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Touchstone Exploration Inc. Management Reports 2025
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Management Reports
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www.touchstoneexploration.com
TSX / LSE: TXP
TOUCHSTONE
Touchstone Exploration Inc.
Management's Discussion and Analysis
For the three months and years ended December 31, 2024 and 2023
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 months and year ended December 31, 2024 with comparisons to the three months and year ended December 31, 2023 is dated March 19, 2025 and should be read in conjunction with the Company's audited consolidated financial statements as at and for the year ended December 31, 2024 (the "audited financial statements") and our 2024 Annual Information Form ("AIF"), each of which are available online on our SEDAR+ profile (www.sedarplus.ca) and website (www.touchstoneexploration.com). The audited financial statements have been prepared by Management in accordance with IFRS Accounting Standards as issued by the International Accounting Standards Board ("IFRS" or "GAAP"). The audited financial statements were prepared by Management and approved by the Company's Board of Directors ("Board").
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 of this MD&A 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, through its subsidiaries, is a petroleum and natural gas exploration and production company active in the Republic of Trinidad and Tobago ("Trinidad"). Touchstone is currently the largest independent onshore oil and natural gas producer in Trinidad, with assets in several reservoirs that have an extensive internally estimated 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". Our strategy is to leverage Canadian experience and capability to our Trinidad onshore properties to create shareholder value.
TOUCHSTONE
2024 Management's Discussion and Analysis
Financial and Operational Results Overview
| Three months ended December 31, | % change | Year ended December 31, | % change | |||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Operational | ||||||
| Average daily production | ||||||
| Crude oil(1) (bbls/d) | 1,310 | 1,133 | 16 | 1,220 | 1,181 | 3 |
| NGLs(1) (bbls/d) | 121 | 622 | (81) | 132 | 201 | (34) |
| Crude oil and liquids(1) (bbls/d) | 1,431 | 1,755 | (18) | 1,352 | 1,382 | (2) |
| Natural gas(1) (Mcf/d) | 23,136 | 40,491 | (43) | 26,290 | 15,593 | 69 |
| Average daily production (boe/d)(2) | 5,287 | 8,504 | (38) | 5,734 | 3,981 | 44 |
| Average realized prices(3) | ||||||
| Crude oil(1) ($/bbl) | 62.50 | 72.26 | (14) | 67.91 | 67.80 | - |
| NGLs(1) ($/bbl) | 62.05 | 72.92 | (15) | 69.10 | 74.07 | (7) |
| Crude oil and liquids(1) ($/bbl) | 62.47 | 72.49 | (14) | 68.03 | 68.72 | (1) |
| Natural gas(1) ($/Mcf) | 2.50 | 2.43 | 3 | 2.48 | 2.36 | 5 |
| Realized commodity price ($/boe)(2) | 27.85 | 26.53 | 5 | 27.39 | 33.10 | (17) |
| Production mix (% of production) | ||||||
| Crude oil and liquids(1) | 27 | 21 | 24 | 35 | ||
| Natural gas(1) | 73 | 79 | 76 | 65 | ||
| Operating netback ($/boe)(2) | ||||||
| Realized commodity price(3) | 27.85 | 26.53 | 5 | 27.39 | 33.10 | (17) |
| Royalty expense(3) | (6.59) | (5.53) | 19 | (6.61) | (8.38) | (21) |
| Operating expense(3) | (7.09) | (3.46) | 100 | (5.10) | (6.68) | (24) |
| Operating netback(3) | 14.17 | 17.54 | (19) | 15.68 | 18.04 | (13) |
| Financial ($000's except per share amounts) | ||||||
| Petroleum and natural gas sales | 13,543 | 20,759 | (35) | 57,470 | 48,098 | 19 |
| Cash from operating activities | 822 | 8,512 | (90) | 13,181 | 12,743 | 3 |
| Funds flow from operations | 3,614 | 10,489 | (66) | 16,748 | 13,730 | 22 |
| Net (loss) earnings | (542) | (21,236) | (97) | 8,272 | (20,598) | n/a |
| Per share - basic | (0.00) | (0.09) | n/a | 0.04 | (0.09) | n/a |
| Per share - diluted | (0.00) | (0.09) | n/a | 0.03 | (0.09) | n/a |
| E&E asset expenditures | 426 | 595 | (28) | 1,046 | 17,638 | (94) |
| PP&E expenditures | 2,680 | 591 | 100 | 22,633 | 1,311 | 100 |
| Capital expenditures(3) | 3,106 | 1,186 | 100 | 23,679 | 18,949 | 25 |
| Working capital deficit(3) | 1,359 | 7,581 | (82) | |||
| Principal long-term bank debt | 27,750 | 15,000 | 85 | |||
| Net debt(3) - end of period | 29,109 | 22,581 | 29 | |||
| Share Information (000's) | ||||||
| Weighted avg. shares outstanding: | ||||||
| Basic | 236,461 | 234,213 | 1 | 235,509 | 233,487 | 1 |
| Diluted | 236,461 | 234,213 | 1 | 236,492 | 233,487 | 1 |
| Outstanding shares - end of period | 236,461 | 234,213 | 1 |
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"). In addition, references to "crude oil and liquids" in this MD&A include crude oil and NGLs. 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 of this MD&A.
(3) Specified financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
TOUCHSTONE
2024 Management's Discussion and Analysis
Highlights of Touchstone's financial and operating results for the three months ended December 31, 2024 include:
- Production: Average quarterly production increased to 5,287 boe/d (73 percent natural gas), compared to 5,211 boe/d (75 percent natural gas) in the third quarter of 2024. The increase reflected incremental output from the Cascadura-2ST1 and Cascadura-3ST1 wells brought online in November 2024, partially offset by natural declines in Cascadura field production.
- Revenue: Petroleum and natural gas sales totaled $13.54 million, consistent with the $13.25 million recorded in the previous quarter.
- Crude oil sales: $7.53 million from average production of 1,310 bbls/d at a realized price of $62.50 per barrel.
- NGL sales: $0.7 million from average production of 121 bbls/d at a realized price of $62.05 per barrel.
- Natural gas sales: $5.32 million from average production of 23.1 MMcf/d (3,856 boe/d) at a realized price of $2.50 per Mcf.
- Operating Netback: Generated $6.89 million in operating netback, down 7 percent from the third quarter of 2024. Quarterly operating netbacks averaged $14.17 per boe, an 8 percent decline from $15.46 per boe in the prior quarter, primarily due to a 41 percent increase in operating expenses driven by revised crude oil field historical head licence expenses.
- Funds Flow from Operations: Increased to $3.61 million from $3.02 million in the previous quarter, as lower operating netbacks were offset by reductions in general and administrative and transaction expenses.
- Net Loss: Recorded a net loss of $542,000 ($0.00 per basic share), primarily due to $2.31 million in pre-tax Ortoire exploration asset impairment expenses and higher depletion expenses following Cascadura reserves reductions.
- Capital Investments: Invested $3.11 million in the quarter, primarily focused on the completion of the flowline from the Cascadura C site to the Cascadura natural gas processing facility and pre-drill expenditures relating to the Cascadura-4 well spudded in January 2025.
- Financial Position: Ended the year with net debt of $29.11 million, resulting in a net debt to funds flow from operations ratio of 1.74 times (see the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information).
- Land Expansion: Continued to expand our Trinidad onshore acreage with the execution of an exploration and production licence for the Rio Claro block.
Highlights of Touchstone's financial and operating results for the year ended December 31, 2024 include:
- Record Production: Achieved annual average production volumes of 5,734 boe/d, a 44 percent increase from 3,981 boe/d in 2023. Production consisted of 1,220 bbls/d of crude oil, 132 bbls/d of NGLs, and 26.3 MMcf/d of natural gas.
- Revenue: Petroleum and natural gas sales totaled $57.47 million, up 19 percent from $48.10 million in 2023. The increase was driven by a full year of Cascadura production, with natural gas sales rising 77 percent, partially offset by a 3 percent decline in crude oil and NGL sales.
- Financial Performance:
- Funds flow from operations: $16.75 million, representing a year-over-year increase of 22 percent from $13.73 million recorded in 2023.
- Operating netback: $32.89 million or $15.68 per boe (2023 - $26.22 million or $18.04 per boe).
TOUCHSTONE
2024 Management's Discussion and Analysis
-
Net earnings: $8.27 million ($0.04 per basic share and $0.03 per diluted share), compared to a net loss of $20.60 million ($0.09 per basic share) in 2023, which included $21.39 million in net non-financial asset impairment expenses in 2023.
-
Capital Program: Invested $23.68 million in development and infrastructure, including four gross (3.6 net) development wells and key upgrades to the Cascadura natural gas processing facility.
-
Strategic Portfolio Optimization:
- Divested three non-core properties and acquired the Balata East block, which supports Cascadura NGL marketing.
-
Expanded onshore Trinidad acreage by approximately 103,000 working interest acres, securing exploration and production licences within the Herra Formation fairway.
-
Safety: Maintained a strong focus on responsible operations, with one lost-time injury recorded in 2024.
Proposed Acquisition
On December 12, 2024, the Company's wholly owned Trinidadian subsidiary signed a share purchase agreement to acquire 100 percent of a Trinidad-based private entity from a third party (the "Proposed Acquisition"). The entity holds a 65 percent operating working interest in the onshore Central Block exploration and production licence, as well as four producing gas wells and a gas processing plant in Trinidad, with state owned Heritage Petroleum Company Limited ("Heritage") holding the remaining 35 percent working interest.
Under the terms of the agreement, Touchstone will pay $23 million in cash, subject to adjustments for closing cash and abandonment fund balances. The transaction is contingent on customary regulatory approvals and conditions precedent, including securing the necessary funding. The Proposed Acquisition is expected to close in the second quarter of 2025 and will be deemed effective as of January 1, 2025.
To finance the Proposed Acquisition, Touchstone and its lender are negotiating a binding term sheet providing for two additional six-year term loan facilities totalling $38.2 million. As of the date hereof, the lender is drafting a Fourth Amended and Restated Loan Agreement along with related security documents. Once finalized, the additional borrowing capacity is expected to take effect upon closing of the Proposed Acquisition.
Highlights of the Proposed Acquisition are as follows:
- Access to Atlantic Liquefied Natural Gas: The entity is a party to natural gas sales contracts providing access to both the local market and liquified natural gas ("LNG") world market pricing.
- Development Opportunities: Touchstone has identified numerous infill well locations and a deeper Cretaceous prospect at the Central block.
- Strategic Infrastructure: The entity's working interest in midstream assets include an 80 MMcf/d gas processing plant, field natural gas and liquids flowlines, and a gas export pipeline to both the domestic market and the Atlantic LNG facility.
- Increased Production: The Proposed Acquisition will increase Touchstone's base net production by approximately 2,000 boe/d (94 percent natural gas) at December 2024 field estimated rates, providing incremental corporate cash flows.
The Central block assets include four wells in the Carapal Ridge, Baraka, and Baraka East liquids-rich natural gas pools. In addition to existing low decline field production, there is potential for facility optimization, infill drilling opportunities and exploration prospects. The private entity holds three gas marketing contracts: one accessing the Trinidad domestic market and two accessing the Atlantic LNG facility in Trinidad. Located in the Herrera fairway, the Central block is contiguous with our Ortoire block, providing strategic potential for natural gas egress and marketing options from future discoveries. Our Coho
TOUCHSTONE
2024 Management's Discussion and Analysis
natural gas production is currently processed at the Central block, and the acquisition provides synergy potential for the field.
For further information regarding the Proposed Acquisition and related advisories thereto, refer to the Company's news release dated December 13, 2024 entitled "Touchstone Exploration Announces the Acquisition of Central Block" which is available under our profile on SEDAR+ (www.sedarplus.ca) and on our website (www.touchstoneexploration.com).
Going Concern
Under its existing Third Amended and Restated Loan Agreement (the "Loan Agreement"), the Company must comply with three financial covenants assessed annually. As of December 31, 2024, Touchstone remained in compliance with all covenants.
The Company is currently negotiating with its lender to amend the Loan Agreement to incorporate two additional term loan facilities relating to the Proposed Acquisition. If the Proposed Acquisition does not proceed with an amendment to the Loan Agreement, Touchstone projects a breach of the debt service coverage covenant as of December 31, 2025, which could result in the bank debt balance becoming due.
The Company's ability to continue as a going concern depends on successfully amending the Loan Agreement or obtaining a waiver for the forecasted breach. At this time, no waiver has been sought, as the existing Loan Agreement is expected to be replaced by the amended version in conjunction with the Proposed Acquisition.
These circumstances create material uncertainties that may cast significant doubt on the Company's ability to continue as a going concern. The audited financial statements do not reflect potential adjustments to the carrying amounts of assets and liabilities, reported amounts of revenue and expenses, and balance sheet classifications that would be required if the going concern assumption were deemed inappropriate. Such adjustments could be material.
Further information is included in Note 1 "Nature of Business" of our audited financial statements.
Terminated Acquisition
On May 1, 2024, Touchstone agreed to acquire Trinity Exploration and Production Plc ("Trinity") through an all-share transaction (the "Offer"), which Trinity's Board recommended. Trinity shareholders approved the offer on June 24, 2024, and regulatory conditions were satisfied by June 28, 2024, with a court hearing to sanction the Offer set for July 31, 2024.
On July 24, 2024, Trinity announced that it had received an unsolicited cash offer from a Trinidad-based third party, postponing the court hearing to August 23, 2024. On August 2, 2024, Trinity's Board withdrew support for the Offer in favour of the competing cash offer. On August 21, 2024, Touchstone confirmed it would not increase its offer. Trinity sought court approval to withdraw the Offer on September 18, 2024, and the Offer officially lapsed on September 25, 2024.
As a result of the terminated acquisition, Touchstone incurred $1,957,000 in transaction expenses during the year ended December 31, 2024.
TOUCHSTONE
2024 Management's Discussion and Analysis
Annual 2024 Guidance
The following table summarizes Touchstone's actual results for the year ended December 31, 2024 compared to the updated financial and operational guidance published in the Company's news release dated November 13, 2024.
| Year ended December 31, 2024 | 2024 Results | 2024 Updated Guidance | Variance(1) | |
|---|---|---|---|---|
| Amount | % | |||
| Capital expenditures(2) ($000's) | 23,679 | 28,000 | (4,321) | (15) |
| Average daily production(1) (boe/d) | 5,734 | 5,600 to 6,200 | (166) | (3) |
| % natural gas | 76 | 76 | - | - |
| % crude oil and liquids | 24 | 24 | - | - |
| Average Dated Brent crude oil price ($/bbl) | 80.52 | 80.00 | 0.52 | - |
| % realized discount to Dated Brent price | 15.5 | 15.7 | (0.2) | (1) |
| Funds flow from operations(1) ($000's) | 16,748 | 17,000 | (252) | (1) |
| Net debt – end of year(1)(2) ($000's) | 29,109 | 32,000 | (2,336) | (9) |
Notes:
(1) The financial performance measures provided in the Company's 2024 updated guidance were based on the midpoint of the average production forecast of 5,900 boe/d.
(2) Specified financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Touchstone slightly underperformed the midpoint of its 2024 annual production guidance due to lower-than-expected production from the Cascadura-3ST1 well, which resulted from limited testing data. This decline contributed to a 1 percent reduction in funds flow from operations compared to the updated 2024 guidance. Pricing remained in line with expectations, with Dated Brent prices marginally higher than forecast, and a realized discount of 15.5 percent versus the expected 15.7 percent.
Capital expenditures were $4.32 million below budget, as the Company chose to defer drilling the Cascadura-4 well to 2025. This deferral, coupled with the lower funds flow from operations, resulted in a net debt balance of $29.11 million as of December 31, 2024, 9 percent lower than the updated guidance.
2025 Outlook and Guidance
We remain focused on financial discipline and maximizing value from our development and exploration assets. Our near-term strategy is to increase cash flow through the development of the Cascadura field, leveraging the processing capacity established in 2024.
On December 9, 2024, we issued a news release announcing the approval of our preliminary financial and operating guidance for 2025. Given the material nature of the Proposed Acquisition, the Company intends to provide updated 2025 guidance following its expected closing.
For further information regarding Touchstone's preliminary 2025 guidance and the related advisories, refer to the Company's news release dated December 9, 2024 entitled "Touchstone Exploration Announces Preliminary 2025 Guidance" which is available under our profile on SEDAR+ (www.sedarplus.ca) and on our website (www.touchstoneexploration.com).
TOUCHSTONE
2024 Management's Discussion and Analysis
Principal Properties and Licences
Touchstone operates upstream petroleum and natural gas activities in Trinidad under state exploration and production licences with the Government of the Republic of Trinidad and Tobago's Ministry of Energy and Energy Industries ("MEEI") and Lease Operatorship Agreements ("LOAs") and an Enhanced Production Service Contract ("EPSC") with the state-owned Heritage. Additionally, the Company holds private subsurface and surface leases with individual landowners. A schedule of Touchstone's Trinidad property interests as of December 31, 2024, is provided below.
| Property | Working interest (%) | Licence type | Licence Expiry | Gross acres(1) | Net acres(2) |
|---|---|---|---|---|---|
| Developed | |||||
| CO-1 | 100 | LOA | December 31, 2030(3) | 1,230 | 1,230 |
| WD-4 | 100 | LOA | December 31, 2030(3) | 700 | 700 |
| WD-8 | 100 | LOA | December 31, 2030(3) | 650 | 650 |
| Balata East | 100 | EPSC | November 30, 2030(3) | 1,270 | 1,270 |
| Barrackpore | 100 | Private | Various | 211 | 211 |
| Fyzabad | 100 | State and Private | August 19, 2032 / Various | 564 | 564 |
| Ortoire - Coho | 80 | State | October 31, 2039 | 1,317 | 1,054 |
| Ortoire - Cascadura | 80 | State | October 31, 2039 | 2,377 | 1,902 |
| 8,319 | 7,581 | ||||
| Exploratory | |||||
| Charuma | 80 | State | June 30, 2030 | 72,784 | 58,227 |
| Cipero | 80 | State | June 30, 2030 | 29,924 | 23,939 |
| Ortoire | 80 | State | July 31, 2026 | 36,950 | 29,560 |
| Rio Claro | 80 | State | November 4, 2030 | 31,983 | 25,586 |
| 171,641 | 137,312 | ||||
| Total | 179,960 | 144,893 |
Notes:
(1) "Gross" means the total area of properties in which we have an interest.
(2) "Net" means the total area of properties in which we have an interest multiplied by the working interest owned by us.
(3) Excluding an option for a five-year renewal, upon which future work commitments over the extended term must be agreed between the Company and Heritage.
Effective November 5, 2024, Touchstone's Trinidadian subsidiary entered into an Exploration and Production (Public Petroleum Rights) Licence for the Rio Claro block. The Company holds an 80 percent operating working interest in the licence, with the National Gas Company of Trinidad and Tobago ("NGC") holding the remaining 20 percent working interest. Similar to the Company's Charuma, Cipero and Ortoire licences, the Rio Claro licence initially has a six-year exploration term, with the possibility of a 19-year extension for areas where commercial discoveries are approved by the MEEI.
For a further details regarding our production, exploration and marketing contracts, please see our 2024 AIF dated March 19, 2025, which is available online on our SEDAR+ profile (www.sedarplus.ca) and website (www.touchstoneexploration.com).
TOUCHSTONE
2024 Management's Discussion and Analysis
Financial and Operational Results
Production volumes
| Three months ended December 31, | % change | Year ended December 31, | % change | |||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Production | ||||||
| Crude oil (bbls) | 120,487 | 104,280 | 16 | 446,420 | 431,119 | 4 |
| NGLs (bbls) | 11,087 | 57,183 | (81) | 48,206 | 73,363 | (34) |
| Crude oil and liquids (bbls) | 131,574 | 161,463 | (19) | 494,626 | 504,482 | (2) |
| Natural gas (Mcf) | 2,128,528 | 3,725,201 | (43) | 9,622,090 | 5,691,547 | 69 |
| Total production (boe) | 486,329 | 782,330 | (38) | 2,098,308 | 1,453,073 | 44 |
| Average daily production | ||||||
| Crude oil (bbls/d) | 1,310 | 1,133 | 16 | 1,220 | 1,181 | 3 |
| NGLs (bbls/d) | 121 | 622 | (81) | 132 | 201 | (34) |
| Crude oil and liquids (bbls/d) | 1,431 | 1,755 | (18) | 1,352 | 1,382 | (2) |
| Natural gas (Mcf/d) | 23,136 | 40,491 | (43) | 26,290 | 15,593 | 69 |
| Average daily production (boe/d) | 5,287 | 8,504 | (38) | 5,734 | 3,981 | 44 |
| Production mix | ||||||
| Crude oil and liquids (%) | 27 | 21 | 24 | 35 | ||
| Natural gas (%) | 73 | 79 | 76 | 65 |
Total and daily average production volumes in Q4 2024 decreased by 38 percent compared to the same period in 2023. This decline was primarily attributed to the flush production from the Cascadura-1ST1 and Cascadura Deep-1 wells which were brought online in September 2023. However, for the full year 2024, total and average daily commodity production volumes increased by 44 percent compared to 2023. This growth was driven by a full year of natural gas and associated liquids production from the Cascadura field.
Crude oil production
Crude oil production showed positive growth in 2024. Fourth quarter production increased by 16 percent, while annual production rose by 4 percent compared to the same periods in 2023. This growth was supported by:
- The CO-374 and CO-375 wells, which began production in late May 2024, contributing an aggregate field estimated 173 bbls/d and 107 bbls/d, respectively, during Q4 and the full year.
- The Balata East field acquired effective June 1, 2024 in exchange for the San Francisco property, which contributed 128 bbls/d during Q4 and 53 bbls/d for the year.
- Incremental production from the Cascadura-3ST1 well, which came online in November 2024, adding 72 bbls/d in Q4 and 19 bbls/d for the year.
These gains helped offset natural production declines and reduced production following the sale of the CO-2 property, effective August 1, 2024 (refer to the "Capital Acquisition and Dispositions" section of this MD&A for further information).
NGL production
NGL production experienced significant declines in 2024. Q4 2024 production decreased by 81 percent, while full-year production fell by 34 percent compared to 2023. This drop was primarily due to flush liquids production from the Cascadura-1ST1 and Cascadura Deep-1 wells in late 2023. The declines were partially offset by contributions from the Cascadura-2ST1 well, which began production in November 2024, adding approximately 103 bbls/d in Q4 2024 and 26 bbls/d for the full year.
TOUCHSTONE
2024 Management's Discussion and Analysis
Natural gas production
Natural gas production averaged 23.1 MMcf/d (3,856 boe/d) in Q4 2024, a 43 percent decrease from 40.5 MMcf/d (6,749 boe/d) in Q4 2023. This decline reflected the high flush production from the Cascadura-1ST1 and Cascadura Deep-1 wells in 2023, which declined throughout 2024. The decrease was slightly offset by incremental production from the Cascadura-2ST1 well, which added approximately 7.2 MMcf/d (1,203 boe/d) in Q4 2024 and 1.8 MMcf/d (302 boe/d) for the 2024 year.
For the year ended December 31, 2024, natural gas production averaged 26.3 MMcf/d (4,382 boe/d), a 69 percent increase compared to 15.6 MMcf/d (2,599 boe/d) in 2023. The significant annual growth was driven by a full year of production from the Cascadura field in 2024, compared to its limited production period in late 2023.
The following table summarizes crude oil and liquids production by property during the three months and years ended December 31, 2024 and 2023.
| (bbls) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| CO-1 | 40,773 | 30,989 | 32 | 146,191 | 125,556 | 16 |
| WD-4 | 39,959 | 39,048 | 2 | 163,909 | 156,928 | 4 |
| WD-8 | 14,706 | 19,856 | (26) | 70,103 | 83,594 | (16) |
| Balata East | 11,793 | - | 100 | 19,580 | - | 100 |
| Cascadura | 17,734 | 57,183 | (69) | 55,309 | 73,363 | (25) |
| Other minor fields | 6,609 | 14,387 | (54) | 39,534 | 65,041 | (39) |
| Crude oil and liquids production | 131,574 | 161,463 | (19) | 494,626 | 504,482 | (2) |
TOUCHSTONE
2024 Management's Discussion and Analysis
The following graphs disclose natural gas production by well during the three months and years ended December 31, 2024 and 2023.
Natural Gas Production by Well for the Three Months Ended December 31, 2024
Natural Gas Production by Well for the Three Months Ended December 31, 2023
Natural Gas Production by Well for the Year Ended December 31, 2024
Natural Gas Production by Well for the Year Ended December 31, 2023
Commodity prices
| Three months ended December 31, | % change | Year ended December 31, | % change | |||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Avg. benchmark prices(1) | ||||||
| Dated Brent ($/bbl) | 74.66 | 84.01 | (11) | 80.52 | 82.49 | (2) |
| WTI ($/bbl) | 70.27 | 78.32 | (10) | 75.72 | 77.62 | (2) |
| Average realized prices(2) | ||||||
| Crude oil ($/bbl) | 62.50 | 72.26 | (14) | 67.91 | 67.80 | - |
| NGLs ($/bbl) | 62.05 | 72.92 | (15) | 69.10 | 74.07 | (7) |
| Crude oil and liquids ($/bbl) | 62.47 | 72.49 | (14) | 68.03 | 68.72 | (1) |
| Natural gas ($/Mcf) | 2.50 | 2.43 | 3 | 2.48 | 2.36 | 5 |
| Realized commodity price(2) ($/boe) | 27.85 | 26.53 | 5 | 27.39 | 33.10 | (17) |
Notes:
(1) Average of the daily closing spot prices for a given product over the specified period. Source: US Energy Information Administration.
(2) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A.
TOUCHSTONE
2024 Management's Discussion and Analysis
Our crude oil and liquids prices received are based on quality differentials and international marketing arrangements and therefore are attributed to factors that are beyond our control. Realized prices are primarily driven by the Brent benchmark price, as Trinidad crude oil and liquids are exported for refining and classified as waterborne crude. We receive the same monthly average price for crude oil and NGL production through various marketing arrangements with Heritage.
The Dated Brent benchmark price of $74.66 per barrel in Q4 2024 represented a decrease of 11 percent from the prior year comparative quarter and a 7 percent decrease relative to the third quarter of 2024. During the quarter, weak economic data from key crude oil consuming regions continued to weigh on growth expectations, which was partially offset by several crude oil producing nations electing to defer previously planned production increases. On an annual basis, the Dated Brent benchmark price averaged $80.52 per barrel, representing a 2 percent decline from the 2023 year.
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Touchstone realized an average crude oil and liquids price of $62.47 per barrel in Q4 2024, down from $72.49 per barrel in the same quarter of 2023. The 14 percent decrease was driven by a 11 percent decline in Dated Brent reference pricing, coupled with a widening differential between our realized crude oil and liquids prices and Dated Brent benchmark pricing, which increased from 13.7 percent to 16.3 percent.
For the full year 2024, we achieved an average crude oil and liquids price of $68.03 per barrel, a slight 1 percent decline from $68.72 per barrel in 2023. While our price differential relative to Dated Brent narrowed from 16.7 percent in 2023 to 15.5 percent in 2024, realized NGL prices were 7 percent lower in 2024. This decline reflected the weighting of NGL sales toward Q4 2023, when Cascadura volumes came online.
We recorded average natural gas prices of $2.50 per Mcf in Q4 2024 and $2.48 per Mcf for the full year, an increase from the equivalent prior-year periods ($2.43 per Mcf in Q4 2023 and $2.36 per Mcf for the 2023 year). These increases were driven by higher heat values from Cascadura field production versus Coho field production, along with the annual 2 percent inflation escalator in our natural gas marketing contract. Touchstone also incurs a $0.125 per Mcf processing fee to the third-party natural gas facility operator for Coho natural gas volumes, which is netted against Coho natural gas sales and reflected in the realized prices reported.
TOUCHSTONE
2024 Management's Discussion and Analysis
12
Petroleum and natural gas sales
| ($000's unless otherwise stated) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Crude oil | 7,531 | 7,535 | - | 30,317 | 29,232 | 4 |
| NGLs | 688 | 4,170 | (84) | 3,331 | 5,434 | (39) |
| Natural gas | 5,324 | 9,054 | (41) | 23,822 | 13,432 | 77 |
| Petroleum and natural gas sales | 13,543 | 20,759 | (35) | 57,470 | 48,098 | 19 |
| Sales mix | ||||||
| Crude oil and liquids (%) | 61 | 56 | 59 | 72 | ||
| Natural gas (%) | 39 | 44 | 41 | 28 |
We sell all produced crude oil and NGL volumes to Heritage, with title transferring at our various sales batteries. As of December 31, 2024, we held approximately 3,838 barrels of crude oil and liquids inventory in comparison to 4,566 barrels as of December 31, 2023. We sell our Coho and Cascadura natural gas volumes to NGC, with title transferring at each processing facility.
In Q4 2024, petroleum and natural gas sales declined 13 percent to $13,543,000, down from $20,759,000 in the same quarter of 2023.
- Crude oil sales remained stable, as lower realized pricing was offset by increased production volumes.
- NGL sales for the quarter fell by $3,482,000, primarily due to natural declines in Cascadura natural gas volumes.
- Natural gas sales decreased by $3,730,000, with a $149,000 gain from higher realized pricing offset by a $3,879,000 decline attributed to lower sales volumes.
For the year ended December 31, 2024, petroleum and natural gas sales totaled $57,470,000, a substantial 19 percent increase from $48,098,000 in 2023.
- Crude oil sales rose by $1,085,000, with $49,000 reflecting higher average realized pricing and $1,036,000 driven by increased sales volumes.
- NGL sales from Cascadura natural gas production generated $3,331,000, down $2,103,000 from 2023, driven by a $240,000 decline in realized pricing and a $1,863,000 decrease from reduced production volumes.
- Natural gas sales increased by $10,390,000 over the prior year, with $1,155,000 driven by higher average prices and $9,235,000 attributed to increased sales volumes.
Petroleum and Natural Gas Sales
TOUCHSTONE
2024 Management's Discussion and Analysis
Royalty expense
Touchstone is obligated to pay a state royalty rate of 12.5 percent on all petroleum and natural gas production under MEEI and Heritage licences. For private leases, the Company incurs private royalties between 10 percent and 12.5 percent of crude oil sales.
In addition to state royalties, our LOAs with Heritage governing our CO-1, WD-4 and WD-8 blocks as well as our Balata East block EPSC apply a sliding scale overriding royalty ("ORR") structure indexed to the average price of crude oil realized in a production month. Base ORR rates are applicable to pre-defined monthly base production levels which decline by 2 percent per annum over the specific licence. For any monthly volumes sold in excess of base production levels, the Company incurs reduced enhanced ORR rates. For any production in excess of defined enhanced production levels, we incur super enhanced ORR rates which represent 50 percent of enhanced ORR rates.
The following table summarizes royalty rates attributable to our Heritage operating agreements based on monthly realized crude oil pricing received.
| Monthly realized oil price ($) | LOA Royalty Rates (%) | Balata East EPSC Royalty Rates (%) | ||||
|---|---|---|---|---|---|---|
| Base ORR | Enhanced ORR | Super Enhanced ORR | Base ORR | Enhanced ORR | Super Enhanced ORR | |
| 30.01 - 40.00 | 20.00 | 7.50 | 3.75 | 17.50 | 9.00 | 4.50 |
| 40.01 - 50.00 | 25.00 | 8.00 | 4.00 | 19.50 | 10.00 | 5.00 |
| 50.01 - 70.00 | 28.00 | 15.50 | 7.75 | 21.00 | 11.50 | 5.75 |
| 70.01 - 90.00 | 33.00 | 17.00 | 8.50 | 26.00 | 18.00 | 9.00 |
| 90.01 - 200.00 | 35.00 | 20.00 | 10.00 | 28.00 | 19.00 | 9.50 |
The following table sets forth royalty expense for the periods indicated.
| ($000's unless otherwise stated) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| State royalties | 1,692 | 2,605 | (35) | 7,142 | 5,886 | 21 |
| Overriding royalties | 1,479 | 1,642 | (10) | 6,556 | 6,003 | 9 |
| Private royalties | 34 | 77 | (56) | 178 | 284 | (37) |
| Royalty expense | 3,205 | 4,324 | (26) | 13,876 | 12,173 | 14 |
| $ per boe(1) | 6.59 | 5.53 | 19 | 6.61 | 8.38 | (21) |
| As a % of petroleum and natural gas sales(1) | 23.7 | 20.8 | 14 | 24.1 | 25.3 | (5) |
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
In the fourth quarter of 2024, royalty expenses decreased by 26 percent compared to the equivalent 2023 quarter, primarily due to lower natural gas and associated liquids sales from our Ortoire block and reduced Heritage ORR, driven by lower realized crude oil prices.
However, for the full year 2024, royalty expenses increased by 14 percent compared to 2023, mainly due to higher natural gas sales from our Cascadura and Coho fields, which are subject solely to a 12.5 percent state royalty. Additionally, Heritage ORR rose by 9 percent during the year ended December 31, 2024, compared to the prior year, reflecting increased production volumes. The increase was partially offset by lower realized crude oil prices and the corresponding impact on sliding scale royalty rates.
On a per boe basis and as a percentage of petroleum and natural gas sales, fourth quarter 2024 royalty expenses increased relative to the same period in 2023, reflecting a decline in production volumes.
TOUCHSTONE
2024 Management's Discussion and Analysis
Conversely, annual 2024 royalty expenses also decreased on a per-boe basis and as a percentage of sales compared to 2023, driven by higher production levels.
Royalty Expense
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Operating expense
| ($000's except per boe amounts) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Operating expense | 3,446 | 2,704 | 27 | 10,704 | 9,705 | 10 |
| $ per boe(1) | 7.09 | 3.46 | 100 | 5.10 | 6.68 | (24) |
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Operating expenses include all periodic lease, field-level, and transportation expenses, as well as directly attributable employee salaries and benefits. The Company's operating expense by product type are approximations prepared by Management, which require a number of assumptions to allocate these costs.
In Q4 2024, operating expenses increased by 27 percent compared to the same period in 2023, primarily due to an estimated $953,000 rise in crude oil and liquids-related expenses. This was driven by higher field maintenance costs in our crude oil-producing fields, including a $447,000 adjustment to historical LOA head license expenses. Q4 2024 natural gas operating expenses declined to approximately $577,000, down from $788,000 in Q4 2023. This $211,000 decrease was largely attributed to a non-routine Ortoire license production bonus recorded in the prior-year equivalent quarter.
For the year ended December 31, 2024, operating expense increased by 10 percent compared to 2023. This increase was primarily driven by a 22 percent rise in natural gas operating expenses and an 8 percent rise in crude oil and liquids expenses, both reflecting higher production levels.
Crude oil and liquids operating expenses for Q4 2024 averaged approximately $21.81 per barrel, a 50 percent increase from the same period in 2023, while full-year 2024 expenses averaged an estimated $17.39 per barrel, an 8 percent increase year-over-year. The fourth quarter increase was primarily due to lower Ortoire liquids production and the historical LOA head license charge, while the year-over-year
TOUCHSTONE
2024 Management's Discussion and Analysis
increase was driven by lower overall liquids production, which is impacted by fixed costs allocated over a lower production base.
Estimated operating expenses for natural gas production averaged $1.62 per boe in Q4 2024, a 28 percent increase from Q4 2023, while full-year 2024 expenses averaged $1.32 per boe, reflecting a 27 percent decline from 2023. The quarter-over-quarter increase was due to reduced production, whereas the annual decrease was driven by increased production following the commencement of Cascadura field operations in September 2024.
Operating Expense
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Operating netback
| Three months ended December 31, | % change | Year ended December 31, | % change | |||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| ($000's) | ||||||
| Petroleum and natural gas sales | 13,543 | 20,759 | (35) | 57,470 | 48,098 | 19 |
| Royalty expense | (3,205) | (4,324) | (26) | (13,876) | (12,173) | 14 |
| Operating expense | (3,446) | (2,704) | 27 | (10,704) | (9,705) | 10 |
| Operating netback(1) | 6,892 | 13,731 | (50) | 32,890 | 26,220 | 25 |
| ($/boe) | ||||||
| Realized commodity price(1) | 27.85 | 26.53 | 5 | 27.39 | 33.10 | (17) |
| Royalty expense(1) | (6.59) | (5.53) | 19 | (6.61) | (8.38) | (21) |
| Operating expense(1) | (7.09) | (3.46) | 100 | (5.10) | (6.68) | (24) |
| Operating netback(1) | 14.17 | 17.54 | (19) | 15.68 | 18.04 | (13) |
Note:
(1) Specified financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
TOUCHSTONE
2024 Management's Discussion and Analysis
Note:
(1) Specified financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
General and administration ("G&A") expense
| ($000's except per boe amounts) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Gross G&A expense | 2,596 | 2,518 | 3 | 10,614 | 10,278 | 3 |
| Capitalized G&A expense | (158) | (104) | 52 | (460) | (827) | (44) |
| G&A expense | 2,438 | 2,414 | 1 | 10,154 | 9,451 | 7 |
| $ per boe(1) | 5.01 | 3.09 | 62 | 4.84 | 6.50 | (26) |
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Gross G&A expenses for both Q4 2024 and the full year increased by 3 percent compared to the same periods in 2023. The increase was driven by higher insurance premiums, travel and information technology costs, partially offset by lower employee salaries and benefits, legal fees, and public company expenses.
Capitalized G&A expenses rose in Q4 2024 compared to the same period in 2023 but declined on an annual basis. Capitalization rates fluctuate based on employee hours allocated to capital projects.
In Q4 2024, G&A expenses averaged $5.01 per boe, a 62 percent increase from $3.09 per boe in Q4 2023, primarily reflecting a 38 percent decline in year-over-year production volumes. On an annual basis, G&A expenses per boe declined by 26 percent compared to 2023, as a 44 percent rise in production volumes in 2024 offset a 7 percent increase in total G&A expenditures.
TOUCHSTONE
2024 Management's Discussion and Analysis
General and Administration Expenses
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Net finance expense
| ($000's except per boe amounts) | Three months ended | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Interest income | - | (1) | 100 | (20) | (58) | (66) |
| Finance lease interest income | (5) | (9) | (44) | (26) | (43) | (40) |
| Lease liability interest | 145 | 84 | 73 | 415 | 287 | 45 |
| Bank debt interest | 627 | 564 | 11 | 2,387 | 2,221 | 7 |
| Accretion on bank debt | 26 | 8 | 100 | 67 | 15 | 100 |
| Finance expense | - | - | n/a | 18 | 114 | (84) |
| Other liability revaluation loss (gain) | - | 2 | (100) | - | (351) | (100) |
| Accretion on decommissioning liabilities | 60 | 69 | (13) | 226 | 257 | (12) |
| Other | (50) | - | n/a | (49) | 11 | n/a |
| Net finance expense | 803 | 717 | 12 | 3,018 | 2,453 | 23 |
| Cash net finance expense(1) | 768 | 638 | 20 | 2,775 | 2,533 | 10 |
| Non-cash net finance expense (income)(1) | 35 | 79 | (56) | 243 | (80) | n/a |
| Net finance expense | 803 | 717 | 12 | 3,018 | 2,453 | 23 |
| $ per boe(1) | 1.65 | 0.92 | 79 | 1.44 | 1.69 | (15) |
Note:
(1) Specified financial measure. Cash net finance expense and non-cash net finance expense (income) are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Net finance expenses for Q4 2024 totaled $803,000, compared to $717,000 in the same period of 2023. For the year ended December 31, 2024, net finance expenses amounted to $3,018,000, reflecting a $565,000 or 23 percent increase from $2,453,000 recognized in 2023.
Relative to Q4 2023, 2024 fourth quarter cash finance expenses increased by $130,000. The increase was primarily driven by higher bank interest expenses due to increased weighted average debt balances and
TOUCHSTONE
2024 Management's Discussion and Analysis
higher lease liability expenses. On an annual basis, cash finance expenses rose by $242,000 compared to 2023. This increase was largely due to higher bank interest expenses and lease liability expenses, which fully offset the impact of the debt issuance expense recorded in 2023. For further details, refer to the "Liquidity and Capital Resources - Bank Debt" section of this MD&A.
Bank Debt and Interest Expense
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 was revalued at each reporting period based on changes to internally forecasted petroleum and natural gas production and forward product pricing. During the 2023 year, the production liability was repaid and extinguished. The Company recognized a revaluation loss of $2,000 and an aggregate revaluation gain of $351,000 in connection with the former obligation during the three months and year ended December 31, 2023, respectively.
Transaction expense
In connection with the terminated acquisition of Trinity, we incurred $1,957,000 in transaction expenses in the 2024 year. In addition, we incurred $66,000 in transaction costs pursuant to the Proposed Acquisition during the three months and year ended December 31, 2024.
Exploration expense
Touchstone incurred $17,000 and $248,000 in exploration expenses during the three months and year ended December 31, 2024, respectively (2023 - $nil and $nil). The costs related to ongoing lease maintenance expenditures in the Royston exploration area of the Ortoire block.
Foreign exchange and foreign currency translation
Touchstone's presentation currency is the United States dollar. Our parent company has a Canadian dollar functional currency while our Trinidadian subsidiaries have Trinidad and Tobago dollar functional currencies. In each reporting period, the change in values of the C$ and TT$ relative to the US$ reporting currency are recognized.
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2024 Management's Discussion and Analysis
19
The applicable foreign exchange ("FX") rates used to translate our TT$ and C$ denominated items are set forth in the following table.
| Applicable FX rates | Three months ended December 31, | Year ended December 31, | % change | |||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| US$:C$ average FX rate(1) | 1.399 | 1.361 | 3 | 1.370 | 1.350 | 1 |
| US$:TT$ average FX rate(2) | 6.750 | 6.751 | - | 6.749 | 6.750 | - |
| December 31, 2024 | September 30, 2024 | December 31, 2024 | December 31, 2023 | % change | ||
| US$:C$ closing FX rate(1) | 1.440 | 1.353 | 6 | 1.440 | 1.325 | 9 |
| US$:TT$ closing FX rate(2) | 6.747 | 6.739 | - | 6.747 | 6.716 | - |
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 months and year ended December 31, 2024, the C$ depreciated 3 percent and 1 percent relative to the US$, respectively, in comparison to the corresponding average rates observed in the 2023 equivalent periods. Relative to the US$, the TT$ remained range bound during the three months and years ended December 31, 2024 and 2023. In aggregate, we recorded foreign exchange gains of $105,000 and $54,000 during the three months and year ended December 31, 2024, respectively (2023 - gains of $129,000 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 6 percent weaker on December 31, 2024 versus September 30, 2024 and 9 percent weaker in comparison to the corresponding rate on December 31, 2023. In comparison to the US$, the TT$ remained consistent over the corresponding periods. We recognized foreign currency translation losses of $483,000 and $758,000 during the three months and year ended December 31, 2024, respectively (2023 - gains of $368,000 and $393,000).
Share-based compensation
For a full description of our share-based compensation plans, refer to Note 19 "Share-based Compensation Plans" of our audited financial statements.
Touchstone has a stock option plan (the "Legacy Stock Option Plan") pursuant to which options to purchase common shares of the Company were granted by the Board to directors, officers, and employees of Touchstone. Touchstone adopted an omnibus incentive compensation plan in June 2023 (the "Omnibus Plan") which replaced the Legacy Stock Option Plan and was adopted to allow the Company to award stock options, restricted share units ("RSUs") and performance share units ("PSUs") to our directors, officers, employees and consultants.
Stock option plans
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. As of December 31, 2024,
TOUCHSTONE
2024 Management's Discussion and Analysis
Touchstone had an aggregate 11,731,000 stock options outstanding under both plans (2023 - 14,327,935). No stock options were granted under either plan in 2024, and 247,935 stock options were exercised by Company directors, officers and employees in 2024.
Long-term incentive plans
As of December 31, 2024 Touchstone had 1,447,780 RSUs and 1,397,780 PSUs outstanding under its Omnibus Plan which were granted in July 2024 (2023 - nil and nil). The RSUs vest one third on each of the next three anniversaries of the grant date and the number of share awards are fixed. The PSUs vest on July 12, 2027, and the number of share awards are variable based on predefined corporate performance measures. Each award may, in the Board's sole discretion, entitle the holder to be issued the number of Company common shares designated in the award or receive a payment in cash. All RSUs and PSUs are currently accounted for as cash settled, with the obligation accrued as an expense over the vesting period based on the fair value of the awards, being the underlying share price at each financial period end.
The Company offers a deferred share unit plan to non-employee directors. As of December 31, 2024, 977,332 deferred share units ("DSUs") were outstanding (2023 - nil). The DSUs fully vest on the grant date but are only available for redemption when the director ceases to be a member of the Board. The fair value of the cash settled DSUs was equal to the underlying share price on the grant date and are subsequently adjusted to the underlying share price at each financial period end.
The following table sets forth share-based compensation expense recorded in relation to issued awards pursuant to our share-based compensation plans for the periods indicated.
| ($000's) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Share-settled compensation | 165 | 418 | (61) | 1,133 | 1,381 | (18) |
| Cash-settled compensation | (21) | - | n/a | 528 | - | n/a |
| Capitalized expense | (16) | - | n/a | (72) | (138) | (48) |
| Share-based compensation expense | 128 | 418 | (69) | 1,589 | 1,243 | 28 |
Share-based compensation expense recognized during the three months and year ended December 31, 2024 was $128,000 and $1,589,000, respectively (2023 - $418,000 and $1,243,000).
Share settled share-based compensation expense relates to options issued under both the Legacy Plan and the Omnibus Plan. This expense decreased for both the three months and year ended December 31, 2024, compared to the same periods in 2023, as no stock options were granted in 2024. As of December 31, 2024, approximately 71 percent of outstanding options were vested, compared to 53 percent as of December 31, 2023.
Cash settled share-based compensation expense pertains to the Company's cash-settled long-term incentive plans and includes both cash or share settled RSUs and PSUs, and cash-settled DSUs. A reversal of $21,000 in cash-settled compensation expense was recorded in the fourth quarter of 2024 based on a decrease in the Company's share price from September 30, 2024. For the year ended December 31, 2024, we recognized an aggregate expense of $528,000 for the inaugural share awards granted in July 2024.
As at December 31, 2024, the Company recognized a $500,000 share-based compensation liability pursuant to our share awards and DSU compensation plans, with $383,000 classified as current and included in accounts payable and accrued liabilities on the consolidated balance sheet (2023 - $nil and $nil).
TOUCHSTONE
2024 Management's Discussion and Analysis
Depletion and depreciation expense
| ($000's except per boe amounts) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Depletion expense | 2,715 | 1,803 | 51 | 7,622 | 4,975 | 53 |
| Depreciation expense | 236 | 182 | 30 | 1,879 | 1,034 | 82 |
| Depletion and depreciation expense | 2,951 | 1,985 | 49 | 9,501 | 6,009 | 58 |
| Depletion expense per boe(1) | 5.58 | 2.30 | 100 | 3.63 | 3.42 | 6 |
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Our petroleum and natural gas producing development assets included in property, plant and equipment ("PP&E") are subject to depletion expense. The net carrying values of our producing development assets are depleted using the unit of production method by reference to the ratio of production in the period over the related proved plus probable reserves, while also considering the estimated future development costs necessary to bring those reserves into production. Depletion expenses fluctuate based on the amount and type of capital spending, the recognition or reversal of development asset impairments, any changes in the quantity of reserves or future development costs, and production volumes. As at December 31, 2024, $167,989,000 in future development costs were included in development asset cost bases for depletion calculation purposes (2023 - $105,252,000).
For the three months and year ended December 31, 2024, depletion expenses related to petroleum and natural gas development assets within PP&E rose by 51 percent and 53 percent, respectively, compared to the same periods in 2023. The increases were primarily driven by lower assigned reserves, higher future development costs, and increased production from the Cascadura field.
On a per boe basis, depletion rates increased by 143 percent in Q4 2024 and 6 percent for the full year, relative to 2023. The Q4 2024 increase was mainly due to a 38 percent drop in production volumes, coupled with reserve reductions and higher development costs. The annual increase in 2024 reflected a smaller reserve base and elevated development costs, partially offset by a 44 percent increase in annual production.
Assets in the E&E phase are not amortized. Depreciation expense for corporate assets is recorded using the declining balance method, while right-of-use ("ROU") assets are depreciated on a straight-line basis over their estimated useful lives.
The increases in depreciation expense reported during the three months and year ended December 31, 2024 relative to the equivalent 2023 periods reflected higher net asset carrying values associated with ROU assets, as well as an increase in depreciation of drilling rig mobilization expense which were recorded when the associated drilling rig was in use in the first quarter of 2024.
Impairment of non-financial assets
Entities are required to conduct an impairment test where there is an indication of impairment or reversal of a non-financial asset. Impairment is recognized when the carrying value of an asset or group of assets exceeds its recoverable amount, defined as the higher of its value in use or fair value less costs of disposal. Any asset impairment that is recorded is recoverable to its original value less any associated depletion and depreciation expense should there be indicators that the recoverable amount of the asset has increased in value since the time of recording the initial impairment. Touchstone assesses E&E asset and PP&E indicators of impairment and impairment reversal on each reporting date.
TOUCHSTONE
2024 Management's Discussion and Analysis
Exploration and evaluation ("E&E") asset impairment
E&E asset impairment expense by operating area for the specified periods are disclosed in the following table.
| Operating Area ($000's) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Cory Moruga | (7) | 19 | n/a | (63) | 66 | n/a |
| Ortoire | 2,310 | 32,649 | (93) | 2,385 | 32,649 | (93) |
| E&E asset impairment expense | 2,303 | 32,668 | (93) | 2,322 | 32,715 | (93) |
During the three months and year ended December 31, 2024, we recognized E&E asset impairment reversals of $7,000 and $63,000, respectively, primarily related to decommissioning asset changes in the previously impaired Cory Moruga block (2023 - expenses of $19,000 and $66,000). The Company's non-operated interest in the Cory Moruga licence was disposed during the year ended December 31, 2024 (refer to the "Capital Acquisitions and Dispositions" section of this MD&A for further information).
We concluded that there were indicators of impairment within the Ortoire E&E asset operating area at December 31, 2024 as a result of aligning future exploration activities with the Company's long-term priorities. We performed an impairment test that concluded that the recoverable amount of the asset was not sufficient to support its carrying value, which resulted in a pre-tax impairment expense of $2,385,000 recorded at December 31, 2024 (2023 - $32,649,000).
As a result of allocating future capital spending to align with the Company's long-term priorities and the results of production tests which deemed the Royston-1X well uneconomic, indicators of impairment were noted in the Ortoire operating area as at December 31, 2023. The Company performed an impairment test which concluded that the recoverable amount of the area was not sufficient to support its carrying value, resulting in an aggregate pre-tax impairment expense of $32,649,000 recorded at December 31, 2023.
PP&E impairment
The following table discloses PP&E impairment expense (reversal) by CGU for the specified periods.
| CGU ($000's) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Coho | (137) | 143 | n/a | (137) | 143 | n/a |
| CO-1/CO-2 | - | (13,865) | (100) | 474 | (13,865) | n/a |
| Fyzabad | - | 2,270 | (100) | - | 2,270 | (100) |
| PP&E impairment (reversal) expense | (137) | (11,452) | (99) | 337 | (11,452) | n/a |
We performed an impairment test on our CO-2 property prior to transferring the assets and related liabilities to held for sale on March 31, 2024. The impairment test determined that the fair value of the property's associated net assets was not sufficient to support its carrying value, which resulted in a pre-tax impairment expense of $474,000 recorded during the year ended December 31, 2024 (refer to the "Capital Acquisitions and Dispositions" section of this MD&A for further information).
On December 31, 2024, 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, the following indicators of potential impairment were identified for the specific CGUs.
- Cascadura CGU - based on a reduction of assigned reserves from negative technical revisions due to well performance along with material increases in future development costs.
TOUCHSTONE
2024 Management's Discussion and Analysis
- Coho CGU - based on a reduction of assigned reserves from negative technical revisions attributed to well performance.
Impairment tests were conducted to estimate the recoverable amounts of both CGUs, confirming that the Cascadura and Coho CGUs exceeded their respective carrying values. As a result, a pre-tax impairment reversal of $137,000 was recognized for the Coho CGU at December 31, 2024, as it had been previously impaired in 2023. No impairment reversal was recorded for the Cascadura CGU, as it had not been previously impaired.
On December 31, 2023, 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, Touchstone recognized an aggregate pre-tax impairment expense of $2,413,000 related to the Coho and Fyzabad CGUs and a pre-tax impairment reversal of $13,865,000 associated with the CO-1/CO-2 CGU. In addition, we recorded an impairment expense of $126,000 related to slow moving oilfield capital inventory not assigned to a specific CGU during the year ended December 31, 2023.
Calculating E&E asset and petroleum and natural gas development asset CGU recoverable amounts involves several assumptions and estimates which are subject to estimation uncertainty, as well as a significant degree of judgement. The estimated recoverable amounts of Touchstone's PP&E CGUs at December 31, 2024 and 2023 were determined using value in use calculations incorporating discounted after-tax cash flows of proved plus probable reserves using forward crude oil and natural gas prices and cost estimates as assessed by the Company's independent qualified reserves evaluator. Discounted future cash flows for each CGU were determined by applying an after-tax 20 percent discount rate. Inputs used in the measurement of estimated recoverable amounts were not based on market data and fall within level 3 of the fair value hierarchy.
As future commodity prices remain volatile, impairments or impairment reversals could be recorded in future periods. Changes in any of the key judgements, such as revisions in reserves, forecasted production, forecasted commodity prices, inflation rates, operating and future development expenditures, future tax rates and/or after-tax discount rates would impact the estimated recoverable amounts. Further information regarding impairments recorded during the years ended December 31, 2024 and 2023 and their related measurement uncertainty is included in Note 9 "Impairment" of our audited financial statements.
Other expense
In the fourth quarter of 2022 we filed a claim through our general and pollution liability policy relating to a crude oil spill in June 2022. In 2023, Touchstone received aggregate insurance proceeds of $552,000 during the year ended December 31, 2023 from the claim.
Income taxes
Current income tax
The Company's two Trinidad exploration and production subsidiaries are subject to the following Trinidad petroleum taxes:
- Supplemental Petroleum Tax 18 percent of gross liquids revenue less related royalties
- Petroleum Profits Tax ("PPT") 50 percent of net taxable profits
- Unemployment Levy ("UL") 5 percent of net taxable profits
- Green Fund Levy ("GFL") 0.3 percent of gross revenue
SPT is levied on a quarterly basis and is applicable to crude oil and liquids volumes. Actual rates vary based on the average realized selling prices of crude oil and liquids in the applicable quarter. The SPT rate is zero when the weighted average realized price of crude oil and liquids for a given quarter is below $75.00 per
TOUCHSTONE
2024 Management's Discussion and Analysis
24
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. Our Ortoire property is not considered a mature oilfield, and thus no capital spending investment tax credits are applicable.
PPT and UL taxes are levied on an annual basis and are calculated based on net taxable profits. Net taxable profits are determined by calculating gross revenue less: royalty expense, SPT paid during the year, capital allowances, operating expense, G&A expense, 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.
Our Trinidad oilfield service subsidiary, which primarily leases oilfield service equipment to a third-party contractor supporting our exploration and production operations, is subject to the greater of a 30 percent corporate income tax on net taxable profits or a 0.6 percent business levy on gross revenue. The subsidiary is also subject to the GFL, as disclosed above. Corporate income tax losses can be carried forward indefinitely, with capital expenditure allowances ranging from 10 percent to 33.3 percent, depending on the nature of the investment.
In addition, our Trinidad-based subsidiaries incur a 10 percent withholding tax on intercompany interest payments from our Canadian head office.
The following table sets forth current income tax expense for the periods indicated.
| ($000's except per boe amounts) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| SPT | - | - | - | - | 234 | (100) |
| PPT | (127) | (5) | (100) | 6 | 376 | (98) |
| UL | (50) | (2) | (100) | 1 | 150 | (99) |
| Other | 268 | 227 | 18 | 1,154 | 346 | 100 |
| Current income tax expense | 91 | 220 | (59) | 1,161 | 1,106 | 5 |
| $ per boe(1) | 0.19 | 0.28 | (32) | 0.55 | 0.76 | (28) |
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
For the three months ended December 31, 2024, the Company recorded a current income tax expense of $91,000, compared to $220,000 in the same period of 2023. The decrease was primarily driven by lower net taxable profits in Trinidad, partially offset by higher withholding taxes on intercompany transactions.
For the 2024 year, the Company recognized a current income tax expense of $1,161,000, up from $1,106,000 in 2023. The year-over-year increase was mainly due to higher withholding taxes, partially offset by lower net taxable profits in Trinidad and the absence of SPT expenses in 2024.
TOUCHSTONE
2024 Management's Discussion and Analysis
TOUCHSTONE
2024 Management's Discussion and Analysis
26
Current Income Tax Expense
Note:
(1) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
Deferred income tax
Touchstone's $17,924,000 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 December 31, 2024 (2023 - $21,433,000). 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 within PP&E.
For the three months and year ended December 31, 2024, we recognized deferred income tax recoveries of $1,227,000 and $3,405,000, respectively, compared to deferred income tax expenses of $8,009,000 and $6,779,000 in the same periods of 2023. The 2024 deferred tax recoveries were primarily driven by an increase in non-capital loss carryforwards and a reduction in the variance between the carrying amounts of PP&E and their income tax basis, partially offset by a decrease in deductible interest reserves. In contrast, the 2023 deferred tax expenses were mainly due to PP&E impairment reversals recognized as of December 31, 2023, which increased the difference between the PP&E carrying values and their respective income tax bases.
Further information regarding our current and deferred income taxes is included in Note 21 "Income Taxes" of our audited financial statements.
Net earnings (loss)
We recorded a net loss of $542,000 ($0.00 per basic share) in the fourth quarter of 2024 compared to a net loss of $21,236,000 ($0.09 per basic share) in the prior year equivalent quarter.
Touchstone recognized net earnings of $8,272,000 ($0.04 per basic share and $0.03 per diluted share) in 2024 in comparison to a net loss of $20,598,000 ($0.09 per basic share) recorded in the 2023 year.
The following table sets forth details of the change in net earnings from the three months and year ended December 31, 2023 to the three months and year ended December 31, 2024.
| ($000's) | Three months ended December 31, | Year ended December 31, |
|---|---|---|
| Net loss – 2023 | (21,236) | (20,598) |
| Cash items | ||
| Funds flow from operations | (6,875) | 3,018 |
| Decommissioning expenditures | - | 1 |
| Cash variances | (6,875) | 3,019 |
| Non-cash items | ||
| Non-cash finance expense | 44 | (323) |
| Gain on asset dispositions | (104) | 1,413 |
| Unrealized foreign exchange | (107) | (315) |
| Share-based compensation expense | 290 | (346) |
| Depletion and depreciation expense | (966) | (3,492) |
| Impairment | 19,176 | 18,730 |
| Deferred income tax | 9,236 | 10,184 |
| Non-cash variances | 27,569 | 25,821 |
| Net (loss) earnings – 2024 | (542) | 8,272 |
Cash from operating activities
The following table details the change in cash from operating activities from the three months and year ended December 31, 2023 to the three months and year ended December 31, 2024.
| ($000's) | Three months ended December 31, | Year ended December 31, |
|---|---|---|
| Cash from operating activities – 2023 | 8,512 | 12,743 |
| (Decrease) increase in funds flow from operations | (6,875) | 3,018 |
| Net decrease in non-cash working capital | (815) | (2,580) |
| Cash from operating activities – 2024 | 822 | 13,181 |
Funds flow from operations
Funds flow from operations is included in the Company's consolidated statements of cash flows. Touchstone considers funds flow from operations to be a key measure of operating performance as it demonstrates the Company's ability to generate the funds necessary to finance capital expenditures and repay debt. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, funds flow from operations provides a useful measure of the Company's ability to generate cash that is not subject to short-term movements in non-cash operating working capital.
In Q4 2024, we generated funds flow from operations of $3,614,000, a decrease of $6,875,000 or 66 percent compared to the $10,489,000 reported in the same quarter of 2023. The decline was primarily due to lower operating netbacks resulting from a 38 percent reduction in production volumes.
On an annual basis, funds flow from operations totaled $16,748,000 in 2024, up from $13,730,000 in 2023. The year-over-year increase was driven by higher operating netbacks, largely attributed to a full year of Cascadura operations, partially offset by transaction expenses incurred during 2024.
TOUCHSTONE
2024 Management's Discussion and Analysis
The following graphs summarize the change in funds flow from operations from the three months and year ended December 31, 2023 to the three months and year ended December 31, 2024.
Change in Funds Flow From Operations
Three Months Ended December 31
Change in Funds Flow From Operations
Year Ended December 31
TOUCHSTONE
2024 Management's Discussion and Analysis
28
Net earnings and funds flow from operations sensitivity
The following table illustrates sensitivities of operating items to operational and business environment changes and the resulting estimated impact to net earnings and funds flow from operations for the year ended December 31, 2024.
| Assumption(1) | Change | Impact on annual net earnings(2) ($000's) | Impact on annual funds flow from operations(2) ($000's) | |
|---|---|---|---|---|
| Business environment | ||||
| Crude oil price ($/bbl)(3)(4) | 67.91 | 10% | 611 | 1,154 |
| Crude oil price ($/bbl)(3)(4) | 67.91 | -10% | (1,127) | (1,991) |
| NGL price ($/bbl)(3)(4) | 69.10 | 10% | (36) | (36) |
| NGL price ($/bbl)(3)(4) | 69.10 | -10% | (291) | (291) |
| Interest rate on revolving debt (%)(5) | 7.36 | ±0.5 | (32) | (63) |
| Common share price (C$) | 0.46 | ±0.05 | (134) | - |
| Operational | ||||
| Crude oil and liquids production (bbls/d) | 1,352 | ±5% | 427 | 1,141 |
| Natural gas production (Mcl/d) | 26,290 | ±5% | 874 | 1,031 |
| Royalty expense ($/boe)(3) | 6.61 | ±5% | (458) | (694) |
| Operating expense ($/boe)(3) | 5.10 | ±5% | (382) | (535) |
| G&A expense ($/boe)(3) | 4.84 | ±5% | (446) | (508) |
Notes:
(1) Assumptions are indicative of actual prices and volumes realized and actual results for the year ended December 31, 2024. The Company's natural gas sales price was fixed and thus excluded from this sensitivity analysis.
(2) Calculations are estimates, are performed independently and will not be indicative of actual results that would occur when multiple variables change concurrently. Calculations are performed prior to the impact of non-financial asset impairment tests.
(3) Supplementary financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
(4) Variances are not similar due to the punitive effects of SPT (refer to the "Financial and Operational Results - Income taxes" section of this MD&A for further information).
(5) The interest rate on the Company's term loan 1 facility is fixed and thus excluded from this sensitivity analysis. The interest rate on the Company's term loan facility 2 (as defined herein) and revolving loan facility is fixed on an annual basis. The calculation assumes that rate changed by 50 basis points as of the respective determination dates (refer to the "Liquidity and Capital resources - Bank debt" section of this MD&A for further information).
Capital Expenditures
E&E asset expenditures
E&E asset expenditures include asset additions in areas that have been determined to be in the exploration phase, which include the Company's interests in the Charuma, Cipero, Ortoire and Rio Claro blocks. E&E asset expenditures during the respective periods are summarized in the following table.
| ($000's) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Licence financial obligations | 426 | 72 | 100 | 973 | 296 | 100 |
| Drilling, completions and well testing | - | 436 | (100) | 73 | 8,678 | (99) |
| Equipment and facilities | - | - | - | - | 7,709 | (100) |
| Capitalized G&A | - | 95 | (100) | - | 559 | (100) |
| Other | - | (8) | (100) | - | 396 | (100) |
| E&E asset expenditures | 426 | 595 | (28) | 1,046 | 17,638 | (94) |
TOUCHSTONE
2024 Management's Discussion and Analysis
E&E asset expenditures for the fourth quarter and full year 2024 totaled $426,000 and $1,046,000, respectively, primarily reflecting financial obligations related to our exploration licenses.
In 2023, our capital program was exclusively focused on exploration activities at the Ortoire property, with investments totaling $595,000 in Q4 and $17,638,000 for the full year. Fourth quarter investments included two production tests on the Royston-1X sidetrack well, which was drilled in the first quarter of 2023, bringing the total number of tests completed in the year to five. Of our annual 2023 E&E investments, $7,709,000 was allocated to the construction and commissioning of the Cascadura natural gas and liquids facility, which commenced operations in September 2023. Upon first production, the carrying value of the Cascadura field was transferred from E&E assets to PP&E.
PP&E expenditures
| ($000's) | Three months ended December 31, | % change | Year ended December 31, | % change | ||
|---|---|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |||
| Drilling and completions | 1,556 | 386 | 100 | 14,299 | 593 | 100 |
| Equipment and facilities | 845 | 177 | 100 | 6,419 | 177 | 100 |
| Capitalized G&A | 158 | 9 | 100 | 460 | 268 | 72 |
| Corporate and other | 121 | 19 | 100 | 1,455 | 273 | 100 |
| PP&E expenditures | 2,680 | 591 | 100 | 22,633 | 1,311 | 100 |
PP&E expenditures for the fourth quarter and annual 2024 periods totaled $2,680,000 and $22,633,000, respectively, as our capital program remained primarily focused on development activities within the Cascadura field. Fourth quarter investments included construction of the Cascadura B lease, completion of the flowline from the Cascadura C surface location to the Cascadura natural gas processing facility, and drilling inventory. For the full year, we drilled two Cascadura development wells and two development wells on our CO-1 block and installed key infrastructure upgrades and flow lines at our Cascadura plant.
In contrast, PP&E expenditures in 2023 were minimal, as the capital program was primarily focused on Ortoire exploration activities. Investments for the year included eight well recompletions, final Cascadura facility commissioning costs, pre-drill expenditures for the Cascadura-2 development well, and enhancements to corporate information technology infrastructure.
Capital Expenditures(1)
Note:
(1) Specified financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
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2024 Management's Discussion and Analysis
30
Capital Acquisitions and Dispositions
Acquisition
Effective June 1, 2024, the Company closed an asset swap transaction with a third party. Touchstone swapped its 100 percent working interest in a non-core privately leased San Francisco property for the counterparty's 100 percent working interest in a licence with Heritage governing the Balata East block. In connection with the transaction, Touchstone recorded a $1,434,000 gain on acquisition during the year ended December 31, 2024, which represented the excess of the $237,000 total identifiable net assets acquired over the $1,197,000 net liabilities of the assets disposed.
Dispositions
In March 2024 we executed a definitive sales and purchase agreement with a third party to dispose of our interest in the CO-2 block for aggregate consideration of approximately $1,066,000. The disposition closed effective August 1, 2024. The transaction resulted in a pre-tax impairment expense of $474,000 and no gain or loss on disposition during the year ended December 31, 2024.
In May 2024, we entered into a sales and purchase agreement to dispose of our non-operated 16.2 percent interest in a previously impaired E&E property with the third-party operator for the counterparty's assumption of approximately $779,000 in aggregate decommissioning and accrued liabilities. The disposition closed in September 2024, with a $779,000 gain on asset disposition recorded during the year ended December 31, 2024.
Further information regarding asset acquisitions and dispositions is included in Note 8 "Property, Plant and Equipment" of our audited financial statements.
Decommissioning Liabilities and Abandonment Funds
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, we are obligated to remit $0.25 per boe sold into an escrow account in the name of the MEEI. The payments are used as a contingency fund for remediation of pollution arising from petroleum operations conducted under the relevant licence and the eventual abandonment of wells and decommissioning of facilities used for operations conducted under the relevant licence. The MEEI shall return the funds in the escrow account once all obligations in respect of environmental remediation are fulfilled to their satisfaction. Contributions to the fund are reflected on the consolidated balance sheet as non-current abandonment fund assets.
With respect to well decommissioning liabilities associated with our Heritage operating agreements, we are responsible for our proportional share of all well abandonment costs, calculated based on our percentage of crude oil sold from a well relative to its cumulative historical production. Touchstone is not responsible for the decommissioning of existing infrastructure and sales facilities. We are required to remit $0.25 per barrel and $1.00 per barrel sold to Heritage into joint well abandonment funds under our LOAs and our Balata East EPSC, respectively. These funds are used solely for well decommissioning. Any costs of wells that are abandoned during the relevant licence term are credited against any future contributions of the well abandonment fund. Upon expiration of the relevant agreement, Heritage shall calculate our total abandonment liability. If our liability exceeds the well abandonment fund, we are obligated to pay the difference. Conversely, if the proceeds of the fund exceed the liability, the surplus shall be returned to Touchstone. These amounts are also recognized as long-term abandonment fund assets on the consolidated balance sheet.
TOUCHSTONE
2024 Management's Discussion and Analysis
As of December 31, 2024 we reported $2,965,000 of accrued or paid contributions into MEEI and Heritage abandonment funds as non-current abandonment fund assets (2023 - $2,081,000).
Under our Heritage operating agreements, we fund Heritage's $0.25 per barrel obligation with respect to Heritage's head licence commitments with the MEEI. As the Company cannot access the contributions for our future well abandonments, the payments are included in operating expense as incurred. Additionally, we are further obligated to remit $0.03 per barrel to Heritage into a general abandonment fund. The non-refundable proceeds are used as a contingency fund for the decommissioning and removal of infrastructure and facilities within a field and are expensed to operating expense as incurred.
We are responsible for all site restoration, well abandonment costs and removal of infrastructure and facilities used in petroleum operations conducted on our private production and exploration agreements.
Touchstone estimated the net present value of the cash flows required to settle decommissioning liabilities to be $9,985,000 at December 31, 2024 compared to $9,733,000 as of December 31, 2023. December 31, 2024 decommissioning liabilities were estimated using a weighted average long-term risk-free rate of 5.5 percent and a long-term inflation rate of 1.9 percent (2023 - 5.3 percent and 2.1 percent, respectively). $60,000 and $226,000 of accretion expenses were recognized during the three months and year ended December 31, 2024, respectively, to reflect the increase in decommissioning liabilities associated with the passage of time (2023 - $69,000 and $257,000).
Decommissioning liability details as at and during the year ended December 31, 2024 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) |
|---|---|---|---|---|
| 593.6 | 4.4 | 13,053 | 15,197 | 9,985 |
Change in Decommissioning Liability
Year Ended December 31
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 14 "Decommissioning Liabilities and Abandonment Fund" of our audited financial statements.
TOUCHSTONE
2024 Management's Discussion and Analysis
Liquidity and Capital Resources
Liquidity
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. Exploration and development activities are anticipated to be financed with a combination of funds flow from operations and other sources of capital. We use shareholders' equity and bank debt as our primary sources of capital.
As at December 31, 2024, we had a cash balance of $6,744,000, a working capital deficit of $1,359,000, a principal long-term bank debt balance of $27,750,000 and no further borrowing capacity under our revolving loan (refer to the "Bank Debt" section below). As at December 31, 2024, we continued to have a working capital deficit, primarily from our 2024 Cascadura field drilling and infrastructure related capital investments. The following table summarizes our changes in cash during the specified periods.
| ($000's) | Three months ended December 31, 2024 | Year ended December 31, 2024 |
|---|---|---|
| Net cash from (used in): | ||
| Operating activities | 822 | 13,181 |
| Investing activities | (3,479) | (20,620) |
| Financing activities | 2,811 | 5,935 |
| Increase (decrease) in cash | 154 | (1,504) |
| Cash, beginning of period | 6,549 | 8,186 |
| Impact of FX on cash balances | 41 | 62 |
| Cash, end of period | 6,744 | 6,744 |
Our principal near term strategy is to increase cash flow generation via the development of our Cascadura field in 2025. We will continue to take a measured approach to future developmental and exploration capital expenditures to manage financial liquidity while proceeding with this plan.
Bank debt
On April 18, 2024, the Company and its Trinidad based lender executed a Third Amended and Restated Loan Agreement, (the "Loan Agreement"), providing for a new $10 million five-year non-revolving term loan facility ("term loan facility 2") and an increase to the existing revolving loan facility borrowing capacity from $7 million to $10 million. In addition, the revolving loan was extended by a two-year period through May 31, 2026, and may be renewed by additional two-year periods by agreement between the parties. The Company withdrew the full amount of the $10 million term loan facility 2 on May 1, 2024.
As at December 31, 2024, the Company had $35,000,000 in aggregate principal bank debt outstanding, with $7,250,000 classified as current on the consolidated balance sheet (December 31, 2023 - $28,000,000 and $13,000,000, respectively).
Details of the facilities pursuant to the Loan Agreement are set forth below.
| Facility | Term loan facility 1 | Term loan facility 2 | Revolving loan |
|---|---|---|---|
| Amount | $30,000,000 | $10,000,000 | $10,000,000 |
| Maturity date | June 15, 2027 | April 30, 2029 | May 31, 2026 - the parties have the option to extend by additional two-year periods |
| Interest rate | 7.85 percent per annum | 7.49 percent through April 2025 - reset annually | 7.23 percent through May 2025 - reset annually |
TOUCHSTONE
2024 Management's Discussion and Analysis
| Facility | Term loan facility 1 | Term loan facility 2 | Revolving loan |
|---|---|---|---|
| Interest payments | Payable quarterly in arrears | Payable monthly in arrears | Payable monthly in arrears |
| Principal payments | Twenty $1.5 million quarterly payments from September 15, 2022 to June 15, 2027; additional principal may be repaid with no penalty | Sixteen $625,000 quarterly payments from July 31, 2025 to April 30, 2029; additional principal may be repaid with a 1 percent penalty during the initial three years | Principal may be repaid at any time, on or before the maturity date without penalty and any amounts repaid may be redrawn at any time |
| December 31, 2024 principal balance | $15,000,000 | $10,000,000 | $10,000,000 |
| December 31, 2024 available credit capacity | $nil | $nil | $nil |
The 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 our two Trinidad upstream oil and gas subsidiaries. The Loan Agreement contains industry standard representations and warranties, undertakings, events of default, and financial covenants assessed on an annual basis.
Under the Loan Agreement, a failure of any covenant constitutes an event of default, upon where 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. The following table lists the financial covenants applicable on a consolidated basis as of December 31, 2024, all of which are evaluated on an annual basis.
| Financial covenant description | Limit | Year ended December 31, 2024 |
|---|---|---|
| Net senior funded debt(1) to trailing annual EBIDA(2) | 3.00 times | 1.27 |
| Net senior funded debt to book value of equity(3) | 0.70 times | 0.24 |
| Debt service coverage(4) | Minimum of 1.75 times | 2.23 |
Notes:
(1) Net senior funded debt is defined in the Loan Agreement as all obligations for senior secured and unsecured borrowed money which bears interest less restricted and unrestricted cash balances. Lease liabilities are excluded from the calculation of net senior funded debt.
(2) EBIDA is defined in the Loan Agreement as earnings (loss) before interest expenses, all non-cash items including depreciation and amortization, and gains or losses attributable to extraordinary and non-recurring items.
(3) Book value of equity is defined in the Loan Agreement as shareholders' capital, contributed surplus and retained earnings or deficit excluding increases and decreases in retained earnings from E&E asset and PP&E impairments or reversals and excluding payments of dividends.
(4) Debt service coverage is defined in the Loan Agreement as the ratio of trailing annual EBIDA to the total of bank debt interest expense due for the future annual period and scheduled principal payments in respect of outstanding bank debt principal for the future annual period.
As of December 31, 2024, the Company was compliant with all covenants provided for in the Loan Agreement.
The Company is currently negotiating with its lender to amend the Loan Agreement to incorporate two additional term loan facilities relating to the Proposed Acquisition. If the proposed acquisition does not proceed with an amendment to the Loan Agreement, the Company projects a breach of the debt service coverage covenant as of December 31, 2025, which could result in the bank debt balance becoming due. Refer to the "Future Operations" section of this MD&A for further information.
At all times, we must maintain a cash reserves balance of not less than the equivalent of two subsequent
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2024 Management's Discussion and Analysis
quarterly interest payments related to the two term loan facilities. Accordingly, Touchstone classified $924,000 of cash as non-current restricted on the consolidated balance sheet as at December 31, 2024 (2023 - $785,000).
Further information regarding the Loan Agreement is included in Note 13 "Bank Debt" of our audited financial statements, and copies of the loan agreement and amendments may be accessed online on our SEDAR+ profile (www.sedarplus.ca).
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-based awards that may be settled in common shares as at the date of this MD&A, December 31, 2024 and December 31, 2023.
| March 19, 2025 | December 31, 2024 | December 31, 2023 | |
|---|---|---|---|
| Common shares outstanding | 236,460,661 | 236,460,661 | 234,212,726 |
| Stock options outstanding | 11,574,000 | 11,731,000 | 14,327,935 |
| RSUs outstanding(1) | 1,408,717 | 1,447,780 | - |
| PSUs outstanding(1)(2) | 1,358,717 | 1,397,780 | - |
| 250,802,095 | 251,037,221 | 248,540,661 |
Notes:
(1) The RSUs and PSUs may be settled in cash or Company common shares upon vesting at the discretion of the Board. Both awards are currently accounted for as cash settled.
(2) Assuming a performance multiplier of one.
Relative to December 31, 2023, our common shares increased as of December 31, 2024 as a result of 2,247,935 stock options exercised by Company directors, officers, and employees. Further information regarding our share-based compensation plans and expense is included in the "Financial and Operational Results - Share-based compensation" section of this MD&A and in Note 19 "Share-Based Compensation Plans" of our audited financial statements.
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.
| ($000's) | Target measure | December 31, 2024 | December 31, 2023 |
|---|---|---|---|
| Net debt(1) | 29,109 | 22,581 | |
| Shareholders' equity | 68,828 | 59,766 | |
| Managed capital(1) | 97,937 | 82,347 | |
| Annual funds flow from operations | 16,748 | 13,730 | |
| Net debt to funds flow from operations ratio(1) | At or < 2.0 times | 1.74 | 1.64 |
| Net debt to managed capital ratio(1) | < 0.4 times | 0.30 | 0.27 |
Note:
(1) Specified financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
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35
Refer to the "Market Risk Management - Liquidity risk" section of this MD&A for further details regarding our approach to managing liquidity.
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 various exploration and production licences with the MEEI, and various lease commitments. The following table outlines our estimated minimum contractual payments as at December 31, 2024.
| ($000's) | Total | Estimated payments due by year | |||
|---|---|---|---|---|---|
| 2025 | 2026 | 2027 | Thereafter | ||
| Operating agreement commitments | |||||
| CO-1 block | 4,840 | 2,779 | 119 | 1,527 | 415 |
| WD-4 block | 4,722 | 2,789 | 94 | 1,502 | 337 |
| WD-8 block | 4,647 | 2,778 | 83 | 1,490 | 296 |
| Balata East block | 3,349 | 145 | 1,453 | 78 | 1,673 |
| Fyzabad block | 671 | 156 | 81 | 83 | 351 |
| Coho area of Ortoire block | 455 | 6 | 3 | 29 | 417 |
| Cascadura area of Ortoire block | 822 | 11 | 5 | 53 | 753 |
| Exploration block commitments | |||||
| Charuma block | 9,737 | 822 | 744 | 786 | 7,385 |
| Cipero block | 23,145 | 376 | 346 | 5,557 | 16,866 |
| Ortoire block | 10,426 | 166 | 10,260 | - | - |
| Rio Claro block | 17,878 | 398 | 366 | 5,577 | 11,537 |
| Office and equipment leases | 530 | 252 | 187 | 73 | 18 |
| Minimum payments | 81,222 | 10,678 | 13,741 | 16,755 | 40,048 |
Under the terms of our Heritage operating agreements, we are obligated to fulfill minimum work commitments on an annual basis over the specific licence term. With respect to these obligations, we are required to drill six development wells in 2025.
As of December 31, 2024, we are obligated to drill an aggregate ten exploration wells on our exploration properties through 2029.
The Company is a party to lease arrangements for a drilling rig, office facilities, vehicles, and equipment. As of December 31, 2024, we recognized $5,866,000 in aggregate lease liabilities, of which $4,368,000 was classified as non-current on the consolidated balance sheet (2023 - $4,328,000 and $2,888,000, respectively). Further information regarding our lease obligations is included in Note 12 "Lease Liabilities" of our audited financial statements.
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, interest rate risk, equity price 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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2024 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, NGL and natural gas 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, ongoing geopolitical factors, inventory levels, weather, and economic factors. Further, our realized crude oil and liquids prices are 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 predominately 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.
Touchstone does not currently hedge our commodity price given that approximately 70 percent of our near term forecasted petroleum and natural gas sales is expected to be derived from natural gas production governed by a fixed price contract through October 2027. The Company will continue to monitor forward commodity prices and may enter 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 (refer to the "Financial and Operational Results - Net earnings and funds flow from operations sensitivity" section of this MD&A for further information).
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 production 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 NGL and natural gas sales are denominated and payable in US$.
Touchstone has further foreign exchange exposure on cash balances denominated in C$ and pounds sterling, head office costs denominated and payable 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.
For the year ended December 31, 2024, with all other variables held constant, a 5 percent change in the C$ to US$ and TT$ to US$ exchange rates would have resulted in an approximate $100,000 increase or decrease in comprehensive income (2023 - $193,000). A 5 percent increase or decrease in the foreign exchange rates applicable to TT$, C$ and pounds sterling dollar-denominated payables and receivables would have resulted in an approximate $78,000 increase or decrease in comprehensive income for the year ended December 31, 2024 (2023 - $175,000). Refer to the "Financial and Operational Results - Foreign exchange and foreign currency translation" section of this MD&A for further information.
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2024 Management's Discussion and Analysis
Interest rate risk
Interest rate risk arises from changes in market interest rates that may affect comprehensive income and cash flows. The Company's term loan facility 2 and revolving loan facility are subject to interest rate risk given the applicable annual interest rates are reset on an annual basis in relation to the one-year term secured overnight financing rate. The current annual interest rates under our term loan facility 2 and revolving facility are 7.49 percent and 7.23 percent, respectively. Refer to the "Financial and Operational Results - Net earnings and funds flow from operations sensitivity" section of this MD&A for further information.
Equity price risk
The Company is exposed to equity price risk on its own common share price in relation to awards issued under its Omnibus Plan and deferred share unit plan, which affects comprehensive income through the revaluation of awards that are accounted for as cash-settled transactions at each period end. Changes in the Company's share price will result in an increase or decrease in the amount that Touchstone recognizes as share-based compensation expense and the amount Touchstone ultimately pays to settle the awards. The Company does not expect to mitigate this risk by entering into equity derivative contracts. Refer to the "Financial and Operational Results - Share-based compensation" section of this MD&A for further information.
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-party credit risk through our contractual arrangements with current or future joint operation partners, marketers of our commodities and other parties. Credit risk is considered to be low for the Company's accounts receivable, as Touchstone's credit exposure typically pertains to monthly commodity sales and joint interest billings due from Trinidad government owned petroleum and natural gas entities, and value added taxes ("VAT") due from the Trinidad government.
However, the Company historically has aged accounts receivables owing for VAT. In comparison to December 31, 2023, our past due VAT accounts receivable balance increased by $2,620,000 as of December 31, 2024. $1,504,000 in past due VAT was collected in the year ended December 31, 2024, which was offset by increased VAT outstanding from 2024 capital and operational expenditures. 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. Subsequent to December 31, 2024, $666,000 in past due VAT receivable was collected and the Trinidad government issued the Company an aggregate $2,955,000 in bonds in lieu of VAT payments that may be sold after July 31, 2025.
The following table details the composition and aging of our accounts receivable as of December 31, 2024.
| Composition | Counterparty | Balance due ($000's) | Balance due (%) | Accounts receivable aging | |
|---|---|---|---|---|---|
| Current ($000's) | Over 90 days ($000's) | ||||
| Crude oil and liquids sales | Heritage | 1,874 | 14 | 1,874 | - |
| Natural gas sales | NGC | 2,460 | 18 | 2,460 | - |
| Joint interest billings | Heritage and NGC | 806 | 5 | 806 | - |
| VAT | Trinidad government | 7,678 | 56 | 1,077 | 6,601 |
| Finance lease | Third-party lessee | 163 | 1 | 163 | - |
| Other | Various | 824 | 6 | 760 | 64 |
| Accounts receivable | 13,805 | 100 | 7,140 | 6,665 |
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2024 Management's Discussion and Analysis
Touchstone is currently engaged in an agreement to lease oilfield service rigs to a third-party contractor. 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 counterparty upon receipt of the final lease payment. As of December 31, 2024, our finance lease receivable balance was $233,000, of which $70,000 was included in non-current other assets on the consolidated balance sheet (2023 - $350,000 and $295,000, respectively).
Further details relating to our financial assets and credit risk can be found in Note 6 "Financial Assets and Credit Risk" of our audited financial statements.
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. Management believes that future cash flows will be adequate to settle 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 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 expense, operating expense, G&A expense, income tax expense 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 flows from operating, investing and financing activities.
The following table sets forth estimated undiscounted cash outflows and financial maturities of our financial liabilities as at December 31, 2024.
| ($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 | 14,373 | 14,373 | - | - |
| Income taxes payable | Yes – liability | 6 | 6 | - | - |
| Lease liabilities(3) | Yes – liability | 7,283 | 2,361 | 3,429 | 1,493 |
| Principal balance of bank debt | Yes – liability | 35,000 | 7,250 | 24,000 | 3,750 |
| Bank debt interest(4) | No – recognized as incurred | 4,314 | 2,425 | 1,690 | 199 |
| Share-based compensation liabilities(5) | Yes – liability | 500 | 383 | 117 | - |
| Financial liabilities | 61,476 | 26,798 | 29,236 | 5,442 |
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 $1,498,000 current portion of lease liabilities and the $383,000 current portion of share-based compensation liabilities.
(3) Includes the notional interest and principal payments.
(4) Based on current interest rates, where two of the Company's three loan facility interest rates are reset on an annual basis.
(5) Accrued obligations associated with share-based compensation expected to be settled in cash.
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 actively monitor our liquidity to ensure that cash flows, potential credit facility capacity and working capital are adequate to support our
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2024 Management's Discussion and Analysis
39
current and future financial liabilities, as well as the Company's capital programs and future work commitments.
Related Party Transactions
Our Chief Executive Officer, Chief Financial Officer and our Trinidad-based director serve as independent board members of a separate Trinidad charitable entity established by Touchstone. For the year ended December 31, 2024, the Company donated $30,000 to the charitable entity (2023 - $16,000).
We have determined that our key management personnel consist of our executive officers and directors. Touchstone provides salaries and directors' fees, annual incentive payments and other benefits to our key management personnel. In addition, we provide share-based compensation to our key management personnel under our share-based compensation plans. Key management personnel compensation paid or payable during the years ended December 31, 2024 and 2023 are disclosed below.
| ($000's) | Year ended December 31, | |
|---|---|---|
| 2024 | 2023 | |
| Salaries and benefits included in G&A expense | 1,517 | 1,244 |
| Director fees included in G&A expense | 405 | 381 |
| Share-based compensation expense | 1,177 | 886 |
| Capitalized salaries, benefits, and share-based compensation expense | 44 | 107 |
| Key management compensation | 3,143 | 2,618 |
The 2024 increase in key management compensation compared to 2023 was primarily attributable to the appointment of an additional employee to the executive management team in 2024.
Non-executive director compensation during the year ended December 31, 2024 is set forth in the following table.
| Director ($000's) | Fees earned | Share-based compensation | All other compensation | Total compensation |
|---|---|---|---|---|
| Jenny Alfandary | 47 | 78 | 14 | 139 |
| Priya Marajh | 47 | 77 | 7 | 131 |
| Kenneth R. McKinnon | 52 | 91 | 8 | 151 |
| Peter Nicol | 49 | 86 | 7 | 142 |
| Beverley Smith | 49 | 81 | 7 | 137 |
| Stanley T. Smith | 52 | 90 | 8 | 150 |
| Harrie Vredenburg | 47 | 76 | 7 | 130 |
| John D. Wright | 62 | 98 | 7 | 167 |
| Director compensation | 405 | 677 | 65 | 1,147 |
Changes in Accounting Policies Including Initial Adoption
There were no changes in accounting policies during the three months and year ended December 31, 2024 that had a material effect on the reported comprehensive income or net assets of the Company. A list of our accounting policies adopted in 2024 is included in Note 4 "Changes to Accounting Policies" of our audited financial statements.
Standards Issued but Not Yet Effective
Financial Instruments and Financial Instruments: Disclosures
In May 2024, the International Accounting Standards Board ("IASB") issued amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures to clarify the date of recognition and derecognition of financial assets and liabilities. The amendments are effective for fiscal years beginning on
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2024 Management's Discussion and Analysis
or after January 1, 2026, with early adoption permitted. The Company is evaluating the impact that the amendments will have on our consolidated financial statements.
Presentation and Disclosure in Financial Statements
IFRS 18 Presentation and Disclosure in Financial Statements ("IFRS 18") was issued in April 2024 by the IASB and will replace IAS 1 Presentation of Financial Statements. The standard introduces new totals, subtotals and categories for income and expenses in the statements of comprehensive income, as well as requiring disclosure about management-defined performance measures and additional requirements regarding the aggregation and disaggregation of certain information. IFRS 18 is required to be adopted retrospectively and is effective for fiscal years beginning on or after January 1, 2027, with early adoption permitted. The Company is assessing the impact that this standard will have on our consolidated financial statements.
Off-balance Sheet Arrangements
The Company did not enter into any off-balance sheet arrangements during the year ended December 31, 2024, other than normal course guarantees entered into in the form of parent guarantees to support work commitments on exploration and production licences. Touchstone 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 of this MD&A.
Significant Accounting Estimates, Judgements and Assumptions
The preparation of consolidated 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 audited financial statements is included in Note 5 "Use of Estimates, Judgements and Assumptions" of our audited financial statements.
The Company believes it 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
For a full understanding of risks that affect Touchstone, the following should be read in conjunction with our 2024 AIF dated March 19, 2025, which is available online on our SEDAR+ profile (www.sedarplus.ca) and website (www.touchstoneexploration.com). Refer to the "Advisories - Forward-Looking Statements" section of this MD&A for additional information regarding the risks to which Touchstone and our business operations are subject to.
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, interest rate risk, equity price risk, credit risk and liquidity
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2024 Management's Discussion and Analysis
risk. The following are certain key risks, uncertainties and opportunities associated with the Company's business that can impact financial results.
Operational matters
The operation of oil and natural gas wells and sales facilities may involve a number of operational and natural hazards. Operational risks include competition, reservoir performance uncertainties, well blow-outs and other operating hazards, lack of infrastructure or transportation to access markets and monetize reserves, and regulatory, environmental and safety concerns. The Company works to mitigate these risks by employing highly skilled personnel and utilizing available technology. We maintain a corporate insurance program in amounts consistent with industry practices to protect against insurable losses. Business interruption insurance may also be purchased for selected facilities, to the extent that such insurance is available. We may become liable for damages arising from such events against which we cannot insure or against which we may elect not to insure because of high premium costs or other reasons. Costs incurred to repair such damage or pay such liabilities will reduce cash from operating activities and may reduce future capital investments.
The oil and natural gas industry is intensely competitive, with the Company competing against companies that may have greater technical and financial resources. There is competition for new exploration and development properties, infrastructure and sales contracts, drilling and other specialized technical equipment and for experienced key human resources.
Exploration
As a participant in the oil and natural gas industry, we are exposed to a high level of exploration and production risk, upon which there is no assurance that hydrocarbon reserves will be discovered and economically produced. Our current and future (to the extent discovered or acquired) proved reserves will decline as reserves are produced from our properties unless we can acquire or develop new reserves. The business of exploring for, developing or acquiring reserves is capital intensive and is subject to numerous estimates and interpretations of geological and geophysical data. There can be no assurance that the Company's future exploration, development and acquisition activities will result in material additions of proved reserves. To manage this risk, to the extent possible, we employ or contract highly qualified geologists, use technology such as seismic and current information system technology as primary exploration tools, and focus our exploration efforts in known hydrocarbon-producing basins. We may also choose to mitigate exploration risk through acquisitions that may require raising additional funds.
It is difficult to project the costs of implementing any exploratory drilling program due to the inherent uncertainties of drilling in unknown formations; the costs associated with encountering various drilling conditions such as unexpected formations or over pressured zones; premature declines of reservoirs and the invasion of water into producing formations; potential environmental damage, blow-outs, cratering, fires and spills, all of which could result in personal injuries, loss of life or threaten wildlife and damage to property of the Company and others; tools lost in the hole; and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.
Foreign location of assets and foreign economic and political risk
Touchstone is subject to additional risks associated with international operations. Our operations may be adversely affected by changes in foreign government policies and legislation or social instability and other factors which are not within our control, including, but not limited to: nationalization, expropriation of property without fair compensation or marketable compensation; changes in laws and policies impacting foreign trade and investment; renegotiation or nullification of existing concessions and contracts; the imposition of specific drilling obligations and the development and abandonment of fields; changes in energy and environmental policies or the personnel administering them; changes in petroleum and natural gas pricing policies; the actions of national labour unions; currency fluctuations and devaluations; currency exchange controls; economic sanctions; taxation of the oil and natural gas sector; and other risks arising out of foreign governmental sovereignty over the areas in which Touchstone's operations are or will be conducted. If the
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2024 Management's Discussion and Analysis
Company's operations are disrupted and/or the economic integrity of its projects are threatened for unexpected reasons, its business may be harmed. Prolonged problems may threaten the commercial viability of our operations. In addition, there can be no assurance that contracts, licences, regulatory applications or other legal arrangements will not be adversely affected by changes in governments in foreign jurisdictions, the actions of government authorities or others, or the effectiveness and enforcement of such arrangements.
Although Management considers political conditions in Trinidad as generally stable, changes may occur in its political, fiscal and legal systems, which might affect the ownership or operation of our interests including, inter alia, changes in exchange rates, exchange control regulations, expropriation of petroleum and natural gas rights, changes in government and in legislative, fiscal and regulatory regimes. Our current business strategy, including our risk management strategies, has been formulated in the light of the current political and regulatory environment and likely future changes. The political and regulatory environment may change in the future, and such changes may have a material adverse effect on the Company.
Commodity prices and marketing
Numerous factors beyond our control do and will continue to affect the marketability and price of crude oil and liquids acquired, produced or discovered by the Company. Accordingly, commodity prices are the Company's most significant financial risk. Prices for crude oil are subject to large fluctuations in response to relatively minor changes in the supply of and demand, market uncertainty, and a variety of additional factors beyond our control. These factors include, but are not limited to, the impact of global economic and political conditions; global energy policy such as the actions of Organization of Petroleum Exporting Countries ("OPEC") and other oil and natural gas exporting nations; governmental regulation; global political stability, the foreign supply and demand of crude oil; risks of supply disruption, the price of foreign imports; and the availability of alternative fuel sources. Crude oil prices may continue to be volatile for a variety reasons including market uncertainties over the supply and demand due to the current state of the global economy, the impact of regional and/or global events on economic activity levels and energy demand such as OPEC and non-OPEC producers' actions in respect of supply, political uncertainties, slowing growth in emerging economies, weakening global relationships and trade relationships, sanctions imposed on certain oil producing nations by other countries and ongoing geopolitical conflicts, including the impact and duration of the ongoing military actions between Russia and Ukraine, as well as Israel and Palestine.
Further, crude oil prices are also subject to the availability of foreign markets and Heritage's ability to access such markets. We monitor market conditions and may selectively utilize derivative instruments to reduce our exposure to crude oil price movements. However, we are of the view that it is neither appropriate nor possible to eliminate 100 percent of our exposure to crude oil and liquids price volatility. Refer to the "Market Risk Management - Commodity price risk" section of this MD&A for further information on how we manage commodity price risk.
These factors could result in a material decrease in our expected petroleum and natural gas sales and a reduction in our petroleum and natural gas production, development and exploration activities. Any substantial and extended decline in the price of petroleum and natural gas would have an adverse effect on the carrying value of the Company's reserves, borrowing capacity, petroleum and natural gas sales, profitability and cash from operating activities and may have a material adverse effect on our business, financial condition, results of operations and prospects.
Environmental regulations
We are subject to environmental laws and regulations that affect aspects of our past, present and future operations. Extensive environmental laws and regulations in Trinidad set various standards regulating certain aspects of health and environmental quality, including air emissions, noise pollution, water quality, wastewater discharges and the generation, transport and disposal of waste and hazardous substances; provide for penalties and other liabilities for the violation of such standards; and establish obligations to remediate current and former facilities and locations where operations are or have been conducted. In addition, special provisions may be appropriate or required in environmentally sensitive areas of operation.
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2024 Management's Discussion and Analysis
We adopt prudent and industry-recommended field operating procedures for all operations, as well as maintaining a robust health, safety and environmental program to protect the environment, our employees and contractors, and the public.
These environmental laws and regulations impose certain costs and risks on the Company, and there remain some uncertainty regarding the impact of climate change and environmental laws and regulations on Touchstone, as we are unable to predict additional legislation or amendments that the Trinidadian government may enact in the future. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material impact on the Company's operations and cash flows. Although we believe that we are in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on our business, financial condition, results of operations and prospects.
Sole purchaser risk and the ability to market
We are exposed to sole purchaser risk in Trinidad as Heritage is the sole purchaser of crude oil and liquids production, and NGC is the sole purchaser of natural gas production. Our ability to market our petroleum and natural gas products depends upon numerous factors beyond our control, including: the availability of third-party pipeline capacity; the supply of and demand for petroleum and natural gas; the availability of alternative fuel sources; the counterparty's future financial viability; and the effects of weather conditions. Deliverability uncertainties relate to third-party processing and storage facilities, operational problems affecting pipelines and facilities as well as government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of crude oil and liquids, and domestic usage of natural gas. Because of these factors, we could be unable to market or to obtain competitive prices for the petroleum and natural gas we produce.
The amount of petroleum and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of these third-party processing facilities and pipeline systems and over which we do not have control. From time to time, these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuation or decrease of operations could have a materially adverse effect on our ability to market our future petroleum and natural gas production. The lack of availability of capacity in any of the third-party processing facilities and pipeline systems could result in our inability to realize the full economic potential of our production or in a material reduction of the price offered for our production. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition, results of operations and cash from operating activities.
Climate change
Our exploration and production facilities and other operations and activities emit greenhouse gas ("GHG") which may require us to comply with emerging GHG emissions legislation. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place to prevent climate change or mitigate its effects. The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on our business, financial condition, results of operations, prospects, our cost of capital and access to capital markets. Climate change has been linked to long-term shifts in climate patterns and extreme weather conditions both of which pose the risk of causing operational difficulties. Further, climate change and its associated impacts may increase our exposure to, and magnitude of, each of the risks identified herein.
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2024 Management's Discussion and Analysis
Reserves estimates
Reserve values are based on a number of variables and assumptions such as future commodity prices, forecasted production volumes, forecasted operating and future development costs, and future governmental regulations. The actual production and ultimate reserves from our properties may be greater or less than the estimates prepared by our independent qualified reserves evaluator. Our reserves evaluator forecasts reserve volumes and future cash flows based upon current and historical well performance through to the economic production limit of individual wells. Notwithstanding established precedence and contractual options for the continuation and renewal of our existing licence, sub-licence and marketing agreements, in many cases the forecasted economic limit of individual wells is beyond the current term of the relevant agreements, and there is no certainty as to any renewal of our existing production and marketing arrangements.
Trinidad exploration and production agreements
The current Heritage operating agreements, MEEI exploration and production licences and joint operating agreements with respect to our properties contain significant obligations on the part of the Company's subsidiaries including minimum work commitments which, upon a continuing default, may give rise to the termination of our operatorship interest therein. There are no assurances that all of these commitments will be fulfilled within the periods allowed. As such, we may lose certain exploration and production rights on the licenced areas affected and may be subject to certain financial penalties that would be levied by Heritage, the MEEI, or the other parties thereto, as applicable. The current forms of licences and sub-licences, as applicable, may, in certain circumstances, be terminated at Heritage's or the MEEI's discretion and are subject to a defined term, and there is no certainty as to any renewal.
Further, the Company is operating under a number of private lease agreements which have expired and are currently being renegotiated. Based on opinions obtained from Trinidad legal counsel, the Company is continuing to recognize crude oil sales as operator and is paying all associated royalties and income taxes, and no title to our land in Trinidad has been disputed. However, there is no certainty that such expired lease agreements will be renewed, on terms satisfactory to the Company or at all, or that our rights as operator will not be disputed. The continuation of production from expired private leases during the renegotiation process is common in Trinidad based on antiquated land title processes. During the year ended December 31, 2024, production volumes produced under expired private lease agreements represented 0.5 percent of annual Company production (2023 - 1.3 percent).
Security
Trinidad has a history of security problems. Violent crime and murder rates, partly as a result of gang crime related to drug trafficking, continues to remain a top priority for the Trinidad government to address. The Company and its personnel are subject to these risks, but through effective security and social programs, Touchstone believes security risks can be managed. The Company maintains insurance in an amount that it considers adequate and consistent with industry practice and its operations; however, it is difficult to obtain insurance coverage to protect against all incidents of crime. The Company may not be able to establish or maintain the safety of its operations and personnel in Trinidad and this violence may affect its operations in the future. Continued or heightened security concerns in Trinidad could have a material adverse impact on the Company's operations. Further, if the perception of overall security and crime rates in Trinidad deteriorates, the Trinidad economy may face lower growth rates, which could negatively affect the Company's financial condition and results of operations.
Control Environment
Management, including the Company's President and Chief Executive Officer and Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting ("ICFR") and disclosure controls and procedures ("DC&P") as at December 31, 2024. In making our assessment, Management used the "Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control - Integrated Framework" issued in 2013 (the "2013 Framework") to evaluate the design and
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2024 Management's Discussion and Analysis
effectiveness of ICFR. Under the supervision of the Chief Executive Officer and the Chief Financial Officer, Touchstone conducted an evaluation of the effectiveness of the Company's ICFR as at December 31, 2024 in accordance with the 2013 Framework. Based on this evaluation, the officers concluded that both ICFR and DC&P were effective as at December 31, 2024. There were no changes during the three months and year ended December 31, 2024 that had materially affected, or were reasonably likely to materially affect, ICFR.
ICFR is a process designed to provide reasonable assurance that all assets are safeguarded, and transactions are appropriately authorized to facilitate the preparation of relevant, reliable and timely information. Internal control systems, no matter how well designed, have inherent limitations and may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Furthermore, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Selected Annual Information
| ($000's except per share amounts) | Year ended December 31 | ||
|---|---|---|---|
| 2024 | 2023 | 2022 | |
| Petroleum and natural gas sales | 57,470 | 48,098 | 42,944 |
| Total revenue | 43,657 | 35,989 | 28,345 |
| Net earnings (loss) | 8,272 | (20,598) | (3,197) |
| Per share – basic | 0.04 | (0.09) | (0.01) |
| Per share – diluted | 0.03 | (0.09) | (0.01) |
| Total assets | 152,273 | 138,948 | 147,877 |
| Total non-current liabilities | 59,935 | 49,031 | 48,074 |
| Total liabilities | 83,445 | 79,182 | 69,497 |
| Total shareholders' equity | 68,828 | 59,766 | 78,380 |
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 and liquids 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.
In 2024, the Company experienced financial growth, with petroleum and natural gas sales increasing to $57.5 million from $48.1 million in 2023 from a 44 percent increase in production volumes. Net earnings rebounded to $8.3 million, as the Company recorded $21.4 million in net non-financial asset impairment expenses in 2023. This resulted in earnings per share of $0.04 (basic) and $0.03 (diluted) in 2024, compared to a loss of $0.09 per basic share in the prior year.
We have never declared or paid any dividends on our outstanding common shares. Any future decision to pay dividends on any class of shares will be made by the Board based on net earnings, financial requirements, the satisfaction of the liquidity and solvency tests imposed by the Business Corporations Act (Alberta) for the declaration thereof, and other conditions existing at such future time.
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2024 Management's Discussion and Analysis
Summary of Quarterly Results
The following is a summary of our unaudited quarterly results for the eight most recently completed fiscal quarters.
| Three months ended | Dec. 31, 2024 | Sept. 30, 2024 | June 30, 2024 | March 31, 2024 | Dec. 31, 2023 | Sept. 30, 2023 | June 30, 2023 | March 31, 2023 |
|---|---|---|---|---|---|---|---|---|
| Operational | ||||||||
| Average daily production (boe/d) | 5,287 | 5,211 | 5,432 | 7,015 | 8,504 | 3,391 | 1,827 | 2,139 |
| Net wells drilled | - | - | 1.0 | 2.6 | - | - | - | 0.8 |
| Realized commodity price(1) ($/boe) | 27.85 | 27.65 | 28.50 | 25.98 | 26.53 | 37.44 | 43.19 | 44.03 |
| Operating netback(1) ($/boe) | 14.17 | 15.46 | 16.44 | 16.39 | 17.54 | 19.27 | 17.00 | 18.97 |
| Financial ($000's except per share amounts) | ||||||||
| Petroleum and natural gas sales | 13,543 | 13,253 | 14,090 | 16,584 | 20,759 | 11,682 | 7,181 | 8,476 |
| Cash from operating activities | 822 | 3,607 | 3,383 | 5,369 | 8,512 | 343 | 2,975 | 913 |
| Funds flow from operations | 3,614 | 3,024 | 3,968 | 6,142 | 10,489 | 2,432 | 6 | 803 |
| Net loss (earnings) | (542) | 1,847 | 3,339 | 3,628 | (21,236) | 988 | (71) | (279) |
| Per share – basic and diluted | (0.00) | 0.01 | 0.01 | 0.02 | (0.09) | 0.00 | (0.00) | (0.00) |
| E&E asset expenditures | 426 | 452 | 60 | 108 | 595 | 3,498 | 4,795 | 8,750 |
| PP&E expenditures | 2,680 | 2,616 | 5,483 | 11,854 | 591 | 111 | 340 | 269 |
| Capital expenditures(1) | 3,106 | 3,068 | 5,543 | 11,962 | 1,186 | 3,609 | 5,135 | 9,019 |
| Working capital deficit(1) | 1,359 | 3,865 | 2,674 | 14,121 | 7,581 | 13,419 | 10,913 | 4,383 |
| Principal long-term bank debt | 27,750 | 25,728 | 26,000 | 13,500 | 15,000 | 16,500 | 18,000 | 19,500 |
| Net debt(1) – end of period | 29,109 | 29,593 | 28,674 | 27,621 | 22,581 | 29,919 | 28,913 | 23,883 |
| Share Information (000's) | ||||||||
| Weighted average – basic | 236,461 | 235,189 | 234,959 | 234,213 | 234,213 | 233,541 | 233,144 | 233,037 |
| Weighted average – diluted | 236,461 | 236,578 | 236,364 | 236,548 | 234,213 | 237,138 | 233,144 | 233,037 |
| Outstanding shares – end of period | 236,461 | 236,461 | 236,307 | 234,213 | 234,213 | 234,213 | 233,428 | 233,037 |
Note:
(1) Specified financial measure. See the "Advisories - Non-GAAP Financial Measures" section of this MD&A for further information.
The following significant items impacted our unaudited financial and operating results over the past eight fiscal quarters:
- We recorded funds flow from operations of $3.6 million in the fourth quarter of 2024, reflecting a 20 percent increase from the prior quarter, as reductions in G&A and transaction expenses fully offset lower operating netbacks. Capital spending totaled $3.1 million, primarily directed toward the Cascadura field, including the completion of the Cascadura C tie-in project and the Cascadura B location, and the purchase of drilling related inventory. As a result, we ended the quarter with a net debt balance of $29.1 million. The Company reported a net loss of $0.5 million, primarily due to $2.3 million in pre-tax Ortoire exploration asset impairment expenses and higher depletion expenses following Cascadura reserves reductions.
- In the third quarter of 2024, we recorded funds flow from operations of $3 million, representing a 24 percent decrease from the $4 million reported in the prior quarter. This decline was due to a 4 percent drop in production and a 3 percent reduction in realized commodity pricing. Capital spending for the quarter totaled $3.1 million, primarily directed toward the Cascadura field. This included initial completions on the Cascadura-2ST1 and Cascadura-3ST1 wells, progress on the Cascadura C tie-in project, and construction of the Cascadura B location. As a result, we exited the quarter with a net debt balance of $29.6 million.
- Funds flow from operations in the second quarter of 2024 was $4 million, reflecting a 35 percent decrease from the $6.1 million reported in the previous quarter. This decline was primarily due to a 23 percent drop in production, partially offset by a 10 percent increase in realized commodity
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2024 Management's Discussion and Analysis
pricing. Capital expenditures totaled $5.5 million, largely focused on advancing the Cascadura C tie-in project and drilling one CO-1 development well. Additionally, on April 16, 2024, we entered into a Loan Agreement for a new $10 million, five-year non-revolving term loan facility, which was fully drawn on May 1, 2024.
- In the first quarter of 2024, we recorded funds flow from operations of $6.1 million, a decrease of $4.3 million from the previous quarter. This decline was primarily due to an 18 percent reduction in production and a 2 percent decrease in realized commodity pricing. We invested $12 million in capital expenditures, mainly focused on development drilling in our Cascadura field and advancing the construction of the flowline from the Cascadura C surface location to the Cascadura natural gas processing facility. As a result, our corporate net debt increased by 22 percent compared to the previous quarter.
- We achieved record production levels and funds flow from operations in the fourth quarter of 2023, which reflected a full quarter of Cascadura field production volumes. Combined with minimal capital spending of $1.2 million, we decreased corporate net debt levels by 25 percent from the preceding quarter. An aggregate $28.9 million (net of income tax) of net impairment expenses mainly related to our Chinook and Royston exploration assets led to a quarterly net loss of $21.2 million.
- In the third quarter of 2023, we generated $2.4 million of funds flow from operations, as we brought on initial natural gas production from our Cascadura wells, thereby achieving an 86 percent increase in quarterly average production on a per boe basis from the preceding quarter. Net debt increased by $1 million from the second quarter of 2023, as we invested $3.6 million in quarterly capital investments predominately relating to final construction and commissioning of the Cascadura natural gas facility.
- 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 13 percent and a 4 percent decline in crude oil 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.
- Funds flow from operations totaled $0.8 million in the first quarter of 2023. During the quarter, we drilled the Royston-1X sidetrack well and continued construction of the Cascadura natural gas facility, resulting in $9 million in capital expenditures. These investments reduced our cash and working capital balances, leading to a net debt position of $23.9 million at quarter-end.
Advisories
Non-GAAP Financial Measures
This MD&A or documents referred to in this MD&A reference various non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as such terms are defined in National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. Such measures are not recognized measures under GAAP and do not have a standardized meaning prescribed by 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.
TOUCHSTONE
2024 Management's Discussion and Analysis
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 royalty and operating expenses from petroleum and natural gas sales. The most directly comparable financial measure to operating netback disclosed in the Company's consolidated financial statements is petroleum and natural gas revenue net of royalties. Operating netback per boe is a non-GAAP ratio calculated by dividing the operating netback by total production volumes for the period. Presenting operating netback on a per boe basis allows Management to better analyze performance against prior periods on a comparable basis.
The following table presents the computation of operating netback for the periods indicated.
| ($000's unless otherwise stated) | Three months ended December 31, | Year ended December 31, | ||
|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |
| Petroleum and natural gas sales | 13,543 | 20,759 | 57,470 | 48,098 |
| Less: royalty expense | (3,205) | (4,324) | (13,876) | (12,173) |
| Petroleum and natural gas revenue, net of royalties | 10,338 | 16,435 | 43,594 | 35,925 |
| Less: operating expense | (3,446) | (2,704) | (10,704) | (9,705) |
| Operating netback | 6,892 | 13,731 | 32,890 | 26,220 |
| Total production (boe) | 486,329 | 782,330 | 2,098,308 | 1,453,073 |
| Operating netback ($/boe) | 14.17 | 17.54 | 15.68 | 18.04 |
Cash and non-cash net finance expense
Cash and non-cash net finance expense are non-GAAP financial measures. Cash finance expenses are calculated as net finance expense as determined in accordance with IFRS, less accretion on bank debt, accretion on decommissioning obligations, and other liability revaluation loss (gain), all of which are non-cash in nature. The Company discloses net finance expense as cash or non-cash to demonstrate the true cost of finance expense to assist Management with evaluating results on a historical basis.
Capital expenditures
Capital expenditures is a non-GAAP financial measure that is calculated as the sum of exploration and evaluation asset expenditures and property, plant and equipment expenditures included in the Company's consolidated statements of cash flows and is most directly comparable to cash used in investing activities. Touchstone considers capital expenditures to be a useful measure of its investment in its existing asset base.
The following table presents the computation of capital expenditures and reconciles capital expenditures to cash used in investing activities for the periods indicated.
| ($000's) | Three months ended December 31, | Year ended December 31, | ||
|---|---|---|---|---|
| 2024 | 2023 | 2024 | 2023 | |
| E&E asset expenditures | 426 | 595 | 1,046 | 17,638 |
| PP&E expenditures | 2,680 | 591 | 22,633 | 1,311 |
| Capital expenditures | 3,106 | 1,186 | 23,679 | 18,949 |
| Abandonment fund expenditures | 226 | 373 | 971 | 626 |
| Proceeds from asset dispositions | - | - | (1,066) | (250) |
| Net change in non-cash working capital | 147 | 812 | (2,964) | 1,790 |
| Cash used in investing activities | 3,479 | 2,371 | 20,620 | 21,115 |
TOUCHSTONE
2024 Management's Discussion and Analysis
Working capital, net debt and managed capital
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.
Management monitors working capital, net debt and managed capital 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. Management defines managed capital as the sum of net debt and shareholders' equity.
The following table presents working capital, net debt and managed capital computations for the periods indicated.
| ($000's) | December 31, 2024 | December 31, 2023 |
|---|---|---|
| Current assets | (22,151) | (22,570) |
| Current liabilities | 23,510 | 30,151 |
| Working capital deficit | 1,359 | 7,581 |
| Principal balance of long-term bank debt | 27,750 | 15,000 |
| Net debt | 29,109 | 22,581 |
| Shareholders' equity | 68,828 | 59,766 |
| Managed capital | 97,937 | 82,347 |
The following table reconciles total liabilities to net debt for the periods indicated.
| ($000's) | December 31, 2024 | December 31, 2023 |
|---|---|---|
| Total liabilities | 83,445 | 79,182 |
| Lease liabilities | (4,368) | (2,888) |
| Other liabilities | (117) | - |
| Decommissioning liabilities | (9,985) | (9,733) |
| Deferred income tax liability | (17,924) | (21,433) |
| Variance of carrying value and principal value of bank debt | 209 | 23 |
| Current assets | (22,151) | (22,570) |
| Net debt | 29,109 | 22,581 |
Net debt to funds flow from operations ratio
The Company monitors its capital structure using a net debt to funds flow from operations ratio, which is a non-GAAP ratio and a capital management measure calculated as the ratio of the Company's net debt to trailing twelve months funds flow from operations for any given period. The 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 and/or low commodity prices.
Net debt to managed capital ratio
The Company further monitors its capital structure using a net debt to managed capital ratio, which is a non-GAAP ratio and capital management measure calculated as the ratio of the Company's net debt to managed capital. The Company's 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.
TOUCHSTONE
2024 Management's Discussion and Analysis
Supplementary Financial Measures
The following supplementary financial measures are referenced 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.
Realized crude oil sales per barrel - is comprised of crude oil product sales as determined in accordance with IFRS, divided by the Company's total crude oil production volumes for the period. Crude oil sales are a component of petroleum and natural gas sales.
Realized NGL sales per barrel - is comprised of NGL product sales as determined in accordance with IFRS, divided by the Company's total NGL production volumes for the period. NGL sales is a component of petroleum and natural gas sales.
Realized crude oil and liquids sales per barrel - is comprised of the sum of crude oil and NGL product sales as determined in accordance with IFRS, divided by the sum of the Company's total crude oil and NGL production volumes for the period. Crude oil and NGL sales are components of petroleum and natural gas sales.
Realized natural gas sales per boe - is comprised of natural gas product sales as determined in accordance with IFRS, divided by the Company's total natural gas production volumes for the period. Natural gas sales are a component of petroleum and natural gas sales.
Royalty expense per boe - is comprised of royalty expense as determined in accordance with IFRS, divided by the Company's total production volumes for the period.
Royalty expense as a percentage of petroleum and natural gas sales - is comprised of royalty expense as determined in accordance with IFRS, divided by petroleum and natural gas sales as determined in accordance with IFRS.
Operating expense per boe - is comprised of operating expense as determined in accordance with IFRS, divided by the Company's total production volumes for the period.
G&A expense per boe - is comprised of G&A expense as determined in accordance with IFRS, divided by the Company's total production volumes for the period.
Net finance expense per boe - is comprised of net finance expense 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 expense 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 expense as disclosed in the Company's consolidated financial statements.
Current income tax expense per boe - is comprised of current income tax expense 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.
TOUCHSTONE
2024 Management's Discussion and Analysis
Such forward-looking statements include, without limitation, forecasts, estimates, expectations and objectives for future operations that are subject to assumptions, risks and uncertainties, many of which are beyond the control of the Company. Forward-looking statements are statements that are not historical facts and are generally, but not always, identified by the words "expect", "plan", "anticipate", "believe", "intend", "maintain", "continue to", "pursue", "design", "result in", "sustain" "estimate", "potential", "growth", "near-term", "long-term", "forecast", "contingent" and similar expressions, or are events or conditions that "will", "would", "may", "could" or "should" occur or be achieved. 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 forward-looking 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 plans, operational strategies, priorities, outlook and development plans, including the Company's preliminary annual 2025 guidance and its expectation to update its 2025 guidance as well as the timing thereof;
- financial condition and outlook and results of operations, including future liquidity and financial capacity and expectations of future growth, including expectations of future production levels and cash flows to be derived therefrom;
- future demand for the Company's petroleum and natural gas products and economic activity in general;
- general economic and political developments in Trinidad and globally;
- 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, estimated field production levels and estimated future production decline rates;
- 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;
- future development and exploration activities to be undertaken in various areas and timing thereof, including the fulfillment of minimum work obligations and exploration commitments;
- terms and estimated future expenditures of the Company's contractual commitments and their timing of settlement;
- terms and title of exploration and production licences and the expected formal extension, renewal 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;
- access to third-party facilities and infrastructure;
- expected levels of royalty expense, operating expense, G&A expense, net finance expense, current income tax expense and other costs associated with the Company's business;
- treatment under current and future governmental regulatory regimes, environmental legislation, and tax laws enacted in the Company's areas of operations and the resulting impact on the Company's capital and operating expenditures;
- current risk management strategies and the benefits to be derived therefrom, including the potential future use of commodity derivatives to manage commodity price risk;
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2024 Management's Discussion and Analysis
- the foreign currency risk strategies of the Company, the benefits to be derived therefrom and the Company's ability to reverse unrealized foreign exchange gains and losses in the future;
- the Company's ability to reverse previously recognized non-financial asset impairment expenses in the future;
- credit risk assumptions, the Company's expectation to receive past due VAT amounts from the Trinidad government and the Company's expectation to liquidate VAT bonds received by the Trinidad government in lieu of payments;
- 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, its ability to obtain waivers if the related annual financial covenants are breached and its ability to make future scheduled interest and principal payments;
- the potential of future acquisitions or dispositions and receiving required regulatory approvals thereto, including the Company's expectation of closing the Proposed Acquisition and the estimated timing thereof;
- the expected completion and effectiveness of the Fourth Amended and Restated Loan Agreement, including the intended use of proceeds and expected timing of closing, and expectations that the proceeds therefrom will fund the Company's Proposed Acquisition and the development thereof;
- 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".
In addition, information and statements relating to reserves are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. The recovery and reserve estimates presented by Touchstone are estimates only, and there is no guarantee that the estimated reserves will be recovered. Consequently, actual results may differ materially from those anticipated in the forward-looking statements.
The Company's actual decisions, activities, results, performance, or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Touchstone will derive from them. 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 commodity pricing 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
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2024 Management's Discussion and Analysis
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 ongoing geopolitical events and their effect on market prices for crude oil and liquids, 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 non-compliance 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 online on our SEDAR+ profile (www.sedarplus.ca).
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.
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 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, 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 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.
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2024 Management's Discussion and Analysis
Product Type Disclosures
This MD&A includes references to crude oil, NGLs, crude oil and liquids and 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. In addition, references to "crude oil and liquids" herein include crude oil and NGLs.
The Company's total and average production volumes for the past eight quarters and references to "crude oil", "NGLs", "crude oil and liquids" 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.
| Three months ended | Dec. 31, 2024 | Sept. 30, 2024 | June 30, 2024 | March 31, 2024 | Dec. 31, 2023 | Sept. 30, 2023 | June 30, 2023 | March 31, 2023 |
|---|---|---|---|---|---|---|---|---|
| Production | ||||||||
| Light and medium crude oil (bbls) | 114,492 | 109,771 | 100,136 | 100,599 | 98,314 | 103,048 | 96,050 | 108,722 |
| Heavy crude oil (bbls) | 5,995 | 4,638 | 5,254 | 5,535 | 5,966 | 5,831 | 6,270 | 6,918 |
| Crude oil (bbls) | 120,487 | 114,409 | 105,390 | 106,134 | 104,280 | 108,879 | 102,320 | 115,640 |
| NGLs (bbls) | 11,087 | 4,101 | 9,207 | 23,811 | 57,183 | 16,180 | - | - |
| Crude oil and liquids (bbls) | 131,574 | 118,510 | 114,597 | 129,945 | 161,463 | 125,059 | 102,320 | 115,640 |
| Conventional natural gas (Mcf) | 2,128,528 | 2,164,853 | 2,278,297 | 3,050,412 | 3,725,201 | 1,121,585 | 383,572 | 461,189 |
| Total production (boe) | 486,329 | 479,319 | 494,313 | 638,347 | 782,330 | 311,990 | 166,249 | 192,504 |
| Average daily production | ||||||||
| Light and medium crude oil (bbls/d) | 1,245 | 1,194 | 1,100 | 1,105 | 1,068 | 1,120 | 1,055 | 1,208 |
| Heavy crude oil (bbls/d) | 65 | 50 | 58 | 61 | 65 | 63 | 69 | 77 |
| Crude oil (bbls/d) | 1,310 | 1,244 | 1,158 | 1,166 | 1,133 | 1,183 | 1,124 | 1,285 |
| NGLs (bbls/d) | 121 | 45 | 101 | 262 | 622 | 176 | - | - |
| Crude oil and liquids (bbls/d) | 1,431 | 1,289 | 1,259 | 1,428 | 1,755 | 1,359 | 1,124 | 1,285 |
| Conventional natural gas (Mcf/d) | 23,136 | 23,531 | 25,036 | 33,521 | 40,491 | 12,191 | 4,215 | 5,124 |
| Average daily production (boe/d) | 5,287 | 5,211 | 5,432 | 7,015 | 8,504 | 3,391 | 1,827 | 2,139 |
The Company's total and average production volumes for the years ended December 31, 2024 and 2023 and references to "crude oil", "NGLs", "crude oil and liquids" 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.
| Year ended December 31, | ||
|---|---|---|
| 2024 | 2023 | |
| Production | ||
| Light and medium crude oil (bbls) | 424,998 | 406,134 |
| Heavy crude oil (bbls) | 21,422 | 24,985 |
| Crude oil (bbls) | 446,420 | 431,119 |
| NGLs (bbls) | 48,206 | 73,363 |
| Crude oil and liquids (bbls) | 494,626 | 504,482 |
| Conventional natural gas (Mcf) | 9,622,090 | 5,691,547 |
| Total production (boe) | 2,098,308 | 1,453,073 |
| Average daily production | ||
| Light and medium crude oil (bbls/d) | 1,161 | 1,113 |
| Heavy crude oil (bbls/d) | 59 | 68 |
| Crude oil (bbls/d) | 1,220 | 1,181 |
| NGLs (bbls/d) | 132 | 201 |
| Crude oil and liquids (bbls/d) | 1,352 | 1,382 |
| Conventional natural gas (Mcf/d) | 26,290 | 15,593 |
| Average daily production (boe/d) | 5,734 | 3,981 |
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2024 Management's Discussion and Analysis
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56
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:
| Oil and natural gas measurement | Other | ||
|---|---|---|---|
| bbl(s) | barrel(s) | AIM | AIM market of the London Stock Exchange plc |
| bbls/d | barrels per day | C$ | Canadian dollar |
| Mbbls | thousand barrels | NGL(s) | Natural gas liquid(s) |
| Mcf | thousand cubic feet | TSX | Toronto Stock Exchange |
| Mcf/d | thousand cubic feet per day | TT$ | Trinidad and Tobago dollar |
| MMcf | million cubic feet | WTI | Western Texas Intermediate |
| MMcf/d | million cubic feet per day | $ or US$ | United States dollar |
| MMBtu | million British Thermal Units | £ | Pounds sterling |
| boe | barrels of oil equivalent | Q4 | Fourth quarter, representing the three months ended December 31 |
| 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 audited financial statements and our December 31, 2024 Annual Information Form dated March 19, 2025, both of which can be accessed online on our SEDAR+ profile (www.sedarplus.ca) and on our website (www.touchstoneexploration.com).
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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
Brian Hollingshead
Executive Vice President Engineering and Business Development
James Shipka
Executive Vice President Asset Development and HSE
Alex Sanchez
Vice President Production and Environment
Cayle Sorge
Vice President Finance
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.
Unit 416A, South Park Plaza
Tarouba Link Road
San Fernando, 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
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2024 Management's Discussion and Analysis