Touchstone Exploration Inc.

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Management's Discussion and Analysis For the three and six months ended June 30, 2023 and 2022

TSX / LSE: TXP

www.touchstoneexploration.com

Management's Discussion and Analysis

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 and six months ended June 30, 2023 with comparisons to the three and six months ended June 30, 2022 is dated August 10, 2023 and should be read in conjunction with the Company's unaudited interim condensed consolidated financial statements as at and for the three and six months ended June 30, 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 stock symbol "TXP".

Touchstone operates 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. Primera Oil and Gas Limited ("POGL"), a wholly owned subsidiary of Touchstone, is a party to a long-term natural gas sales agreement with The National Gas Company of Trinidad and Tobago Limited ("NGC") related to all Ortoire property natural gas sales.

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Second Quarter 2023 Management's Discussion and Analysis

Financial and Operating Results Summary

	Three months ended June 30, 2023 2022	Three months ended June 30, 2023 2022	% change	Six months ended June 30, 2023 2022	Six months ended June 30, 2023 2022	% change
Operational
Average daily production
Crude oil(1) (bbls/d)	1,124	1,420	(21)	1,204	1,408	(14)
Natural gas(1) (Mcf/d)	4,215	-	n/a	4,667	-	n/a
Average daily production_(boe/d)_(2)	1,827	1,420	29	1,982	1,408	41
Average realized prices(3)
Crude oil(1) ($/bbl)	62.26	97.48	(36)	63.64	90.61	(30)
Natural gas(1) ($/Mcf)	2.11	-	n/a	2.12	-	n/a
Realized commodity price_($/boe)_(2)	43.19	97.48	(56)	43.64	90.61	(52)
Production mix_(% of production)_
Crude oil(1)	62	100		61	100
Natural gas(1)	38	-		39	-
Operating netback_($/boe)_(2)
Realized commodity price(3)	43.19	97.48	(56)	43.64	90.61	(52)
Royalties(3)	(12.94)	(34.97)	(63)	(12.98)	(31.80)	(59)
Operating expenses(3)	(13.25)	(17.52)	(24)	(12.61)	(17.35)	(27)
Operating netback(3)	17.00	44.99	(62)	18.05	41.46	(56)
Financial
($000's except per share amounts)
Petroleum and natural gas sales	7,181	12,596	(43)	15,657	23,092	(32)
Cash from operating activities	2,975	3,533	(16)	3,888	3,883	-
Funds flow from operations	6	1,150	(99)	809	2,593	(69)
Net loss	(71)	(262)	(73)	(350)	(498)	(30)
Per share – basic and diluted	(0.00)	(0.00)	-	(0.00)	(0.00)	-
Exploration capital expenditures	4,795	2,932	64	13,545	4,806	100
Development capital expenditures	340	436	(22)	609	1,116	(45)
Capital expenditures(3)	5,135	3,368	52	14,154	5,922	100
Working capital deficit (surplus)(3)				10,913	(346)	n/a
Principal long-term bank debt				18,000	24,000	(25)
Net debt(3)–end ofperiod				28,913	23,654	22
Share Information (000's)
Weighted average shares outstanding – basic and diluted	233,144	212,204	10	233,091	211,517	10
Outstanding shares – end of period				233,428	212,275	10

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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Second Quarter 2023 Management's Discussion and Analysis

Results of Operations

Financial highlights

($000's except per share	Three months	ended June 30,	%	Six months	ended June 30,	%
amounts)	2023	2022	change	2023	2022	change
Net loss	(71)	(262)	(73)	(350)	(498)	(30)
Per share – basic and diluted	(0.00)	(0.00)	-	(0.00)	(0.00)	-
Cash from operating activities	2,975	3,533	(16)	3,888	3,883	-
Funds flow from operations	6	1,150	(99)	809	2,593	(69)

Net loss

We recorded a net loss of $71,000 ($0.00 per basic share) in the second quarter of 2023 compared to a net loss of $262,000 ($0.00 per basic share) in the prior year equivalent quarter. Compared to the prior year second quarter, the variance from the same period of 2023 predominately reflected a decrease of $1,144,000 in funds flow from operations, offset by various non-cash items, including a $715,000 net increase in gain on asset dispositions and a $684,000 year-over-year net decrease in deferred income tax expenses.

Net loss for the six months ended June 30, 2023 was $350,000 ($0.00 per basic share), representing a 30 percent decrease from the $498,000 ($0.00 per basic share) net loss recognized in the corresponding 2022 period. Decreases in realized crude oil pricing and production primarily led to a $1,784,000 decrease in funds flow from operations in comparison to the equivalent 2022 period, which was offset by positive yearover-year variances in various non-cash items, including a net increase in gain on asset dispositions and decreases in non-cash finances expenses and deferred income taxes.

The following table sets forth details of the change in net loss from the three and six months ended June 30, 2022 to the three and six months ended June 30, 2023.

($000's)	($000's)	Three months ended June 30,	Six months ended June 30,
Netloss– 2022		(262)	(498)
Cash items
	Funds flow from operations	(1,144)	(1,784)
	Decommissioning expenditures	(32)	(32)
Cash variances		(1,176)	(1,816)
Non-cash items
	Gain on asset dispositions	715	680
	Unrealized foreign exchange	(191)	(212)
	Equity-based compensation expense	147	30
	Depletion and depreciation expense	(66)	(513)
	Impairment expense	21	142
	Non-cash finance expenses	57	471
	Deferred income tax	684	1,366
Non-cash variances		1,367	1,964
Net loss – 2023		(71)	(350)

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Second Quarter 2023 Management's Discussion and Analysis

Cash from operating activities

Details of the change in cash from operating activities from the three and six months ended June 30, 2022 to the three and six months ended June 30, 2023 are included in the table below.

($000's)	($000's)	Three months ended June 30,	Six months ended June 30,
Cash from operating activities–2022		3,533	3,883
	Change in funds flow from operations	(1,144)	(1,784)
	Net changein non-cash working capital	586	1,789
Cash from operating activities – 2023		2,975	3,888

Funds flow from operations

Funds flow from operations was $6,000 in the second quarter of 2023 compared to $1,150,000 recognized in the prior year equivalent quarter. On a year to date basis, we generated funds flow from operations of $809,000 in 2023 compared to $2,593,000 in the same period of 2022. Relative to the corresponding 2022 periods, current year operating netbacks decreased substantially during the three and six months ended June 30, 2023, reflecting decreases in crude oil production and realized pricing, partially offset by incremental net natural gas sales from our Coho-1 well and decreased royalty expenses. The decline in operating netbacks in each period of 2023 in comparison to 2022 were slightly offset by reduced current income tax and other expenses.

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Second Quarter 2023 Management's Discussion and Analysis

Production volumes

	Three months ended June 30,	Three months ended June 30,	%	Six months ended June 30,	Six months ended June 30,	%
	2023	2022	change	2023	2022	change
Production
Crude oil (bbls)	102,320	129,212	(21)	217,960	254,837	(14)
Natural gas_(Mcf)_	383,572	-	n/a	844,761	-	n/a
Total production (boe)	166,249	129,212	29	358,754	254,837	41
Average daily production
Crude oil (bbls/d)	1,124	1,420	(21)	1,204	1,408	(14)
Natural gas_(Mcf/d)_	4,215	-	n/a	4,667	-	n/a
Average daily production (boe/d)	1,827	1,420	29	1,982	1,408	41
Production mix
Crude oil_(%)_	62	100		61	100
Natural gas_(%)_	38	-		39	-

Second quarter and year to date 2023 crude oil production volumes decreased 21 percent and 14 percent from the prior year equivalent periods, respectively. The decreases predominately reflected natural declines, as 2022 oil production volumes included flush production from the three development wells brought onstream in the first quarter of 2022. In addition, key wells in our LOA fields had increased downtime in the second quarter of 2023 while awaiting workovers, and we sold incremental Royston-1 oil production test volumes in the prior year comparative periods.

Coho-1 contributed average net production volumes of 4.2 MMcf/d or 703 boe/d in the second quarter of 2023, representing an 18 percent decrease from 5.1 MMcf/d (854 boe/d) produced in the first quarter of 2023. The Coho-1 well experienced higher water volumes and lower flowing pressures and is thus declining at an increased rate than anticipated. Further, the well was down for four days in the second quarter of 2023 to run pressure gauges and conduct a build-up test. For the six months ended June 30, 2023, the well contributed average net production volumes of 4.7 MMcf/d (778 boe/d).

Average Daily Production

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2,500
2,250 100% 100% 100% 100% 100%
2,000
57% 60% 62%
1,750
1,500
1,250
1,000
750
500
250
-
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023
Natural gas (boe/d) Crude oil (bbls/d) Liquids production as a % of total production
bbls/d or boe/d
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Second Quarter 2023 Management's Discussion and Analysis

The following table and graphs summarize crude oil production by property during the three and six months ended June 30, 2023 and 2022.

(bbls)	Three months 2023	ended June 30, 2022	% change	Six months 2023	ended June 30, 2022	% change
Coora	35,998	42,581	(15)	75,890	78,423	(3)
WD-4	36,763	50,913	(28)	80,500	102,163	(21)
WD-8	17,692	21,802	(19)	37,087	43,517	(15)
Fyzabad	6,270	6,434	(3)	13,188	14,806	(11)
San Francique	4,436	5,243	(15)	9,212	9,736	(5)
Ortoire	-	1,270	n/a	-	4,126	n/a
Other	1,161	969	20	2,083	2,066	1
Crude oilproduction	102,320	129,212	(21)	217,960	254,837	(14)

Crude Oil Production by Property for the Six Months Ended June 30, 2023

Crude Oil Production by Property for the Six Months Ended June 30, 2022

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Coora Coora
WD-4
WD-4 40%
37%
35%
31% WD-8
WD-8
Fyzabad
Fyzabad
San Francique
San Francique Ortoire
1% 17% 1% 17%
6% Other 6% Other
1%
4% 4%
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Commodity prices

	Three months	ended June 30,	%	Six months	ended June 30,	%
	2023	2022	change	2023	2022	change
Avg. benchmark prices(1)
Brent ($/bbl)	77.99	113.84	(31)	79.58	107.20	(26)
WTI ($/bbl)	73.99	108.57	(32)	75.06	101.43	(26)
Average realized prices(2)
Crude oil($/bbl)	62.26	97.48	(36)	63.64	90.61	(30)
Natural gas_($/Mcf)_	2.11	-	n/a	2.12	-	n/a
Realized commodity price($/boe)	43.19	97.48	(56)	43.64	90.61	(52)
Crude oil realized price discount as a % of Brent	(20.2)	(14.4)		(20.0)	(15.5)
Crude oil realized price discount as a % of WTI	(15.9)	(10.2)		(15.2)	(10.7)

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

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Second Quarter 2023 Management's Discussion and Analysis

by the Brent benchmark price, as Trinidad crude oil is exported for refining and classified as waterborne crude.

Second quarter and year to date 2023 benchmark crude oil prices decreased compared to the same periods in 2022, due to the global economic slowdown and impact of rising interest rates to mitigate inflation creating downward pressure on demand, as well as record U.S. production contributing to increased global crude inventories.

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Average Realized Crude Oil Price [(1)] and Differential to Brent
120
110
100
90
80
70
60
50
40
20.0% 20.2%
30 14.8% 15.6% 17.2% 14.4% 15.7% 15.3%
20
10
-
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023
Realized price Brent reference price Realized price differential as a % of Brent
$/bbl
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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.

Touchstone realized an average crude oil price of $62.26 per barrel in the second quarter of 2023 compared to an average of $97.48 per barrel reported in the equivalent quarter of 2022. Relative to the second quarter of 2022, the 36 percent decrease in 2023 was predominately driven by a 31 percent decrease in Brent reference pricing, combined with a widening of the realized price differential in relation to Brent benchmark pricing from 14.4 percent to 20.2 percent.

On a year to date basis, we realized an average crude oil price of $63.64 per barrel in 2023, a 30 percent decrease relative to the $90.61 per barrel price received during the six months ended June 30, 2022. The decrease from the corresponding 2022 period reflected a 26 percent decrease in the average Brent reference price and an increase of the realized price differential in relation to Brent reference pricing from 15.5 percent to 20.0 percent.

We realized average Coho-1 natural gas prices of $2.11 Mcf and $2.12 per Mcf during the three and six months ended June 30, 2023, respectively. 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	Three months	ended June 30,	%	Six months	ended June 30,	%
stated)	2023	2022	change	2023	2022	change
Crude oil	6,370	12,596	(49)	13,870	23,092	(40)
Natural gas	811	-	n/a	1,787	-	n/a
Petroleum and natural gas sales	7,181	12,596	(43)	15,657	23,092	(32)
Sales mix
Crude oil_(%)_	89	100		89	100
Natural gas_(%)_	11	-		11	-

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Second Quarter 2023 Management's Discussion and Analysis

We sell all produced crude oil volumes to Heritage, with title transferring at our various sales batteries. As of June 30, 2023, we held 4,421 barrels of crude oil inventory in comparison to 4,021 barrels as of December 31, 2022. We sell our Coho-1 natural gas volumes to NGC, with title transferring at the Coho sales facility.

Petroleum and natural gas sales in the second quarter of 2023 decreased 43 percent to $7,181,000 from $12,596,000 in the comparative quarter of 2022. Compared to the second quarter of 2022, 2023 crude oil sales declined by $6,226,000, with $3,605,000 reflecting a decrease in realized pricing and $2,621,000 attributed to a reduction in sales volumes. This variance was slightly offset by an incremental $811,000 of natural gas sales from our Coho-1 well.

For the six months ended June 30, 2023, petroleum and natural gas sales were $15,657,000, representing a $7,435,000 or 32 percent decrease from the $23,092,000 recognized in the equivalent 2022 period. Relative to the prior year period, crude oil sales recognized during the six months ended June 30, 2023 declined by $9,222,000, with $5,881,000 attributed to a decrease in average realized pricing and $3,341,000 of the variance reflecting decreased sales volumes. We recognized $1,787,000 in natural gas sales during the six months ended June 30, 2023.

Petroleum and Natural Gas Sales

Petroleum and Natural Gas Sales	Petroleum and Natural Gas Sales	Petroleum and Natural Gas Sales
- 2,000 4,000 6,000 8,000 10,000 12,000 14,000 $000's	100% 100% 100% 100% 100% 89% 88% 89% Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023 Crude oil Natural gas Liquids sales as a % of total sales
*Royalties*
($000's unless otherwise stated) Three months ended June 30, % change Six months ended June 30, % change 2023 2022 2023 2022
Crown royalties 843 1,461 (42) 1,843 2,662 (31) Private royalties 62 122 (49) 139 228 (39) Overriding royalties 1,247 2,936 (58) 2,674 5,215 (49)
Royalties 2,152 4,519 (52) 4,656 8,105 (43)
Per boe(1) 12.94 34.97 (63) 12.98 31.80 (59) As a % of petroleum and natural gas sales(1) 30.0 35.9 (16) 29.7 35.1 (15)

Note:

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

Royalties decreased 52 and 43 percent in the three and six months ended June 30, 2023, respectively, compared to the same periods of 2022. The decreases were largely due to the 49 and 40 percent decrease in crude oil sales in the same respective periods. Additional natural gas sales recognized in the 2023 periods were only subject to a 12.5 percent crown royalty.

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Second Quarter 2023 Management's Discussion and Analysis

Royalties as a percentage of petroleum and natural gas sales decreased to 30.0 percent in the second quarter of 2023 compared to 35.9 percent in the prior year equivalent quarter. For the six months ended June 30, 2023, royalties represented 29.7 percent of petroleum and natural gas sales compared to 35.1 percent in the same period of 2022. Relative to the corresponding 2022 periods, the decreases in effective royalty rates during the three and six months ended June 30, 2023 were attributed to reduced realized crude oil pricing and corresponding sliding scale ORR rates, as well as incremental 2023 natural gas production that incurs a lower royalty rate.

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Royalties
5,000
4,000
3,000
2,000 31.0% 33.2% 34.2% 35.9% 34.3% 31.5% 29.5% 30.0%
1,000
-
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023
Royalties Royalties as a % of petroleum and natural gas sales¹
$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.

Operating expenses

($000's except per boe	Three months	ended June 30,	%	Six months	ended June 30,	%
amounts)	2023	2022	change	2023	2022	change
Operating expenses	2,203	2,264	(3)	4,523	4,421	2
Per boe(1)	13.25	17.52	(24)	12.61	17.35	(27)

Note:

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

Second quarter 2023 operating expenses declined marginally from the comparative period of 2022. Relative to the prior year equivalent period, 2023 second quarter crude oil related operating expenses decreased by approximately 20 percent, consistent with the 21 percent year-over-year decline in crude oil production. An estimated $396,000 of additional operating costs were incurred related to Coho-1 natural gas production during the three months ended June 30, 2023.

For the six months ended June 30, 2023, operating expenses increased by 2 percent from the prior year comparative quarter. 2023 crude oil operating expenses decreased by approximately 12 percent from the prior year second quarter based on a 14 percent production decline, with Touchstone recognizing an estimated $644,000 in incremental operating costs attributed to natural gas production.

Operating expenses per boe decreased 24 and 27 percent in the three and six months ended June 30, 2023, respectively, compared to the same periods of 2022. The per unit decreases in comparison to the comparative 2022 periods were attributed to incremental Coho-1 well production that averaged estimated operating expenses of $6.19 per boe and $4.56 per boe during the three and six months ended June 30, 2023, respectively. During the second quarter and year to date 2023 periods, estimated crude oil operating expenses were $17.66 per barrel and $17.80 per barrel, respectively, representing slight increases from the respective prior year periods due to inflationary pressures on various cost categories.

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Second Quarter 2023 Management's Discussion and Analysis

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Operating Expenses
3,000
$18.16
$17.17 $17.52
2,500
$15.24
$14.70
2,000 $12.07 $13.25
$12.05
1,500
1,000
500
-
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023
Operating expenses Operating expenses per boe¹
$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.

Operating netback

	Three months	ended June 30,	%	Six months	ended June 30,	%
	2023	2022	change	2023	2022	change
($000's)
Petroleum and natural gas sales	7,181	12,596	(43)	15,657	23,092	(32)
Royalties	(2,152)	(4,519)	(52)	(4,656)	(8,105)	(43)
Operating expenses	(2,203)	(2,264)	(3)	(4,523)	(4,421)	2
Operating netback(1)	2,826	5,813	(51)	6,478	10,566	(39)
($/boe)
Realized commodity price(1)	43.19	97.48	(56)	43.64	90.61	(52)
Royalties(1)	(12.94)	(34.97)	(63)	(12.98)	(31.80)	(59)
Operating expenses(1)	(13.25)	(17.52)	(24)	(12.61)	(17.35)	(27)
Operating netback(1)	17.00	44.99	(62)	18.05	41.46	(56)

Operating Netback[(1)]

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6,000 $44.99
$37.83 $37.55
5,000
$29.96
4,000 $27.77
$21.05
3,000
$18.97
$17.00
2,000
1,000
-
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023
Operating netback Operating netback per boe
$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.

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Second Quarter 2023 Management's Discussion and Analysis

General and administration ("G&A") expenses

($000's except per boe	Three months	ended June 30,	%	Six months	ended June 30,	%
amounts)	2023	2022	change	2023	2022	change
Gross G&A expenses	2,617	2,142	22	4,970	4,347	14
Capitalized G&A expenses	(241)	(245)	(2)	(493)	(477)	3
G&A expenses	2,376	1,897	25	4,477	3,870	16
Per boe(1)	14.29	14.68	(3)	12.48	15.19	(18)

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 increased 22 percent and 14 percent in the three and six months ended June 30, 2023, respectively, compared to the same periods in 2022. The increases in the three and six months ended June 30, 2023 were primarily attributable to higher employee headcount and costs, 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 throughout 2023.

Capitalized G&A expenses remained consistent in the three and six months ended June 30, 2023 compared to the same periods in 2022.

Second quarter 2023 G&A expenses were $14.29 per boe, representing a 3 percent decrease from the $14.68 per barrel reported in the second quarter of 2022. A 25 percent increase in second quarter 2023 net G&A expenses in relation to the prior year equivalent quarter was fully offset by a 29 percent increase in production volumes on a boe basis. Year to date 2023 G&A expenses on a boe basis declined 18 percent from the equivalent 2022 period, as a 41 percent increase in production volumes achieved in 2023 offset a 16 percent increase in net G&A expenditures.

General and Administration Expenses

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3,000
2,500 $17.03
$15.71
$14.25 $14.68 $14.29
2,000
$11.42
$10.91
1,500 $9.32
1,000
500
-
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023
G&A expenses G&A expenses per boe¹
$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.

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Second Quarter 2023 Management's Discussion and Analysis

Net finance expenses

($000's except per boe	Three months	ended June 30,	%	Six months	ended June 30,	%
amounts)	2023	2022	change	2023	2022	change
Interest income	(17)	(7)	100	(45)	(8)	100
Finance lease interest income	(12)	(17)	(29)	(24)	(34)	(29)
Lease liability interest	77	63	22	128	126	2
Bank debt interest	538	589	(9)	1,063	1,178	(10)
Debt issuance expense	114	-	n/a	114	-	n/a
Production liability revaluation (gain) loss	(146)	(80)	83	(308)	119	n/a
Accretion on decommissioning liabilities	63	54	17	123	120	3
Other	14	16	(13)	11	59	(81)
Net finance expenses	631	617	2	1,062	1,560	(32)
Cash net finance expenses	712	641	11	1,248	1,275	(2)
Non-cash net finance (income) expenses	(81)	(24)	100	(186)	285	n/a
Net finance expenses	631	617	2	1,062	1,560	(32)
Per boe(1)	3.80	4.78	(21)	2.96	6.12	(52)

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 second quarter of 2023 were $631,000 compared to $617,000 recognized in the same period of 2022. For the six months ended June 30, 2023, net finance expenses were $1,062,000, representing a $498,000 or 32 percent decrease from the $1,560,000 recognized in the prior year comparative period.

Relative to the second quarter of 2022, the $71,000 increase in cash finance costs recognized in the second quarter of 2023 was primarily attributed to $114,000 incurred for debt issuance costs, partially offset by a $51,000 decrease in bank debt interest expenses. Refer to the " Liquidity and Capital Resources - Bank Debt " section herein for further details. On a year to date basis, 2023 cash finance expenses decreased by $27,000 from the comparative 2022 period, as the aforementioned debt issuance expense of $114,000 was fully offset by a $115,000 decline in bank interest expenses reflecting decreased weighted average debt balances outstanding and a $37,000 increase in interest income recognized during the six months ended June 30, 2023.

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Bank Debt and Interest Expense
30,000
25,000 589 589 583 555
525 538
20,000
292
15,000
10,000
148
5,000
-
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023
Weighted average debt outstanding Bank debt interest expense
$000's
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Second Quarter 2023 Management's Discussion and Analysis

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 2023	ended June 30, 2022	% change	Six months 2023	ended June 30, 2022	% change
US$:C$ avg. FX rate(1)	1.345	1.277	5	1.349	1.272	6
US$:TT$ avg. FX rate(2)	6.751	6.754	-	6.752	6.756	-
	June 30,	March 31,	%	June 30,	December 31,	%
	2023	2023	change	2023	2022	change
US$:C$ closing FX rate(1)	1.325	1.353	(2)	1.325	1.357	(2)
US$:TT$ closing FX rate(2)	6.749	6.748	-	6.749	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.

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 three and six months ended June 30, 2023, the C$ depreciated 5 percent and 6 percent relative to the US$, respectively, in comparison to the corresponding average rates observed in the 2022 equivalent periods. Relative to the US$, the TT$ remained range bound during the three and six months ended June 30, 2023 and 2022. In aggregate, we recorded a foreign exchange loss of $48,000 and a foreign exchange gain of $62,000 during the three and six months ended June 30, 2023, respectively (2022 - gains of $140,000 and $196,000). 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$, the C$ closed 2 percent stronger on June 30, 2023 versus March 31, 2023 and December 31, 2022. In comparison to the US$, the TT$ remained consistent over the corresponding periods. We recognized foreign currency translation gains of $207,000 and $204,000 during the three and six months ended June 30, 2023, respectively (2022 - loss of $267,000 and gain of $133,000).

Equity-based awards

We have a stock 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.

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Second Quarter 2023 Management's Discussion and Analysis

On May 11, 2023, the Board adopted an omnibus incentive compensation plan (the "Omnibus Plan"), which was approved by our shareholders at our annual general and special meeting on June 29, 2023. The Omnibus Plan was adopted by the Board primarily to allow for a variety of equity-based awards that provide the Company with the ability to grant different types of incentives to our directors, officers, employees and consultants including stock options, restricted share units and performance share units. No additional stock options will be granted under the legacy stock option plan, and all outstanding stock options previously issued pursuant to the legacy stock option plan will continue to be governed by such plan and will continue to vest in accordance with their existing vesting schedules.

The maximum number of common shares reserved for issuance under the legacy stock option plan and the Omnibus Plan at any time is limited to 10 percent of our issued and outstanding common shares, on a non-diluted basis. As of June 30, 2023, we had 11,538,101 shares options outstanding under our legacy stock option plan, which represented 4.9 percent of our issued and outstanding common shares (December 31, 2022 - 11,928,435 and 5.1 percent, respectively).

The following table sets forth equity compensation expenses recorded in relation to our share option plan for the periods indicated.

($000's)	Three months 2023	ended June 30, 2022	% change	Six months 2023	ended June 30, 2022	% change
Gross equity-based compensation	294	491	(40)	717	802	(11)
Capitalized equity-based compensation	(42)	(92)	(54)	(104)	(159)	(35)
Equity-based compensation	252	399	(37)	613	643	(5)

Equity-based compensation expenses declined 37 percent and 5 percent in the three and six months ended June 30, 2023, respectively, compared to the equivalent periods in 2022. The decreases in gross equitybased compensation and capitalized equity-based compensation during the three and six months ended June 30, 2023 compared to the same periods of 2022 were primarily attributable to decreases in the fair value of equity-based awards granted in 2022 versus previously granted awards. In addition, the Company has yet to issue its Board approved 2023 annual stock option awards. Further information regarding our equity compensation plans are included in Note 11 " Shareholders' Capital " of our interim financial statements.

Depletion and depreciation expense

($000's except per boe	Three months	ended June 30,	%	Six months	ended June 30,	%
amounts)	2023	2022	change	2023	2022	change
Depletion expense	943	912	3	2,025	1,784	14
Depreciation expense	98	63	56	393	121	100
Depletion and depreciation expense	1,041	975	7	2,418	1,905	27
Depletion expense per boe(1)	5.67	7.06	(20)	5.64	7.00	(19)

Note:

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

For the three and six months ended June 30, 2023, depletion expense associated with our petroleum and natural gas development assets included in property, plant and equipment ("PP&E") increased by 3 percent and 14 percent, respectively, compared to the same periods of 2022. The increases in depletion expenses in 2023 primarily reflected depletion associated with Coho-1 well production.

On a boe basis, the Company's depletion rates decreased 20 percent and 19 percent during the three and

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Second Quarter 2023 Management's Discussion and Analysis

six months ended June 30, 2023, respectively, in comparison to the equivalent prior year periods, primarily based on increased production volumes attributed to our Coho-1 well.

The increases in depreciation expense reported during the three and six months ended June 30, 2023 relative to the equivalent 2022 periods reflected higher net asset carrying values associated with lease right-of-use assets as a result of increased lease liability carrying values, as well as an increase in depreciation of drilling rig mobilization expenses which were recorded when the associated drilling rig was in use in the first quarter of 2023.

Impairment of non-financial assets

E&E asset impairment

During the three and six months ended June 30, 2023, we recognized E&E asset impairments of $14,000 and $29,000 predominately related to our Cory Moruga exploration property, respectively (2022 - $35,000 and $171,000). 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 June 30, 2023, we identified no indicators of impairment relating to our Ortoire CGU, which had a carrying value of $65,310,000 representing the full E&E asset balance on the consolidated balance sheet (December 31, 2022 - $51,352,000).

PP&E impairment

On June 30, 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.

Other expenses

($000's except per boe	Three months	ended June 30,	%	Six months	ended June 30,	%
amounts)	2023	2022	change	2023	2022	change
Other expenses	(440)	540	n/a	(440)	540	n/a
Per boe(1)	(2.65)	4.18	n/a	(1.23)	2.12	n/a

Note:

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

In the second quarter of 2022, the Company accrued $540,000 in estimated costs related to an oil spill that occurred as a result of vandalism in June 2022. In the fourth quarter of 2022 we filed a claim through our general and pollution liability policy which has a $250,000 deductible for all pollution claims. Touchstone received partial insurance proceeds of $440,000 in the second quarter of 2023 from this claim.

Income taxes

The Company's two Trinidad exploration and production subsidiaries are subject to supplemental petroleum tax ("SPT"), petroleum profit tax ("PPT") and unemployment levy ("UL").

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

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Second Quarter 2023 Management's Discussion and Analysis

$75.00 per barrel and 18 percent when weighted average realized prices fall between $75.00 and $90.00 per barrel. For quarterly average prices greater than $90.00, the SPT rate is 18 percent plus 0.2 percent per $1.00 above $90.00 per barrel. 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. The 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 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	Three months	ended June 30,	%	Six months	ended June 30,	%
amounts)	2023	2022	change	2023	2022	change
SPT	-	1,043	(100)	4	1,270	(100)
PPT	103	319	(68)	229	580	(61)
UL	41	129	(68)	91	233	(61)
Other	36	56	(36)	71	92	(23)
Current income tax expenses	180	1,547	(88)	395	2,175	(82)
Per boe(1)	1.08	11.97	(91)	1.10	8.53	(87)

Note:

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

During the three and six months ended June 30, 2023, the Company recognized current income tax expenses of $180,000 and $395,000, respectively, compared to $1,547,000 and $2,175,000 in the same periods of 2022. Relative to the corresponding periods of 2022, the decrease in second quarter and year to date June 30, 2023 current income taxes was based on reduced SPT expenses as crude oil realized pricing was below the $75.00 threshold in both periods, as well as a decline in estimated 2023 Trinidadbased net taxable profits.

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Current Income Tax Expense
1,750
$11.97 $11.80
1,500
1,250
1,000
$5.32
750 $5.00
500 $3.07
$1.69
250 $1.12 $1.08
-
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023
Income tax expense Current income tax expense per boe¹
$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.

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Second Quarter 2023 Management's Discussion and Analysis

During the three and six months ended June 30, 2023, we recognized deferred income tax recoveries of $383,000 and $830,000, respectively, compared to expenses of $301,000 and $536,000 in the same periods of 2022, reflecting an increase in deductible interest reserves, partially offset by the use of noncapital carry forward losses.

The Company's $13,717,000 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 June 30, 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. E&E asset expenditures during the respective periods are summarized in the following table.

($000's)	Three months 2023	ended June 30, 2022	% change	Six months 2023	ended June 30, 2022	% change
Licence financial obligations	72	173	(58)	146	343	(57)
Drilling, completions and well testing	1,976	93	100	7,343	1,022	100
Equipment and facilities	2,534	2,212	15	5,540	2,661	100
Capitalized G&A	150	167	(10)	315	318	(1)
Other	63	287	(78)	201	462	(56)
E&E asset expenditures	4,795	2,932	64	13,545	4,806	100

Our 2023 capital program remained heavily focused on exploration activities on the Ortoire property, as we invested $4,795,000 and $13,545,000 during the three and six months ended June 30, 2023, respectively. Second quarter 2023 investments included two production tests on the Royston-1X sidetrack well drilled in the first quarter of 2023. Second quarter and year to date 2023 expenditures were also invested in constructing the Cascadura natural gas and liquids facility.

During the three and six months ended June 30, 2022, we invested $2,932,000 and $4,806,000 in E&E assets, respectively. The investments primarily focused on facility and pipeline expenditures related to the Coho-1 facility, investments for the Cascadura facility and Royston-1 production testing operations incurred in the first quarter of 2022.

PP&E expenditures

($000's)	Three months 2023	ended June 30, 2022	% change	Six months 2023	ended June 30, 2022	% change
Drilling and completions	155	321	(52)	209	789	(74)
Capitalized G&A	91	78	17	178	159	12
Corporate and other	94	37	100	222	168	32
PP&E expenditures	340	436	(22)	609	1,116	(45)

Second quarter and year to date 2023 expenditures on PP&E were minimal given our capital program continued to focus on Ortoire exploration activities. We performed four development well recompletions and invested in corporate information technology infrastructure during the six months ended June 30, 2023.

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Second Quarter 2023 Management's Discussion and Analysis

Second quarter and year to date 2022 PP&E expenditures were $436,000 and $1,116,000, respectively. Expenditures were related to completion costs for three development wells drilled in the fourth quarter of 2021 as well as lease preparation costs for two Coora-1 drilling locations.

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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
-
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023
E&E assets 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, with an effective date of December 31, 2021. The New Dome and South Palo Seco dispositions closed on April 30, 2022, while the Palo Seco disposition closed on May 31, 2023. Touchstone recognized an $800,000 gain on asset disposition during the three and six months ended June 30, 2023 in relation to the Palo Seco property disposition.

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 and 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 LOAs with Heritage, we are obligated to remit $0.25 per boe sold into various escrow accounts. As of June 30, 2023, we reported $1,567,000 of accrued or paid contributions into MEEI and Heritage abandonment funds as long-term abandonment fund assets (December 31, 2022 - $1,446,000).

Touchstone estimated the net present value of the cash flows required to settle decommissioning liabilities to be $11,017,000 as at June 30, 2023 compared to $11,182,000 as of December 31, 2022. June 30, 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). $63,000 and $123,000 of accretion expenses were recognized during the three and six months ended June 30, 2023, respectively, to reflect the increase in decommissioning liabilities associated with the passage of time (2022 - $54,000 and $120,000).

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Second Quarter 2023 Management's Discussion and Analysis

Decommissioning liability details as at and during the six months ended June 30, 2023 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	14,272	17,253	11,017

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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.

On May 25, 2023, we entered into a second amended and restated loan agreement with our Trinidad based lender providing for a $7 million revolving loan facility in addition to the existing term loan facility (the "Second Amended Loan Agreement"). The $7 million revolving loan component was fully drawn on June 1, 2023, primarily to maintain financial flexibility while we proceeded with Royston-1X production testing operations and Cascadura facility construction. Refer to the " Liquidity and Capital Resources - Bank Debt " section herein for further details.

As at June 30, 2023, we had a cash balance of $10,138,000, a working capital deficit of $10,913,000 and a long-term bank debt balance of $18,000,000.

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Second Quarter 2023 Management's Discussion and Analysis

The following table summarizes our changes in cash during the 2023 periods specified.

($000's)	Three months ended June 30, 2023 March 31, 2023	Three months ended June 30, 2023 March 31, 2023	% change
Net cash from (used in):
Operating activities	2,975	913	100
Investing activities	(9,253)	(4,661)	99
Financing activities	5,601	(1,866)	n/a
Change in cash	(677)	(5,614)	(88)
Cash, beginning of period	10,859	16,335
Impact of FX on cash balances	(44)	138	n/a
Cash, end ofperiod	10,138	10,859	(7)

Our second quarter 2023 cash and working capital balances declined in comparison to March 31, 2023 and December 31, 2022 based on ongoing investments directed toward our Ortoire block. During the six months ended June 30, 2023, we increased our bank debt balance by $4,000,000, with $7,000,000 drawn on the new revolving component and $3,000,000 paid on our existing term component.

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 increase when the Cascadura natural gas and liquids facility is online. In addition, we expect to continually renew the Company's revolving component of its bank debt past the initial May 31, 2024 period, the balance of which is currently included in current liabilities.

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	June 30, 2023	December 31, 2022
Net debt(1)		28,913	16,008
Shareholders'equity		79,020	78,380
Managed capital(1)		107,933	94,388
Trailing twelve-month funds flow from operations(2)		1,756	3,540
Net debt to funds flow from operations ratio(1)	At or < 2.0 times	16.47	4.52
Net debt to managed capital ratio(1)	< 0.4 times	0.27	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 June 30, 2023 includes the sum of funds flow from operations for the six months ended June 30, 2023 and funds flow from operations for the July 1, 2022 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

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Second Quarter 2023 Management's Discussion and Analysis

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.

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, June 30, 2023 and December 31, 2022.

	August 10, 2023	June 30, 2023	December 31, 2022
Common shares outstanding	233,463,560	233,427,560	233,037,226
Share options outstanding	11,480,434	11,538,101	11,928,435
Fully diluted common shares	244,943,994	244,965,661	244,965,661

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

Bank debt

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.

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. Effective December 30, 2021, we withdrew an additional $15 million on the credit facility, resulting in the full principal balance of $30 million outstanding.

On May 25, 2023, the parties entered into the Second Amended Loan Agreement, which provided for a $7 million revolving loan facility in addition to the existing $30 million term facility. Aside from adding the revolving loan component, the Second Amended Loan Agreement did not alter any material terms of the prior December 21, 2021 amended and restated loan agreement. The Second Amended Loan Agreement remains a senior secured syndicated loan, with Republic Bank Limited acting as lender, arranger and administrative agent. The Second Amended 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. Details of each component is set forth below.

Facility	Term loan component	Revolving loan component
Amount	$30,000,000	$7,000,000
		May 30, 2024 - the parties have the option to
Maturity date	June 15, 2027	extend annually by additional periods of up to
		one year
Interest rate	7.85 percent per annum	7.29 percent through May 2024 - reset annually
Interest payments	Payable quarterly in arrears	Payable monthly in arrears

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Second Quarter 2023 Management's Discussion and Analysis

Facility		Term loan component	Revolving loan component
		Twenty $1.5 million quarterly payments from	Principal may be repaid at any time, on or
Principal	payments	September 15, 2022 to June 15, 2027; additional principal may be repaid with no	before the maturity date without penalty and any amounts repaid may be redrawn at any
		penalty	time

The $7 million revolving loan component was fully drawn on June 1, 2023. As at June 30, 2023, the principal balance of the term loan component was $24 million, with sixteen equal and consecutive quarterly principal payments of $1.5 million outstanding. The following table details the movements of the Company's bank debt balance during the six months ended June 30, 2023.

($000's)	Term loan component	Revolving loan component	Bank debt
Balance, December 31, 2022	26,962	-	26,962
Payments	(3,000)	-	(3,000)
Advances	-	7,000	7,000
Accretion	(1)	-	(1)
Balance, June 30, 2023	23,961	7,000	30,961
Current	6,000	7,000	13,000
Non-current	17,961	-	17,961
Bank debt balance	23,961	7,000	30,961

The Second Amended Loan Agreement contains industry standard representations and warranties, undertakings, events of default, and financial covenants tested on an annual basis. Pursuant to the Second Amended Loan Agreement, 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 June 30, 2023, the Company was compliant with all covenants provided for in the Second Amended Loan Agreement.

At all times, we must maintain a cash reserves balance of not less than the equivalent of two subsequent quarterly interest payments related to the term loan component. Accordingly, Touchstone classified $903,000 of cash as long-term restricted on the consolidated balance sheet as at June 30, 2023 (December 31, 2022 - $1,021,000).

Further information regarding the loan arrangement is included in Note 8 " Bank Debt " of our interim financial statements, and copies of the loan 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 June 30, 2023, we recognized $3,223,000 in aggregate lease liabilities, of which $1,662,000 was classified as long-term on the consolidated balance sheet (December 31, 2022 - $2,255,000 and $1,373,000, respectively). Touchstone entered into a minimum five year lease for additional office space in Trinidad effective April 1, 2023, resulting in a $1,256,000 lease liability and associated right-of-use asset recognized. Further information regarding our lease obligations is included in Note 7 " Lease Liabilities " of our interim financial statements.

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Second Quarter 2023 Management's Discussion and Analysis

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. During the three and six months ended June 30, 2023, we recognized gains on revaluation of $146,000 and $308,000, respectively, based on decreases in estimated future production levels (2022 - $80,000 gain and $119,000 loss). At June 30, 2023, our estimated production liability balance was $310,000, 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 June 30, 2023.

($000's) Total	Estimated payments due by year
	2023 2024 2025 Thereafter
Operating agreement commitments Coora blocks 13,229 WD-4 block 4,357 WD-8 block 4,366 Fyzabad block 760 Coho area of Ortoire block 56 Cory Moruga exploration block 1,150 Ortoire exploration block 14,412 Office and equipmentleases 922	4,878 2,572 2,629 3,150 20 1,282 1,312 1,743 18 1,279 1,309 1,760 76 79 80 525 6 6 5 39 49 105 110 886 194 6,409 6,518 1,291 246 182 207 287
Minimum payments 39,252	5,487 11,914 12,170 9,681

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. As at June 30, 2023, four development wells and two heavy workover commitments are required to be performed prior to December 31, 2023. The Company is currently in discussions with Heritage to defer two of the development wells to 2024.

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.

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.

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Second Quarter 2023 Management's Discussion and Analysis

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 are a party to 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 price increases. We had no commodity financial management contracts in place as of the date hereof or during the three and six months ended June 30, 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 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 third-

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Second Quarter 2023 Management's Discussion and Analysis

party 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 $1,067,000 as of June 30, 2023, as we collected approximately $2,544,000 in past due amounts during the six months ended June 30, 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 June 30, 2023.

Composition Counterparty Balance due ($000's) Balance due (%)	Accounts receivable aging
	Current ($000's) Over 90 days ($000's)
Crude oil sales Heritage 1,359 20 Natural gas sales NGC 348 5 Joint interest billings Heritage and NGC 889 13 VAT Trinidad government 3,603 54 Finance leases Third-party lessees 69 1 Other Various 466 7
	1,359 -
	348 -
	889 -
	1,229 2,374
	69 -
	405 61
Accounts receivable 6,734 100	4,299 2,435

Effective March 1, 2021, we executed separate arrangements to lease our oilfield service rigs and swabbing units to two third-party contractors. 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 upon receipt of the final lease payments. As of June 30, 2023, our aggregate finance lease receivable balance was $442,000, of which $373,000 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.

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.

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Second Quarter 2023 Management's Discussion and Analysis

The following table sets forth estimated undiscounted cash outflows and financial maturities of our financial liabilities as at June 30, 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 13,958 Income taxes payable Yes – liability 308 Lease liabilities Yes – liability 4,328 Bank debt principal Yes – liability 31,000 Bank debt interest No – recognized as incurred 4,393	13,958 - - 308 - - 1,735 579 2,014 13,000 12,000 6,000 2,155 1,963 275
Financial liabilities 53,987	31,156 14,542 8,289

Notes:

(1) The undiscounted cash outflows equal their financial statement carrying values, with the exception of lease liabilities and bank debt 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 and six months ended June 30, 2023, $106,000 and $167,000 in legal fees and disbursements charged by Norton Rose Fulbright Canada LLP were incurred, respectively (2022 - $15,000 and $64,000). $106,000 was included in accounts payable and accrued liabilities as at June 30, 2023 (2022 - $15,000).

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 three and six months ended June 30, 2023, $4,000 and $8,000 in products were purchased, respectively (2022 - $2,000 and $8,000). As at June 30, 2023, $4,000 was included in accounts payable and accrued liabilities (2022 - $2,000).

Changes in Accounting Policies Including Initial Adoption

There were no changes in accounting policies during the three and six months ended June 30, 2023 that had a material effect on the reported comprehensive income (loss) or net assets of the Company.

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.

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Second Quarter 2023 Management's Discussion and Analysis

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 and consultants 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 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 " Advisories - Forward-looking Statements " section in this MD&A for additional information regarding the risks to which Touchstone and our business operations are subject to.

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 April 1, 2023 and ended June 30, 2023 that had materially affected, or were reasonably likely to materially affect, internal control over financial reporting.

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Second Quarter 2023 Management's Discussion and Analysis

Summary of Quarterly Results

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

Three months ended	June 30, 2023	March 31, 2023	Dec. 31, 2022	Sept. 30, 2022	June 30, 2022	March 31, 2022	Dec. 31, 2021	Sept. 30, 2021
Operational
Average daily production_(boe/d)_	1,827	2,139	2,229	1,272	1,420	1,396	1,336	1,333
Net wells drilled	-	0.8	-	-	-	-	3.0	0.8
Realized commodity price(1) ($/boe)	43.19	44.03	48.36	84.85	97.48	83.55	66.81	62.37
Operating netback(1) ($/boe)	17.00	18.97	21.05	37.55	44.99	37.83	29.96	27.77
Financial
($000's except per share amounts)
Petroleum and natural gas sales	7,181	8,476	9,919	9,933	12,596	10,496	8,212	7,650
Cash from (used in) operating activities	2,975	913	(1,189)	3,058	3,533	350	1,406	404
Funds flow from operations	6	803	691	256	1,150	1,443	1,309	1,093
Net (loss) earnings	(71)	(279)	(1,921)	(778)	(262)	(236)	6,514	(51)
Per share – basic and diluted	(0.00)	(0.00)	(0.01)	(0.00)	(0.00)	(0.00)	0.03	(0.00)
E&E asset expenditures	4,795	8,750	2,290	2,692	2,932	1,874	2,946	7,542
PP&E expenditures	340	269	219	207	436	680	5,190	2,315
Capital expenditures(1)	5,135	9,019	2,509	2,899	3,368	2,554	8,136	9,857
Working capital deficit (surplus)(1)	10,913	4,383	(4,992)	4,537	(346)	(4,259)	(6,925)	4,657
Principal long-term bank loan	18,000	19,500	21,000	22,500	24,000	25,500	27,000	7,125
Net debt(1) –end of period	28,913	23,883	16,008	27,037	23,654	21,241	20,075	11,782
Share Information (000's)
Weighted average – basic	233,144	233,037	217,106	212,647	212,204	210,823	210,732	210,732
Weighted average – diluted	233,144	233,037	217,106	212,647	212,204	210,823	218,102	210,732
Outstanding shares – end of period	233,428	233,037	233,037	213,113	212,275	211,164	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:

We recorded negligible funds flow from operations in the second quarter of 2023, as operating netbacks declined by $0.8 million from the prior quarter based on a 15 percent and a 4 percent decline in production and realized pricing, respectively. Touchstone entered into a $7 million additional revolving facility with its current lender in the quarter which was fully drawn on June 1, 2023. $5.1 million in quarterly capital investments led to a $5 million increase in net debt from the preceding quarter.
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.

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Second Quarter 2023 Management's Discussion and Analysis

In the fourth quarter of 2022, we generated $0.7 million of 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 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, 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 bank debt balance from $20 million to $30 million and withdrew the remaining $15 million available balance on December 30, 2021. Net non-financial asset 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 were $9.9 million, as we drilled an exploration well and incurred rig mobilization and inventory costs for our fourth quarter 2021 development drilling program.

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 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

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Second Quarter 2023 Management's Discussion and Analysis

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.

($000's unless otherwise stated)	Three months 2023	ended June 30, 2022	Six months 2023	ended June 30, 2022
Petroleum and natural gas sales	7,181	12,596	15,657	23,092
Less: royalties	(2,152)	(4,519)	(4,656)	(8,105)
Petroleum and natural gas revenue, net of royalties	5,029	8,077	11,001	14,987
Less: operating expenses	(2,203)	(2,264)	(4,523)	(4,421)
Operating netback	2,826	5,813	6,478	10,566
Production_(boe)_	166,249	129,212	358,754	254,837
Operating netback ($/boe)	17.00	44.99	18.06	41.46

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 2023	ended June 30, 2022	Six months 2023	ended June 30, 2022
E&E asset expenditures	4,795	2,932	13,545	4,806
PP&Eexpenditures	340	436	609	1,116
Capital expenditures	5,135	3,368	14,154	5,922
Abandonment fund expenditures	56	30	122	59
Proceeds from asset dispositions	(250)	(100)	(250)	(135)
Net change in non-cash working capital	4,312	1,186	(112)	6,806
Cash used in investing activities	9,253	4,484	13,914	12,652

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 the 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.

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Second Quarter 2023 Management's Discussion and Analysis

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 and is most directly comparable to total liabilities disclosed in the Company's consolidated balance sheets. The following table presents working capital and net debt computations for the periods indicated.

($000's)	June 30, 2023	December 31, 2022	June 30, 2022
Current assets	(17,914)	(26,415)	(20,717)
Currentliabilities	28,827	21,423	20,371
Working capital deficit (surplus)	10,913	(4,992)	(346)
Principal long-term balance of bank debt	18,000	21,000	24,000
Net debt	28,913	16,008	23,654

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

($000's)	June 30, 2023	December 31, 2022	June 30, 2022
Total liabilities	73,184	69,497	73,760
Lease liabilities	(1,662)	(1,373)	(2,085)
Other liabilities	-	-	(546)
Decommissioning liabilities	(11,017)	(11,182)	(11,741)
Deferred income tax liability	(13,717)	(14,557)	(15,074)
Variance of carrying value and principal value of bank debt	39	38	57
Current assets	(17,914)	(26,415)	(20,717)
Net debt	28,913	16,008	23,654

The Company's forward net debt to funds flow from operations ratio is the desired target Touchstone strives to achieve and maintain. 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.

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.

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Second Quarter 2023 Management's Discussion and Analysis

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. Depletion expense is a component of depletion and depreciation expenses as disclosed in the Company's financial statements.

Other expenses per boe - is comprised of other 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;
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 Cascadura wells ;
the performance characteristics of the Company's petroleum and natural gas properties including current and future crude oil and liquids and natural gas production levels and estimated field production levels;
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;

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Second Quarter 2023 Management's Discussion and Analysis

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 formal extension or execution of certain contracts;
expectations regarding the Company's ability to 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 bank debt covenants and its ability to make future scheduled interest and principal payments;
expectations regarding renewing the Company's revolving credit facility past May 2024;
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 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

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Second Quarter 2023 Management's Discussion and Analysis

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.

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

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Second Quarter 2023 Management's Discussion and Analysis

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	June 30, 2023	March 31, 2023	Dec. 31, 2022	Sept. 30, 2022	June 30, 2022	March 31, 2022	Dec. 31, 2021	Sept. 30, 2021
Production
Light and medium crude oil_(bbls)_	96,050	108,722	111,114	110,467	122,778	117,253	113,724	111,725
Heavy crude oil_(bbls)_	6,270	6,918	6,126	6,592	6,434	8,372	9,193	10,924
Crude oil_(bbls)_	102,320	115,640	117,240	117,059	129,212	125,625	122,917	122,649
Conventional natural gas_(Mcf)_	383,572	461,189	527,105	-	-	-	-	-
Total production (boe)	166,249	192,505	205,091	117,059	129,212	125,625	122,917	122,649
Average daily production
Light and medium crude oil_(bbls/d)_	1,055	1,208	1,207	1,200	1,349	1,303	1,236	1,214
Heavy crude oil_(bbls/d)_	69	77	67	72	71	93	100	119
Crude oil_(bbls/d)_	1,124	1,285	1,274	1,272	1,420	1,396	1,336	1,333
Conventional natural gas_(Mcf/d)_	4,215	5,124	5,729	-	-	-	-	-
Average daily production (boe/d)	1,827	2,139	2,229	1,272	1,420	1,396	1,336	1,333

The Company's total and average production for the six months ended June 30, 2023 and 2022 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 51-101 using a conversion of 6 Mcf to 1 boe where applicable.

	Six months ended June 30,	Six months ended June 30,	%
	2023	2022	change
Production
Light and medium crude oil_(bbls)_	204,772	240,031	(15)
Heavy crude oil_(bbls)_	13,188	14,806	(11)
Crude oil_(bbls)_	217,960	254,837	(14)
Conventional natural gas_(Mcf)_	844,761	-	n/a
Total production (boe)	358,754	254,837	41
Average daily production
Light and medium crude oil_(bbls/d)_	1,131	1,326	(15)
Heavy crude oil_(bbls/d)_	73	82	(11)
Crude oil_(bbls/d)_	1,204	1,408	(14)
Conventional naturalgas (Mcf/d)	4,667	-	n/a
Average daily production (boe/d)	1,982	1,408	41

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Second Quarter 2023 Management's Discussion and Analysis

References to Touchstone

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

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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Second 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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Second Quarter 2023 Management's Discussion and Analysis

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Touchstone Exploration Inc. — Interim / Quarterly Report 2023

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