Touchstone Exploration Inc.

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Management's Discussion and Analysis For the three months ended March 31, 2023 and 2022

TSX / LSE: TXP

www.touchstoneexploration.com

Management's Discussion and Analysis As at and for the three months ended March 31, 2023 and 2022

This Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of Touchstone Exploration Inc. ("Touchstone", "we", "our", "us" or the "Company") for the three months ended March 31, 2023 with comparisons to the three months ended March 31, 2022 is dated May 11, 2023 and should be read in conjunction with the Company's unaudited interim condensed consolidated financial statements as at and for the three months ended March 31, 2023 (the "interim financial statements"), as well as with the Company's audited consolidated financial statements as at and for the year ended December 31, 2022 (the "audited 2022 financial statements"). The interim financial statements have been prepared by Management in accordance with International Accounting Standard 34 " Interim Financial Reporting " using accounting policies consistent with International Financial Reporting Standards ("IFRS" or "GAAP") as issued by the International Accounting Standards Board. Accounting policies adopted by the Company are set out in the notes to the audited 2022 financial statements. This MD&A should also be read in conjunction with Touchstone's MD&A for the three months and year ended December 31, 2022, as disclosure which is unchanged from December 31, 2022 may not be duplicated herein.

Unless otherwise stated, all financial amounts presented herein are rounded to thousands of United States dollars ("$" or "US$").

The Company may also reference Canadian dollars ("C$") and Trinidad and Tobago dollars ("TT$") herein, which are the functional and operational currencies of the Company's parent company and operating subsidiaries, respectively. All production volumes disclosed herein are sales volumes and are based on Company working interest before royalty burdens. Certain prior year amounts have been reclassified to conform to the current year presentation.

In all cases where percentage (%) figures are provided, such percentages have generally been rounded to the nearest whole number and limited to increases or decreases of 100 percent.

Certain measures in this MD&A do not have any standardized meaning prescribed under IFRS and therefore are considered non-GAAP financial measures. Readers are cautioned that this MD&A should be read in conjunction with Touchstone's disclosure under the " Advisories " section herein which provides information on non-GAAP financial measures, forward-looking statements, oil and natural gas measures, product type disclosures and references to Touchstone.

About Touchstone Exploration Inc.

Touchstone is incorporated under the laws of Alberta, Canada with its head office located in Calgary, Alberta. The Company is a petroleum and natural gas exploration and production company active in the Republic of Trinidad and Tobago ("Trinidad"). Touchstone is currently one of the largest independent onshore oil and natural gas producers in Trinidad, with assets in several large, high-quality reservoirs that have significant internally estimated total petroleum and natural gas initially-in-place and an extensive inventory of petroleum and natural gas development and exploration opportunities. 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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First Quarter 2023 Management's Discussion and Analysis

Financial and Operating Results Summary

	Three months ended	Three months ended
	March 31,	December 31,	March 31,
	2023	2022	2022
Operational
Average daily production
Crude oil(1) (bbls/d)	1,285	1,274	1,396
Natural gas(1) (Mcf/d)	5,124	5,729	-
Average daily production_(boe/d)_(2)	2,139	2,229	1,396
Average realized prices(3)
Crude oil(1) ($/bbl)	64.86	75.10	83.55
Natural gas(1) ($/Mcf)	2.12	2.11	-
Realized commodity price_($/boe)_(2)	44.03	48.36	83.55
Production mix_(% of production)_
Crude oil(1)	60	57	100
Natural gas(1)	40	43	-
Operating netback_($/boe)_(2)
Realized commodity price(3)	44.03	48.36	83.55
Royalties(3)	(13.01)	(15.24)	(28.55)
Operating expenses(3)	(12.05)	(12.07)	(17.17)
Operating netback(3)	18.97	21.05	37.83
Financial($000's except per share amounts)
Petroleum and natural gas sales	8,476	9,919	10,496
Cash from (used in) operating activities	913	(1,189)	350
Funds flow from operations(3)	803	691	1,443
Net loss	(279)	(1,921)	(236)
Per share – basic and diluted	(0.00)	(0.01)	(0.00)
Exploration capital expenditures	8,750	2,290	1,874
Development capital expenditures	269	219	680
Capitalexpenditures(3)	9,019	2,509	2,554
Working capital deficit (surplus)(3)	4,383	(4,992)	(4,259)
Principal long-term balance of term loan	19,500	21,000	25,500
Net debt(3)–end of period	23,883	16,008	21,241
Share Information(000's)
Weighted average shares outstanding – basic and diluted	233,037	217,106	210,823
Outstanding shares – end of period	233,037	233,037	211,164

Notes:

(1) In the table above and elsewhere in this MD&A, references to "crude oil" refer to light and medium crude oil and heavy crude oil product types combined; references to "NGLs" refer to condensate; and references to "natural gas" refer to conventional natural gas, all as defined in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Refer to the " Advisories - Product Type Disclosures " section of this MD&A for further information.

(2) In the table above and elsewhere in this MD&A, references to "boe" mean barrels of oil equivalent that are calculated using the energy equivalent conversion method. Refer to the " Advisories - Oil and Natural Gas Measures " section in this MD&A for further information.

(3) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

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First Quarter 2023 Management's Discussion and Analysis

First quarter 2023 financial and operational highlights

Produced quarterly average volumes of 2,139 boe/d, representing a 4 percent decrease compared to the fourth quarter of 2022 and a 53 percent increase relative to the 1,396 boe/d produced in the prior year equivalent quarter.
Natural gas production from our Coho-1 well averaged net volumes of 5.1 MMcf/d (854 boe/d) in the quarter and contributed $976,000 of net natural gas sales at an average realized price of $2.12/Mcf.
Realized petroleum and natural gas sales of $8,476,000 compared to $10,496,000 in the 2022 comparative quarter, as the incremental $976,000 in net natural gas sales were offset by decreased crude oil sales of $2,996,000, reflecting a 22 percent decline in realized crude oil pricing and an 8 percent decrease in crude oil production.
Generated an operating netback of $3,652,000, representing a 23 percent decrease from the 2022 equivalent quarter primarily attributed to a 19 percent decline in petroleum and natural gas sales.
Reported funds flow from operations of $803,000 in the quarter compared to $691,000 in the preceding quarter and $1,443,000 in the prior year equivalent quarter.
Recognized a net loss of $279,000 ($0.00 per basic share) in the quarter compared to a net loss of $236,000 ($0.00 per basic share) reported in the same period of 2022.
$9,019,000 in quarterly capital investments primarily focused on expenditures directed to the drilling of the Royston-1X sidetrack well and progressing construction of the Cascadura natural gas and liquids facility.
Exited the quarter with a cash balance of $10,859,000, a working capital deficit of $4,383,000 and a principal balance of $25,500,000 remaining on our term credit facility, resulting in a net debt position of $23,883,000.

Principal Properties and Licences

A schedule of our core Trinidad property interests as of March 31, 2023 is set forth below.

Property	Property	Working interest (%)	Licence type	Gross acres(1)	Net acres(2)
Developed
	CO-1	100	Lease Operatorship	1,230	1,230
	CO-2	100	Lease Operatorship	469	469
	WD-4	100	Lease Operatorship	700	700
	WD-8	100	Lease Operatorship	650	650
	Barrackpore(3)	100	Private	211	211
	Fyzabad(3)	100	Crown and Private	564	564
	Ortoire - Coho	80	Crown	1,317	1,054
	Ortoire - Cascadura	80	Crown	2,377	1,902
	San Francique(3)	100	Private	1,277	1,277
		92		8,795	8,057
Exploratory
	Ortoire	80	Crown	41,037	32,830
Total		82		49,832	40,887

Notes:

(1) "Gross" means acres in which the Company has an interest.

(2) "Net" means the Company's interest in the gross acres.

(3) In January 2023, Touchstone announced an asset swap agreement for the noted properties with a third-party Trinidadian private company. Refer to the " Asset Exchange Transaction " section of this MD&A for further details.

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First Quarter 2023 Management's Discussion and Analysis

We operate Trinidad-based upstream petroleum and natural gas activities under state exploration and production licences with the Trinidad and Tobago Ministry of Energy and Energy Industries ("MEEI"), Lease Operatorship Agreements ("LOAs") with Heritage Petroleum Company Limited ("Heritage") and private subsurface and surface leases with individual landowners. The LOAs contain marketing arrangements, whereas any oil sold from MEEI licences and private agreements are marketed under a separate crude oil sales agreement with Heritage. We executed a long-term natural gas sales agreement with The National Gas Company of Trinidad and Tobago Limited ("NGC") related to all natural gas sales from our Ortoire property in December 2020.

Asset Exchange Transaction

In January 2023, Primera Oil and Gas Limited ("POGL"), a wholly owned subsidiary of Touchstone, entered into an Asset Exchange Agreement for the exchange of certain onshore Trinidad assets with a privately held Trinidadian entity. Pursuant to the agreement, POGL agreed to swap our operated 100 percent working interests in the Fyzabad, San Francique and Barrackpore producing blocks for the counterparty's working interest in the Rio Claro, Balata East and Balata East Deep Horizons blocks for no cash consideration with the asset exchange becoming effective upon closing. The agreement remains subject to certain closing conditions, including receipt of applicable regulatory approvals and an extension of the Rio Claro Exploration and Production (Public Petroleum Rights) Licence.

Ortoire Exploration Operations

Cascadura

We are proceeding with natural gas and liquids facility construction operations on the Cascadura A surface location to meet the long-term production capabilities of the previously drilled Cascadura-1ST1 and Cascadura Deep-1 wells. We continue to target completion and commissioning for first production on or about June 30, 2023.

In addition, we have completed constructing the Cascadura C surface location, which will be the location of our first Cascadura development well.

We are continuing to negotiate a marketing arrangement for the associated liquids from the Cascadura reservoir and expect to initially truck condensate to sales facilities.

Royston

In February 2023, we drilled the Royston-1X exploration well, which was a sidetrack from the original Royston-1 well drilled in 2021. Royston-1X kicked off from the Royston-1 wellbore at a depth of approximately 7,150 feet and reached a total measured depth of 11,316 feet.

Based on openhole wireline logs, we identified five target intervals in the well to potentially test. The initial Royston-1X well production test in subthrust sheet of the Herrera Formation at depths between 11,102 and 11,168 feet confirmed the presence of light crude oil at non-commercial rates. The section of the formation appeared to be a low permeability reservoir, and further testing will not be conducted.

The next well test will target a gross interval of seventy feet in the middle portion of the subthrust sheet and will be performed with a service rig. Testing operations at this interval are expected in late May once the service rig has moved in following demobilization of the drilling rig to the Cascadura C location.

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First Quarter 2023 Management's Discussion and Analysis

Results of Operations

Financial highlights

($000's except per share amounts)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Net loss	(279)	(236)	18
Per share – basic and diluted	(0.00)	(0.00)	-
Cash from operating activities	913	350	100
Funds flow from operations	803	1,443	(44)

Net loss

We recorded a net loss of $279,000 ($0.00 per basic share) in the first quarter of 2023 compared to a net loss of $236,000 ($0.00 per basic share) in the prior year equivalent quarter. Compared to the first quarter of 2022, the variance from the first quarter of 2023 predominately reflected a decrease of $640,000 in funds flow from operations, partially offset by various non-cash costs, including a $682,000 year-over-year decrease in deferred income tax expenses. The following table sets forth details of the change in net loss from the three months ended March 31, 2022 to the three months ended March 31, 2023.

($000's)	Three months ended March 31,
Net loss–2022	(236)
Cash items
Funds flow from operations	(640)
Cash variances	(640)
Non-cash items
Gain on asset dispositions	(35)
Unrealized foreign exchange	(21)
Equity-based compensation expense	(117)
Depletion and depreciation expense	(447)
Impairment expense	121
Non-cash finance expenses	414
Deferred income tax	682
Non-cash variances	597
Net loss – 2023	(279)

Cash from operating activities

Details of the change in cash from operating activities from the three months ended March 31, 2022 to the three months ended March 31, 2023 are included in the table below.

($000's)	Three months ended March 31,
Cash from operating activities–2022	350
Change in funds flow from operations	(640)
Net changein non-cash working capital	1,203
Cash from operating activities – 2023	913

Funds flow from operations

We generated funds flow from operations of $803,000 in the first quarter of 2023 compared to $1,443,000 in the prior year comparative quarter. In comparison to the first quarter of 2022, first quarter 2023 operating netbacks decreased by $1,101,000, reflecting decreases in crude oil production and realized pricing, partially offset by incremental net natural gas sales revenue from the Coho-1 well and decreased royalty

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First Quarter 2023 Management's Discussion and Analysis

expenses. The decline in operating netbacks were slightly offset by $413,000 of reduced current income tax expenses recorded in the first quarter of 2023. The following graph summarizes the change in funds flow from operations from the three months ended March 31, 2022 to the three months ended March 31, 2023.

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Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

Production volumes

	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Production
Crude oil (bbls)	115,640	125,625	(8)
Natural gas_(Mcf)_	461,189	-	n/a
Totalproduction(boe)	192,505	125,625	53
Average daily production
Crude oil (bbls/d)	1,285	1,396	(8)
Natural gas_(Mcf/d)_	5,124	-	n/a
Average daily production(boe/d)	2,139	1,396	53
Crude oil and liquids_(%)_	60	100
Natural gas_(%)_	40	-

Average first quarter 2023 crude oil production volumes of 1,285 bbls/d decreased 8 percent from the 1,396 bbls/d produced in the prior year equivalent quarter, predominately reflecting natural declines. In addition, we sold 2,856 net barrels of crude oil from our Royston-1 production test in the first quarter of 2022, representing an average of 32 bbls/d.

Coho-1 contributed average net production volumes of 5.1 MMcf/d or 854 boe/d in the first quarter of 2023, representing an 11 percent decrease from 5.7 MMcf/d (955 boe/d) produced in the fourth quarter of 2022. The decline was due to higher flush production experienced when the well was brought online in October 2022, with first quarter 2023 production representing stabilized production rates.

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First Quarter 2023 Management's Discussion and Analysis

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Average Daily Production
2,250
2,000
1,750
1,500
1,250
1,000
750
500
250
-
Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023
Crude Oil NGLs Natural Gas
boe/d
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The following table and graphs summarize crude oil production by property during the three months and years ended March 31, 2023 and 2022.

(bbls)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Coora	39,892	35,842	11
WD-4	43,737	51,250	(15)
WD-8	19,395	21,715	(11)
Fyzabad	6,918	8,372	(17)
San Francique	4,776	4,493	6
Ortoire	-	2,856	n/a
Other	922	1,097	(16)
Crude oilproduction	115,640	125,625	(8)

Crude Oil Production by Property for the Three Months Ended March 31, 2023 (bbls)

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Coora
WD-4
38%
34%
WD-8
Fyzabad
San Francique
1% 17% Other
4%
6%
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Crude Oil Production by Property for the Three Months Ended March 31, 2022 (bbls)

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Coora
41% WD-4
WD-8
28%
Fyzabad
San Francique
Ortoire
1% 17%
2% Other
4%
7%
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First Quarter 2023 Management's Discussion and Analysis

Commodity prices

	Three months ended March 31,	Three months ended March 31,	%
	2023	2022	change
Average benchmark prices(1)
Brent ($/bbl)	81.07	100.87	(20)
WTI ($/bbl)	76.13	94.29	(19)
Average realized prices(2)
Crude oil($/bbl)	64.86	83.55	(22)
Naturalgas ($/Mcf)	2.12	-	n/a
Realized commodity price ($/boe)	44.03	83.55	(47)
Crude oil realized price discount as a % of Brent	(20.0)	(17.2)
Crude oil realized price discount as a % of WTI	(14.8)	(11.4)

Notes:

(1) Average of the daily closing spot prices for a given product over the specified time period. Source: US Energy Information Administration.

(2) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

Our crude oil price received is based on quality differentials and international marketing arrangements and therefore are attributed to factors that are beyond our control. Our crude oil realized price is primarily driven by the Brent benchmark price, as Trinidad crude oil is exported for refining and classified as waterborne crude.

In the first quarter of 2023 crude oil benchmark pricing decreased compared with both the first and fourth quarter of 2022. The decrease was primarily due to volatile supply and demand balances due to economic uncertainties and ongoing geopolitical factors.

Average Realized Crude Oil Price[(1)] and Differential to Brent

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25
120.00
110.00 20.0
100.00 20
17.2
90.00 80.00 13.9 14.8 15.6 14.4 15.7 15.3
15
70.00
60.00
50.00 10
40.00
30.00
5
20.00
10.00
- -
Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023
Realized price Brent reference price Differential to Brent
$000's
Brent Realized Price Differential (%)
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Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

We realized an average crude oil price of $64.86 per barrel in the first quarter of 2023 compared to an average of $83.55 per barrel in the equivalent quarter of 2022. Relative to the first quarter of 2022, the 22 percent decrease in 2023 was predominately driven by the aforementioned 20 percent decrease in Brent reference pricing, combined with a widening of our realized price differential in relation to Brent benchmark pricing from 17.2 percent to 20.0 percent.

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First Quarter 2023 Management's Discussion and Analysis

Natural gas sales from our Coho-1 well received an average price of $2.12 per Mcf in the first quarter of 2023, consistent with the preceding quarter. Touchstone is obligated to pay a $0.125 per Mcf processing fee to the third-party natural gas facility operator which is netted against natural gas sales.

Petroleum and natural gas sales

($000's unless otherwise stated)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Crude oil	7,500	10,496	(29)
Natural gas	976	-	n/a
Petroleum and natural gas sales	8,476	10,496	(19)
Crude oil and liquids_(%)_	88	100
Natural gas_(%)_	12	-

We sell all produced crude oil volumes to Heritage, with title transferring at our various sales batteries. As at March 31, 2023, we held 3,910 barrels of crude oil inventory in comparison to 4,021 barrels as of December 31, 2022.

Petroleum and natural gas sales in the first quarter of 2023 decreased 19 percent to $8,476,000 from $10,496,000 in the first quarter of 2022. Compared to the first quarter of 2022, crude oil sales declined by $2,996,000, with $2,162,000 reflecting lower realized pricing and $834,000 attributed to a reduction in sales volumes. This variance was slightly offset by $976,000 of natural gas sales from our Coho-1 well.

Royalties

($_000's_unless otherwise stated)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Crown royalties	1,000	1,201	(17)
Private royalties	77	106	(27)
Overriding royalties	1,427	2,279	(37)
Royalties	2,504	3,586	(30)
Per boe(1)	13.01	28.55	(54)
As a % of petroleum and natural gas sales(1)	29.5	34.2	(14)

Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

Touchstone is obligated to pay a crown royalty rate of 12.5 percent on all petroleum and natural gas production under MEEI and Heritage licences. For private leases, the Company incurs private royalties between 10 and 12.5 percent of crude oil sales.

We operate under LOAs with Heritage on our CO-1, CO-2, WD-4 and WD-8 blocks, which in addition to crown royalties apply a sliding scale overriding royalty ("ORR") structure indexed to the average price of crude oil realized in a production month. Base ORR rates are applicable to pre-defined monthly base production levels which decline by 2 percent per annum over the specific licence. For any monthly volumes sold in excess of base production levels, we are entitled to reduced enhanced ORR rates. For any production in excess of defined enhanced production levels, we incur super enhanced ORR rates which represent 50 percent of enhanced ORR rates. The following table summarizes royalty rates attributable to our LOAs based on monthly realized crude oil pricing received.

Monthly realized oil price($)	LOA Royalty Rates(%)
	Base ORR Enhanced ORR Super Enhanced ORR
50.01 - 70.00 70.01 - 90.00 90.01 - 200.00	28.00 15.50 7.75 33.00 17.00 8.50 35.00 20.00 10.00

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First Quarter 2023 Management's Discussion and Analysis

Royalties as a percentage of petroleum and natural gas sales decreased to 29.5 percent in the first quarter of 2023 compared to 34.2 percent in the prior year equivalent quarter. Relative to 2022, the decrease in our effective royalty rate during the three months ended March 31, 2023 was attributed to reduced crude oil pricing and corresponding sliding scale ORR rates, as well as natural gas production which is only subject to the 12.5 percent crown royalty.

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Royalties
5,000 40
35.9
34.2 34.3
33.2
30.5 31.0 31.5 35
4,000 29.5
30
25
3,000
20
2,000 15
10
1,000
5
- 0
Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023
Royalties % of Petroleum and natural gas sales
(1)
$000's
Royalty %
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Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

Operating expenses

($000's except per boe amounts)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Operating expenses	2,320	2,157	8
Per boe(1)	12.05	17.17	(30)

Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

Operating expenses include all periodic lease, field-level and transportation expenses and directly attributable employee salaries and benefits.

First quarter 2023 operating expenses increased by $163,000 or 8 percent from the first quarter of 2022, as an additional $248,000 was recorded in relation to Coho-1 natural gas production, slightly offset from decreased well service expenditures and reduced variable costs related to an 8 percent decrease in crude oil production.

2023 first quarter operating expenses were $12.05 per boe, representing a 30 percent decrease from the $17.17 per boe reported in the prior year equivalent period. The per unit decrease in comparison to the first quarter of 2022 was attributed to incremental Coho-1 well production that averaged operating expenses of $0.54/Mcf ($3.23 per boe) in the first quarter of 2023. Operating costs related to crude oil and liquids production averaged approximately $17.92 per barrel in the first quarter of 2023 versus $17.17 per barrel in the prior year equivalent quarter. The increase in comparison to the first quarter of 2022 was mainly attributed to an 8 percent decline in first quarter 2023 crude oil production volumes.

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First Quarter 2023 Management's Discussion and Analysis

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Operating Expenses
3,000 22
18.16 20
17.17 17.52
2,500 18
14.78 15.24 14.70
16
2,000 12.07 12.05 14
12
1,500
10
8
1,000
6
500 4
2
- -
Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023
Operating expenses Operating expenses (per boe)
$000's (1) $/boe
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Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

Operating netback

	Three months ended March 31,	Three months ended March 31,	%
	2023	2022	change
($000's)
Petroleum and natural gas sales	8,476	10,496	(19)
Royalties	(2,504)	(3,586)	(30)
Operating expenses	(2,320)	(2,157)	8
Operating netback(1)	3,652	4,753	(23)
($/boe)
Realized commodity price(1)	44.03	83.55	(47)
Royalties(1)	(13.01)	(28.55)	(54)
Operating expenses(1)	(12.05)	(17.17)	(30)
Operating netback(1)	18.97	37.83	(50)

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Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

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First Quarter 2023 Management's Discussion and Analysis

General and administration ("G&A") expenses

($000's except per boe amounts)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Gross G&A expenses	2,353	2,205	7
Capitalized G&A expenses	(252)	(232)	9
G&A expenses	2,101	1,973	6
Per boe(1)	10.91	15.71	(31)

Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

Gross G&A expenses in the first quarter of 2023 were $2,353,000 compared to $2,205,000 in the same period of 2022. The $148,000 or 7 percent increase in comparison to the prior year first quarter was mainly due to increases in employee headcount and salaries, travel, insurance and legal expenses, slightly offset by foreign exchange variances from the translation of Canadian head office costs based on a weaker Canadian dollar in 2023.

The increase in capitalized G&A as a percentage of gross G&A in the first quarter of 2023 in relation to the prior year comparative period was predominantly from increased employee hours allocated to capital projects, as we drilled the Royston-1X sidetrack well and continued with Cascadura facility construction operations in the first quarter of 2023.

First quarter 2023 G&A expenses were $10.91 per boe, representing a 31 percent decrease from the $15.71 per boe reported in the first quarter of 2022. A 6 percent increase in first quarter 2023 net G&A expenses in relation to the prior year equivalent quarter was fully offset by a 53 percent increase in production volumes on a boe basis.

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General and Administration Expenses
3,000 22
20
2,500 17.03 18
15.71
14.25 14.68 16
2,000 12.57 14
11.42
10.91
12
1,500 9.32
10
8
1,000
6
500 4
2
- -
Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023
G&A expenses G&A expenses (per boe)
$000's (1) $/boe
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Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

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First Quarter 2023 Management's Discussion and Analysis

Net finance expenses

($000's except per boe amounts)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Interest income	(28)	(1)	100
Finance lease interest income	(12)	(17)	(29)
Lease liability interest	51	63	(19)
Term loan interest	525	589	(11)
Accretion on term loan	(3)	44	n/a
Production liability revaluation (gain) loss	(162)	199	n/a
Accretion on decommissioning liabilities	60	66	(9)
Net finance expenses	431	943	(54)
Cash net finance expenses	536	634	(15)
Non-cash netfinance (income) expenses	(105)	309	n/a)
Net finance expenses	431	943	(54)
Per boe(1)	2.24	7.51	(70)

Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

Net finance expenses in the first quarter of 2023 were $431,000 compared to $943,000 recognized in the same period of 2022, with cash finance expenses decreasing by $98,000.

Relative to the first quarter of 2022, the slight decrease in cash finance costs in the same period of 2023 was primarily attributed to a decline in term loan interest expenses, as we began repaying the loan in accordance with its amortization period in the third quarter of 2022. Refer to the " Liquidity and Capital Resources - Term loan " section herein for further details.

Production liability revaluation gains or losses are recognized as a result of a change in the production royalty obligation estimated by the Company at each reporting period in connection with our former term loan. Refer to the " Liquidity and Capital Resources - Other liabilities " section of this MD&A for further information.

Foreign exchange and foreign currency translation

Touchstone's presentation currency is the United States dollar. Our parent company has a Canadian dollar functional currency while our Trinidadian subsidiaries have Trinidad and Tobago dollar functional currencies. In each reporting period, the change in values of the C$ and TT$ relative to the US$ reporting currency are recognized. The applicable foreign exchange ("FX") rates used to translate our TT$ and C$ denominated items are set forth below.

Applicable FX rates	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
US$:C$ avg. FX rate(1)	1.353	1.267	7
US$:TT$ avg. FX rate(2)	6.752	6.758	-
	March 31,	December 31,	%
	2023	2022	change
US$:C$ closing FX rate(1)	1.353	1.357	-
US$:TT$ closing FX rate(2)	6.748	6.742	-

Notes:

(1) Source: TSX InfoSuite average daily exchange rates for the specified periods and daily exchange rates for the specified dates.

(2) Source: Central Bank of Trinidad and Tobago average daily buying and selling exchange rates for the specified periods and average daily buying and selling exchange rates for the specified dates.

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First Quarter 2023 Management's Discussion and Analysis

The revenues and expenses of our Canadian head office and Trinidadian operations are translated to US$ at the average monthly exchange rates relative to the date of the transactions. Fluctuations in the exchange rate between the TT$ and the US$ and the C$ to US$ could have a material effect on our reported results. Refer to the " Market Risk Management - Foreign currency risk " section of this MD&A for further information.

During the first quarter of 2023, the C$ depreciated 7 percent and the TT$ remained consistent relative to the US$ in comparison to the corresponding average rates observed in the 2022 first quarter. In aggregate, we recorded a foreign exchange gain of $110,000 in the first quarter of 2023 compared to a gain of $56,000 reported in the prior year equivalent quarter. Foreign exchange gains and losses include amounts that are unrealized in nature and may be reversed in the future as a result of fluctuations in prevailing exchange rates.

The assets and liabilities of our parent company and subsidiaries are translated to US$ dollars at the exchange rate on the reporting period date for presentation purposes, with all foreign currency differences recorded in other comprehensive loss. Relative to the US$, the C$ and TT$ closing March 31, 2023 foreign exchange rates remained consistent with the corresponding closing rates observed on December 31, 2022. We recognized a foreign currency translation loss of $3,000 in the first quarter of 2023 compared to a gain of $400,000 recorded in the comparative 2022 quarter.

Equity-based awards

We have a share option plan pursuant to which options to purchase common shares of the Company may be granted by the Board of Directors ("Board") to our directors, officers, employees and consultants. Equitybased compensation expense is recognized as the options vest. Unless otherwise determined by the Board, vesting typically occurs one third on each of the next three anniversaries of the grant date as recipients render continuous service to the Company, and the share options typically expire five years from the date of the grant. The maximum number of common shares issuable on the exercise of outstanding share options at any time is limited to 10 percent of our issued and outstanding common shares. As of March 31, 2023 and December 31, 2022, we had 11,928,435 shares options outstanding, which represented 5.1 percent of our outstanding common shares. The following table sets forth equity compensation expenses recorded in relation to our share option plan for the periods indicated.

($000's)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Gross equity-based compensation	423	311	36
Capitalized equity-based compensation	(62)	(67)	(7)
Equity-based compensation	361	244	48

In the first quarter of 2023, the Company recorded equity-based compensation of $361,000 compared to $244,000 in the prior year equivalent quarter. The increase in comparison to the same period of 2022 mainly reflected increased participant headcount for awards granted in April 2022. Further information regarding our equity compensation plan is included in Note 11 " Shareholders' Capital " of our interim financial statements.

Depletion and depreciation expense

($000's except per boe amounts)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Depletion expense	1,082	872	24
Depreciationexpense	295	58	100
Depletion and depreciation expense	1,377	930	48
Depletion expense per boe(1)	5.62	6.94	(19)

Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

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First Quarter 2023 Management's Discussion and Analysis

First quarter 2023 depletion expense associated with our petroleum and natural gas development assets included in property, plant and equipment ("PP&E") increased by $210,000 or 24 percent in comparison to the prior year equivalent quarter, reflecting depletion associated with Coho-1 well production. On a boe basis, the 19 percent decline in relation to the first quarter of 2022 was attributed to a 53 percent increase in production volumes.

Depletion expenses will fluctuate based on the amount and type of capital spending, the recognition or reversal of PP&E impairments, the quantity of reserves added and production volumes. The depletion rates are calculated on proved plus probable reserves, considering the future development costs to produce the reserves.

Assets in the E&E phase are not amortized. Depreciation expense is recorded on corporate assets on a declining balance basis, and right-of-use assets associated with capital leases are depreciated over their estimated useful lives on a straight-line basis. Depreciation expense increased by $237,000 in the first quarter of 2023 in comparison to the 2022 equivalent period, reflecting an increase in depreciation of drilling rig mobilization expenses, which are recorded when the associated drilling rig is in use.

Impairment of non-financial assets

E&E asset impairment

In the first quarter of 2023, we recognized E&E asset impairment expenses of $15,000 related to non-core properties (2022 - $136,000). Fist quarter 2023 impairment expenses reflected licence financial obligations, partially offset by changes in long-term inflation estimates that decreased corresponding decommissioning liabilities.

Our 16.2 percent non-operated working interest in the Cory Moruga licence continues to have an estimated recoverable value of $nil, and the operator of the licence has entered into a sale and purchase agreement for the property with a third party.

As of March 31, 2023, we identified no indicators of impairment relating to our Ortoire CGU, which had a carrying value of $60,464,000 representing the full E&E asset balance on the consolidated balance sheet (December 31, 2022 - $51,352,000).

PP&E impairment

On March 31, 2023 and 2022, we evaluated our petroleum and natural gas development assets included in PP&E for indicators of any potential impairment or reversal. As a result of these assessments, no indicators were identified.

Income taxes

The Company's two Trinidad exploration and production subsidiaries are subject to the following Trinidad petroleum taxes:

Supplemental Petroleum Tax 18 percent of gross liquids revenue less related royalties
• Petroleum Profits Tax ("PPT") 50 percent of net taxable profits • Unemployment Levy ("UL") 5 percent of net taxable profits • Green Fund Levy 0.3 percent of gross revenue

SPT is levied on a quarterly basis and is applicable to produced crude oil and liquids volumes. Actual rates vary based on the average realized selling prices of crude oil and liquids in the applicable quarter. The SPT rate is zero when the weighted average realized price of crude oil and liquids for a given quarter is below $75.00 per barrel and 18 percent when weighted average realized prices fall between $75.00 and $90.00.

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First Quarter 2023 Management's Discussion and Analysis

For quarterly average prices greater than $90.00, the SPT rate is 18 percent plus 0.2 percent per $1.00 above $90.00. The tax base for the calculation of SPT is crude oil and liquids sales less related royalties paid, less 30 percent investment tax credits on mature oilfields for allowable tangible and intangible capital expenditures incurred in the applicable fiscal quarter. Our Ortoire property is not considered a mature oilfield, and thus no capital spending investment tax credits are applicable.

PPT and UL taxes are levied on an annual basis and are calculated based on net taxable profits. Net taxable profits are determined by calculating gross revenue less: royalty expenses, SPT paid during the year, capital allowances, operating expenses, G&A expenses, and certain finance expenses. PPT losses may be carried forward indefinitely to reduce PPT in future years but can only be used to shelter a maximum of 75 percent of income subject to PPT per annum. UL losses cannot be carried forward to reduce future year UL. Developmental and exploratory capital expenditure allowances (tangible and intangible) are amortized on a five-year straight-line basis.

The following table sets forth current income tax expenses for the periods indicated.

($000's except per boe amounts)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
SPT	4	227	(98)
PPT	126	261	(52)
UL	50	104	(52)
Other	35	36	(3)
Current income tax expenses	215	628	(66)
Per boe(1)	1.12	5.00	(78)

Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

During the three months ended March 31, 2023, we recognized current income taxes expense of $215,000 compared to $628,000 for the same period of 2022. The decrease in first quarter 2023 income tax expenses was based on reduced SPT expenses as crude oil realized pricing was below the $75.00 threshold, as well as a decline in Trinidad-based net taxable profits.

Current Income Tax Expense

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1,800 14
11.97 11.80
1,600
12
1,400
10
1,200
1,000 8
5.32
5.00
800 6
600 3.36
3.07 4
400
1.69
1.12 2
200
- -
Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023
Income tax Income tax (per boe)
$000's (1) $/boe
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Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

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First Quarter 2023 Management's Discussion and Analysis

During the three months ended March 31, 2023, we recognized a deferred income tax recovery of $447,000 as a result of an increase in deductible interest reserves, partially offset by the use of non-capital carry forward losses (2022 - expense of $235,000). Our $14,100,000 net deferred income tax liability balance represented the estimated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective income tax bases as at March 31, 2023 (December 31, 2022 - $14,557,000). The deferred income tax balance remained in a liability position mainly from the discrepancy between the financial statement carrying values and the income tax values of the Company's petroleum and natural gas development assets included in PP&E.

Capital Expenditures and Dispositions

E&E asset expenditures

E&E asset expenditures include asset additions in areas that have been determined to be in the exploration phase. Touchstone's core exploration property is the Ortoire block. Our E&E asset expenditures during the respective periods are summarized in the following table.

($000's)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Licence financial obligations	74	170	(56)
Drilling, completions and well testing	5,367	929	100
Equipment and facilities	3,006	449	100
Capitalized G&A	165	151	9
Other	138	175	(21)
E&E asset expenditures	8,750	1,874	100

Our first quarter 2023 capital program remained heavily focused on exploration activities on the Ortoire property, where our $8,750,000 in investments primarily focused on drilling the Royston-1X sidetrack well and progressing construction of the Cascadura natural gas and liquids facility (refer to the " Ortoire Exploration Operations " section of this MD&A for further information).

During the three months ended March 31, 2022, we continued production testing operations on the original Royston-1 wellbore, with further expenditures directed towards the Coho-1 natural gas facility and pipeline installation.

PP&E expenditures

($000's)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022	% change
Drilling and completions	54	468	(88)
Capitalized G&A	87	81	7
Corporate and other	128	131	(2)
PP&E expenditures	269	680	(60)

First quarter 2023 expenditures on PP&E were $269,000, as we conducted minimal field development activity, with only one well recompletion performed.

Aggregate first quarter 2022 PP&E expenditures of $680,000 included completion costs for our three wells drilled in the fourth quarter of 2021 as well as lease preparation costs for two Coora-1 well locations.

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First Quarter 2023 Management's Discussion and Analysis

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Capital Expenditures [(1)]
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
-
Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023
E&E asset PP&E
$000's
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Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

Dispositions

In 2021 the Company executed sale and purchase agreements with a third party to dispose of our non-core New Dome, Palo Seco and South Palo Seco properties for aggregate consideration of $350,000, subject to customary closing adjustments. The transactions were effective December 31, 2021, and we closed the New Dome and South Palo Seco dispositions on April 30, 2022. The Palo Seco disposition has received all required regulatory approvals and is scheduled to close on May 31, 2023.

Decommissioning Liabilities and Abandonment Fund

Our decommissioning and reclamation liabilities relate to future site restoration and well abandonment costs including the costs of production equipment removal and land reclamation based on current Trinidad environmental regulations. The estimates are reviewed at least quarterly and adjusted as new information regarding the liability is determined and include assumptions in respect of actual costs to abandon wells and facilities or reclaim a property, the time frame in which such costs will be incurred, historical well production and annual inflation factors.

Pursuant to production and exploration licences with the MEEI and lease operating agreements with Heritage, we are obligated to remit $0.25 per boe sold into various escrow accounts. As of March 31, 2023, we reported $1,511,000 of accrued or paid contributions into MEEI and Heritage abandonment funds as long-term abandonment fund assets (December 31, 2022 - $1,446,000).

We estimated the net present value of the cash flows required to settle our decommissioning liabilities to be $10,955,000 as at March 31, 2023 compared to $11,182,000 as of December 31, 2022. March 31, 2023 decommissioning liabilities were estimated using a weighted average long-term risk-free rate of 5.2 percent and a long-term inflation rate of 2.1 percent (December 31, 2022 - 5.3 percent and 2.4 percent, respectively). $60,000 of accretion expenses were recognized in the first quarter of 2023 to reflect the increase in decommissioning liabilities associated with the passage of time (2022 - $66,000).

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First Quarter 2023 Management's Discussion and Analysis

Decommissioning liability details as of March 31, 2023, excluding those associated with assets classified as held for sale, are summarized in the table and graph below.

Number of well locations (net)	Number of facility locations (net)	Undiscounted balance ($000's)	Inflation adjusted balance ($000's)	Discounted balance ($000's)
737.6	3.8	14,281	17,334	10,955

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Environmental stewardship is a core value at Touchstone, and abandonment and reclamation activities are made in a prudent, responsible manner with the oversight of the Board and in accordance with local regulations. Decommissioning liabilities are considered critical accounting estimates. There are significant uncertainties related to future decommissioning expenditures, and the impact on our consolidated financial statements could be material. The eventual timing of and costs for these expenditures could differ from current estimates. Further information regarding decommissioning liabilities is included in Note 9 " Decommissioning Liabilities " of our interim financial statements.

Liquidity and Capital Resources

Our policy is to maintain a strong capital base to preserve investor, creditor, and market confidence and to sustain the future development of our business. We consider our capital structure to include shareholders' equity, working capital and bank debt. Touchstone's capital management objective is to fund current period decommissioning and capital expenditures necessary for the replacement of production declines using only funds flow from operations. Exploration and development activities will be financed with a combination of funds flow from operations and other sources of capital. We use shareholders' equity and bank debt as our primary sources of capital.

As at March 31, 2023, we had a cash balance of $10,859,000, a working capital deficit of $4,383,000 and a principal balance of $25,500,000 remaining on our term credit facility.

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First Quarter 2023 Management's Discussion and Analysis

The following table summarizes our changes in cash for the periods specified.

($000's)	Three months ended March 31, 2023 December 31, 2022	Three months ended March 31, 2023 December 31, 2022	% change
Net cash from (used in):
Operating activities	913	(1,189)	n/a
Investing activities	(4,661)	(1,734)	100
Financing activities	(1,866)	10,714	n/a
Change in cash	(5,614)	7,791	n/a
Cash, beginning of period	16,335	8,732
Impact of FX on cash balances	138	(188)	n/a
Cash, end ofperiod	10,859	16,355	(34)

Our first quarter 2023 cash and working capital balances declined in comparison to December 31, 2022 based on ongoing investments directed toward our Ortoire block and repaying our third $1.5 million installment on our term loan, partially offset by $913,000 in cash generated from operating activities.

Our near-term development plan is strategically balanced between maintaining base crude oil and natural gas production levels, bringing our Cascadura discovery onstream and investing in future Ortoire development and exploratory activities. We will continue to take a measured approach to future developmental and exploration drilling in an effort to manage financial liquidity while proceeding with this plan. We expect 2023 cash levels and working capital balances to decline in the short term as we continue to proceed to invest in our Cascadura natural gas and liquids facility in anticipation of future production and cash flows therefrom.

Capital management

When evaluating our capital structure, Management's long-term strategy is to maintain net debt to trailing twelve-month funds flow from operations at or below a ratio of two times in a normalized commodity price environment. This ratio may increase at certain times as a result of increased capital expenditures or low commodity prices. We also monitor our capital management through the net debt to managed capital ratio. Our strategy is to utilize more equity than debt, thereby targeting net debt to managed capital at a ratio of less than 0.4 to 1. The following table details our internal capital management calculations for the periods specified.

specified.
($000's)	Target measure	March 31, 2023	December 31, 2022
Net debt(1)		23,883	16,008
Shareholders'equity		78,521	78,380
Managed capital(1)		102,404	94,388
Trailing twelve-month fundsflow fromoperations(1)(2)		2,900	3,540
Net debt to funds flow from operations ratio(1)	At or < 2.0 times	8.24	4.52
Net debt to managed capital ratio(1)	<0.4times	0.23	0.17

Notes:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

(2) Trailing twelve-month funds flow from operations as at March 31, 2023 includes the sum of funds flow from operations for the three months ended March 31, 2023 and funds flow from operations for the April 1 through December 31, 2022 interim period.

Our net debt to funds flow from operations ratio has exceeded our target based on continuing E&E asset investments, notably Cascadura facility capital expenditures required to bring the natural gas discovery onstream. We expect funds flow from operations to increase in the second half of 2023, and we forecast to achieve and will strive to maintain our capital management targets when our Cascadura wells are onstream at optimized production rates.

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First Quarter 2023 Management's Discussion and Analysis

Shareholders' equity

The Company is authorized to issue an unlimited number of voting common shares without nominal or par value. From time to time, we may access capital markets to meet our additional financing needs and to maintain flexibility in funding our capital programs. The following table summarizes our outstanding common shares and share options as at the date of this MD&A, March 31, 2023 and December 31, 2022.

	May 11,	March 31,	December 31,
	2023	2023	2022
Common shares outstanding	233,037,226	233,037,226	233,037,226
Share options outstanding	11,928,435	11,928,435	11,928,435
Fully diluted common shares	244,965,661	244,965,661	244,965,661

Further information regarding our shareholders' capital and equity-based compensation plan is included in " Results of Operations - Equity-based awards " section herein and in Note 11 " Shareholders' Capital " of our interim financial statements.

Term loan

Touchstone Exploration (Trinidad) Ltd., the Company's indirectly wholly owned Trinidadian subsidiary, entered into a $20 million, seven-year term credit facility arrangement effective June 15, 2020 with Republic Bank Limited, a chartered bank owned by Republic Financial Holdings Limited. Republic Financial Holdings Limited is headquartered in Trinidad and the registered owner of ten banks in the Caribbean region, as well as other financial services subsidiaries. The term credit facility arrangement is a senior secured syndicated loan, with Republic Bank Limited acting as initial lender, arranger and administrative agent.

On closing, we withdrew $15 million to satisfy our obligations relating to prepaying our former C$20 million Canadian-based term loan. On December 21, 2021, the parties entered into an amended and restated loan agreement providing for a $10 million increase in the principal balance to $30 million. The amendment did not amend any other terms of the prior term loan agreement. Effective December 30, 2021, we withdrew an additional $15 million on the credit facility, resulting in the full principal balance of $30 million outstanding.

The term loan bears a fixed interest rate of 7.85 percent per annum, compounded and payable quarterly. Prepayments are permitted with a one percent penalty and a 30-day notice period, and no penalty shall apply on principal repayments after three years. The term loan agreement is principally secured by a pledge of equity interests and fixed and floating security interests over all present and after acquired assets of Touchstone Exploration (Trinidad) Ltd. and its wholly owned Trinidadian subsidiary, POGL.

As at March 31, 2023, the principal balance outstanding was $25.5 million. Seventeen equal and consecutive quarterly principal payments of $1.5 million remain outstanding.

For financial reporting purposes, the term loan and its modification were initially measured at fair value and subsequently measured at amortised cost, with the aggregate associated financing fees unwound using the effective interest rate method to the face value at maturity. As at March 31, 2023, the term loan balance was $25,459,000 of which $6,000,000 was classified as current on the consolidated balance sheet (December 31, 2022 - $26,962,000 and $6,000,000, respectively).

The term loan agreement contains industry standard representations and warranties, undertakings, events of default, and financial covenants tested on an annual basis. Pursuant to the term loan arrangement, a failure of any covenant constitutes an event of default. Upon an event of default, the lender can declare the principal balance and any accrued interest immediately due and payable. We routinely review all operational and financial covenants based on actual and forecasted results and can amend development and exploration plans to comply with the covenants. We are committed to having an adaptable capital expenditure program that can be adjusted to a tightening of liquidity sources if necessary. As at March 31, 2023, the Company was compliant with all covenants provided for in the credit facility.

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First Quarter 2023 Management's Discussion and Analysis

At all times, we must maintain a cash reserves balance of not less than the equivalent of two subsequent quarterly interest payments. Accordingly, Touchstone classified $962,000 of cash as long-term restricted on the consolidated balance sheet as at March 31, 2023 (December 31, 2022 - $1,021,000).

Further information regarding the term loan is included in Note 8 " Term Loan " of our interim financial statements, and copies of the credit facility agreement and amendments may be accessed through our profile on SEDAR (www.sedar.com).

Other liabilities

Lease liabilities

The Company is a party to lease arrangements for a drilling rig, office space and office equipment. As of March 31, 2023, we recognized $1,913,000 in aggregate lease liabilities, of which $1,374,000 was classified as long-term on the consolidated balance sheet (December 31, 2022 - $2,255,000 and $1,373,000, respectively). Further information regarding our lease obligations is included in Note 7 " Lease Liabilities " of our interim financial statements.

Production liability

We granted our former lender a production payment equal to 1.33 percent of petroleum and natural gas sales from Trinidad land holdings, payable quarterly through October 31, 2023. The production liability is revalued at each reporting period based on changes to internally forecasted petroleum and natural gas production and forward product pricing and is thus subject to variability. In the first quarter of 2023, we recognized a gain on revaluation of $162,000 predominately from the decline in strip crude oil pricing from December 31, 2022 (2022 - loss of $199,000). At March 31, 2023, our estimated production liability balance was $542,000, with the full balance included in accounts payable and accrued liabilities on the consolidated balance sheet (December 31, 2022 - $816,000).

Contractual Obligations and Commitments

We have contractual obligations in the normal course of business which include minimum work obligations under various operating agreements with Heritage, exploration commitments under our Cory Moruga and Ortoire block exploration and production licences with the MEEI, and various lease commitments for office space and motor vehicles. The following table outlines our estimated minimum contractual payments as at March 31, 2023.

($000's) Total	Estimated payments due by year
	2023 2024 2025 Thereafter
Operating agreement commitments Coora blocks 13,234 WD-4 block 4,441 WD-8 block 4,448 Fyzabad block 760 Cory Moruga exploration block 1,175 Ortoire exploration block 14,468 Office and equipment leases 1,889	4,883 2,572 2,629 3,150 29 1,282 1,349 1,781 27 1,315 1,346 1,760 26 78 79 577 99 105 110 861 33 6,406 6,546 1,483 424 348 372 745
Minimumpayments 40,415	5,521 12,106 12,431 10,357

Under the terms of our Heritage operating agreements, we are required to fulfill minimum work obligations on an annual basis over the specific licence term. With respect to these obligations, we have four development wells and two heavy workover commitments to perform in 2023.

In 2022, we were granted an extension to the exploration phase of the Ortoire licence to July 31, 2026, and we are obligated to drill three exploration wells prior to the end of the amended licence term, with one well drilled (Royston-1X) in February 2023.

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First Quarter 2023 Management's Discussion and Analysis

Market Risk Management

We are exposed to normal financial risks inherent in the international oil and natural gas industry including, but not limited to, commodity price risk, foreign exchange rate risk, credit risk and liquidity risk. The risk exposures are proactively reviewed, and Management seeks to mitigate these risks through various business processes and internal controls.

Management has overall responsibility for the establishment of risk management strategies and objectives. Our risk management policies are designed to identify the risks faced by the Company, to set appropriate risk limits, and to monitor adherence to risk limits. Risk management policies are reviewed and revised regularly to reflect changes in market conditions and our operating activities. Management of cash flow variability is an integral component of our business strategy. Changing business conditions are monitored regularly and, where material, reviewed with the Board to establish risk management guidelines to be used by Management.

Commodity price risk

Our operational results and financial condition are dependent on the commodity prices received for our crude oil, natural gas and NGL production. We have entered into a long-term fixed price natural gas contract for our Ortoire natural gas production. However, movements in crude oil and liquids pricing could affect our cash from operating activities, the value of our development properties, the level of capital expenditures and our ability to meet financial obligations as they come due.

Crude oil prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, the COVID-19 pandemic, the ongoing Russia-Ukraine military conflict, inventory levels, weather, economic and geopolitical factors. Further, our realized crude oil price is based on quality differentials and international marketing arrangements and therefore are attributed to factors that are beyond our control.

Our long-term fixed price natural gas sales agreement with NGC contains options for price negotiations on each fifth anniversary of our initial October 2022 production date. The price of natural gas in Trinidad is predominantly based on domestic supply and demand, with demand largely from domestic power generation and petrochemical facilities. There can be no guarantee that we may be able to negotiate future price increases for natural gas, and a material decline in natural gas sales prices will result in a reduction of the Company's cash from operating activities and financial position.

We maintain a risk management strategy to protect our cash from operations from the volatility of crude oil and liquids prices. Our strategy focuses on the periodic use of puts, costless collars, swaps or fixed price contracts to limit exposure to fluctuations in crude oil prices while allowing for participation in crude oil price increases.

We had no commodity financial management contracts in place as of the date hereof or during the three months ended March 31, 2023 and 2022. We will continue to monitor forward commodity prices and may enter into future commodity-based risk management contracts to reduce the volatility of crude oil and liquids sales and protect future development and exploration capital programs. Additionally, we continually review our capital program and implement initiatives to adapt to such price changes.

Foreign currency risk

Foreign currency exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of our financial assets or liabilities. Touchstone does not hedge its foreign exchange risk.

As we primarily operate in Trinidad, fluctuations in the exchange rate between the TT$ and the US$ could have a significant effect on financial results. Although the sales prices of crude oil and liquids are determined by reference to US$ denominated benchmark prices, the majority of the invoices for such sales are paid in

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First Quarter 2023 Management's Discussion and Analysis

TT$, exposing the Company to foreign exchange risk. To mitigate this risk, we attempt to match revenues received in TT$ by entering into contracts denominated and payable in TT$ when possible. We also attempt to limit our exposure to foreign currency risk through collecting and paying foreign currency denominated balances in a timely fashion. In addition, we have further foreign exchange risk regarding our US$ denominated debt and related interest payments. These risks are mitigated by the fact that the TT$ is informally pegged to the US$ and all natural gas sales are denominated and payable in $US.

Touchstone has further foreign exchange exposure on cash balances denominated in C$ and pounds sterling, on head office costs and our production liability denominated in C$, and costs denominated and payable in pounds sterling required to maintain our AIM listing. Any material movements in the C$ to US$ and the pounds sterling to US$ exchange rates may result in unanticipated fluctuations or have a material effect on our reporting results.

Credit risk

Credit risk arises from the potential that Touchstone may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with the agreed terms. We may be exposed to thirdparty credit risk through our contractual arrangements with current or future joint operation partners, marketers of our commodities and other parties. Touchstone has established credit policies and controls designed to mitigate the risk of default or non-payment with respect to petroleum and natural gas sales and financial derivative transactions. However, we are exposed to sole purchaser risk in Trinidad as Heritage is the sole purchaser of crude oil and liquids and NGC is the sole purchaser of Ortoire natural gas production.

In addition, the Company historically has aged accounts receivables owing for Trinidad-based value added taxes ("VAT"). In comparison to December 31, 2022, our past due VAT accounts receivable balance decreased by $698,000 as of March 31, 2023, as we collected approximately $1,696,000 in past due amounts in the first quarter of 2023. Although ultimate collection is erratic and therefore the timing thereof cannot be estimated with any certainty, Management believes that the VAT accounts receivable balances are ultimately collectable as we have not experienced any past collection issues. The following table details the composition and aging of our accounts receivable as of March 31, 2023.

Composition Counterparty Balance due ($000's) Balance due(%)	Accounts receivable aging
	Current ($000's) Over 90 days ($000's)
Crude oil sales Heritage 1,594 24 Natural gas sales NGC 417 7 Joint interest billings Heritage 606 9 VAT Trinidad government 3,492 53 Finance leases Third-party lessees 80 1 Other Various 362 6
	1,594 -
	417 -
	606 -
	1,161 2,331
	80 -
	301 61
Accounts receivable 6,551 100	4,159 2,392

Effective March 1, 2021, we entered into separate three-year arrangements to lease our oilfield service rigs and swabbing units to two third-party contractors. The lease arrangements were classified as finance leases, as substantially all of the risks and rewards incidental to ownership of the underlying assets are held by the lessees. We have determined that the credit risk related to the associated receivable balance is negligible, as the assets are secured by the underlying equipment, with ownership transferring to the counterparties subsequent to receipt of the final lease payments. As of March 31, 2023, our aggregate finance lease receivable balance was $488,000, of which $408,000 was included in long-term other assets on the consolidated balance sheet (December 31, 2022 - $534,000 and $457,000, respectively).

Liquidity risk

Liquidity risk is the risk that we will not be able to meet our obligations associated with our financial liabilities. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. We believe that future cash flows will be adequate to meet financial obligations as they come due.

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First Quarter 2023 Management's Discussion and Analysis

Our approach to managing liquidity is to ensure that it will have sufficient liquidity to meet liabilities when due, under both normal and unusual conditions without incurring unacceptable losses or jeopardizing our business objectives. Stewardship of our capital structure and potential liquidity risk is managed through our financial and operating forecast process. The forecast of our future cash flows is based on estimates of petroleum and natural gas production, crude oil and liquids forward prices, capital expenditures, royalty expenses, operating expenses, G&A expenses, income tax expenses and other investing and financing activities. The forecast is regularly updated based on changes in commodity prices, capital expenditures, production expectations, income tax and royalty regulations, and other factors that in our view would impact cash flow.

To manage our capital structure, we may reduce our fixed cost structure, adjust capital and exploration spending, issue new equity or seek additional sources of debt financing. We will continue to manage our capital expenditures to reflect current financial resources in the interest of sustaining long-term viability. The following table sets forth estimated undiscounted cash outflows and financial maturities of our financial liabilities as at March 31, 2023.

($000's) Recognized in financial statements Undiscounted cash outflows(1)	Financial maturity by period
	Less than 1 year 1 to 3 years Thereafter
Accounts payable and accrued liabilities(2) Yes – liability 15,616 Income taxes payable Yes – liability 213 Lease liabilities Yes – liability 2,184 Term loan principal Yes – liability 25,500 Term loan interest No – recognized as incurred 4,421	15,616 - - 213 - - 690 1,259 235 6,000 12,000 7,500 1,806 2,198 417
Financial liabilities 47,934	24,325 15,457 8,152

Notes:

(1) The undiscounted cash outflows equal their financial statement carrying values, with the exception of lease liabilities and term loan principal.

(2) Excludes the current portion of lease liabilities.

We actively monitor our liquidity to ensure that cash flows, potential credit facility capacity and working capital are adequate to support these financial liabilities, as well as the Company's capital programs and future work commitments.

Related Party Transactions

Our Corporate Secretary and former director is a senior partner of our Canadian legal counsel, Norton Rose Fulbright Canada LLP. For the three months ended March 31, 2023, $61,000 in legal fees and disbursements charged by Norton Rose Fulbright Canada LLP were incurred, of which $61,000 included in accounts payable and accrued liabilities as at March 31, 2023 (2022 - $49,000 and $25,000, respectively).

Further, our Trinidad-based director is a member of the board of directors of a private Trinidad engineering services company that provides oilfield supplies to Touchstone. During the first quarter of 2023, $4,000 in products were purchased (2022 - $6,000). As at March 31, 2023, $4,000 was included in accounts payable and accrued liabilities (2022 - $5,000).

Changes in Accounting Policies Including Initial Adoption

There were no changes in accounting policies during the three months ended March 31, 2023 that had a material effect on the reported comprehensive income (loss) or net assets of the Company.

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First Quarter 2023 Management's Discussion and Analysis

Standards Issued but Not Yet Effective

There are no standards or interpretations issued, but not yet adopted, that are anticipated to have a material effect on the comprehensive income (loss) or net assets of the Company.

Off-balance Sheet Arrangements

The Company does not believe it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a material current or future effect on the Company's financial condition, results of operations, liquidity or capital expenditures, other than the commitments disclosed in the " Contractual Obligations and Commitments " section herein.

Significant Accounting Estimates, Judgements and Assumptions

The preparation of financial statements in conformity with IFRS requires Management to make estimates, judgements, and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, revenues and expenses. Actual results may differ from estimates, and those differences may be material. The estimates, judgements and assumptions used are subject to updates based on experience and the application of new information. Estimates and underlying assumptions are reviewed on an ongoing basis, and any revisions to accounting estimates are recognized in the period in which the estimates are revised.

A full list of the significant estimates and judgements made by Management in the preparation of the interim financial statements and the audited 2022 financial statements is included in Note 4 " Use of Estimates, Judgements and Assumptions " of our audited 2022 financial statements.

The Company has hired individuals who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Furthermore, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.

Business Risks

As a participant in the international oil and natural gas industry, we are exposed to a variety of risks including, but not limited to, political, operational, financial, and environmental risks. As discussed in the " Liquidity and Capital Resources " and " Market Risk Management " sections of this MD&A, we are exposed to normal financial risks inherent in the international oil and natural gas industry including, among others, commodity price risk, foreign exchange rate risk, credit risk and liquidity risk.

Please refer to our 2022 Annual Information Form dated March 23, 2023 for a full understanding of risks that affect Touchstone, which can be found on our SEDAR profile (www.sedar.com) and website (www.touchstoneexploration.com). Refer to the " Forward-looking Statements " advisory section in this MD&A for additional information regarding the risks to which Touchstone and our business operations are subject to.

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First Quarter 2023 Management's Discussion and Analysis

Selected Quarterly Information and Trends

The following is a summary of our unaudited quarterly results for the eight most recently completed fiscal quarters.

Three months ended	March 31, 2023	Dec. 31, 2022	Sept. 30, 2022	June 30, 2022	March 31, 2022	Dec. 31, 2021	Sept. 30, 2021	June 30, 2021
Operational
Average daily production_(boe/d)_	2,139	2,229	1,272	1,420	1,396	1,336	1,333	1,411
Net wells drilled	0.8	-	-	-	-	3.0	0.8	-
Realized commodity price(1) ($/boe)	44.03	48.36	84.85	97.48	83.55	66.81	62.37	59.06
Operating netback(1) ($/boe)	18.97	21.05	37.55	44.99	37.83	29.96	27.77	26.30
Financial
($000's except per share amounts)
Petroleum and natural gas sales	8,476	9,919	9,933	12,596	10,496	8,212	7,650	7,586
Cash from (used in) operating activities	913	(1,189)	3,058	3,533	350	1,406	404	1,029
Funds flow from operations	803	691	256	1,150	1,443	1,309	1,093	1,226
Net (loss) earnings	(279)	(1,921)	(778)	(262)	(236)	6,514	(51)	(284)
Per share – basic and diluted	(0.00)	(0.01)	(0.00)	(0.00)	(0.00)	0.03	(0.00)	(0.00)
E&E asset expenditures	8,750	2,290	2,692	2,932	1,874	2,946	7,542	6,664
PP&E expenditures	269	219	207	436	680	5,190	2,315	125
Capital expenditures(1)	9,019	2,509	2,899	3,368	2,554	8,136	9,857	6,789
Working capital deficit (surplus)(1)	4,383	(4,992)	4,537	(346)	(4,259)	(6,925)	4,657	(4,671)
Principal long-term bank loan	19,500	21,000	22,500	24,000	25,500	27,000	7,125	7,500
Net debt(1) –end of period	23,883	16,008	27,037	23,654	21,241	20,075	11,782	2,829
Share Information (000's)
Weighted average – basic	233,037	217,106	212,647	212,204	210,823	210,732	210,732	209,757
Weighted average – diluted	233,037	217,106	212,647	212,204	210,823	218,102	210,732	209,757
Outstanding shares – end of period	233,037	233,037	213,113	212,275	211,164	210,732	210,732	210,732

Note:

(1) Non-GAAP financial measure. See the " Advisories - Non-GAAP Financial Measures " section of this MD&A for further information.

The oil and natural gas industry is cyclical. Our financial position, results of operations and cash flows are principally affected by production levels and commodity prices, particularly crude oil prices. Commodity price fluctuations can indirectly impact expected production by changing the amount of funds available to reinvest in exploration, development and acquisition activities in the future. Changes in commodity prices impact revenue and cash flow available for exploration and development and the economics of potential capital projects as low commodity prices can potentially reduce the quantities of reserves that are commercially recoverable. Our capital program is dependent on cash generated from operating activities and access to capital markets.

The following significant items impacted our unaudited financial and operating results over the past eight fiscal quarters:

First quarter 2023 funds flow from operations were $0.8 million, relatively consistent with the preceding quarter. In the quarter we drilled the Royston-1X sidetrack well and continued constructing the Cascadura natural gas facility, incurring an aggregate $9.0 million in capital expenditures. These investments decreased our cash and working capital balances, as we exited the quarter with $23.9 million in net debt, a $7.9 million increase from the previous quarter.
In the fourth quarter of 2022, we generated $0.7 million in funds flow from operations, as we brought on initial natural gas production from our Coho-1 well, thereby achieving a 75 percent increase in quarterly average production on a boe basis from the preceding quarter. In addition, we completed two private placements raising net proceeds of $12.3 million, leading to an $11 million decrease in

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First Quarter 2023 Management's Discussion and Analysis

net debt from the previous quarter.

In the third quarter of 2022, we recorded $0.3 million in funds flow from operations, which decreased by $0.8 million from the previous quarter based on a 10 percent decline in production and a 13 percent reduction in realized commodity prices, partially offset by reduced royalty and operating expenses. We invested $2.9 million in capital expenditures, which were directed at completing the Coho-1 pipeline and sales facility and proceeding with the Cascadura development facility, resulting in a 14 percent increase in net debt from the second quarter of 2022.
We generated $1.2 million in funds flow from operations in the second quarter of 2022, which reflected a $0.5 million provision for oil spill reclamation costs due to vandalism. We continued with development costs relating to our Coho and Cascadura production facilities, investing $3.4 million in capital projects. As a result, net debt increased by $2.4 million or 11 percent from the prior quarter.
We generated $1.4 million in funds flow from operations in the first quarter of 2022, as production and realized pricing increased by 4 percent and 25 percent from the fourth quarter of 2021, respectively. Capital expenditures of $2.6 million led to an increase in net debt of $1.2 million from the preceding quarter.
We recorded $1.3 million in funds flow from operations in the fourth quarter of 2021, as production was consistent and realized crude oil pricing increased by 7 percent from the prior quarter. We increased our net debt by $8.3 million from the third quarter of 2021, as $8.1 million was invested in exploration and development drilling activities. Further, we increased our term loan balance from $20 million to $30 million and withdrew the remaining $15 million available balance on December 30, 2021. Net impairment reversals of $13.7 million and the associated deferred income tax expense of $7.2 million led to net earnings of $6.5 million reported in the quarter.
In the third quarter of 2021, we maintained base crude oil production levels and generated $1.1 million in funds flow from operations. Capital expenditures increased from the prior quarter, as we drilled an exploration well and incurred rig mobilization and inventory costs for our fourth quarter 2021 development drilling program. The increased capital activity in the quarter led to a $9 million increase in net debt from the second quarter of 2021.
We generated $1.2 million in funds flow from operations in the second quarter of 2021, reflecting 13 percent and 8 percent increases in realized crude oil pricing and production from the first quarter of 2021, respectively. Ortoire E&E investment was $6.7 million, resulting in a net debt balance of $2.8 million.

Control Environment

Touchstone is required to comply with National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings . There were no changes in the Company's internal control over financial reporting during the period beginning on January 1, 2023 and ended March 31, 2023 that had materially affected, or were reasonably likely to materially affect, internal control over financial reporting.

Advisories

Non-GAAP Financial Measures

This MD&A or documents referred to in this MD&A reference various non-GAAP financial measures, nonGAAP 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 IFRS 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

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First Quarter 2023 Management's Discussion and Analysis

and potential investors with additional information regarding the Company's performance, liquidity and ability to generate funds to finance its operations. Below is a description of the non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures disclosed in this MD&A.

Funds flow from operations

Funds flow from operations is included in the Company's consolidated statements of cash flows. Touchstone considers funds flow from operations to be a key measure of operating performance as it demonstrates the Company's ability to generate the funds necessary to finance capital expenditures and repay debt. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, funds flow from operations provides a useful measure of the Company's ability to generate cash that is not subject to short-term movements in non-cash operating working capital.

Operating netback

Touchstone 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 operating netback for the periods indicated.

($000's unless otherwise stated)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022
Petroleum and natural gas sales	8,476	10,496
Less: royalties	(2,504)	(3,586)
Petroleum and natural gas revenue, net of royalties	5,972	6,910
Less: operating expenses	(2,320)	(2,157)
Operating netback	3,652	4,753
Production_(boe)_	192,505	125,625
Operating netback ($/boe)	18.97	37.83

Capital expenditures

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 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 capital expenditures and reconciles capital expenditures to cash used in investing activities for the periods indicated.

($000's)	Three months ended March 31, 2023 2022	Three months ended March 31, 2023 2022
E&E asset expenditures	8,750	1,874
PP&Eexpenditures	269	680
Capital expenditures	9,019	2,554
Abandonment fund expenditures	66	29
Proceeds from asset dispositions	-	(35)
Net change in non-cash working capital	(4,424)	5,620
Cash used in investing activities	4,661	8,168

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First Quarter 2023 Management's Discussion and Analysis

Working capital, net debt, net debt to funds flow from operations ratio, managed capital and net debt to managed capital ratio

Touchstone closely monitors its capital structure with a goal of maintaining a strong financial position to fund current operations and future growth. The above measures are capital management measures used by Management to steward the Company's overall debt position and assess overall financial strength.

Management monitors working capital and net debt as part of the Company's capital structure to evaluate its true debt and liquidity position and to manage capital and liquidity risk. Working capital is calculated by subtracting current liabilities from current assets as they appear on the applicable consolidated balance sheet. Net debt is calculated by summing the Company's working capital and the principal (undiscounted) long-term amount of senior secured debt.

The following table presents working capital and net debt computations for the periods indicated.

($000's)	March 31, 2023	December 31, 2022	March 31, 2022
Current assets	(19,656)	(26,415)	(22,393)
Current liabilities	24,039	21,423	18,134
Working capital deficit (surplus)	4,383	(4,992)	(4,259)
Principal long-term balance of term loan	19,500	21,000	25,500
Net debt	23,883	16,008	21,241

The following table reconciles total liabilities to net debt for the periods indicated.

($000's)	March 31, 2023	December 31, 2022	March 31, 2022
Total liabilities	69,927	69,497	72,517
Lease liabilities	(1,374)	(1,373)	(2,308)
Other liabilities	-	-	(844)
Decommissioning liabilities	(10,955)	(11,182)	(11,027)
Deferred income tax liability	(14,100)	(14,557)	(14,764)
Variance of carrying value and principal value of term loan	41	38	60
Current assets	(19,656)	(26,415)	(22,393)
Net debt	23,883	16,008	21,241

The Company's forward net debt to funds flow from operations ratio is the desired target Touchstone strives to achieve and maintain in a normalized commodity price environment. This ratio may increase at certain times as a result of increased capital expenditures or low commodity prices.

Management defines managed capital as the sum of net debt and shareholders' equity. The Company's forward net debt to managed capital ratio is the desired target that the Company strives to maintain, as Management's strategy is to utilize more equity than debt.

Supplementary Financial Measures

The following supplementary financial measures are disclosed herein.

Realized commodity price per boe - is comprised of petroleum and natural gas sales as determined in accordance with IFRS, divided by the Company's total production volumes for the period.

Royalties per boe - is comprised of royalties as determined in accordance with IFRS, divided by the Company's total production volumes for the period.

Royalties as a percentage of petroleum and natural gas sales - is comprised of royalties as determined in accordance with IFRS, divided by petroleum and natural gas sales as determined in accordance with IFRS.

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First Quarter 2023 Management's Discussion and Analysis

Operating expenses per boe - is comprised of operating expenses as determined in accordance with IFRS, divided by the Company's total production volumes for the period.

G&A expenses per boe - is comprised of G&A expenses as determined in accordance with IFRS, divided by the Company's total production volumes for the period.

Net finance expenses per boe - is comprised of net finance expenses as determined in accordance with IFRS, divided by the Company's total production volumes for the period.

Depletion expense per boe - is comprised of depletion expenses as determined in accordance with IFRS, divided by the Company's total production volumes for the period.

Current income tax expense per boe - is comprised of current income tax expenses as determined in accordance with IFRS, divided by the Company's total production volumes for the period.

Forward-looking Statements

Certain information provided in this MD&A, including documents incorporated by references herein, may constitute forward-looking statements and information (collectively, "forward-looking statements") within the meaning of applicable securities laws. All statements and information, other than statements of historical fact, made by Touchstone that address activities, events, or developments that the Company expects or anticipates will or may occur in the future are forward-looking statements.

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. Readers are cautioned that the assumptions used in the preparation of such forward-looking statements, although considered reasonable at the time of preparation, may prove to be imprecise, and as such, undue reliance should not be placed on forwardlooking statements.

In particular, forward-looking statements contained in this MD&A may include, but are not limited to, the Company's internal projections, estimates or expectations with respect to the following:

business and operational strategies;
financial condition and outlook and results of operations, including future liquidity and financial capacity and expectations of future growth, including expectations of increases in future production and cash flows therefrom;
future demand for the Company's petroleum and natural gas products and economic activity in general;
the quality and quantity of prospective hydrocarbon accumulations and targeted future production testing intervals based on internal interpretations of wireline logs;
expectations regarding the ability of the Company to raise capital and to continually add to reserves through exploration, acquisitions and development;
future capital expenditure programs, including the anticipated timing of completion, allocation and costs thereof and the method of funding;
estimated timing of development, ultimate production and production rates from its Ortoire wells;
current and future crude oil and liquids and natural gas production levels and estimated field production levels;

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First Quarter 2023 Management's Discussion and Analysis

the performance characteristics of the Company's petroleum and natural gas properties;
future development and exploration activities to be undertaken in various areas and timing thereof, including future cash flows to be derived therefrom and the fulfillment of minimum work obligations and exploration commitments;
terms and estimated future expenditures of the Company's contractual commitments and their timing of settlement;
terms and title of exploration and production licences and the expected renewal or formal execution of certain contracts;
expectations regarding the Company's ability to obtain contract extensions or fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its properties;
receipt of anticipated and future regulatory approvals and exploration and production licence renewals or amendments;
access to third-party facilities and infrastructure;
expected levels of royalties, operating expenses, G&A expenses, net finance expenses and other costs associated with the Company's business;
treatment under current and future governmental regulatory regimes, environmental legislation, royalty regimes and tax laws enacted in the Company's areas of operations;
current risk management strategies and the benefits to be derived therefrom, including the future use of commodity derivatives to manage commodity price risk;
the foreign currency risk strategies of the Company and the benefits to be derived therefrom and the Company's ability to reverse unrealized foreign exchange gains and losses in the future;
credit risk assumptions and the Company's expectation to receive past due VAT amounts from the Trinidad government;
future liquidity and future sources of liquidity and the Company's expectation to settle all current and future financial liabilities in a timely manner;
future compliance with the Company's term loan covenants and its ability to make future scheduled interest and principal payments;
estimated amounts of the Company's future obligations in connection with its production liability and its ability to make such future scheduled payments;
the potential of future acquisitions or dispositions and receiving regulatory approvals and closing previously announced transactions, including estimated timing thereof;
general economic and political developments in Trinidad and globally;
estimated amounts, timing and the anticipated sources of funding for the Company's decommissioning liabilities;
effect of business and environmental risks on the Company; and
the statements under " Significant Accounting Estimates, Judgements and Assumptions ".

Although the Company believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, operational, competitive, political and social uncertainties and contingencies, many of which are beyond the Company's control.

The Company is exposed to numerous operational, technical, financial and regulatory risks and uncertainties, many of which are beyond its control and may significantly affect anticipated future results. The Company is exposed to risks associated with negotiating with foreign governments as well as country

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First Quarter 2023 Management's Discussion and Analysis

risk associated with conducting international activities. Operations may be unsuccessful or delayed as a result of competition for services, supplies and equipment, mechanical and technical difficulties, ability to attract and retain qualified employees on a cost-effective basis, extreme weather-related events, and commodity and marketing risk. The Company is subject to significant drilling risks and uncertainties including the ability to find petroleum and natural gas reserves on an economic basis and the potential for technical problems that could lead to well blow-outs and environmental damage. The Company is exposed to risks relating to the inability to obtain timely regulatory approvals, surface access, access to third-party gathering and processing facilities, transportation and other third-party operation risks. The Company is subject to industry conditions including changes in laws and regulations, the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced. There are uncertainties in estimating the Company's reserve base due to the complexities in estimated future production, costs and timing of expenses and future capital. The Company is subject to the risk that it will not be able to fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its properties. The financial risks the Company is exposed to include, but are not limited to, the impact of global economic conditions, the impact of significant volatility in market prices for crude oil and liquids, the impact (and duration thereof) of the ongoing military actions between Russia and Ukraine and related sanctions on crude oil and liquids prices, the ability to access sufficient capital from internal and external sources, changes in income tax laws, royalties and incentive programs relating to the Trinidad oil and natural gas industry, fluctuations in interest rates, and fluctuations in foreign exchange rates. The Company is subject to local regulatory legislation, the compliance with which may require significant expenditures and noncompliance with which may result in fines, penalties or production restrictions or the termination of licence, exploration, lease operating or joint operating rights related to the Company's interests in Trinidad. Readers are cautioned that the foregoing list of risk factors is not exhaustive. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed under the Company's profile on SEDAR (www.sedar.com).

Management has included the above summary of assumptions and risks related to forward-looking statements and other information provided in this MD&A in order to provide shareholders and investors with a more complete perspective on the Company's current and future operations, and such information may not be appropriate for other purposes. Actual results, performance or achievement could differ materially from that expressed in or implied by any forward-looking statements in this MD&A, and accordingly, investors should not place undue reliance on any such forward-looking statements. Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future.

Any forward-looking statement is made only as of the date of this MD&A, and Touchstone undertakes no obligation or intent to update or revise any forward-looking statement or statements to reflect information, events, results, circumstances or otherwise after the date on which such statement is made or to reflect the occurrence of unanticipated events, except as required by law, including applicable securities laws. New factors emerge from time to time, and it is not possible for Touchstone to predict all of such factors or to assess in advance the impact of each such factor on Touchstone's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

All forward-looking statements and information contained in this MD&A are expressly qualified by this cautionary statement.

Readers are further cautioned that the preparation of consolidated financial statements in accordance with IFRS requires Management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. These estimates may change, having either a positive or negative effect on comprehensive income (loss), as further information becomes available and as the economic environment or other factors change.

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First Quarter 2023 Management's Discussion and Analysis

Oil and Natural Gas Measures

To provide a single unit of production for analytical purposes, natural gas production has been converted mathematically to barrels of oil equivalent. We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalent conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

Product Type Disclosures

This MD&A includes references to crude oil, NGLs, natural gas, total production and average daily production volumes. Under NI 51-101, disclosure of production volumes should include segmentation by product type as defined in the instrument. In this MD&A, 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 the instrument.

The Company's total and average production for the past eight quarters and the references to "crude oil", "NGLs" and "natural gas" reported in this MD&A consist of the following product types as defined in NI 51101 using a conversion of 6 Mcf to 1 boe where applicable.

Three months ended	March 31, 2023	Dec. 31, 2022	Sept. 30, 2022	June 30, 2022	March 31, 2022	Dec. 31, 2021	Sept. 30, 2021	June 30, 2021
Production
Light and medium crude oil_(bbls)_	108,722	111,114	110,467	122,778	117,253	113,724	111,725	115,487
Heavy crude oil_(bbls)_	6,918	6,126	6,592	6,434	8,372	9,193	10,924	12,116
Crude oil_(bbls)_	115,640	117,240	117,059	129,212	125,625	122,917	122,649	127,603
NGLs - condensate_(bbls)_	-	-	-	-	-	-	-	842
Conventional natural gas_(Mcf)_	461,189	527,105	-	-	-	-	-	-
Total production (boe)	192,505	205,091	117,059	129,212	125,625	122,917	122,649	128,445
Average daily production
Light and medium crude oil_(bbls/d)_	1,208	1,207	1,200	1,349	1,303	1,236	1,214	1,269
Heavy crude oil_(bbls/d)_	77	67	72	71	93	100	119	133
Crude oil_(bbls/d)_	1,285	1,274	1,272	1,420	1,396	1,336	1,333	1,402
NGLs - condensate_(bbls/d)_	-	-	-	-	-	-	-	9
Conventional natural gas_(Mcf/d)_	5,124	5,729	-	-	-	-	-	-
Average daily production (boe/d)	2,139	2,229	1,272	1,420	1,396	1,336	1,333	1,411

References to Touchstone

For convenience, references in this document to the "Company", "we", "us", "our", and "its" may, where applicable, refer only to Touchstone.

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First Quarter 2023 Management's Discussion and Analysis

Abbreviations

The following is a list of abbreviations that may be used in this MD&A:

Oiland	natural gas measurement	Other
bbl(s)	barrel(s)	AIM	AIM market of the London Stock Exchange plc
bbls/d	barrels per day	Brent	Dated Brent
Mbbls	thousand barrels	C$	Canadian dollar
Mcf	thousand cubic feet	NGL(s)	Natural gas liquid(s)
Mcf/d	thousand cubic feet per day	TSX	Toronto Stock Exchange
MMcf	million cubic feet	TT$	Trinidad and Tobago dollar
MMcf/d	million cubic feet per day	WTI	Western Texas Intermediate
MMBtu	million British Thermal Units	$ or US$	United States dollar
boe	barrels of oil equivalent	£	Pounds sterling
boe/d	barrels of oil equivalent per day
Mboe	thousand barrels of oil equivalent

Additional Information

Additional information related to Touchstone and factors that could affect our operations and financial results are included with reports on file with the Canadian securities regulatory authorities, including the interim financial statements, the audited 2022 financial statements and related Management's discussion and analysis and our December 31, 2022 Annual Information Form dated March 23, 2023, all of which can be accessed online under our SEDAR profile at www.sedar.com or from our website at www.touchstoneexploration.com.

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First Quarter 2023 Management's Discussion and Analysis

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Corporate Information

Directors John D. Wright Chair of the Board

Jenny Alfandary Paul R. Baay Priya Marajh Kenneth R. McKinnon Peter Nicol Beverley Smith Stanley T. Smith Harrie Vredenburg

Corporate Secretary Thomas E. Valentine

Officers and Senior Executives Paul R. Baay President and Chief Executive Officer

Scott Budau

Chief Financial Officer

James Shipka Chief Operating Officer

Brian Hollingshead Vice President Engineering and Business Development

Alex Sanchez Vice President Production and Environment

Head Office

Touchstone Exploration Inc. 4100, 350 7th Avenue SW Calgary, Alberta, Canada T2P 3N9

Registered Office 3700, 400 3rd Avenue SW Calgary, Alberta, Canada T2P 4H2

Operating Offices Touchstone Exploration (Trinidad) Ltd. #30 Forest Reserve Road Fyzabad, Trinidad, W.I.

Primera Oil and Gas Limited #14 Sydney Street Rio Claro, Trinidad, W.I.

Stock Exchange Listings Toronto Stock Exchange London Stock Exchange AIM Symbol: TXP

Banker

Republic Bank Limited Port of Spain, Trinidad, W.I.

Auditor KPMG LLP Calgary, Alberta, Canada

Reserves Evaluator GLJ Ltd. Calgary, Alberta, Canada

Legal Counsel

Norton Rose Fulbright LLP Calgary, Alberta, Canada London, United Kingdom

Transfer Agent and Registrar Odyssey Trust Company Calgary, Alberta, Canada

Link Group London, United Kingdom

UK Nominated Advisor and Joint Broker Shore Capital London, United Kingdom

UK Joint Broker Canaccord Genuity London, United Kingdom

UK Public Relations FTI Consulting London, United Kingdom

Cayle Sorge Vice President Finance

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First Quarter 2023 Management's Discussion and Analysis

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Touchstone Exploration Inc. — Interim / Quarterly Report 2023

10573_rns_2023-05-12_8e524ced-71e8-4d4e-88bc-ca435058253b.pdf