned to read the applicable advisories contained herein.

Touchstone's 2023 year-end reserves reflect the initial transition of our Cascadura production base into the PDP reserves category as we brought onstream the first two Cascadura wells, Cascadura-1ST1 and Cascadura Deep-1. In addition to successfully constructing and commissioning the Cascadura natural gas and liquids facility in 2023, we also prepared for our Cascadura C delineation and development program.

In 2023 we achieved initial production from our Cascadura field which produced net volumes of 37.4 MMcf/d of natural gas and 622 bbls/d of natural gas liquids in the fourth quarter of 2023, contributing to corporate average quarterly net production volumes of 8,504 boe/d and average 2023 annual net production volumes of 3,981 boe/d.

2023 Year-end Reserves Report Highlights

Relative to year-end 2022 and after 2023 production, we increased gross PDP reserves by 180 percent to 13,547 Mboe, decreased gross 1P reserves by 12 percent to 33,696 Mboe, decreased gross 2P reserves by 10 percent to 67,379 Mboe and decreased gross 3P reserves by 10 percent to 108,859 Mboe in 2023.
PDP reserves replaced 2023 annual production by 699 percent, reflecting Cascadura-1ST1 and Cascadura Deep-1 natural gas and associated liquids volumes that were brought online in 2023.
With the addition of Cascadura property reserves, PDP reserves represent 40 percent of 1P reserves, reflecting an attractive ratio of base production to low risk proved undeveloped ("PUD") drilling targets.
Reductions in our 1P, 2P, and 3P year-end reserves balances from 2022 reflected the removal of eight PUD locations on our non-core legacy crude oil blocks and Royston, technical revisions to the natural gas liquids yields at Cascadura, increased annual production volumes in 2023 and a limited 2023 development capital program.
Our net present value of future net revenues discounted at 10 percent ("NPV10") on a before tax PDP basis increased by 142 percent to $151.4 million, decreased by 30 percent to $372.5 million on a 1P basis, decreased by 27 percent to $730.1 million on a 2P basis, and decreased by 29 percent to $1.05 billion on a 3P basis from the prior year.
Realized after tax PDP NPV10 of $99.8 million representing an increase of 93 percent from the prior year, after tax 1P NPV10 decreased by 25 percent from year-end 2022 to $191.4 million, after tax 2P NPV10 decreased by 24 percent from the prior year to $342.5 million and after tax 3P NPV10 decreased by 26 percent from 2022 to $482.6 million.
We continue to maintain a long producing reserve life index of 7.9 years 1P and 14.4 years 2P, reflecting the low decline nature of our asset base.
The Cascadura-2 well was drilled subsequent to the effective date of the Reserves Report and will be reflected in our future reserve evaluations.

2023 Year-end Reserves Report Summary

Touchstone's year-end light and medium crude oil, heavy crude oil, conventional natural gas and natural gas liquid 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 ("COGE 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+ (www.sedarplus.ca) on or before March 30, 2024.

The reserve estimates set forth below are based upon GLJ's Reserves Report dated February 29, 2024 with an effective date of December 31, 2023. The Reserves Report uses the average price forecasts of the three leading Canadian oil and gas evaluation consultants (GLJ, McDaniel & Associates Consultants Ltd. and Sproule Associates Ltd. (collectively, the "Consultants")). All values in this news release are based on the three Consultants' average forecast pricing and GLJ's estimates of future operating and capital costs as of December 31, 2023. Please refer to "Advisories: Reserves Disclosure" for further information. In certain tables set forth below, the columns may not add due to rounding.

2023 Reserves Summary by Category


	PDP	1P	2P	3P

Total gross reserves⁽¹⁾ (Mboe)	13,547	33,696	67,379	108,859
Reserve additions (reductions)⁽²⁾ (Mboe)	10,158	(3,313)	(6,241)	(10,281)
NPV10 before income tax⁽³⁾ ($000's)	151,433	372,547	730,065	1,052,803
NPV10 after income tax⁽³⁾ ($000's)	99,791	191,466	342,527	482,575

^Notes:

^{(1) Gross reserves are the Company's working interest share before deduction of royalties.}
^{(2) Reserve additions (reductions) exclude 2023 annual production. See "}^{Advisories: Oil and Gas Metrics}^".
^{(3) Based on the Consultants' average December 31, 2023 forecast prices and costs. See "}^{Forecast prices and costs}^{" herein}

Year-Over-Year Reserves Data


	December 31, 2023		December 31, 2022⁽¹⁾		% Change

PDP gross reserves⁽²⁾ (Mboe)		13,547		4,843		180
1P gross reserves⁽²⁾ (Mboe)		33,696		38,463		(12	)
2P gross reserves⁽²⁾ (Mboe)		67,379		75,074		(10	)
3P gross reserves⁽²⁾ (Mboe)		108,859		120,594		(10	)

PDP NPV10 before income tax⁽³⁾ ($000's)		151,433		62,561		142
1P NPV10 before income tax⁽³⁾ ($000's)		372,547		530,264		(30	)
2P NPV10 before income tax⁽³⁾ ($000's)		730,065		993,714		(27	)
3P NPV10 before income tax⁽³⁾ ($000's)		1,052,803		1,473,380		(29	)

PDP NPV10 after income tax⁽³⁾ ($000's)		99,791		51,770		93
1P NPV10 after income tax⁽³⁾ ($000's)		191,446		256,623		(25	)
2P NPV10 after income tax⁽³⁾ ($000's)		342,527		450,624		(24	)
3P NPV10 after income tax⁽³⁾ ($000's)		482,575		654,913		(26	)

^Notes:

^{(1) Prior year reserve estimates per GLJ's independent reserves evaluation dated March 3, 2023 with an effective date of December 31, 2022.}
^{(2) Gross reserves are the Company's working interest share before deduction of royalties.}
^{(3) Based on the three Consultants' average December 31, 2023 forecast prices and costs. See "}^{Forecast prices and costs}^{" herein.}

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		3,360		224		56,296		580		13,547
Developed non-producing		1,331		10		4,020		37		2,048
Undeveloped		3,846		0		80,427		849		18,100
Total 1P		8,538		234		140,743		1,467		33,696

Probable		8,084		58		145,180		1,344		33,683
Total 2P		16,622		292		285,923		2,811		67,379

Possible		5,141		87		205,911		1,933		41,480
Total 3P		21,763		379		491,834		4,744		108,859
Company Net⁽³⁾ 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		2,022		199		49,259		508		10,939
Developed non-producing		856		9		3,518		32		1,484
Undeveloped		2,786		0		70,374		743		15,258
Total 1P		5,664		209		123,150		1,283		27,681

Probable		6,056		51		127,032		1,176		28,456
Total 2P		11,720		260		250,183		2,460		56,137

Possible		3,780		78		180,171		1,691		35,578
Total 3P		15,500		338		430,354		4,151		91,715

Notes:

^{(1) Gross reserves are the Company's working interest share before deduction of royalties.}
^{(2) NGLs are comprised of 100% condensate.}
^{(3) Net reserves are the Company's working interest share after the deduction of royalty obligations.}

Summary of Net Present Values of Future Net Revenues


Net Present Values Before Income Taxes⁽¹⁾ ($000's)	Undiscounted		Discounted at 5%		Discounted at 10%		Discounted at 15%		Discounted at 20%

Proved
Developed producing		203,893		173,513		151,433		134,704		121,630
Developed non-producing		41,188		32,603		27,853		24,538		21,988
Undeveloped		316,080		243,189		193,262		157,745		131,632
Total 1P		561,162		449,304		372,547		316,987		275,251

Probable		708,321		487,694		357,518		274,398		218,055
Total 2P		1,269,483		936,998		730,065		591,386		493,306

Possible		920,790		504,989		322,738		228,824		173,899
Total 3P		2,190,273		1,441,987		1,052,803		820,210		667,205

^Note:
^{(1) Based on the three Consultants' average December 31, 2023 forecast prices and costs. See "}^{Forecast prices and costs}^{" herein.}


Net Present Values After Income Taxes⁽¹⁾⁽²⁾ ($000's)	Undiscounted		Discounted at 5%		Discounted at 10%		Discounted at 15%		Discounted at 20%

Proved
Developed producing		118,430		109,202		99,791		91,684		84,890
Developed non-producing		14,408		13,126		11,716		10,546		9,583
Undeveloped		137,087		103,315		79,938		63,308		51,161
Total 1P		269,925		225,643		191,446		165,539		145,633

Probable		296,550		207,139		151,082		114,601		89,695
Total 2P		566,475		432,782		342,527		280,140		235,328

Possible		386,142		216,473		140,048		100,088		76,482
Total 3P		952,617		649,255		482,575		380,228		311,810

Notes:

^{(1) Based on the three Consultants' average December 31, 2023 forecast prices and costs. See "}^{Forecast prices and costs}^{" herein.}
^{(2) The after-tax net present values prepared by GLJ in the evaluation of the Company's petroleum 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, 2023. 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 gross proved plus probable reserves as of December 31, 2023 by product type against such reserves as at December 31, 2022 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, 2022⁽²⁾		9,977			468			146,677			3,571			38,463
Extensions and improved recovery⁽³⁾		327			-			-			-			327
Technical revisions⁽⁴⁾		(1,359	)		(209	)		(242	)		(2,030	)		(3,638	)
Economic factors⁽⁵⁾		(2	)		-			-			-			(2	)
Production		(406	)		(25	)		(5,692	)		(74	)		(1,454	)
December 31, 2023		8,538			234			140,743			1,467			33,696

Total Probable
December 31, 2022⁽²⁾		8,711			416			144,850			3,342			36,611
Extensions and improved recovery⁽³⁾		82			-			-			-			82
Technical revisions⁽⁴⁾		(702	)		(359	)		330			(1,998	)		(3,003	)
Economic factors⁽⁵⁾		(7	)		-			-			-			(7	)
Production		-			-			-			-			-
December 31, 2023		8,084			58			145,180			1,344			33,683

Total Proved plus Probable
December 31, 2022⁽²⁾		18,688			884			291,527			6,913			75,074
Extensions and improved recovery⁽³⁾		409			-			-			-			409
Technical revisions⁽⁴⁾		(2,061	)		(567	)		87			(4,028	)		(6,641	)
Economic factors⁽⁵⁾		(9	)		-			-			-			(9	)
Production		(406	)		(25	)		(5,692	)		(74	)		(1,454	)
December 31, 2023		16,622			292			285,923			2,811			67,379

^Notes:
^{(1) NGLs are comprised of 100 percent condensate.}
^{(2) Prior year reserve estimates per GLJ's independent reserves evaluation dated March 3, 2023 with an effective date of December 31, 2022.}
^{(3) Reserve amounts for Infill Drilling, Extensions and Improved Recovery are combined and reported as "Extensions and Improved Recovery".}
^{(4) Technical revisions factor includes all changes in reserves due to well performance and previously booked wells which were drilled in the year.}
^{(5) Economic factors are the change in reserves exclusively due to changes in pricing.}

December 31, 2023 gross proved plus probable reserves were 67,379 Mboe, representing a 7,695 Mboe or 10 percent decrease from the 75,074 Mboe reported in the prior year. Relative to December 31, 2022, light and medium crude oil reserves decreased by 2,006 Mbbl. The annual decline predominately reflected a combination of annual production, the removal of two proved undeveloped drilling locations at Royston and six proved undeveloped drilling locations at our CO-2 field, partially offset by two new proved undeveloped drilling locations at our CO-1 property and improved recovery from well recompletions at our WD-4 field. Proved plus probable heavy crude oil reserves decreased by 592 Mbbl from the prior year, reflecting the removal of all future recompletion activity at our Fyzabad property and 2023 production. Proved plus probable conventional natural gas reserves decreased by 5,604 MMcf relative to December 31, 2022, mainly attributed to annual Cascadura and Coho field production. Proved plus probable natural gas liquids reserves decreased by 4,102 Mbbl in comparison to December 31, 2022, reflecting a reduction in forecasted Cascadura natural gas liquids yields and 2023 annual production.

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)	PDP		1P	2P	3P

2024		50	19,270	28,260	28,260
2025		-	12,143	24,786	24,786
2026		-	21,505	28,236	28,236
2027		-	11,493	40,857	40,857
2028		-	12,995	18,537	18,537
Thereafter		-	-	-	-
Total undiscounted		50	77,406	140,676	140,676
Total discounted at 10% per year		48	62,540	112,018	112,018

The following table sets forth the changes in undiscounted future development costs ("FDC") included in the Reserves Report against such costs in our December 31, 2022 reserves report prepared by GLJ dated March 3, 2023.


($000's unless otherwise stated)	PDP		1P	2P	3P

(Decrease) increase in forecasted well costs		(140)	11,692	19,414	19,414
Decrease in forecasted well locations		-	(15,630)	(15,481)	(15,481	)
Decrease in forecasted facility and pipeline costs		-	(5,400)	(4,623)	(4,623	)
Total decrease in FDC from 2022		(140)	(9,338)	(690)	(690	)
Total decrease in FDC from 2022 (%)		(74)	(11)	-	-

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 commodity prices and inflation rates reflected in the Reserves Data as of December 31, 2023. These price assumptions were provided to the Company by GLJ and represented the average price forecast of the three Consultants as of the date of the Reserves Report.

Consultants Average Price Forecast
Forecast Year	Brent Spot Crude Oil⁽¹⁾ ($/bbl)		Henry Hub Natural Gas⁽¹⁾ ($/MMBtu)		Inflation Rate (% per year)

2024		78.00		2.75		0.0
2025		79.18		3.64		2.0
2026		80.36		4.02		2.0
2027		81.79		4.10		2.0

2028		83.41		4.18		2.0
2029		85.09		4.27		2.0
2030		86.79		4.35		2.0
2031		88.52		4.44		2.0
2032		90.29		4.53		2.0
2033		92.10		4.62		2.0
Thereafter		+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

2023

2023 - 2019 Total

Estimated capital expenditures⁽¹⁾⁽²⁾($000's)

18,949

88,213

Change in FDC ($000's)

(9,338

)

(690

)

31,407

72,034

Finding and development ("F&D") costs⁽²⁾⁽³⁾($000's)

9,611

18,259

119,620

160,247

Reserve (reductions) additions⁽³⁾⁽⁴⁾ (Mboe)

(3,313

)

(6,241

)

26,161

51,791

F&D costs per boe⁽²⁾⁽³⁾ ($/boe)

n/a

4.57

3.09

Estimated operating netback⁽¹⁾⁽²⁾ ($/boe)

18.04

22.62

Recycle ratio⁽²⁾⁽³⁾

n/a

4.9

7.3

^Notes:
^{(1) Financial information is based on the Company's preliminary 2023 unaudited financial statements and is therefore subject to change. See "}^{Advisories: Unaudited Financial Information}^".
^{(2) Non-GAAP financial measure. See "}^{Advisories: Non-GAAP Financial Measures}^".
^{(3) See "}^{Advisories: Reserves Disclosure}^{" and "}^{Advisories: Oil and Gas Metrics}^".
^{(4) Based on gross reserves, which are the Company's working interest share before deduction of royalties.}

January 2024 Sales Volumes and Realized Prices

In January 2024, we achieved average net sales volumes of 7,436 boe/d as follows:

Cascadura contributed net sales volumes of 5,799 boe/d consisting of:
net natural gas sales volumes of 32.8 MMcf/d or 5,460 boe/d with a realized price of $2.47 per Mcf; and
net natural gas liquids volumes of 339 bbls/d with an average realized price of $68.15 per barrel;
Coho field net average natural gas sales volumes were 2.8 MMcf/d or 467 boe/d at a realized price of $2.28 per Mcf (excluding third party processing fees); and
average net daily crude oil sales volumes were 1,170 bbls/d per day with an average realized price of $68.15 per barrel.

January 2024 production decreased by approximately 11 percent from December 2023, attributed to natural declines and the Cascadura Deep-1 well being shut in for four days in the month.

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.
Paul Baay, President and Chief Executive Officer
James Shipka, Chief Operating Officer
Brian Hollingshead, VP Engineering and Business Development
Telephone: 403.750.4487

Advisories

Forward-Looking Statements

The information provided in this news release contains certain 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 "expect", "plan", "anticipate", "believe", "intend", "maintain", "continue to", "pursue", "design", "result in", "sustain" "estimate", "potential", "growth", "near-term", "long-term", "forecast", "contingent" and similar expressions, or are events or conditions that "will", "would", "may", "could" or "should" occur or be achieved. The forward-looking statements contained in this news release speak only as of the date hereof and are expressly qualified by this cautionary statement.

Specifically, this news release includes, but is not limited to, forward-looking statements relating to: the Company's business plans, strategies, priorities and development plans; the sustainability and low decline nature of our asset base; estimated crude oil, NGL and natural gas reserves and the net present values of future net revenue therefrom; and the forecasted future production, commodity prices, inflation rates and all future costs used by GLJ in their evaluation. The Company's actual decisions, activities, results, performance, or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Touchstone will derive from them.

Information and 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 (see "Advisories: Reserves Disclosure").

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 2022 Annual Information Form dated March 23, 2023 which is available under the Company's profile on SEDAR+ (www.sedarplus.ca) and on the Company's website (www.touchstoneexploration.com). The forward-looking statements contained in this news release are made as of the date hereof, and except as may be required by applicable securities laws, the Company assumes no obligation or intent to update publicly or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

Reserves Disclosure

The disclosure in this news release 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, 2023 will be contained in the Company's Annual Information Form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before March 30, 2024. All reserves values, future net revenue and ancillary information contained in this news release are derived from the Reserves Report unless otherwise noted. Unless otherwise noted, reserve references in this news release are Company "gross reserves". Company gross reserves are the Company's total working interest reserves before the deduction of any royalties payable by the Company. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. All reserves assigned in the Reserves Report are located onshore in the Republic of Trinidad and Tobago and presented on a consolidated basis.

The recovery and reserve estimates of Touchstone's crude oil, NGL and natural gas 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. There are numerous uncertainties inherent in estimating quantities of petroleum and natural gas reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. This news release summarizes the crude oil, NGL 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, 2023 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 estimates of future net revenues presented herein 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.

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.

"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" 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 percent 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.

Certain terms used in this news release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 - Revised Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities ("CSA 51-324") and/or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA 51-324 and the COGE Handbook, as the case may be.

Oil and Gas Measures

Where applicable, natural gas has been converted to barrels of oil equivalent (boe) based on six thousand cubic feet (Mcf) to one barrel (bbl) 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. This conversion factor is an industry accepted norm and is not based on either energy content or prices.

Oil and Gas Metrics

This news release contains several oil and gas metrics that are commonly used in the oil and gas industry such as reserves additions (reductions), reserve life index ("RLI"), 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 news release, should not be relied upon for investment purposes.

Reserve additions (reductions) 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.

RLI is calculated by dividing the applicable reserves by forecasted 2024 production volumes derived from the Reserve Report.

F&D costs represent the costs of exploration and development incurred (refer to "Advisories:Non-GAAP Financial Measures"). Specifically, F&D costs are 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, 2023 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 (refer to "Advisories: Non-GAAP Financial Measures"). The Company's annual audit of its December 31, 2023 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 2023 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, 2023, 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, 2023 on SEDAR+ (www.sedarplus.ca) on March 21, 2024.

Supplemental Information Regarding Product Types

This news release includes references to fourth quarter and annual 2023 average daily production. The following table provides production by product type composition as defined by NI 51-101.


Period	Light and Medium Crude Oil (bbls/d)		Heavy Crude Oil (bbls/d)		Conventional Natural Gas (Mcf/d)		Natural Gas Liquids (bbls/d)		Total Oil Equivalent (boe/d)

Fourth quarter of 2023		1,068		65		40,491		622		8,504
Annual 2023		1,113		68		15,593		201		3,981

In this news release, any references to "crude oil" refer to "light crude oil and medium crude oil" and "heavy crude oil" combined product types; references to "NGLs" refer to condensate; and references to "natural gas" refer to the "conventional natural gas" product type, all as defined in NI 51-101. Any references to "crude oil and liquids" herein include crude oil and NGLs.

Non-GAAP Financial Measures

This news release may reference various non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as such terms are defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure. Such measures are not recognized measures under GAAP and do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS" or "GAAP") and therefore may not be comparable to similar financial measures disclosed by other issuers. Readers are cautioned that the non-GAAP financial measures referred to herein should not be construed as alternatives to, or more meaningful than, measures prescribed by IFRS, and they are not meant to enhance the Company's reported financial performance or position. These are complementary measures that are commonly used in the oil and natural gas industry and by the Company to provide shareholders and potential investors with additional information regarding the Company's performance. Non-GAAP financial measures presented herein include operating netback, capital expenditures, 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 a non-GAAP financial measure calculated by deducting royalties and operating expenses from petroleum and natural gas sales. The most directly comparable financial measure to operating netback disclosed in the Company's consolidated financial statements is petroleum and natural gas revenue net of royalties. Operating netback per boe is a non-GAAP ratio calculated by dividing the operating netback by total production volumes for the period. Presenting operating netback on a per boe basis allows Management to better analyze performance against prior periods on a comparable basis.

The following table presents the computation of estimated operating netback disclosed herein, using unaudited financial information for the year ended December 31, 2023 in both periods presented.


($000's unless otherwise stated)	Year ended December 31, 2023			Five years ended December 31, 2023

Petroleum and natural gas sales		48,098			178,856
Less: royalties		(12,173	)		(52,539	)
Petroleum and natural gas revenue, net of royalties		35,925			126,317
Less: operating expenses		(9,705	)		(42,647	)
Estimated operating netback		26,220			83,670
Production (boe)		1,453,073			3,698,125
Estimated operating netback ($/boe)		18.04			22.62

Capital expenditures is a non-GAAP financial measure that is calculated as the sum of exploration and evaluation asset expenditures and property, plant and equipment expenditures included in the Company's consolidated statements of cash flows and is most directly comparable to cash flows used in investing activities. Touchstone considers capital expenditures to be a useful measure of its investment in its existing asset base. The following table presents the computation of estimated capital expenditures disclosed herein, using unaudited financial information for the year ended December 31, 2023 in both periods presented.


($000's)	Year ended December 31, 2023		Five years ended December 31, 2023

Exploration and evaluation asset expenditures		17,638		75,506
Property, plant and equipment expenditures		1,311		12,707
Estimated capital expenditures		18,949		88,213