First Quarter FISCAL 2026 Summary (BNG Q1F2026)

International exploration & production

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 months June 30, 2025 and June 30, 2024. This MD&A dated August 7, 2025, should be read in conjunction with the Company's unaudited interim condensed consolidated financial statements and related notes for the three months ended June 30, 2025. The interim 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 interim 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-IFRS Measurements", "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, 2025, consolidated financial statements and other filings are available on SEDAR at https://www.sedarplus.ca. In the following discussion, the three months ended June 30, 2025, may be referred to as "first quarter of fiscal 2026", "Q1 fiscal 2026", "current quarter", and "the quarter". The comparative three months ended June 30, 2024, may be referred to as "first quarter of fiscal 2025", "Q1 fiscal 2025" and "prior year's quarter".

FIRST QUARTER FISCAL 2026 SUMMARY

Financial summary:

• Sales revenue - Crude oil sales revenue was $1.0 million in the first quarter of fiscal 2026, 45% lower than $1.9 million in Q1 fiscal 2024. Production was 120 barrels of oil per day ("bopd") in Q1 fiscal 2025, 31% lower than 174 bopd in Q1 fiscal 2025 and realized pricing was 21% lower during Q1 fiscal 2026 compared to Q1 fiscal 2025.

• Funds from operations 1 - Funds used in operations was $23 thousand during the first quarter of fiscal 2026 compared to funds from operations of $203 thousand in Q1 fiscal 2024. The decrease was mainly due to lower sales revenue of $0.9 million, offset by lower operating expense of $0.4 million and lower G&A expense of $0.3 million.

• Net loss - Bengal reported a net loss of $0.3 million in the first quarter of fiscal 2026 compared to net loss of $0.2 million in the first quarter of fiscal 2025.

  Operational summary:

• Production volumes - The Company's share of total Cuisinier production in the current quarter was 10,910 bbls (120 bopd) decrease of 31% compared to production of 15,793 bbls (175 bopd) in the first quarter of fiscal 2025. The decrease in production was due to a change in field measurement process by the operator from allocation to metering as well as natural declines and well uptime. Incremental production from workover activity was expected during the quarter however production improvements were delayed due to a flooding event in the Cooper Basin restricting surface operations.

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,

‌1 See "Non-IFRS and Other Financial Measures" on page 11 of this MD&A.

2

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 suitable locations to implement a waterflood in the main part of the reservoir. Bengal is strongly encouraging the operator to focus its development activities on pressure maintenance in the reservoir before considering new drilling activity.

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 is encouraged by wellhead pressure measured at Wareena 5 and believes that additional testing is justified upon the 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 two 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 a reduction in the outcome-based LWP and a potential 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, despite significant efforts to secure a farm-in partner for this permit, was unable to secure one with the appropriate expertise and financial capacity within prescribed timelines, and thus, on May 2, 2025, Bengal submitted a notification of withdrawal in relation to its renewal application of the retention lease. This was accepted by the Australian Government on May 6, 2025. Given that these assets had nil carrying value, there was no financial statement impact from this relinquishment. There are no abandonment liabilities associated with this licence.

Business development

From time to time Bengal is in ongoing has 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 of these discussions.

OPERATING SUMMARY

($000s except per share, %, volumes and operating netback(1) amounts)

Three months ended

June 30.

RESULTS OF OPERATIONS

Production Three months ended

June 30,

The Company's share of total Cuisinier production in the current quarter was 10,910 bbls (120 bopd) decrease of 31% compared to production of 15,793 bbls (174 bopd) in the first quarter of fiscal 2025. The decrease in production was due to downhole issues in four Cuisinier wells deferring 35 bopd of production during downtime. Workover activities in Q1 fiscal 2026 have restored production at three of the four wells thus far. The decrease in production in the last part of fiscal 2025 and continued to fiscal 2026 was the result of overall pressure declines in the reservoir. The decrease in production was due to a change in field measurement process by the operator from allocation to metering as well as natural declines and well uptime. Incremental production from workover activity was expected during the quarter however production improvements were delayed due to a flooding event in the Cooper Basin restricting surface operations.

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

June 30,

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 was US$66.56/bbl and US$90.35/bbl for the current and previous year's quarters respectively, which is a decrease of 26%. Brent reference price between the two fiscal quarters was 20% lower. During the current quarter fiscal 2026, the value of the pipeline oil decreased by $0.1 million due pricing, contributing to 5% of the oil price decrease.

Oil sales were $1.0 million in the first quarter of fiscal 2026, compared to $1.9 million in the first quarter of fiscal 2025. Factors include the 21% decline in oil price as well as production decreased by 31% from 174 bbl/d in Q1 fiscal 2024 to 120 bbl/d in Q1 fiscal 2026.

The following table outlines average benchmark prices:

(1) See Non-IFRS and Other Financial Measures.

Operating netback was $54.08/bbl for Q1 fiscal 2026, 16% lower than Q1 fiscal 2025 of $64.08/bbl. The decrease in operating netback was driven primarily by lower realized oil price of $95.60/bbl compared to $120.43/bbl, a decrease of 21% partially offset by a decrease in operating expenses. The decrease in oil sales of 21% correlates with the decrease in Brent reference price between the first quarters of fiscal 2026 and fiscal 2025.

Royalties Three months ended

June 30,

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 of $0.1 million were consistent between the three months ended June 30, 2025 and June 30, 2024. Royalties as a % of revenue was higher at 9.7% compared to the three months ended June 30, 2024 of 7.5%. The net increase in pipeline oil change in the three months ended June 30, 2024 contributed to a lower royalty rate in the prior period. On an annual basis, royalty rate is expected to be 7% to 9% for the remainder of fiscal 2026.

Operating Expense

Operating Expense Three months ended

June 30,

Total operating expense during the current quarter fiscal 2026 was $0.4 million compared to $0.7 million in the first quarter of fiscal 2025. Transportation costs per barrel were higher during the current quarter due to a fixed portion of these costs that did not decrease concurrently with production. Production expense was positively impacted by a $0.2 million credit recognizing joint venture audit findings recorded during the quarter. The Company continues its ongoing audit of joint venture expenditures.

General and Administrative (G&A) Expense

G&A Three months ended

June 30,

Net G&A expense for the three months ended June 30, 2025, was $0.5 million, $0.3 million lower than the three months ended June 30, 2024, overall lower activity levels and reduced staffing levels.

Share-based Compensation ("SBC")

SBC Three months ended

June 30,

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.

Depletion and Depreciation (DD&A)

DD&A Three months ended

June 30,

Depletion expense in the current fiscal quarter June 30, 2025 was lower compared to the prior fiscal quarter June 30, 2024 due to lower production. There were no indicators of impairment in the current fiscal quarter June 30, 2025.

Finance Expense

Finance Expense Three months ended

June 30,

Accretion expense on decommissioning and restoration liabilities was consistent between the three months ended June 30, 2025 and June 30, 2024. Interest expense for three months ended June 30, 2025 stemmed from the Note Payable of $1.7 million entered into March 2025 with interest rate of 10%.

CAPITAL EXPENDITURES

Capital expenditures Three months ended

June 30,

Expenditures were minimal as the Company is looking to obtain additional financing and joint venture partners for capital development.

SHARE CAPITAL

Trading history Three months ended

June 30,

At June 30, 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 Note Payable totalling $3.5 million at June 30, 2025 (March 31, 2025 - $3.5 million). At June 30, 2025, the Company had a positive working capital of $1.7 million (March 31, 2025 - $1.6 million), which the Company defines as total current assets less total current liabilities, excluding lease obligations and current portion of decommissioning obligations, and Note Payable.

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 (Note 17) and without future development could result in a decline in production and revenues with additional net cash used in operating activities. 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 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.

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 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 June 30, 2025.

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 June 30, 2025, the Company had the following capital work commitments:

Permit Work Program Obligation period ending

Estimated expenditure (net) (millions CAD$)(1)

ATP 934 - Onshore Australia 260 km2 3D seismic and up to three wells

February 2027 8.0

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

(1)Translated at June 30, 2025 at an exchange rate of AUD$1.00 = CAD$0.8943.

The Company entered into a lease agreement for office space in October 2023 with a contract term ending in February 2027. At June 30, 2025, the contractual obligations for which the Company is responsible are as follows:

(1)The current portion the Note Payable $14 thousand is classified as Trade and other payables.

RELATED PARTY TRANSACTIONS

On March 3, 2025, the Company entered into an agreement to refinance its Joint Venture payment plan. The

$1.7 million Note Payable is with Texada, a company controlled by a controlling shareholder and director of Bengal. During the quarter interest of $43 thousand was accrued and due to Texada. At June 30, 2025, accounts payable balance included an accrued interest payable of $12 thousand (March 31, 2025 $15 thousand). Cash interest of $43 thousand was paid in the three months ended June 30, 2025.

SELECTED QUARTERLY INFORMATION

(1)See Non-IFRS and Other Financial Measures on page 12 of this MD&A.

Production declined materially during Q3 fiscal 2024 at the Cuisinier oil field when field allocations resulted in a 50 bbl/d decrease in production net to Bengal. Production was impacted during the past four quarters due to a combination of joint venture allocations that remain under dispute and downhole issues disrupting production at four wells. This decrease in production corresponded to decreases in revenue, funds from operations and income. Ongoing volatility in US Brent prices from Q3 fiscal 2023 to Q1 fiscal 2026 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 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. Net loss in Q4 2025 was impacted by impairment expense of $2.5 million associated with the non-prospective exploration acreage in the Barta block. The operating netback in Q4 2025 was lower due to the oil price collapse in Q4 2025 and the 22% lower production volumes, which negatively impacted the per barrel basis of the operating expense, resulting in overall operating netback of $9.62 per barrel.

DISCLOSURE CONTROLS & PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING (ICFR)

Disclosure Controls and Procedures

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and includes controls and procedures designed to ensure that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the Company's management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure.

The Chief Executive Officer and Chief Financial Officer oversee this evaluation process and have concluded that the design and operation of these disclosure controls and procedures are not effective due to the material weaknesses identified in internal controls over financial reporting as noted below. The Chief Executive Officer and Chief Financial Officer have individually signed certifications to this effect.

Internal Controls over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of Bengal are responsible for designing and ensuring the operating effectiveness of internal controls over financial reporting ("ICFR") or causing them to be designed and operating effectively under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.

Bengal's certifying officers have assessed the design and operating effectiveness of internal controls over financial reporting and concluded that the Company's ICFR were effective at March 31, 2025, with the exception of the material weaknesses noted below.

No changes in internal controls over financial reporting were identified during the period that have materially affected or are reasonably likely to materially affect the Company's internal controls over financial reporting.

While Bengal's Chief Executive Officer and Chief Financial Officer believe the Company's internal controls and procedures provide a reasonable level of assurance that they are reliable, an internal control system cannot prevent all errors and fraud. It is management's belief that any control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

During the design and operating effectiveness assessment, certain material weaknesses in internal controls over financial reporting were identified, as follows:

• Management is aware that there is a lack of segregation of duties due to the small number of employees dealing with general and administrative and financial matters. However, management believes that at this time the potential benefits of adding employees to clearly segregate duties do not justify the costs; and

• Bengal does not have full-time in-house personnel to address all complex and non-routine financial accounting issues and tax matters that may arise. It is not deemed as economically feasible at this time to have such personnel. Bengal relies on external experts for review and advice on complex financial accounting issues.

These material weaknesses in internal controls over financial reporting result in a reasonable possibility that a material misstatement will not be prevented or detected on a timely basis. Management and the Board of Directors work to mitigate the risk of material misstatement; however, management and the Board of Directors do not have reasonable assurance that this risk can be reduced to a remote likelihood of a material misstatement.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

The timely preparation of the financial statements requires management to make judgements, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates, which are reviewed on an ongoing basis.

Significant estimates and judgments made by management in the preparation of these financial statements are outlined below. The economic climate may have significant adverse impacts on the Company, including material declines in revenue and cash flows, and related impacts to working capital levels and/or debt balances, which may also have a direct impact on the Company's operating results and financial position. These and other factors may adversely affect the Company's liquidity and the Company's ability to generate income and cash flows to meet the Company's current and future obligations. A full discussion of the Company's critical judgments and accounting estimates is included in its fiscal 2025 consolidated financial statements dated June 30, 2025.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accounting policies applied are consistent with those of the previous fiscal year as described in Note 3 of the Company's fiscal 2025 consolidated financial statements for the year ended March 31, 2025.

NON-IFRS AND OTHER FINANCIAL MEASURES

Non-IFRS Financial Measures

Within this MD&A, references are made to terms commonly used in the oil and gas industry. Operating netback, operating netback per barrel, funds from (used in) operations, funds from (used in) operations per share, do not have any standardized meaning under IFRS and are referred to as non-IFRS measures. Management believes the presentation of the non-IFRS measures above provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis.

Operating Netback

Bengal utilizes operating netback as key performance indicator and is utilized by Bengal to better analyze the operating performance of its petroleum and natural gas assets against prior periods. Operating netback is

calculated oil sales deducting royalties and operating expenses. The following table reconciles petroleum and natural gas revenue to operating netback:

Operating netback Three months ended

June 30,

Funds from (used in) operations

Management utilized funds from (used in) operations as a measure to assess the Company's ability to generate cash not subject to short-term movements in non-cash operating working capital. Funds from (used in) operations is calculated by adding back all non-cash expense deductions to the net loss for the period ended. The following table reconciles cash from operating activities to funds from operations, which is used in this MD&A:

Funds from (used in) operations Three months ended June 30,

CAPITAL MANAGEMENT MEASURES

Working capital

Bengal uses working capital to monitor its capital structure, liquidity and its ability to fund current operations. Working capital is calculated as current assets less current liabilities but excludes other obligations and current portion of decommissioning obligations.

NON-IFRS FINANCIAL RATIOS

Bengal uses operating netback per boe to assess the Company's operating performance on a per unit of production basis. Operating netback per barrel equals operating netback divided by the applicable number of barrels of production.

Operating netback Three months ended

June 30,

Bengal uses funds from operations per share to assess the ability of the Company to generate the funds necessary for financing, operating, and capital activities on a per-share basis. This is a non-IFRS measure calculated by dividing funds from operations by weighted average basic and diluted shares outstanding for the periods disclosed.

ABBREVIATIONS

The following abbreviations used in this MD&A have the meanings set forth below: bbl - barrel

bbl/d - barrels per day

$/bbl - dollars per barrel

ft3 - cubic feet

boe/d barrels of oil equivalent per day

FY - fiscal year

K - thousand

km - kilometres

km2 - square kilometres

Q1 - three months ended June 30

Q2 - three months ended September 30 Q3 - three months ended December 31 Q4 - three months ended March 31

WI - working interest

COSPA - crude oil sales and purchase agreement

RISK FACTORS

There are a number of risk factors facing companies that participate in the oil and gas industry. A complete list of risk factors is provided in Bengal's Annual Information Form dated June 30, 2025, filed on SEDAR at https://www.sedarplus.ca.

Companies engaged in the oil and gas industry are exposed to a number of business risks, which can be described as operational, financial and political risks, many of which are outside of the Company's control. More specifically, these include risks of economically finding Reserves and producing oil and gas in commercial quantities, marketing the production, commodity prices, environmental and safety risks, and risks associated with the foreign jurisdiction in which the Company operates. In order to mitigate these risks, the Company has an experienced base of qualified technical and financial personnel in Canada. Further, the Company has focused its foreign operations and plans to target future foreign operations in known and prospective hydrocarbon basins in jurisdictions that have previously established long-term oil and gas ventures with foreign oil and gas companies.

Bengal monitors and updates its cash projection models on a regular basis, which assists in the timing decision of capital expenditures. Farm-outs of projects may be arranged if capital constraints are an issue or if the risk profile dictates that Bengal wishes to hold a lesser working interest position. Equity, if available and if on favorable terms, may be utilized to help fund Bengal's capital program.

An investment in the shares of the Company should be considered speculative due to the nature of the Company's involvement in the exploration for and the acquisition, development and production of oil and natural gas in foreign countries, and its current stage of development. An investor should consider carefully the risk factors set out in the annual information form and consider all other information contained herein and, in the Company's, other public filings before making an investment decision. Additional risks and uncertainties not currently known to the management of the Company may also have an adverse effect on Bengal's business and the information set out in the annual information form does not purport to be an exhaustive summary of the risks affecting Bengal.

Exploration, Development and Production Risks

Oil and natural gas exploration involves a high degree of risk, for which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that expenditures made on future exploration by Bengal will result in new discoveries of oil or natural gas in commercial quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over pressured zones, tools lost in the hole and changes in drilling plans and locations because of prior exploratory wells or additional seismic data and interpretations thereof.

The long-term commercial success of Bengal will depend on its ability to find, acquire, develop and commercially produce oil and natural gas Reserves. No assurance can be given that Bengal will be able to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, Bengal may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from

extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

In addition, oil and gas operations are subject to the risks of exploration, development and production of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, cratering, sour gas releases, fires, and spills. Losses resulting from the occurrence of any of these risks could have a materially adverse effect on future results of operations, liquidity, and financial condition.

Bengal attempts to minimize exploration, development, and production risks by utilizing a high-end technical team with extensive experience and multidisciplinary skill sets to assure the highest probability of success in its drilling efforts. Bengal's collaboration of a team of seasoned veterans in the oil and gas business, each with a unique expertise in the various upstream to downstream technical disciplines of prospect generation to operations, provides the best assurance of competency, risk management and drilling success. A full cycle economic model is utilized to evaluate all hydrocarbon prospects. Detailed geological and geophysical techniques are regularly employed including 3D seismic, petrography, sedimentology, petrophysical log analysis and regional geological evaluation.

Risks Associated with Foreign Operations

International operations are subject to political, economic and other uncertainties, including, among others, risk of war, risk of terrorist activities, border disputes, expropriation, renegotiations or modification of existing contracts, restrictions on repatriation of funds, import, export and transportation regulations and tariffs, taxation policies, including royalty and tax increases and retroactive tax claims, exchange controls, limits on allowable levels of production, currency fluctuations, labor disputes, sudden changes in laws, government control over domestic oil and gas pricing and other uncertainties arising out of foreign government sovereignty over the Company's international operations. With respect to taxation matters, the governments, and other regulatory agencies in the foreign jurisdictions in which Bengal operates and intends to operate in the future may make sudden changes in laws relating to taxation or impose higher tax rates, which may affect Bengal's operations in a significant manner. These governments and agencies may not allow certain deductions in calculating tax payable that Bengal believes should be deductible under applicable laws or may have differing views as to values of transferred properties. This can result in significantly higher tax payable than initially anticipated by Bengal. In many circumstances, readjustments to tax payable imposed by these governments and agencies may occur years after the initial tax amounts were paid by Bengal, which can result in the Company having to pay significant penalties and fines. Furthermore, in the event of a dispute arising from international operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of courts in Canada.

Prices, Markets and Marketing of Crude Oil and Natural Gas

Oil and natural gas are commodities that have prices determined based on world demand, supply and other factors, all of which are beyond the control of Bengal. World prices for oil and natural gas have fluctuated in recent years due to geo-political matters. Any material decline in prices could result in a reduction of net production revenue. Certain wells or other projects may become uneconomic because of a decline in world oil prices and natural gas prices, leading to a reduction in the volume of Bengal's oil and gas Reserves. Bengal might also elect not to produce from certain wells at lower prices. All these factors could result in a material decrease in Bengal's future net production revenue, causing a reduction in its oil and gas acquisition and development activities. In addition to establishing markets for its oil and natural gas, Bengal must also successfully market its oil and natural gas to prospective buyers. The marketability and price of oil and natural gas, which may be acquired or discovered by Bengal, may be affected by numerous factors beyond its control.

The ability of Bengal to market its natural gas may depend upon its ability to acquire space on pipelines, which deliver natural gas to commercial markets. Bengal may also likely be affected by deliverability uncertainties related to the proximity of its Reserves to pipelines and processing facilities and related to operational problems with such pipelines and facilities and extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.

Substantial Capital Requirements and Liquidity

Bengal's cash flow from its Reserves may not be sufficient to always fund its ongoing activities, as was the case in the current fiscal quarter. From time to time, Bengal may require additional financing to carry out its oil and gas acquisition, exploration, and development activities. Failure to obtain such financing on a timely basis could cause Bengal to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If Bengal's revenues from its Reserves decrease because of lower oil and natural gas prices or otherwise, it may affect Bengal's ability to expend the necessary capital to replace its Reserves or to maintain its production. If Bengal's funds from (used in) operations are not sufficient to satisfy its capital expenditure requirements or interest requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available on terms acceptable to Bengal.

Bengal monitors and updates its cash projection models on a regular basis, which assists in the timing decision of capital expenditures. Farm outs of projects may be arranged if capital constraints are an issue or if the risk profile dictates that Bengal wishes to hold a lesser working interest position. Equity, if available and if on favorable terms, may be utilized to help fund Bengal's capital program.

Health, Safety and Environment

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state, and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge.

Changing Regulation

Emission, carbon and other regulations impacting climate and climate related matter are dynamic and constantly evolving. With respect to environmental, social and governance ("ESG") and climate reporting, the International Sustainability Standards Board has issued an IFRS Sustainability Disclosure Standard with the aim to develop sustainability disclosure standards that are globally consistent, comparable, and reliable. In addition, the Canadian Securities Administrators have issued a proposed National Instrument 51-107 Disclosure of Climate related Matters. The cost to comply with these standards, and others that may be developed or evolve over time, has not yet been quantified by the Company.

Insurance

Bengal's involvement in the exploration for and development of oil and gas properties may result in the Company becoming subject to liability for pollution, blow-outs, property damage, personal injury, or other hazards. Although Bengal has insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, Bengal may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to Bengal. The occurrence of a significant event that Bengal is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on Bengal's financial position, results of operations or prospects.

Competition

Bengal actively competes for reserve acquisitions, exploration leases, licenses and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial and personnel Resources than Bengal. Bengal's competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators. Bengal's ability to successfully bid on and acquire additional property rights, to discover Reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon developing and maintaining close working relationships with its future industry partners and joint operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

Significant counterparty

Bengal's operating activities are conducted primarily with a single counterparty responsible for the operations of the Cuisinier field as well as the transportation, marketing and sales of all the Company's production and is responsible for the schedule of oil liftings and ultimate payment for oil sales. This counterparty invoices Bengal for all transportation costs and collects JV payments associated with development and operations as well as collects for and distributes proceeds of oil sales to Bengal. The material working capital assets and liabilities held by a single counterparty without a right to offset may create a liquidity risk.

ADDITIONAL INFORMATION

Additional information relating to Bengal is filed on SEDAR and can be viewed at https://www.sedarplus.ca. Information can also be obtained by contacting the Company at Bengal Energy Ltd., Suite 640, 630 - 6th Avenue SW., Calgary, Alberta T2P 0S8, by email to info@bengalenergy.ca or by accessing Bengal's website at https://www.bengalenergy.ca.

FORWARD-LOOKING STATEMENTS

Certain statements contained within this MD&A constitute "forward-looking statements" or "forward-looking information" ("forward-looking statements") as defined by applicable securities laws. These statements relate to future events or Bengal's future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek," "anticipate," "budget," "plan," "continue," "estimate," "expect," "forecast," "may," "will," "project," "predict," "potential," "targeting," "intend," "could," "might," "should," "believe" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Bengal believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon. The projections, estimates and beliefs contained in such forward-looking statements are based on management's estimates, opinions, and assumptions at the time the statements were made, including assumptions relating to: the impact of economic conditions in North America and Australia and globally; industry conditions; changes in laws and regulations including, without limitation, the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; increased competition; the availability of qualified operating or management personnel; fluctuations in commodity prices, foreign exchange or interest rates; stock market volatility and fluctuations in market valuations of companies with respect to announced transactions and the final valuations thereof; results of exploration and testing activities; and the ability to obtain required approvals and extensions from regulatory authorities.

In particular, this MD&A contains forward-looking statements pertaining to the following:

• Oil and natural gas production levels;

• The size of the oil and natural gas Reserves;

• The adverse impacts on the Company as a result of the current challenging economic climate;

• Bengal's drilling program and waterflood program;

• The belief that the Cooper Basin assets offer attractive upside potential for oil and gas;

• The timing of equipping for production cased wells;

• The continued engagement in early-stage discussions with third parties with respect to potential business combination transactions;

• The continued integration of subsurface data from production licenses in the selection of exploration and appraisal drilling locations;

• Projections of market prices and costs including, but not limited to, expected royalty rates;

• Expectations regarding the ability to raise capital and to continually add to Reserves through acquisitions and development;

• That required payments will be met out of operational cash flows and alternative forms of financing;

• Bengal's ability to finance its potential working capital deficiency and to source funds for the same;

• Treatment under governmental regulatory regimes and tax laws;

• Capital expenditures program and estimates of costs; and

• That funding of working capital requirements, commitments and other planned expenses will be by cash on hand, cash flows, farm-outs, joint ventures, share issuances or other alternative forms of capital raising and funds will be sufficient to meet requirements including but not limited to Bengal's exploration activities through fiscal 2026 and its capital program.

• The likelihood of recoveries from joint venture audits with respect to expenditure and production allocation

  The forward-looking statements contained herein are subject to numerous known and unknown risks and uncertainties that may cause Bengal's actual results, performance or achievement to differ materially from those expectations expressed in, or implied by, these forward-looking statements, including but not limited to, risks associated with:

• Fluctuations in commodity prices, foreign exchange or interest rates;

• Changes in the demand for or supply of Bengal's products;

• Liabilities inherent in oil and natural gas operations;

• The failure to obtain required regulatory approvals or extensions;

• The failure to satisfy the conditions under farm-in and joint venture agreements;

• The failure to secure required equipment and personnel;

• Changes in general global economic conditions including, without limitations, the economic conditions in North America and Australia;

• Uncertainties associated with estimating oil and natural gas Reserves;

• Increased competition for, among other things: capital, acquisitions of Reserves, undeveloped lands and skilled personnel;

• The availability of qualified operating or management personnel; and lack of in Country management associated with operating and exploration assets;

• Incorrect assessment of the value of acquisitions;

• Inability to meet commitments due to inability to raise funds or complete farm-outs;

• Geological, technical, drilling and processing problems;

• Bengal's development and exploration opportunities;

• The results of exploration and development drilling and related activities;

• Changes in laws and regulations including, without limitation, the adoption of new environmental, royalty and tax laws and regulations and changes in how they are interpreted and enforced;

• The ability to access sufficient capital from internal and external sources; and

• Counter-party credit risk, stock market volatility and market valuation of Bengal's stock.

• Weather

Statements relating to "Reserves" or "Resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, which the Resources and Reserves described, can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement. The forward-looking statements contained in this document speak only as of the date of this document and Bengal does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable securities laws. Additional information on these and other factors that could affect Bengal's operations and financial results are included in reports on file with Canadian securities authorities and may be accessed through the SEDAR website at https://www.sedarplus.ca. and at Bengal's website https://www.bengalenergy.ca.

Disclosure of Oil and Gas Information

Unless otherwise specified, Reserves data set forth in this document is based upon an independent reserve assessment and evaluation prepared by GLJ with an effective date of March 31, 2025 (the "GLJ Report"). The GLJ Report has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") and the reserve definitions contained in National Instrument 51-101 - Standards of Disclosure For Oil and Gas Activities.

This document discloses unbooked drilling locations. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per area based on industry practice and internal review. Unbooked locations do not have attributed Reserves or Resources. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas Reserves, Resources or production. The drilling locations on which the Company actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.

Test Rates

References in this MD&A to production test rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or ultimate recovery. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the test results are historical and not indicative of expected production.

Internal Estimates

Certain information contained herein is based on estimated values the Company believes to be reasonable and are subject to the same limitations as discussed under "Forward-looking Statements" above.

CORPORATE INFORMATION

AUDITORS

MNP LLP • Calgary, Canada

LEGAL COUNSEL

Burnet, Duckworth & Palmer LLP • Calgary, Canada Piper Alderman • Sydney, Australia

BANKERS

Royal Bank of Canada • Calgary, Canada Commonwealth Bank • Sydney, Australia

REGISTRAR AND TRANSFER AGENT

Computershare • Toronto, Canada

DIRECTORS

Chayan Chakrabarty Dr. Brian J. Moss Barry Herring

W. B. (Bill) Wheeler

R. Neal Grant

DISCLOSURE COMMITTEE

Chayan Chakrabarty Jerrad Blanchard

AUDIT COMMITTEE

Barry Herring (Chairman)

W. B. (Bill) Wheeler

R. Neal Grant

RESERVES COMMITTEE

Dr. Brian J. Moss (Chairman) Barry Herring

R. Neal Grant

COMPENSATION COMMITTEE

Dr. Brian J. Moss (Chairman) Barry Herring

R. Neal Grant

GOVERNANCE AND NOMINATING COMMITTEE

W.B. (Bill) Wheeler (Chairman) Dr. Brian J. Moss

Barry Herring

HEALTH, SAFETY AND ENVIRONMENT COMMITTEE

R. Neal Grant (Chairman)

W. B. (Bill) Wheeler Dr. Brian J. Moss

OFFICERS

Chayan Chakrabarty, President & Chief Executive Officer Richard N. Edgar, Executive Vice President

Jerrad Blanchard, Chief Financial Officer Bruce Allford, Secretary

STOCK EXCHANGE LISTING - TSX: BNG

NOTICE

These interim condensed consolidated financial statements have not been reviewed by the Entity's auditors.

(signed) "Chayan Chakrabarty"

Chayan Chakrabarty

President & Chief Executive Officer

(signed) "Jerrad Blanchard"

Jerrad Blanchard Chief Financial Officer

BENGAL ENERGY LTD.

(Thousands of Canadian dollars) (unaudited)

Going concern (Note 2) Commitments (Note 17)

See accompanying notes to the interim condensed consolidated financial statements.

See accompanying notes to the interim condensed consolidated financial statements.

BENGAL ENERGY LTD.

(Thousands of Canadian dollars) (unaudited)

Three months ended

See accompanying notes to the interim condensed consolidated financial statements.

BENGAL ENERGY LTD.

(Thousands of Canadian dollars) (unaudited)

Three months ended

See accompanying notes to interim condensed consolidated financial statements.

BENGAL ENERGY LTD.

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three months ended June 30, 2025 and 2024

(Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)

1. REPORTING ENTITY

   Bengal Energy Ltd. (the "Company" or "Bengal") is incorporated under the laws of the Province of Alberta and is involved in the exploration, development and production of oil and gas Reserves in Australia. The consolidated financial statements (the "financial statements") of the Company as at June 30, 2025 and 2024 and for the three months ended June 30, 2025 and 2024 are comprised of the Company and its wholly owned subsidiaries including Bengal Energy Australia (Pty) Ltd. ("Bengal Pty") and Bengal Energy International Inc., which were incorporated in Australia and Canada respectively. The Company conducts many of its activities jointly with others; these financial statements reflect only the Company's proportionate interest in such activities.

   The Company has its registered office at 2400, 525 - 8th Avenue SW, Calgary, Alberta T2P 1G1 and its head and principal office at Suite 640, 630 - 6th Avenue SW, Calgary, Alberta, Canada, T2P 0S8.

2. BASIS OF PREPARATION AND GOING CONCERN

   These financial statements have been prepared in accordance with International Accounting Standards ("IAS") 34, "Interim Financing Reporting". These interim financial statements do not include all the information required for full annual financial statements and have not been reviewed by the Company's independent auditors.

   These financial statements were approved and authorized for issuance by the Board of Directors on August 7, 2025.

   The consolidated financial statements are prepared on a historical cost basis except as detailed in the accounting policies disclosed in the Company's audited consolidated financial statements for the year ended March 31, 2025. The Company's presentation currency is Canadian dollars. The functional currency of the Canadian parent entity is Canadian dollars; the functional currency of the Australian subsidiary is Australian dollars.

   Going Concern

   These financial statements have been prepared on a going concern basis. The going concern basis assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business.

   At June 30, 2025, the Company had a positive working capital of $1.7 million (March 31, 2025 positive working capital of $1.6 million), which the Company defines as total current assets less total current liabilities, generated a net loss of $0.3 million (three months ended June 30, 2024 - net loss of $0.2 million), and had net cash used in operating activities of $0.1 million (three months ended June 30, 2024 - net cash used in operating activities of $0.3 million).

   The Company's working capital includes both accrued accounts receivable and accounts payable. 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 Bengal'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. 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 (Note 17) 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. There can be no assurances about generating net cash from operating activities or that additional financing will be available for the Company. This could result in a continued decline in production and revenues with additional net cash used in operating activities. These matters create material uncertainty that may cast significant doubt about the Company's ability to continue as a going concern. These financial statements do not give effect to adjustments that would be necessary

   BENGAL ENERGY LTD.

   NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

   Three months ended June 30, 2025 and 2024

   (Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)

   to the carrying values and classification of assets and liabilities should the Company be unable to continue as a going concern. These adjustments could be material.

   Evolving Demand for Energy - Changing Regulation

   Emission, carbon, and other regulations impacting climate and climate-related matters are dynamic and constantly evolving. With respect to environmental, social, and governance ("ESG") and climate reporting, the International Sustainability Standards Board has issued an IFRS Sustainability Disclosure Standard with the aim to develop sustainability disclosure standards that are globally consistent, comparable, and reliable. In addition, the Canadian Securities Administrators have issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters. The cost and financial reporting impact of compliance with these standards, and others that may be developed or evolve over time, has not yet been quantified by the Company.

3. MATERIAL ACCOUNTING POLICIES

   The accounting policies used to prepare these financial statements are consistent with those described in

   Note 3 of the Company's consolidated financial statements for the year ended March 31, 2025.

4. MANAGEMENT JUDGMENTS AND ESTIMATES

   The timely preparation of the financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of these financial statements are outlined below.

   The economic climate may have significant adverse impacts on the Company, including material declines in revenue and cash flows, and related impacts to working capital levels and/or debt balances, which may also have a direct impact on the Company's operating results and financial position. These and other factors may adversely affect the Company's liquidity and the Company's ability to generate income and cash flows to meet the Company's current and future obligations.

5. EXPLORATION AND EVALUATION ASSETS ("E&E ASSETS")

   ($000s)
   Balance, March 31, 2024	$ 11,993
   Additions	14
   Capitalized share-based compensation	4
   E&E impairment	(2,530)
   Exchange adjustments	227
   Balance, March 31, 2025	$ 9,708
   Additions (recoveries)	(60)
   Exchange adjustments	(42)
   Balance, June 30, 2025	$ 9,606
   A summary of E&E assets is shown in the table below:
   ($000s)
   ATP 732 / PCA 332 - Tookoonooka	$ 7,525
   ATP 934 - Barrolka	2,056
   Other	25
   Balance, June 30, 2025	$ 9,606

   BENGAL ENERGY LTD.

   NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

   Three months ended June 30, 2025 and 2024

   (Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)

   Exploration and evaluation assets consist of the Company's exploration projects in Australia, which are pending the determination of proved or probable Reserves. Costs primarily consist of acquisition costs, geological and geophysical work, seismic and drilling, and completion costs until the drilling of wells is completed, and the results have been evaluated. There were no impairment indicators as at June 30, 2025.

   As at March 31, 2025, the Company performed an assessment of its E&E assets in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, to determine whether indicators of impairment existed. Management identified indicators of impairment related to its non-core tenure at ATP 752, primarily due to the absence of budgeted or planned substantive expenditure for further exploration and evaluation activities in the specific area, as well as the prioritization of the Company's 100% owned exploration assets over ATP 752 prospects, as outlined in the Company's internal assessment.

   As a result of these indicators, an impairment test was conducted in accordance with IAS 36, Impairment of Assets. The recoverable amount of the ATP 752 E&E assets was determined to be lower than their carrying amount, resulting in an impairment charge of $2.5 million recognized in the consolidated statement of income (loss) for the year ended March 31, 2025. The impairment charge reflects management's current assessment of the prospectivity and future capital plans for these assets.

   The Company continues to actively market its Australian exploration assets, including ATP 752, for potential farm-out opportunities or disposition. Future changes in market conditions, successful farm-out activities, or additional financing could impact the recoverable amount of these assets, and management will reassess impairment indicators on a quarterly basis.

6. PROPERTY, PLANT AND EQUIPMENT ("PP&E")

   ($000s)	Petroleum and natural gas properties	Other assets	Right-of-use assets	Total
   Cost: Balance, March 31, 2024	$ 53,186	$ 347	$ 143	$ 53,676
   Additions	56	-	-	56
   Disposal of equipment	(265)	-	-	(265)
   Research and development credit	(133)	-	-	(133)
   Change in decommissioning and
   restoration liability	(583)	-	-	(583)
   Exchange adjustments	1,369	-	-	1,369
   Balance, March 31, 2025	$ 53,630	$ 347	$ 143	$ 54,120
   Additions	-	-	-	-
   Exchange adjustments	(313)	-	-	(313)
   Balance, June 30, 2025	$ 53,317	$ 347	$ 143	$ 53,807

   ($000s)	Petroleum and	Other	Right-of-	Total
   Accumulated depletion, depreciation and impairment loss:	natural gas properties	assets	use assets
   Balance, March 31, 2024	$ 34,207	$ 335	$ 143	$ 34,685
   Depletion and depreciation	879	2	-	881
   Exchange adjustments	997	-	-	997
   Balance, March 31, 2025	$ 36,083	$ 337	$ 143	$ 36,563
   Depletion and depreciation	252	-	-	252
   Exchange adjustments	(232)	-	-	(232)
   Balance, June 30, 2025	$ 36,103	$ 337	$ 143	$ 36,583
   ($000s)
   Net carrying amount:
   Balance, March 31, 2025	$ 17,547	$ 10	$ -	$ 17,557

   BENGAL ENERGY LTD.

   NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

   Three months ended June 30, 2025 and 2024

   (Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)

   Balance, June 30, 2025 $ 17,214 $ 10 $ - $ 17,224

   As at June 30, 2025 and March 31, 2025, there were no external or internal indicators of impairment. Due to minimal capital activity in the current fiscal year, the Company did not capitalize general and administration expense. The calculation of depletion for the three months ended June 30, 2025 included

   $19.6 million for estimated future development costs associated with proved and probable reserves in Australia (March 31, 2025 - $19.6 million).

   During the year ended March 31, 2025, the Company disposed of some of its surplus equipment with book cost of $0.3 million for net proceeds of $0.2 million. In March 2025, the Company received a tax credit of

   $0.2 million on its research and development costs incurred in the fiscal year March 31, 2025. The credit is recorded as a credit to property, plant and equipment in the period the Company received the assessment from the Australian Tax Office.

7. NOTE PAYABLE

   On March 3, 2025, the Company entered into an agreement to refinance its Joint Venture payment plan having an outstanding principal balance owing of Australian $1.8 million as of February 28, 2025. The loan agreement ("Texada Loan" or "Note Payable") is with Texada Capital Management ("Texada"), a company controlled by a controlling shareholder and director of Bengal.

   The Note Payable is in the principal amount of $1.7 million, which amount was used to repay the Joint Venture payment plan in full. The Note Payable has a maturity date of April 1, 2027, with interest only payable until the date of maturity. Interest is payable at 10% per annum, payable quarterly. The Note Payable is secured by a security interest over all of Bengal's present and later acquired assets other than shares in its wholly owned subsidiary, Bengal Pty. The Company may at any time repay the principal sum owing under the Note Payable, in whole or in part, without any notice or penalty, provided that any such prepayment shall be in a minimum amount of Cdn$200,000. Texada has the right to accelerate repayment of the Note Payable if, at any time, the principal holder, ceases to own, in the aggregate, less than 51% of the issued and outstanding voting shares in the capital of the Company. There are no financial covenants associated with this Note Payable.

   During the quarter interest of $43 thousand was accrued and due to Texada.

8. DECOMMISSIONING AND RESTORATION LIABILITY

   Changes to decommissioning and restoration obligations were as follows:

   ($000s)
   Balance, March 31, 2024	$ 3,477
   Change in estimate	(583)
   Accretion	152
   Exchange adjustments	64
   Balance, March 31, 2025	$ 3,110
   Accretion	31
   Exchange adjustments	(13)
   Balance, June 30, 2025	$ 3,128

   The Company's decommissioning liabilities result from ownership interests in petroleum and natural gas properties. The Company estimates the total unadjusted and uninflated cash flows required to settle its decommissioning and restoration costs at June 30, 2025 is $3.3 million (March 31, 2025 - $3.3 million) which will be incurred between 2028 and 2065. At June 30, 2025, an inflation factor of 3.0% (March 31, 2025 - 3.0%) and a risk-free discount rate of 4.0% (March 31, 2025 - 4.0%) have been applied to the decommissioning and restoration liability.

   BENGAL ENERGY LTD.

   NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

   Three months ended June 30, 2025 and 2024

   (Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)

9. SHARE CAPITAL

   Authorized:

   Unlimited number of common shares with no par value.

   Unlimited number of preferred shares, of which none have been issued.

   Issued: The following provides a continuity of share capital:

   	Number of common shares	Amount
   Balance, March 31, 2025	485,304,215	118,796
   Balance, June 30, 2025	485,304,215	118,796

10. SHARE-BASED COMPENSATION

    The Company has a share option plan for directors, officers and employees of the Company whereby share options representing up to 10% of the issued and outstanding common shares can be granted by the Board of Directors. Share options are granted for a term of up to five years and vest one-third after the first year and one-third on each of the next two anniversary dates. The exercise price of each option equals the market price of the Company's common shares on the date of the grant.

    Stock options granted under the plan can be exercised on a cashless basis, whereby the recipient receives a lesser number of shares in lieu of paying the exercise price based on the deemed market price of the shares on the exercise date, and withholding taxes if the option holder so elects.

    A summary of stock option activity is presented below:

    	Options	Weighted average exercise price
    Balance, March 31, 2024	10,620,000	0.08
    Granted	1,500,000	0.03
    Forfeited	(2,550,000)	0.08
    Balance, March 31, 2025	9,570,000	0.07
    Balance, June 30, 2025	9,570,000	0.07
    Exercisable, June 30, 2025	8,070,000	0.08

    Exercise Price	Number Outstanding	Remaining Life (years)	Number Exercisable
    $0.00 to $0.03	1,500,000	4.2	-
    $0.04 to $0.08	8,070,000	0.7	8,070,000
    	9,570,000	1.2	8,070,000

    There were no options granted during for the three months ended June 30, 2025.

11. REVENUE

    Revenue from the sales of crude oil is based on the consideration specified in the Liquids Aggregation Agreement ("LAA") with the joint venture operator. The Company recognizes revenue when it transfers control of the product to the buyers, which, under the current Crude Oil Transportation Agreement, is generally at the time the Crude Oil marketers obtain legal control of the crude at a receipt facility. At the time of physical lifting at port, title is transferred and the transaction price is based on the average benchmark pricing and adjusted for quality and other factors specified in the Liquids Aggregation Agreement. The transaction price as prescribed in the LAA is a variable price based on various benchmark commodity pricing that may be adjusted for quality, location, delivery method or other factors depending on the agreed-upon terms of the contract. The Company uses US dollar Brent pricing as the closest publicly available source against which to benchmark its crude pricing. The amount of revenue recorded

    BENGAL ENERGY LTD.

    NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

    Three months ended June 30, 2025 and 2024

    (Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)

    can vary depending on the grade, quality, and quantity of crude oil transferred to the joint venture operator. Revenues are typically collected 60 days following delivery to Port Bonython.

12. PER SHARE AMOUNTS

    Loss per share is calculated based on net loss and the weighted-average number of common shares outstanding.

    ($000s except per share amounts) Three months ended June 30,

    	2025	2024
    Net loss for the period	(258)	(210)
    Weighted average number of common shares - basic (000s)	485,304	485,304
    - diluted (000s)	485,304	485,304
    Basic and diluted (loss) income per share	$ (0.00)	$ (0.00)

    For the three months ended June 30, 2025, 9,570,000 (three months ended June 30, 2024 - 10,620,000) of the options were considered anti-dilutive.

13. FINANCE EXPENSE

    ($000s) Three months ended

    June 30,

    	2025	2024
    Accretion on decommissioning liability	31	37
    Interest expense	52	4
    	83	195

14. FINANCIAL RISK MANAGEMENT

The Company has exposure to credit, liquidity, and market risk from its use of financial instruments. This note presents information about the Company's exposure to these risks, the Company's objectives and policies and processes for measuring and managing risk.

The Board of Directors has overall responsibility for identifying the principal risks of the Company and ensuring the policies and procedures are in place to appropriately manage these risks. Bengal's management identifies, analyzes and monitors risks and considers the implication of the market condition in relation to the Company's activities.

(a) Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations and arises principally from Bengal's cash calls paid to joint venture partners and receivables from petroleum and natural gas marketers. As at June 30, 2025, Bengal's receivables consisted of $1.6 million (March 31, 2025 - $1.7 million) from joint venture partners.

Bengal has a Liquids Aggregation Agreement with a purchaser and has not experienced any collection problems to date. Cash calls paid to Bengal's Australian joint venture partners are held in trust accounts by the partner until spent. Bengal attempts to mitigate the risk from joint venture receivables by approving significant spending by partners prior to expenditure and only paying the cash call shortly before the funds are to be spent.

The carrying amount of accounts receivable and cash and cash equivalents represents the maximum credit exposure. Bengal establishes an allowance for doubtful accounts as determined by management based on their assessment of collection. Bengal does not have an allowance for doubtful