International exploration & production
Management's Discussion & Analysis
Three and nine months ended
December 31, 2024 and 2023
BENGAL ENERGY LTD.
The following Management's Discussion and Analysis ("MD&A") of the consolidated financial results of Bengal Energy Ltd. ("Bengal" or the "Company") is at and for the three and nine months ended December 31, 2024. This MD&A dated February 6, 2025, should be read in conjunction with the Company's unaudited interim condensed consolidated financial statements and related notes for the quarter ended December 31, 2024. The condensed consolidated financial statements of the Company have been prepared in accordance with International Accounting Standard No.34, Interim Financial Reporting ("IAS 34"). These accompanying condensed consolidated financial statements have not been reviewed by the Company's independent auditors.
The functional currency of the Company's operating subsidiary, Bengal Energy (Australia) Pty Ltd. ("Bengal Australia"), is the Australian dollar; the functional currency of the Company is the Canadian dollar ("CAD"). The Company's presentation currency is the CAD. In this MD&A, all dollar amounts are expressed in CAD unless otherwise noted.
This MD&A contains non-IFRS measures, abbreviations and forward-looking information relating to future events and the Company's future performance. Please refer to "Non-IFRSMeasurements", "Abbreviations" and "Advisories" sections at the end of this MD&A for further information. Additional information relating to Bengal, including Bengal's audited March 31, 2024, consolidated financial statements and other filings are available on SEDAR at www.sedarplus.ca. In the following discussion, the three months ended December 31, 2024, may be referred to as "third quarter of fiscal 2025", "Q3 fiscal 2025", "current quarter", and "the quarter". The comparative three months ended December 31, 2023, may be referred to as "third quarter of fiscal 2024", "Q3 fiscal 2024".
THIRD QUARTER 2025 SUMMARY
Financial summary:
- Sales revenue - Crude oil sales revenue was $1.4 million in the third quarter of fiscal 2025, 11% lower than $1.6 million in Q3 fiscal 2024. Oil lifted was 22% lower in Q3 fiscal 2025 at 124 bbl/d compared to 174 bbl/d in Q3 fiscal 2024. The decreased volume was partially offset by a 25% increase in realized oil prices. More than half of the volumes in the third quarter of fiscal 2025 were sold in October at US$79.53/bbl, which coupled with a stronger US dollar relative to the Canadian dollar, resulted in higher realized prices.
- Funds from operations1 - Funds from operations was $23 thousand during the third quarter of fiscal 2025 compared to funds used in operations of $143 thousand in Q3 fiscal 2024, helped by lower royalties and operating expenses.
- Net loss - Bengal reported a net loss of $0.4 million in the third quarter of fiscal 2025 compared to net loss of $0.5 million in the third quarter of fiscal 2024, the decrease in net loss was due to lower royalties, operating and G&A costs more than offsetting the decline in revenue.
Operational summary:
● Production volumes - The Company's share of total Cuisinier production in the current quarter was 11,420 bbls (124 bbl/d), a decrease of 29% compared to production of 16,013 bbls (174 bbl/d) in the third quarter of fiscal 2024. The Company continues to investigate the material change in production allocation provided by the Cuisinier operator. Bengal has requested field support to clarify the nature of the change in allocation and is awaiting further information from the operator.
● Capital expenditures - Capital activity was limited as Bengal has delayed its capital programs subject to the availability of financing.
1 See "Non-IFRS and Other Financial Measures" on page 13 of this MD&A.
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MANAGEMENT'S DISCUSSION AND ANALYSIS
Business Overview
Bengal's producing and non-producing assets are situated in Australia's Cooper Basin, a region featuring large accumulations of very light and high-quality crude oil and natural gas. The Company's core Australian assets, Petroleum Lease ("PL") 303 Cuisinier, Authority to Prospect ("ATP") 934 Barrolka, Potential Commercial Area ("PCA") 332 (formerly ATP 732) Tookoonooka, and four petroleum licenses are situated within an area of the Cooper Basin that is well served with production infrastructure and take-away capacity for produced crude oil and natural gas. Still in early stages in terms of appraisal and development, Bengal believes these assets offer attractive upside potential for both oil and gas. Australia presents a stable political, fiscal, and economic environment in which to operate, and a favourable royalty regime for oil and gas production. In addition, Bengal owns a 26km 6" high pressure gas pipeline (PPL 138) connecting the Wareena field to a large raw gas network passing Bengal's prospects at ATP 934.
Under the State of Queensland Regulatory process, ATPs are granted by the State generally for a period of twelve years with one-third of the original grant area expiring every four years. At the end of the final term of the ATP, an application can be made to continue a portion of the permit in the form of a Potential Commercial Area ("PCA"). PCAs have a life span of five to fifteen years. PCA applications include a commercial viability report that indicates that the area is likely to be commercially viable within the applied term. This allows for extra time to commercialize any identified Resource. These PCAs remain a part of the ATP until expiry. If a discovery of oil or gas is made, an application for a PL is made to allow for production. PLs are granted for up to a thirty-year term.
Bengal has a 30.375% interest in two PLs on the former ATP 752 Barta block, PL 303 and PL 1028. In addition, the Company has three PCAs associated with ATP 752 which are the Barta block, PCA 206 and PCA 207 and PCA 155 in the Wompi block which contains the Nubba well. Bengal also holds a 100% working interest in four PLs including PPL 138 adjacent to the 100% owned ATP 934.
Following extensive public consultation, in late December 2023 the Queensland government released a document outlining its plans for increased restrictions to petroleum activities within the rivers and floodplains area of the Lake Eyre Basin (LEB) catchment. Bengal Energy areas affected by this are the western portion of the Durham Downs block (ATP 934) where Bengal holds a 40% interest and PCA 115 (Nubba)(ATP 752 Wompi) in which Bengal holds a 38% interest. Of these permits, work can continue to develop gas resources under an existing petroleum lease. No additional PL's have been acquired by Bengal since the new Queensland Legislation came into effect.
In the Wompi portion of the Bengal ATP 752 permit (Bengal 38.5% WI) the discovered volumes of natural gas in the Nubba well are deemed too small for commerciality, and Bengal and partners will move to relinquish this block. In the western portion of ATP 934 in the Durham Downs East block (Bengal 40% W.I.) which is the part of ATP 934 which was farmed out, the operator is expected to withdraw from the permit subject to the terms of the Joint Operating Agreement (JOA) leaving Bengal with 100% interest. Bengal anticipates relinquishing this interest and is working with the regulator to secure favourable relinquishment terms. Neither of these assets have any carrying value in the Company's financial statements. Bengal prospects within Barrolka East (ATP 934 - 100% WI), Ghina (PL 1109 - 100% WI), Wareena (PL 1110 - 100% WI), Ramses PL 411, Karnak PL 188 and Tookoonooka (PCA 332 - 100% WI) are unaffected.
AUSTRALIA - Cooper Basin, Queensland
PL 303 Barta Block Cuisinier (controlling permit ATP 752) (30.357% WI)
The Company continues to evaluate the results of its water injection program at Cuisinier. The injection of produced formation water has resulted in both increased production in up to four offsetting wells and reduced water handling charges. Whilst the JV has observed compelling evidence that the overall field decline has been temporarily arrested with a modest upward trend in oil production during periods of operation, the water injection program has suffered from extended shut-in periods due to equipment failure and lack of available replacement parts. The program was intermittently operational during fiscal 2025; however, its impact to the joint venture is not currently measurable given unexplained changes to the Operator's allocation methodology. Bengal continues to challenge the Operator on this performance shortfall; however, despite reservoir response, it is expected that the operator will permanently suspend the pilot due to ongoing mechanical failures. Based on the results of the pilot, despite mechanical failures, the operator is evaluating locations to implement a waterflood in the main part of the reservoir.
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PL 114 Wareena, PL 157 Ghina, PL 188 Ramses, PL 411 Karnak, PPL 138 pipeline (100% WI)
The Company has a 100% working interest in four PLs and a natural gas pipeline connected to transportation infrastructure into the Eastern Australia Gas Market. These non-productive PLs are highly compatible and near ATP 934. Bengal continues to integrate subsurface data from the PLs to enhance the Company's understanding of ATP 934 and to finalize the selection of exploration and appraisal drilling locations.
Included in this program are: two potential recompletions at Ramses; the Wareena 5 well; the Ghina recompilation; and the redrill or sidetracking opportunity at the Karnak well. The reinstatement of the existing gas pipeline will support the production of raw gas into existing infrastructure. The Company completed workover activities at Wareena 1 and Wareena 5 in November 2022. Initial test results indicate Wareena 1 would require additional stimulation and dewatering to yield commercial production rates. The Company was encouraged by wellhead pressure measured at Wareena 5 and believes that additional testing is justified upon availability of financing and field equipment.
The 100% ownership of these assets presents an appraisal and development opportunity that will be operated by the Company and is seen as a steppingstone for Bengal's natural gas platform upon which future development and appraisal work at the existing PLs and exploration growth through ATP 934 can be undertaken.
PCA 332 Tookoonooka (100% WI; formerly ATP 732)
Bengal conducted an acid treatment in 2022 on the Caracal-1 well to improve well bore inflow with positive results and moderate inflow of very light 53-degree gravity oil from the Wyandra zone. While not immediately commercially viable, these results are being evaluated with the possibility of fracture stimulation being considered to further enhance productivity being put in place. The well is currently suspended with shut-in pressure data being monitored.
ATP 732 reached the end of its term in March of 2023 and the Company lodged an application over the northern portion of the ATP for continuation in the form of PCA 332 for a further 15 years. Based on the positive results from Caracal-1, the application was approved on January 30, 2023. The PCA, granted by the Queensland Government in record time, provides much-needed certainty for Bengal to focus on its hydrocarbon projects in the Talgeberry-Tintaburra corridor. The majority of PCA 332 is covered by 3D seismic which has outlined the prospective targets as described in the Company's press release: "Bengal Energy Announces Independent Oil and Natural Gas Resource Report" dated March 30, 2022. The Company announced the completion of its Field Resource Maturation and Development Plan for its Tookoonooka PCA332 on March 14, 2024.
ATP 934 Barrolka East (100% WI)
ATP 934 is the Company's 100% owned natural gas exploration block. Bengal received approval of a special amendment for ATP 934 in March 2021 which relinquished 50% of the existing ATP area and extended the term of the ATP by entering an outcome based on the Later Work Permit ("LWP") for another 6 years to February 28, 2027. As part of the special amendment, another relinquishment of 118 sub blocks (50% of the remaining sub blocks) (88,972 acres) was required by February 28, 2023. The relinquishment was made and accepted by the regulator during April of 2023.The relinquished area was not considered to be prospective by the Company due to the lack of identified prospects and limited physical access. The current LWP includes the drilling of up to three wells and acquisition of 260 km2 of 3D seismic. The Company has proposed a further swap of non-prospective land in the Durham Downs portion of this ATP in consideration for further extension.
AC/RL 10 Katandra (100% WI)
The Katandra permit is in the offshore Ashmore-Cartier region of the Timor Sea and holds the Katandra 1 oil discovery and the up-dip, Katandra North opportunity. The opportunity is hosted in the prolific Berriasian sandstones of the Upper Vulcan Formation. Bengal has entered into a binding term sheet agreement with an undisclosed party which grants an option to acquire an 80% working interest in the prospect in exchange for assignment of operatorship and carrying out all administrative support activities and possible future financing arrangements on the permit until such time as the applied for five year extension of the permit has been approved by the regulatory authority and the option has been exercised by the option holder. All associated expenses are being carried by the farm-in party.
Business development
Bengal is in ongoing discussions regarding potential farm-out opportunities surrounding its exploration and development portfolio as well as other corporate initiatives aimed at increasing shareholder value. The Company is unable to estimate the chance of success or update status until the culmination of any or all these initiatives.
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OPERATING SUMMARY
($000s except per share, %, volumes | Three months ended | Nine months ended | |||
and operating netback(1) amounts) | 2024 | December 31, | 2024 | December 31, | |
2023 | 2023 | ||||
Oil sales ($) | 1,431 | 1,609 | 4,585 | 5,218 | |
Operating netback(1) ($) | 706 | 592 | 2,218 | 2,384 | |
Cashflow from (used in) operating | 298 | (122) | |||
activities ($) | 759 | 14 | |||
Funds from (used in) operations(1) ($) | 23 | (143) | (68) | (28) | |
-Per share ($) (basic and diluted) | (0.00) | (0.00) | (0.00) | (0.00) | |
Net loss | (370) | (504) | (1,188) | (1,081) | |
-Per share ($) (basic and diluted) | (0.00) | (0.00) | (0.00) | (0.00) | |
Capital expenditures ($) | 12 | 71 | 70 | 399 | |
Oil production (bbl/d) | 124 | 174 | 141 | 175 | |
Operating netback(1) ($/bbl) | 61.83 | 36.97 | 57.04 | 49.41 | |
Non-IFRS and Other Financial Measures. | |||||
RESULTS OF OPERATIONS | |||||
Production | Three months ended | Nine months ended | |||
2024 | December 31, | 2024 | December 31, | ||
2023 | 2023 | ||||
Oil production (bbl) | 11,420 | 16,013 | 38,883 | 48,246 | |
Oil production (bbl/d) | 124 | 174 | 141 | 175 |
The Company's share of total Cuisinier production in the current quarter was 11,420 bbls (124 bbl/d), a decrease of 29% compared to production of 16,013 bbls (174 bbl/d) in the third quarter of fiscal 2024.The Company continues to investigate the material change in production allocation provided by the Cuisinier operator which has resulted in a 50 bbl/d decrease in production net to Bengal during the second quarter when compared to the operator's budget. Bengal has requested field support to clarify the nature of the change in allocation and is awaiting further information from the operator.
Revenue/Pricing
The following table outlines the oil lifting from bills of lading, pipeline oil estimates, applicable prices and oil sales reflected in the Company's financial statements:
Three months ended | Nine months ended | ||||
2024 | December 31, | 2024 | December 31, | ||
2023 | 2023 | ||||
Oil lifting | |||||
Volume (000s bbls) | 12.4 | 16.0 | 35.7 | 51.0 | |
Weighted average price (USD/bbl) | 76.92 | 81.39 | 83.73 | 96.05 | |
Sales CAD$ | A | 1,485 | 1,704 | 4,244 | 5,575 |
Pipeline oil | (1.0) | 0.0 | |||
Volume - change (000s bbls) | 0.0 | (2.8) | |||
Price - change (USD/bbl) | (6.38) | (13.82) | 0.68 | (5.41) | |
Net sales - change CAD$ | B | (54) | (95) | 341 | (357) |
Total oil sales CAD$ | A+B | 1,431 | 1,609 | 4,585 | 5,218 |
The price received for Bengal's Australian oil sales is benchmarked on US Brent for the month in which the bill of lading occurs, plus a realized premium due to oil quality differences. Pipeline oil is the term used to describe oil moving along the pipeline from the wellhead to the port which has been legally transferred to the buyer but not priced and waiting to be sold. Lifting occurs when the oil is moved from the port to the ship. The Cuisinier Joint Venture has recently negotiated a revised COPSA with corresponding transportation agreements effective January 1, 2025, through to December 31, 2025.
The realized weighted average price of oil lifting sales decreased by 5% from US$81.39/bbl for the three months ended December 31, 2023, to US$76.92/bbl for the three months ended December 31, 2024. For the nine months ended December 31, 2024, the realized weighted average price of oil lifting sales increased by 3% to
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USD$83.73/bbl, helped by timing of oil lifting in the months with higher reference pricing. For the three months ended December 31, 2024, over 50% of oil lifting was in the month of October 2024, with US$79.53/bbl.
Oil sales were $1.4 million in the quarter ended December 31, 2024. Oil sales were 11% lower compared with the $1.6 million recorded in the quarter ended December 31, 2023, stemming from lower sales volume, offset by higher realized price between the two period, as well as by the higher pipeline volume at period end December 31, 2024, at Brent reference price of US$82.86/bbl.
Oil sales were $4.6 million for the nine months ended December 31, 2024; a 12% decrease compared to $5.2 million in the nine months ended December 31, 2023. This correlates with the 19% decrease in production between the two fiscal period, offset by higher realized oil prices of $117.92/bbl in the current fiscal period compared to $108.15/bbl for the nine months ended December 31, 2023, which was supported by increase in the value of US dollars compared to Canadian and Australian dollars.
The following table outlines average benchmark prices:
Three months ended | Nine months ended | |||
2024 | December 31, | 2024 | December 31, | |
2023 | 2023 | |||
Brent oil ($/bbl) | 104.41 | 113.93 | 109.76 | 111.79 |
Brent oil (USD/bbl) | 74.61 | 83.73 | 79.70 | 82.90 |
Number of CAD$ for 1 USD | 1.40 | 1.36 | 1.38 | 1.35 |
Number of CAD$ for 1 AUD | 0.91 | 0.89 | 0.91 | 0.89 |
The following table outlines operating netback: | ||||
Operating netback(1) | Three months ended | Nine months ended | ||
2024 | December 31, | 2024 | December 31, | |
($000s and $/bbl) | 2023 | 2023 | ||
Oil sales | 1,431 | 1,609 | 4,585 | 5,218 |
Royalties | (86) | (205) | (349) | (419) |
Operating expense | (639) | (812) | (2,018) | (2,415) |
Operating netback | 706 | 592 | 2,218 | 2,384 |
Oil sales ($/bbl) | 125.31 | 100.48 | 117.92 | 108.15 |
Royalties ($/bbl) | (7.53) | (12.80) | (8.98) | (8.68) |
Operating expense ($/bbl) | (55.95) | (50.71) | (51.90) | (50.06) |
Operating netback ($/bbl) | 61.83 | 36.97 | 57.04 | 49.41 |
- See Non-IFRS and Other Financial Measures.
Operating netback was $61.83/bbl for Q3 fiscal 2025, 67% higher than Q3 fiscal 2024 of $36.97/bbl. The increase in operating netback was driven primarily by higher oil sales price of $125.31/bbl compared to $100.48/bbl, (25%) as well as the 41% lower royalties per barrel.
Operating netback for the nine months ended December 31, 2024, of $57.04/bbl compared to the nine months ended December 31, 2023 of $49.41/bbl, increased by 15%, with the oil sales realized price contributing to majority of the increase.
Royalties
Royalties | Three months ended | Nine months ended | ||||||
2024 | December 31, | 2024 | December 31, | |||||
2023 | 2023 | |||||||
Royalty expense | 86 | 205 | 349 | 419 | ||||
$/bbl | $ | 10.28 | $ | 12.80 | $ | 9.58 | $ | 8.68 |
% of revenue | 6.0% | 12.7% | 7.6% | 8.0% |
In Queensland Australia, oil royalties are based on a government-established rate net of eligible expenditures which scales according to benchmark oil prices plus a Native Title royalty of 1%. Royalties were lower at 6.0% in the three months ended December 31, 2024, compared to 12.7% in the three months ended December 31, 2023. The higher royalty percentage in the three months ended December 31, 2023, contained year-end royalty adjustments booked by the operator, which added additional royalties in fiscal 2024 and reduced year to date royalties in fiscal 2025.
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Royalties were lower by $0.1 million between the nine months ended December 31, 2024, compared to the nine months ended December 31, 2023, with the same factors as above. On an annual basis, royalty rate is expected to be 7% to 9% for the remainder of fiscal 2025.
Operating Expense
Operating Expense | Three months ended | Nine months ended | |||||
2024 | December 31, | 2024 | December 31, | ||||
($000s and $/bbl) | 2023 | 2023 | |||||
Production | 212 | 304 | 652 | 800 | |||
Transportation | 427 | 508 | 1,366 | 1,615 | |||
639 | 812 | 2,018 | 2,415 | ||||
Production ($/bbl) | 18.56 | 18.98 | $ | 16.77 | $ | 16.58 | |
Transportation ($/bbl) | 37.39 | 31.72 | $ | 35.13 | $ | 33.47 | |
$ | 55.95 | $ | 50.71 | $ | 51.90 | $ | 50.06 |
Total operating expense during Q3 fiscal 2025 decreased by 21% compared to Q3 fiscal 2024 primarily due to decrease in production as previously described.
The operating expense for the nine months ended December 31, 2024, was $2.0 million, 16% lower than the nine months ended December 31, 2023, of $2.4 million. Operating expense per barrel in these two fiscal periods was 4% higher from $50.06 to $51.90, stemming from the 19% lower volumes, offset by the fixed component of operating costs.
General and Administrative (G&A) Expense
G&A | Three months ended | Nine months ended | ||
2024 | December 31, | 2024 | December 31, | |
2023 | 2023 | |||
Net G&A expense | 644 | 713 | 2,163 | 2,355 |
Capitalized G&A | - | 28 | 19 | 138 |
Total G&A expense | 644 | 741 | 2,182 | 2,493 |
Net G&A expense for the three months ended December 31, 2024, was $0.6 million, comparable to $0.7 million in the three months ended December 31, 2023.
For the nine months ended December 31, 2024, bet G&A expense was $2.2 million, 12% lower than $2.4 million for the nine months ended December 31, 2023. This was to lower activity levels and reduced staffing levels.
Share-based Compensation ("SBC")
SBC | Three months ended | Nine months ended | ||
2024 | December 31, | 2024 | December 31, | |
2023 | 2023 | |||
Expensed SBC | 7 | 7 | 9 | 23 |
Capitalized SBC | - | - | 4 | 1 |
7 | 7 | 13 | 24 |
The Company uses the Black-Scholes pricing model to estimate the fair value of options on the date of grant and amortizes the estimated expense over the vesting period with a corresponding charge to contributed surplus. Options expire five years from the grant date. There were 750,000 options issued during the third quarter of fiscal 2025 with a value of $0.01 per share and a total of 1,500,000 options issued during the nine months ended December 31, 2024. Share-based compensation for Q3 fiscal 2025 includes only the value of newly granted options in fiscal 2025 as the value of previous grants has been fully recognized in previous periods.
The Company uses the Black-Scholes pricing model to estimate the fair value of options on the date of grant and amortizes the estimated expense over the vesting period with a corresponding charge to contributed surplus. Options expire five years from the grant date.
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Depletion and Depreciation (DD&A)
DD&A | Three months ended | Nine months ended | ||
2024 | December 31, | 2024 | December 31, | |
2023 | 2023 | |||
Petroleum and natural gas properties | 274 | 299 | 932 | 868 |
Other assets | 1 | 1 | 2 | 2 |
Right-of-use assets | - | 7 | - | 22 |
DD&A | 275 | 307 | 934 | 892 |
DD&A ($/bbl) | 24.08 | 19.17 | 24.02 | 18.49 |
Depletion expense increased on a per barrel basis in the current fiscal quarter of 2025 compared to the third fiscal quarter of 2024 due to decrease in reserves volumes on which depletion is calculated.
Finance Expense
Finance Expense | Three months ended | Nine months ended | ||
2024 | December 31, | 2024 | December 31, | |
2023 | 2023 | |||
Accretion expense on decommissioning | 38 | 113 | ||
and restoration liability | 45 | 133 | ||
Interest expense (income) | 87 | (1) | 93 | 7 |
125 | 44 | 206 | 140 |
Accretion expense on decommissioning and restoration liabilities was consistent between the three and nine months ended December 31, 2024, and December 31, 2023. Interest expense for three months ended December 31, 2024, stems from the Joint Venture payment plan with a carrying value of $2.2 million entered into in October 2024.
CAPITAL EXPENDITURES
Capital expenditures | Three months ended | Nine months ended | ||
2024 | December 31, | 2024 | December 31, | |
2023 | 2023 | |||
Geological, geophysical and workovers | 12 | 71 | 84 | 399 |
Drilling | - | - | - | - |
12 | - | 84 | 399 | |
Exploration and evaluation expenditures | - | 10 | 15 | 52 |
Development and production expenditures | 12 | 61 | 69 | 347 |
12 | 71 | 84 | 399 |
Development and production expenditures were minimal in the three and nine months ended December 31, 2024, as the Company is looking to obtain additional financing and joint venture partners for capital development.
SHARE CAPITAL
Trading history | Three months ended | Nine months ended | ||
2024 | December 31, | 2024 | December 31, | |
2023 | 2023 | |||
High ($/share) | 0.01 | 0.05 | 0.04 | 0.08 |
Low ($/share) | 0.01 | 0.02 | 0.04 | 0.02 |
Close ($/share) | 0.01 | 0.03 | 0.01 | 0.03 |
Average Daily Volume | 1,733 | 1,267 | 9,957 | 3,338 |
Weighted average shares outstanding | ||||
(000s) | 485,304 | 485,304 | ||
Basic | 485,304 | 485,304 | ||
Diluted | 485,304 | 485,304 | 485,304 | 485,304 |
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At February 6, 2025, there were 485,304,215 common shares issued and outstanding, together with 9,570,000 outstanding options.
LIQUIDITY RISK AND CAPITAL RESOURCES
Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including work commitments, as they are due. Bengal prepares an annual budget and updates forecasts for operating, financing, and investing activities on an ongoing basis to ensure it will have sufficient liquidity to meet its liabilities when due.
Bengal's financial liabilities consist of trade and other payables and Joint Venture payment plan, totalling $3.1 million at December 31, 2024 (March 31, 2024 - $3.2 million).
At December 31, 2024, the Company had working capital of $1.0 million (March 31, 2024 - $0.2 million), which the Company defines as total current assets less total current liabilities.
The Company's working capital includes both accrued accounts receivable and trade and other payable, and the current portion of Joint Venture payment plan. The Company does not have the legal right to offset these accounts and therefore there is a risk that the inability to collect on accrued receivables could impair Benga's ability to pay joint venture liabilities resulting in a default under the Cuisinier Joint Operating Agreement. This default could result in the Company losing some or all of its working interest in the Cuisinier field.
Over the past 21 months, the Company has accrued an outstanding balance of $2.0 million due to the operator of the Cuisinier field resulting from withholding payments associated with disputed overhead charges. These disputed charges relate to overhead allocations, interest and penalties that Bengal does not consider allowable by the operator and is challenging through the joint venture audit process. During October 2024, the Company entered into an agreement with the operator to settle the outstanding payable under a 24-month payment plan that will include equal principal installments plus interest (Westpac Bank Bill Swap Rate or "BBSW") through October 2026. Any audit adjustments posted during this time will reduce the outstanding payable amount and any failure to meet the payment obligations of the plan will result in a default under the terms of the joint venture agreement resulting in the loss of some or all the Company's working interest in the Cuisinier field.
The Company also has significant capital work commitments associated with its exploration and evaluation assets that if unfulfilled could result in a loss of acreage as described in Note 17 of the accompanying interim condensed consolidated financial statements and without future development could result in a decline in production and revenues with additional net cash used in operating activities. The Company's ability to continue as a going concern is dependent upon its ability to generate net cash from operating activities and/or raise additional financing to meet its ongoing operational requirements and to fund its future development costs associated with exploration and evaluation assets and petroleum and natural gas properties development. As outlined in Note 2 of the interim condensed consolidated financial statements, the Company has assessed that there is material uncertainty that may cast significant doubt about its ability to continue as a going concern.
The majority of the Company's oil sales are benchmarked on US Brent prices. The Company incurs most of its expenditures in Australian dollars whereas the Company generates most of its revenues in US dollars. The Company is acting with its joint venture partners to reduce discretionary operational spending and limiting its capital expenditures capital towards lower risk projects that meet its internal economic hurdles and are expected to offer near-term cash flow upside.
OFF BALANCE SHEET TRANSACTIONS
The Company does not have any off-balance sheet transactions as at December 31, 2024.
COMMITMENTS
The Queensland Government regulatory authority granted the Company Authority to Prospect 934 ("ATP 934") under a revised work program on March 1, 2015. The Company consolidated its ownership of ATP 934, resulting in a 100% and 40% operating interest in the northern and southern block of this permit respectively in 2018. The work program consists of 260 km2 of 3D seismic and up to three wells. In February 2023, the Company extended its ATP 732 permit and received a Potential Commercial Area ("PCA") over 343 km2. This included additional work commitments related to both ATP 732 and PCA 332 as outlined below.
At December 31, 2024, the Company had the following capital work commitments:
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Permit | Work Program | Obligation | Estimated |
period ending | expenditure (net) | ||
(millions CAD$)(1) | |||
ATP 934 - Onshore Australia | 260 km2 3D seismic and up to three | February 2027 | 7.9 |
wells | |||
ATP 732 - Onshore Australia | Geological and up to three wells | February 2029 | 6.8 |
PCA 332 - Onshore Australia | Initial Production testing | February 2029 | 3.9 |
PCA 332 - Onshore Australia | Extended Production testing | February 2035 | 2.3 |
- Translated at December 31, 2024 at an exchange rate of AUD$1.00 = CAD$0.8915.
The Company entered into a lease agreement for office space in October 2023 with a contract term ending in February 2027.
At December 31, 2024, the contractual obligations for which the Company is responsible are as follows:
Contractual obligations
(000s) | Total | Less than 1 | 1-3 years | 4-5 years | After 5 | ||||
year | years | ||||||||
Office lease | 50 | 23 | 27 | - | - | ||||
Joint Venture payment plan | 1,673 | 969 | 704 | - | - | ||||
Decommissioning and restoration | 3,695 | - | 794 | - | 2,901 | ||||
5,368 | 969 | 1,498 | - | 2,901 | |||||
SELECTED QUARTERLY INFORMATION | |||||||||
Fiscal quarter | Dec 31 | Sep 30 | Jun 30 | Mar 31 | Dec 31 | Sep 30 | Jun 30 | Mar 31 | |
($000s except per share, | 2024 | 2024 | 2024 | 2024 | 2023 | 2023 | 2023 | 2023 | |
volumes and operating | Q3 2025 | Q2 2025 | Q1 2025 | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 | Q4 2023 | |
netback(1)) | |||||||||
Oil sales ($) | 1,431 | 1,252 | 1,902 | 1,815 | 1,609 | 1,937 | 1,672 | 1,954 | |
Cashflow from (used in) | 298 | ||||||||
operating activities ($) | (129) | (291) | (287) | 592 | (643) | (102) | (704) | ||
Funds from (used in) | 23 | ||||||||
operations(1) ($) | (294) | 203 | 329 | (143) | 123 | (8) | (431) | ||
-Per share($)-basic and diluted | - | - | - | - | - | - | - | - | |
Net (loss) income | (370) | (608) | (210) | (11,647) | (504) | (213) | (364) | (803) | |
-Per share($)-basic and diluted | - | - | - | - | - | - | - | - | |
Capital expenditures ($) | 12 | 9 | 63 | 75 | 71 | 115 | 213 | 395 | |
Working capital (deficit) | 957 | 152 | 448 | 199 | (53) | 160 | (491) | (284) | |
Total assets | 33,558 | 35,494 | 35,326 | 34,361 | 47,987 | 46,793 | 48,419 | 49,697 | |
Shares outstanding (000) | 485,304 | 485,304 | 485,304 | 485,304 | 485,304 | 485,304 | 485,304 | 485,304 | |
Operations: | |||||||||
Oil production (bbl/d) | 124 | 127 | 174 | 162 | 174 | 176 | 176 | 182 | |
Operating netback(1) ($/bbl) | 61.83 | 42.84 | 64.08 | 67.49 | 36.97 | 59.48 | 51.68 | 65.75 |
- See Non-IFRS and Other Financial Measures on page 12 of this MD&A.
Production was relatively stable over the past eight quarters averaging 169 bbl/d despite natural reservoir declines in the Cuisinier oil field until the current quarter when field allocations resulted in a 50 bbl/d decrease in production net to Bengal. Ongoing volatility in US Brent prices from Q3 fiscal 2023 to Q2 fiscal 2025 resulted in volatility in oil sales with the production declines impacting the current quarter as described above. Net income, cashflow and funds from operations were impacted primarily by production volumes. The impact of volatile commodity pricing and production decreases in the quarter impacted cash flow from operations. Working capital deficiency occurred during the fiscal Q4 2023 and fiscal Q1 2024 as a result of the Cuisinier joint venture royalty adjustment. Working capital at Q3 2025 improved due to Joint Venture payment plan obtained in October 2024. Net loss in Q4 2024 was impacted by an impairment expense of $11.6 million recognized in its property plant and equipment balance.
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