INTERNATIONAL EXPLORATION & PRODUCTION
2022 Annual Report
Twelve Months Ended
March 31, 2022
BENGAL ENERGY LTD
TABLE OF CONTENTS
Message to Shareholders ............................................................................................ 3
Management's Discussion & Analysis ....................................................................... 6
Consolidated Financial Statements .......................................................................... 31
Notes to the Consolidated Financial Statements .................................................... 42
Corporate Information ............................................................................................... 66
BENGAL ENERGY LTD.
MESSAGE TO SHAREHOLDERS
This past year, we have continued to witness a remarkable turnaround for the global upstream energy
industry as economies recovered from the Covid-19 pandemic and oil and gas prices surged. During fiscal
2022, Bengal Energy Ltd. (“Bengal” or the “Company”) benefited from this recovery in crude oil prices. With
zero debt, our free cash flow from operations continues to be deployed to our operated projects in the
Cooper Basin, and we are entirely committed to generating value for shareholders.
The near-term outlook for crude oil and natural gas prices in the Australian market has strengthened
because of geo-political conflicts impacting supply and a resumption to more normal demand levels as the
impact of the COVID 19 pandemic diminishes. We are now encouraged by the medium-term bullish outlook
for natural gas demand for eastern Australia and optimistic about the multiple egress and marketing
opportunities available to optimize returns on the Company’s natural gas-rich asset. At the time of writing,
both oil and natural gas prices are at robust levels with Brent oil being priced on the spot market at US$110-
120 per barrel and east coast Australia spot gas prices of Australian$40 per gigajoule.
Production for the fiscal year ended March 31, 2022, averaged 183 barrels of oil per day, at which level,
we generate $3.5 million of free cash flow on an annualized basis at Brent oil price of US$ 100/barrel.
Bengal’s independently evaluated Proved Plus Probable (“2P”) reserves for the fiscal year ended March
31, 2022, are 5,778 thousand barrels of oil (“Mbbls”), and Proved (“1P”) reserves are 2,145 Mbbls compared
to 5,789 Mbbls and 2,163 Mbbls for 2P and 1P reserves respectively at March 31, 2021. The net present
value (NPV10, before tax) of Bengal’s 2P reserves, net of future development costs, at March 31, 2022, is
$149.0 million, or $0.30 per share compared to $87.6 million at March 31, 2021. The 2P after-tax net asset
value is $115 million for the current year compared to $69.2 million in the prior year.
The Company commissioned a third-party Resource Assessment effective March 20, 2022; this is distinct
from and incremental to the Company’s March 31, 2022, Year-end Reserves Report. Results indicate Best
Estimate Contingent Resources of 1.1 million barrels of light crude oil and 19 billion cubic feet of natural
gas for a total Barrel of Oil Equivalent of 4.3 million. Prospective Resources Best Estimate is 10.6 million
barrels of light crude oil and 29.3 billion cubic feet of natural gas for a total of 15.5 million barrels of oil
equivalent.
Our goal is to consistently add value per share by capitalizing on the significant inventory of development,
appraisal, and exploration opportunities that we have added to our portfolio over the last five years, which
is quantified by our third-party Reserves and Resources evaluations. The initial work program on the 100%-
owned Wareena and Caracal projects was started in Calendar Q1 2022, faced several weather-related
interruptions to road and lease access, and we now expect results in Q3 of this year. In Q1, 2022, Bengal
was able to access additional funding through a Private Placement raising $4.2 million through the issuance
of 52.3 million shares, with participation in this funding of both Canadian and Australian investors and
insiders. This funding and our free cash flow are being deployed towards the Wareena and Caracal work
programs.
Included in the Wareena project is the reinstatement of two gas wells (Wareena-1 and Wareena-5) and an
existing gas pipeline to produce raw gas into the existing transportation infrastructure. With deeper zone
water shut off on Wareena-5, the next activity will be to achieve the same on Wareena-1, followed by
flowback tests to determine initial natural gas productive capabilities for the two wells. Negotiations
regarding natural gas processing and sales are ongoing with Santos as the owner of the transportation and
processing infrastructure. The company is evaluating multiple options for commercialization of expected
natural gas production, including connection through a third-party gathering system with existing processing
infrastructure, as well as an innovative proof of concept for alternative monetization. The Caracal-1 well, a
53 API oil discovery on ATP 732, was re-entered and produced oil to the surface. While this well is currently
being assessed to determine capacity for improved commercial production, the Company has secured an
offtake agreement for this oil with the nearby Inland Oil Refinery, and in parallel is moving forward with a
longer-term lease retention application for this prospective block with multiple egress options for its crude
oil resources.
Considerable progress has been made by the Company with the deployment of both our Early Oil
Production System (EOPS) and our Early Gas Production System (EGPS). The EOPS will be field-tested
during the current quarter and the EGPS is expected to be onsite and operating by August. We have
received strong expressions of interest from other operators in Queensland and South Australia about the
availability of these systems on a contract basis. As we mature these opportunities, we expect to announce
updates outlining expected benefits to all shareholders from these technologies developed by the
Company.
In Bengal’s non-operated Cuisinier oilfield, a pilot reservoir pressure maintenance scheme was initiated
during the prior fiscal year in the southeast quadrant of the pool, with the injection of water taking place at
the Cuisinier 24 well. The broad nature of the Cuisinier structure combined with variable flank aquifer
pressure support has resulted in pressure depletion within the central portion of the Cuisinier pool. The
injection of produced formation water is anticipated to both increase production in up to four offsetting wells
and reduce water handling charges. The Cuisinier water injection pilot has continued to face a range of
surface facility-related operational issues resulting in downtime, which have not allowed the significant
subsurface success potential of this pilot to be realized yet. Bengal Energy personnel are now working
collaboratively with the Operator’s Onshore Operations and Development Leadership towards rectifying the
surface facility operational challenges. Currently, the water injection rate into C24 is approximately 300 bpd
at a wellhead pressure of 9,600 Kilopascal (1392 psi). Nearby wells are being monitored for total fluid
produced and water cut to help to determine which wells are affected by the pilot program. Upon
establishing success of the pilot, the Joint Venture (“JV”) expects to begin a multi-phase water injection
scheme, targeted fracture stimulation and more commercially efficient development drilling. Since inception
of the pilot, 33,500 barrels of water have been injected into the C24 well at an average rate of approximately
275 barrels of water per day over 115 operating days since December 2021.
During Q2 and Q3 of this year, we are focused on converting near term cash generating opportunities at
the Wareena and Caracal fields. Our next phase of development is aimed at unlocking currently stranded
gas assets at Ramses, Ghina and Nubba and finalizing the reinstatement of the Wareena to Coonaberry
pipeline. The stranded gas assets are developed on the back of the field trial of our EGPS. One of the
Ramses well has a Jurassic oil resource which we are planning to access with a dual packer and sliding
side sleeve completion. We are currently working at determining export routes for this high pour point light
oil. A more challenging appraisal will be worked through at Karnak where the current well bore has
significant washouts. The plan is to either sidetrack or drill a new well in a more crestal position to access
the gas resource associated with this well. In parallel, we expect to see new development and appraisal
drilling activity on our Cuisinier asset, consistent performance of the Cuisinier Water Flood Pilot and are
working on Joint Venture participation in exploration drilling on ATP 732 as well as developing new
opportunities for Permian Gas drilling on ATP 934. This year’s activities are targeted at creating a stable
and flexible production and cash flow platform from which to drive sustainable growth and we are excited
for the opportunity to deliver on this promise through a balanced mix of development, appraisal, and
exploration projects during the coming year.
Our success will continue to be driven by our dedicated and talented team of employees who are passionate
about delivering our strategies and plans to create value for shareholders. Complementing our team, our
Board of Directors is an indispensable source of guidance and day-to-day support which we rely on as we
drive forward towards our value-creation objectives to benefit all shareholders. We look forward to executing
our plans in the months ahead for the ongoing benefit of all stakeholders and we thank you for your
continued support.
-4-
Sincerely,
(signed) “Chayan Chakrabarty”
Chayan Chakrabarty
President & CEO
Note: this Message to Shareholders contains forward-looking statements and is subject to the
forward-looking statement disclaimer in the Management’s Discussion & Analysis for the Years
Ended March 31, 2022, and 2021
-5-
INTERNATIONAL EXPLORATION & PRODUCTION
Management’s Discussion & Analysis
Three and Twelve Months Ended
March 31, 2022 and 2021
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 twelve months ended March 31,
2022.
This MD&A dated June 15, 2022 should be read in conjunction with the Company’s consolidated financial
statements and related notes for the years ended March 31, 2022 and 2021. The consolidated financial
statements of the Company have been prepared in accordance with International Financial Reporting
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
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 and Other Financial Measures, abbreviations and forward-looking
information relating to future events and the Company’s future performance. Please refer to “Non-IFRS and
Other Financial Measures s”, “Abbreviations” and “Advisories” sections at the end of this MD&A for further
information. These do not have any standardized meaning in accordance with International Financial
Reporting Standards (“IFRS”) as prescribed by the International Accounting standards Board and therefore
may not be comparable with the calculation of similar financial measures disclosed by other entities.
Additional information relating to Bengal, including Bengal’s audited March 31, 2022 consolidated financial
statements and other filings are available on SEDAR at www.sedar.com.
In the following discussion, the three months ended March 31, 2022 may be referred to as “fourth quarter of
fiscal 2022”, "Q4 fiscal 2022", “Q4 FY 2022”, “current quarter”, and “the quarter”. The comparative three
months ended March 31, 2021, may be referred to as “fourth quarter of fiscal 2021”, "Q4 fiscal 2021" “Q4 FY
2021”, and “prior year’s quarter”. The year ended March 31, 2022, may be referred to as “fiscal 2022”,
“current year”, and “the year”. The comparative year ended March 31, 2021, may be referred to as “the
previous year”, “prior year”, and “fiscal 2021”.
FOURTH QUARTER FISCAL 2022 SUMMARY
Financial Summary:
• Reserves –Bengal’s independently evaluated Proved Plus Probable (“2P”) reserves for the fiscal
year ended March 31, 2022 are 5,778 thousand barrels of oil (“Mbbls”) and Proved (“1P”) reserves
are 2,145 Mbbls compared to 5,789 Mbbls and 2,163 Mbbls for 2P and 1P reserves respectively
at March 31, 2021. The net present value (NPV10, before tax) of Bengal’s 2P reserves, net of
future development costs, at March 31, 2022 is $149.0 million, or $0.30 per share compared to
$87.6 million at March 31, 2021. The 2P after tax net asset value is $115 million for the current
year compared to $69.2 million in the prior year.
● Sales revenue – Crude oil sales revenue was $2.4 million in the fourth quarter of fiscal 2022, which
is 50% higher than the $1.6 million recorded in Q4 fiscal 2021. Full year fiscal 2022 sales revenue
was $7.7 million compared to $5.2 million for the full year fiscal 2021.
● Funds from (used in) operations1 – Bengal generated $0.5 million of funds from operations during
Q4 fiscal 2022 compared to a $0.2 million funds used in operations during Q4 fiscal 2021. For the
full year fiscal 2022, the Company generated $1.4 million of funds from operations compared to $0.3
million funds used in operations during the prior fiscal year.
● Net income – Bengal reported net income of $0.2 million for the current quarter compared to net
income of $3.9 million in the fourth quarter of fiscal 2021. For the full year fiscal 2022, the Company
reported a net loss of $0.4 million compared net income of $3.9 million in the prior year. Several
non-operational items contributed to net income during the prior year that were absent in the current
1 See “Non-IFRS and Other Financial Measures” on page 16 of this MD&A
-7-
period, including $3.7 million of foreign exchange gains and a $3.5 million gain on the settlement of
the Company’s Credit Facility.
● Private placement – On March 7, 2022 the Company closed a private placement to issue 52.3
million shares for $4.2 million of proceeds.
Operational Summary:
● Production volumes – The Company’s share of total production in the current quarter was 15,647
bbls of light crude oil, which is a 14% decline from the 18,222 bbls produced in the fourth quarter of
fiscal 2021. The current quarter production averaged 174 bbls/day compared to 202 bbls/day
produced in the fourth quarter of fiscal 2021. Full year fiscal 2022 saw total production of 66,797
bbls compared to 80,530 bbls for full year fiscal 2021. The full year fiscal 2022 production per day
averaged 183 bbls compared to 221 bbls/day for the full year fiscal 2021.
● Capital expenditures – During the year, the Company commenced capital programs on two of its
100% owned and operated projects at Wareena (Petroleum Lease (“PL”) 1110 & Producing Pipeline
(“PPL”) 138) and Caracal (Authority to Prospect (“ATP”) 732). Bengal incurred $2.2 million in capital
expenditures during Q4 fiscal 2022 as compared to $0.5 million in Q4 fiscal 2021 and a total of $4.3
million during the current year compared to $1.2 million during fiscal 2021. Work in these projects
is currently ongoing.
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, PL 303 Cuisinier, ATP 934 Barrolka, ATP 732 Tookoonooka, and four petroleum licenses acquired
in calendar 2019 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.
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, and under certain conditions relative to exploration success, an application can be made
to continue a portion of the permit in the form of a PCA (Potential Commercial Area). 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
the resource. These PCA’s 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 two PLs on the former ATP 752 Barta block, PL 303 and PL 1028, in addition to three PCAs,
PCA 206, PCA 207 Barta West and PCA 155 Wompi block-Nubba/Yilgarn. Bengal also holds four PLs
(PL 114 Wareena, PL 157 Ghina, PL 188 Ramses, PL 411 Karnak) including a pipeline license PPL 138
adjacent to ATP 934.
AUSTRALIA – Cooper Basin, Queensland
PL303 and PL 1028 Cuisinier (controlling permit ATP 752) (30.357% WI)
A pilot reservoir pressure maintenance scheme was initiated during the prior fiscal year and after resolving
mechanical issues, water injection activities resumed during calendar Q4 2021. The location of this pilot is
in the southeast quadrant of the Cuisinier pool, with injection of water taking place at the Cuisinier 24 well.
The broad nature of the Cuisinier structure combined with variable flank aquifer pressure support has
resulted in pressure depletion within the central portion of the Cuisinier pool. The injection of produced
-8-
formation water is anticipated to both increase production in up to four offsetting wells and reduce water
handling charges. The Cuisinier water injection pilot has continued to face a range of surface facility-related
operational issues resulting in downtimes, which have not allowed the significant subsurface success
potential of this pilot to be realized as yet. Bengal Energy personnel are now working with the Operator’s
Onshore Operations and Development Leadership to work collaboratively towards rectifying the surface
facility design challenges.
Upon establishing success of the pilot, the Joint Venture (“JV”) expects to begin a multi-phase water injection
scheme, targeted fracture stimulation and more commercially efficient development drilling. Since inception
of the pilot, 33,500 barrels of water have been injected into the C24 well at an average rate of approximately
275 barrels of water per day over 115 operating days since December 2021. Currently, the water injection
rate into C24 is approximately 300 bpd at a wellhead pressure of 9,600 Kilopascal. Nearby wells are being
monitored for total fluid produced and water cut to help to determine which wells are being affected by the
pilot program.
In December 2021, Bengal participated in the Chef exploration drilling project. Following a review of the well
logs, the ATP 752 JV parties have decided to plug and abandon the well. This exploration well is located
outside of the producing Cuisinier field PL 303, in a location 4 km to the northeast with primary targets in the
Jurassic Birkhead Formation and Hutton Sandstone, and secondary targets within the Triassic Nappamerri
Group. The well encountered multiple oil shows in the primary and secondary targets; however, no
commercial pay was identified at this location. While not a commercial success, the identified oil shows may
support continued exploration targeting both the Jurassic Birkhead and newly discovered oil-bearing Triassic
Nappamerri formations.
PL 114 Wareena, PL 157 Ghina, PL 188 Ramses, PL 411 Karnak, PPL 138 pipeline (100% WI)
The Company acquired a 100% working interest in four PLs and a natural gas pipeline connected to
transportation infrastructure into the Eastern Australia Gas Market (collectively, the "Assets"). These non-
productive PLs are highly compatible with and in close proximity to 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 is the reinstatement of two gas wells (Wareena-1 and Wareena-5) and an existing
gas pipeline to produce raw gas into existing infrastructure. Planning and execution of the project continued
through Q4 fiscal 2022 including performing a deeper zone water shut off on Wareena-5. Negotiations
regarding natural gas processing and sales are ongoing with Santos as the owner of the processing
infrastructure. The company is evaluating various options for commercialization for expected natural gas
production, including connection through existing processing infrastructure and an innovative proof of
concept for alternative monetization.
The 100% ownership of the acquired Assets presents an appraisal and development opportunity that will be
operated by the Company and is seen to be not only complementary to our proven producing, non-operated
Cuisinier asset, but also as a key steppingstone for Bengal’s natural gas platform upon which future
exploration growth through ATP 934 can be undertaken.
ATP 732 Tookoonooka (100% WI)
The Company has conducted preliminary workover and stimulation program at the Caracal-1 well, a 53 API
oil discovery in the Wyandra zone. The well produced oil to the surface, although at lower-than-expected
rates and is currently being assessed to determine capacity for commercial production. This would allow the
Company to progress towards a PL or PCA on the block.
In June 2019, the Company applied for an amendment to the LWP (“Later Work Program”) for the third term
of ATP 732 permit. On October 22, 2019, the Company received approval from the Queensland regulatory
authority for an amended LWP for the third, four-year term commencing April 1, 2019, to March 31, 2023.
The approved LWP was revised to minimum activities of reprocessing seismic and inversion work with an
estimated cost of $0.05 million and geological and geophysical investigation at an estimated cost of $0.05
million during the four-year term.
-9-
ATP 934 Durham Downs East Farmout Block (40% WI)
Bengal entered into an agreement with Santos in July of 2020 to farm-in on a portion of the ATP 934 block.
Santos carried the drilling costs of one well to earn a 60% operated interest in the ATP 934 southern farm-
out block, which represents 57.8% of the total block acreage post April 2020 relinquishment. On October 14,
2021, Santos completed the drilling of the Legbar-1 exploration well. Santos paid 100% of the costs to drill,
plug and abandon the well and has accordingly earned a 60% working interest in 103,760 km2 gross
exploration land.
While the Legbar-1 Well did not indicate commercial quantities of hydrocarbons, thick, high quality reservoir
sands were encountered in the primary Permian Toolachee formation and in the Jurassic Birkhead zone,
with evidence of residual hydrocarbon saturation in both zones. In addition, fluorescence shows and
elevated gas readings through the Jurassic Birkhead Fm/Top Hutton Sandstone indicate oil has passed
through the reservoir, supporting the search for a valid closure to test this play. The findings from the Legbar-
1 well will help Bengal refine its exploration targets going forward, both with Santos in the Santos Farm-out
Block, and across the balance of ATP 934 which is 100% owned by Bengal.
Business Development
The Company is in discussions with potential industry and financial partners to fund some of these oil and
gas-related activities.
OPERATING SUMMARY
($000s except per share, %,
volumes and operating netback amounts)
Three months ended
March 31
Oil revenue
Operating netback(1)
Cash from operations
Funds from (used in) operations(1)
Per share ($) (basic and diluted)
Net income (loss)
Per share ($) (basic and diluted)
Capital expenditures
Oil volumes (bbl/d)
Operating netback (1)($/bbl)
Non-IFRS and Other Financial Measures
2022
2,374
$
1,425
$
437
$
$
515
$ 0.00
$
217
$ 0.00
$
2,244
174
91.06
2021
1,601
670
70
(158)
0.00
3,040
$
$
$
$
$
$
$ 0.01
$
533
202
36.67
$
$
Twelve months ended
March 31
2022
2021
$ 4,822
7,650
$
$ 2,754
4,109
$
301
$
835
$
$
(305)
1,432
$
$ 0.00
0.00
$
$
(374) $ 3,928
$ (0.00) $ 0.03
$ 1,254
$
221
$ 34.20
4,322
183
61.52
$
-10-
RESULTS OF OPERATIONS
Production
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
Oil production (bbls/d)
Oil production (bbls)
174
15,647
202
18,222
183
66,797
221
80,530
Production during Q4 fiscal 2022 decreased 14% compared the Q4 fiscal 2021 and total current fiscal year
production decreased 17% compared to the fiscal 2021. These decreases represent natural production
declines at the Cuisinier field. During fiscal 2022, the only capital activity incurred in the field related to the
water injection pilot program, which is currently injecting water at a rate of 300 bbls per day. To date there is
insufficient data to determine the impact of water injection on the reservoir and oil production.
Revenue/Pricing
The following table outlines for oil lifting from bills of lading, pipeline oil estimates, applicable prices and oil
sales reflected in the Company’s financials:
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
Oil lifting
Volume (000s bbls)
Weighted average price ($US/bbl)
A. Sales (CDN $000’s)
14.0
107.36
1,864
17.0
63.88
1,390
67.3
83.66
7,131
85.7
43.26
5,028
Pipeline oil
Volume (000s bbls), change 1.6 1.2 (0.5) (4.7)
Price ($US/bbl), change 30.20 9.90 50.63 (39.56)
B. Net sales (CDN $000’s)
510 211 519 206
A.+B. Total oil sales (CDN $000s)
2,374 1,601
7,650 5,234
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 that 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.
Realized crude oil prices during the current quarter increased by 68% compared to the previous year’s
quarter based on increased benchmark Brent pricing. The realized weighted average price of oil lifting
sales was US $107.36/bbl for the current quarter compared to US $63.88/bbl during Q4 fiscal 2021. This
increase in pricing was partially offset by a 14% decrease in production.
During the current quarter, the higher pipeline oil amount was due to both an increase in price of US
$30.20/bbl and a 400 bbl volume increase. After adjusting for changes in pipeline oil, sales for the current
quarter are $1.9 million, which is a 34% increase from the $1.4 million recorded during the prior year’s
quarter.
-11-
The following table outlines average benchmark prices:
Brent oil ($/bbl)
Brent oil (US$/bbl)
Number of CAD$ for 1 AUS$
Number of CAD$ for 1 US$
($000s)
Operating netbacks(1)
Oil sales
Realized gain on financial instruments
Royalties
Operating expenses
Operating netback
($/bbl)
Oil sales
Realized gain on financial instruments
Royalties
Operating expenses
Operating netback
See Non-IFRS and Other Financial Measures
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
127.38
100.30
0.92
1.27
77.85
60.82
0.99
1.28
100.69
80.55
0.93
1.25
58.99
44.35
0.95
1.33
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
2,374
-
(142)
(807)
1,425
151.72
-
(9.08)
(51.58)
91.06
1,601
-
(96)
(835)
670
87.86
-
(5.27)
(45.92)
36.67
7,650
-
(459)
(3,082)
4,109
114.53
-
(6.87)
(46.14)
61.52
5,234
1,033
(314)
(3,199)
2,754
64.99
12.83
(3.90)
(39.72)
34.20
In Q4 fiscal 2022, operating netbacks were $1.4 million or $91.06/bbl compared to Q4 fiscal 2021 at $0.7
million or $36.67/bbl. The primary reason for the 113% increase in operating netbacks is improved realized
pricing on crude oil sales, which more than offset production declines. For the full year fiscal 2022, operating
netbacks were $4.1 million or $61.52/bbl compared to $2.8 million or $34.20/bbl in the prior fiscal year also
due to higher realized crude oil sales prices.
-12-
Royalties
Royalties
Royalty expense ($000s)
$/bbl
% of revenue
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
142
9.08
6
96
5.27
6
459
6.87
6
314
3.90
6
In Queensland Australia, oil royalties are based on a government-established rate which scales according
to benchmark oil prices plus a Native Title royalty of 1%.
Royalty rates approximate 6% of oil sales for Q4 fiscal 2022 consistent with Q4 fiscal 2021 and for fiscal
2022 compared with fiscal 2021.
Operating Expenses
($000s)
Operating expenses
Production
Transportation
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
303
504
807
214
621
835
11.74
34.08
45.82
940
2,142
3,082
14.07
32.07
46.14
568
2,631
3,199
7.05
32.67
39.72
Production - $/bbl 19.36
32.22
Transportation - $/bbl
51.58
Operating expenses for the three months ended March 31, 2022, were 13% higher than the previous year’s
fiscal Q4 on a per barrel basis. For the entire fiscal year, operating expenses per barrel were 16% higher
than the prior year, while total expense decreased with production. Production costs during Q4 2022 were
impacted by approximately $0.1 million of one-time maintenance operations associated with water injection
pilot as well as industry wide inflationary pressures. Transportation costs decreased during the current
quarter because of reduced water handling associated with water recycled into the water injection pilot.
General and Administrative (G&A) Expenses
($000s)
G&A
Net G&A expenses
Capitalized G&A expenses
Total G&A expenses
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
843
-
843
2,652
168
2,820
2,334
7
2,341
892
35
927
-13-
Total G&A expenses in the fourth quarter of fiscal 2022 were 10% higher than fiscal Q4 2021. The full-year
fiscal 2022 G&A expenses were 20% higher than the prior year. During the prior fiscal year, the Company
benefited from the Canadian federal government’s emergency wages and emergency rent subsidy programs
associated with the COVID-19 Pandemic. Effective September 2021, Bengal was no longer eligible for these
subsidies resulting in approximately $0.1 million and $0.5 million of incremental G&A for the fiscal quarter
and year ended March 31, 2022 respectively.
Share-based Compensation (“SBC”)
($000s)
SBC
Expensed share-based compensation
Capitalized share-based compensation
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
37
5
42
3
-
3
135
10
145
9
-
9
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. Share-based compensation expense is higher in
fiscal 2022 due to the value of options granted in March of 2021 that were recognized during this financial
year. At March 31, 2022, there were 12,445,000 outstanding options.
Depletion, Depreciation and Amortization (DD&A)
($000s)
DD&A
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
Petroleum and natural gas properties
Other assets
Right-of-use assets
242
1
8
251
293
1
7
301
DD&A - $/bbl
15.47
16.08
1,033
4
30
1,067
15.46
1,285
6
42
1,333
15.96
The Company’s proved plus probable (2P) reserve volumes at March 31, 2022, decreased by approximately
11,000 bbls compared to March 31, 2021. In addition, future capital costs to develop 2P reserves at March
31, 2022, were $61.5 million compared to $60.9 million at March 31, 2021.
Depletion expense is incurred in Australian dollars and therefore impacted by fluctuations in the foreign
exchange rates between Canadian and Australian dollars. Strengthening of the Canadian dollar against the
Australian dollar resulted in lower depletion per barrel for both the year and quarter ended March 31, 2022.
Production for full year fiscal 2022 was 66,797 bbls compared to 80,530 bbls for the previous year
contributing to a lower total depletion for fiscal 2022.
-14-
Impairment
($000s)
Impairment expense
Exploration and evaluation assets
Petroleum and natural gas properties
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
-
-
-
-
-
-
568
-
568
-
-
-
As at March 31, 2022, the Company concluded that there were no triggers for impairment on its E&E
assets. During Q3 Fiscal 2022, the Company recorded $0.6 million of impairment associated with
uneconomic drilling results at the Chef-1 location in the ATP 752 block.
Finance Expense
($000s)
Finance expense
Interest income
Accretion expense on decommissioning
and restoration liability
Interest on lease liability
Interest – other
Interest on credit facility
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
(7)
15
1
4
-
13
(1)
5
2
-
136
142
(7)
38
5
9
-
45
(1)
19
10
-
881
909
The Company had no outstanding credit facilities during fiscal 2022, therefore there was no corresponding
interest expense.
-15-
CAPITAL EXPENDITURES
($000s)
Capital expenditures
Geological and geophysical and workover
Drilling
Completions
Acquisition
Office
Exploration and evaluation expenditures
Development and production expenditures
Office
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
2,130
16
(4)
-
2
2,144
588
1,554
2
2,144
63
1
158
311
-
533
61
472
-
533
3,489
591
240
-
2
4,322
1,231
3,089
2
4,322
196
13
1,014
31
-
1,254
61
1,193
-
1,254
During the quarter ended March 31, 2022, the Company incurred $0.6 million of exploration and evaluation
expenditures associated with ongoing operations on the Caracal-1 well at ATP 732 to stimulate with the
objective of delivering oil to surface and allowing for a Petroleum Lease application. The minimal exploration
expenditures incurred during Q4 fiscal 2021 related to prospect interpretation. The $1.6 million of
development expenditures incurred in the current fiscal quarter and the $3.1 million incurred during the fiscal
year relate primarily to the workover operations around the Wareena-1 and Wareena-5 wells and the
associated Wareena pipeline, which is currently ongoing. The objective of these workovers is to restore
production to these previously producing wells. During Q4 fiscal 2021 and for the entire year of fiscal 2021,
the $0.5 million and $1.2 million respectively of development expenditures related primarily to the Cuisinier
water injection pilot. For the fiscal year ended March 31, 2022 $1.2 million of exploration and evaluation
expenditures relate to operations at Caracal-1 and exploration wells drilled in ATP 752 (Chef-1) and ATP
934 (Legbar-1), compared to $0.1 million of expenditures in the previous year relating to processing and
interpretation of geological prospects.
SHARE CAPITAL
Trading history
High ($)
Low ($)
Close ($)
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
0.12
0.06
0.12
0.10
0.03
0.08
0.14
0.06
0.12
0.14
0.02
0.08
Volume (000s)
2,962
8,472
11,255
17,864
Shares outstanding (000s)
485,305
432,987
485,305
432,987
Weighted average shares outstanding (000s)
- basic and diluted
446,938
227,205
436,427
133,073
-16-
At June 15, 2022, there were 485,304,515 common shares issued and outstanding, together with 12,445,000
outstanding options. On March 7, 2022 the Company closed a private placement to issue 52.3 million shares
for $4.2 million of proceeds.
On February 26, 2021, Bengal issued 330,720,000 common shares as part of a private placement
transaction with Texada Capital Management Ltd. (“Texada”), which is controlled by Bill Wheeler, who is a
director of the Company. As part of another private placement transaction, on March 7, 2022, the Company
issued 52,317,521 common shares, of which 41,067,871 were acquired by Texada. Following these
transactions, Texada controls approximately 82% of the Company’s outstanding shares.
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 lease liability and amounted to $3.2
million at March 31, 2022 (March 31, 2021 - $2.0 million).
At March 31, 2022, the Company had working capital2 of $5.5 million, including cash and short-term deposits
of $5.4 million, compared to working capital2 of $4.3 million at March 31, 2021. Working capital2 is calculated
as current assets less current liabilities but excludes other obligations and current portion of
decommissioning obligations.
On March 7, 2022 the Company closed a private placement to issue 52.3 million shares for $4.2 million of
proceeds.
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.
To mitigate the net impact of low crude oil prices, the Company is acting with its joint venture partners to
reduce discretionary spending and focus capital towards lower risk projects with near-term cash flow upside.
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 acquired an additional 21.43% working
interest and received ministerial approval for the acquisition on August 11, 2015. In Q4 fiscal 2018, the
Company consolidated its ownership of ATP 934 and now holds a 100% and 40% operating interest in the
northern and southern block of this this permit. The purchase consideration was AUS$0.3 million cash and
potential future cash payments of up to AUS$1.0 million, which is made up of a AUS$0.2 million on
certification by an independent competent person appointed by Bengal Energy (Australia) Pty Ltd. of not less
than 25 billion cubic feet of proved reserves and AUS$0.8 million due upon the delivery of the first shipments
of gas to market. The work program consists of 260 km2 of 3D seismic and up to three wells.
2 See "Non-IFRS and Other Financial Measures " on page 15 of this MD&A.
-17-
At March 31, 2022, the Company had the following capital work commitments:
Country and permit
Work program
Obligation period Estimated expenditure
ending (net) (millions CAD$)
(1)
Onshore Australia –
ATP 934
Onshore Australia –
ATP 732
Offshore Australia
AC/RL 10
260 km2 3D seismic and
up to three wells
February 2027
Geological and geophysical
studies
Geological and geophysical
studies
March 2023
March 2023
8.3(2)
0.1
0.1
(1) Translated at March 31, 2022 at an exchange rate of AUS$1.00 = CAD$0.9366.
(2) During fiscal 2021, the Company received confirmation that the commitment on ATP 934 was reduced in exchange for a
50% relinquishment of the non-potential acreage of ATP 934 at the end of the first term expiry date of February 28, 2021.
At March 31, 2022, the contractual obligations for which the Company is responsible are as follows:
($000s)
Contractual obligations
April 2022 to March 2059
Office lease
Decommissioning and restoration
Total
182
3,379
3,561
Less than
1 year
1-3
years
4-5
years
After
5 years
103
-
103
79
798
877
-
-
-
-
2,581
2,581
OFF BALANCE SHEET TRANSACTIONS
The Company does not have any off-balance sheet transactions.
-18-
SELECTED QUARTERLY INFORMATION
Fiscal quarter ($000s)
Mar 31
Dec 31
Sep 30 June 30
2020
Q4 2022 Q3 2022 Q2 2022 Q1 2022 Q4 2021 Q3 2021 Q2 2021 Q1 2021
Jun 30 Mar 31
2021
Dec 31
Sep 30
2021
2022
2020
2021
2020
2021
Oil sales
2,374
Cash flows from (used in) operations 437
Funds from (used in) operations(1)
515
Per share – basic and diluted ($) 0.00
Net income (loss)
217
Per share – basic and diluted ($) 0.00
2,074
Capital expenditures
Working capital (deficiency)(1)
5,548
1,845
607
381
0.00
(494)
(0.00)
1,392
2,943
1,884
565
417
0.00
85
0.00
649
3,961
1,547
(774)
119
0.00
(182)
(0.00)
137
1,601
70
(158)
(0.00)
3,040
0.01
533
1,274
1,260
1,099
335
(210)
(166)
62
(67)
130
0.00
(0.00)
670 (182) 400
0.01 (0.00) 0.00
99
498
(0.00)
124
4,218
4,270
(15,068) (15,129) (14,908)
Total assets
48,500
42,835
42,321
42,429
44,246
41,914
41,138 41,097
Shares outstanding (000s)
485,305 432,987
432,987 432,987
432,987 102,267
102,267 102,267
Operations:
Oil volumes (bbls/d)
Operating netback(1) ($/bbl)
174
183
199
176
202
211
231
238
91.06
64.58
51.08
41.30
36.67
42.37
27.15
31.60
(1)
See "Non-IFRS and Other Financial Measures " on page 15 of this MD&A.
Production has been declining over the past eight quarters due to natural reservoir declines in the Cuisinier
oil field, with the exception of Q2 fiscal 2022, which benefited from incremental production from two wells
offline for work-over activity in Q1 fiscal 2022. Ongoing volatility with a generally increasing trend in US
Brent prices during the past eight quarters resulted in a trend towards increased oil sales and operating
netbacks despite natural declines in production rates. Cash flow from operations in Q1 fiscal 2021 benefited
from recovery of joint venture audit findings (note that subsequent audits have been delayed due to COVID
19 restrictions), followed by a use of cash in Q2 fiscal 2021 due to low commodity prices. Rising commodity
pricing increased cash flow from operations with the exception of Q1 fiscal 2022 when revenue and cash
flow were significantly impacted by low commodity prices. Over the years, net (losses)/income have been
affected by fluctuations in foreign exchange, hedging gains and losses and capital development. Net income
from Q4 fiscal 2020 through Q4 fiscal 2021 was materially impacted by the impact of US/CAD exchange
rates to the Company’s US dollar Westpac Credit facility as well as the impact of gains and losses on
derivative financial instruments. After the repayment of debt and cancellation of all derivative instruments in
Q4 fiscal 2021, net income is less subject to foreign exchange and commodity price volatility. Working
capital3 deficiency occurred during the periods from Q1 fiscal 2021 to Q3 fiscal 2021 due to the
reclassification of the Company’s debt from long term to current due to the delay in negotiating an extension
to the maturity date.
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
3 See "Non-IFRS and Other Financial Measures " on page 15 of this MD&A.
-19-
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 not effective at
March 31, 2022 due to 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 has limited 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 and for tax planning, tax provision and compilation of corporate tax
returns.
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 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, which are reviewed
on an ongoing basis. Significant estimates and judgments made by management in the preparation of these
financial statements are outlined below.
-20-
(a) Critical judgments in applying accounting policies
The following are the critical judgments, apart from those involving estimations (see below), that
management has made in the process of applying the Company’s accounting policies and that have the
most significant effect on the amounts recognized in these financial statements.
Identification of Cash-generating units
Petroleum and natural gas properties are aggregated into cash-generating units, for the purpose of
assessing recoverability, based on their ability to generate largely independent cash flows. By their
nature, these estimates and assumptions are subject to measurement uncertainty and may impact the
carrying value of the Company's assets in future periods.
Impairment indicators
At the end of each reporting period, the Company reviews the petroleum and natural gas properties for
external or internal circumstances that indicate that the petroleum and natural gas properties may be
impaired. For the purpose of impairment testing, assets are grouped together into cash generating units
(“CGU”s) for the purpose of impairment testing, which is the lowest level at which there are identifiable
cash inflows that are largely independent of the cash flows of other groups of assets. If any such
indication of impairment exists, the Company makes an estimate of its recoverable amount. A CGU’s
recoverable amount is the higher of its fair value less costs to sell (“FVLCS”) and its value in use (“VIU”).
The application of the Company’s accounting policy for exploration and evaluation, petroleum and natural
gas properties required management to make certain judgments as to future events and circumstances
as to whether economic quantities of reserves have been found.
(b) Key sources of uncertainty
The following are the key assumptions concerning the sources of estimation uncertainty at the end of
the reporting period that have a significant risk of causing adjustments to the carrying amounts of assets
and liabilities.
Decommissioning provisions
The Company estimates future remediation costs of production facilities, wells and pipelines at different
stages of development and construction of assets or facilities. In most instances, removal of assets
occurs many years into the future. This requires judgment regarding abandonment date, future
environmental and regulatory legislation, the extent of reclamation activities, the engineering
methodology for estimating cost, future removal technologies in determining the removal cost and
liability-specific discount rates to determine the present value of these cash flows.
Impairment of petroleum and natural gas assets
Petroleum and natural gas properties are assessed for recoverability at a cash generating unit (“CGU”)
level. The determination of CGUs is subject to management judgements. Recoverability is assessed by
comparing the carrying value of the asset to its recoverable amount, which is based on the higher of fair
value of the assets less the cost to sell (“FVLCS”) or value in use (“VIU”).
The significant estimates used in the determination of the recoverable amount include the following:
• proved and probable oil and gas reserves and the related cash flows
• discount rates – the discount rates used to calculate the net present value of proved and
probable oil and gas reserves may be influenced by changes in the general economic
environment which could result in significant changes to the estimate
The estimate of proved plus probable oil and gas reserves and the related cash flows requires the
expertise of independent third party reserve engineers and includes significant assumptions related to:
• Forecasted oil and gas commodity prices
• Forecasted production
• Forecasted operating costs
-21-
• Forecasted royalty costs
• Forecasted future development costs
Reserves
The estimate of proved and probable oil and gas reserves is integral to the calculation of the amount of
depletion charged to the statement of operations and is also a key determinant in assessing whether the
carrying value of any of the Company’s petroleum and natural gas properties has been impaired.
Changes in reported reserves can impact asset carrying values due to changes in expected future cash
flows.
The Company’s reserves are evaluated and reported on by independent reserve engineers at least
annually in accordance with Canadian Securities Administrators’ National Instrument 51-101– Standards
of Disclosure For Oil and Gas Activities ("NI-51-101"). Reserve estimation is based on a variety of factors
including engineering data, geological and geophysical data, projected future rates of production,
forecasted oil and gas commodity prices, all of which are subject to significant judgment and
interpretation. Additional the Reserve estimation includes future development costs, which represent
the Company’s best estimate of the nature cost and timing development activities expected in the future
and required to access identified reserves. These future capital estimates include significant judgements
and uncertainty.
Share-based payments
The Company measures the cost of its share-based payments to directors, officers, employees and
certain consultants by reference to the fair value of the equity instruments at the date at which they are
granted. The assumptions used in determining fair value include: share price, expected lives of options,
risk-free rates of return, share price volatility and the estimated forfeiture rate. Changes to assumptions
may have a material impact on the amounts presented.
Liquidity
As part of its capital management process, the Company prepares budgets and forecasts, which are
used by management and the Board of Directors to direct and monitor the strategy and ongoing
operations and liquidity of the Company. Budgets and forecasts are subject to significant judgment and
estimates relating to activity levels, future cash flows and the timing thereof and other factors which may
or may not be within the control of the Company. The current challenging economic climate may lead
to adverse changes in cash flow or working capital4 levels, which may also have a direct impact on the
Company’s results and financial positions. These and other factors may adversely affect the Company’s
liquidity and the Company’s ability to generate profits in the future.
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 operations, funds from operations per share, adjusted net
income and adjusted net income 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 netback:
4 See "Non-IFRS and Other Financial Measures " on page 15 of this MD&A.
-22-
($000s)
Operating netbacks
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
Oil sales
Realized gain on financial instruments
Royalties
Operating expenses
Operating netback
2,374
-
(142)
(807)
1,425
1,601
-
(96)
(835)
670
7,650
-
(459)
(3,082)
4,109
5,234
1,033
(314)
(3,199)
2,754
Funds from operations
Management utilized funds from operations 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 operations is calculated
by adding back all non-cash expense deductions to the net loss for the quarter and year. The following table
reconciles cash from operations to funds from (used in) operations, which is used in this MD&A:
($000s)
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
Cash from operating activities
Changes in non-cash working capital
Funds from (used in) operations
437
78
515
70
(228)
(158)
835
597
1,432
301
(606)
(305)
Capital Management measures
Working capital
Bengal uses working capital to monitor its capital structure, liquidity, and its ability to fund current operations.
Working capital is calculated as current assets less current liabilities but excludes other obligations and
current portion of decommissioning obligations.
-23-
Non-IFRS Financial Ratios
Bengal uses operating netback per boe to assess the Company’s operating performance on a per unit of
production basis. Operating netback per barrel equals operating netback divided by the applicable number
of barrels.
Operating netbacks per barrel
($/bbl)
Oil sales
Realized gain on financial instruments
Royalties
Operating expenses
Operating netback
Three months ended
March 31
2021
2022
Twelve months ended
March 31
2021
2022
151.72
-
(9.08)
(51.58)
91.06
87.86
-
(5.27)
(45.92)
36.67
114.53
-
(6.87)
(46.14)
61.52
64.99
12.83
(3.90)
(39.72)
34.20
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
bbls
bbls/d
bopd
$/bbl
ft3
FY
K
km
km2
Q1
Q2
Q3
Q4
WI
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
barrel
barrels
barrels per day
barrels of oil per day
dollars per barrel
cubic feet
fiscal year
thousand
kilometres
square kilometres
three months ended June 30
three months ended September 30
three months ended December 31
three months ended March 31
working interest
-24-
RISK FACTORS
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 both Canada and
Australia. 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 below 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 below does not purport to be an exhaustive summary of the risks affecting Bengal.
Risks Relating to the COVID-19 Pandemic
The COVID-19 pandemic has resulted in emergency actions taken by governments worldwide, which has
had an effect on the Company. The actions taken by these governments have typically included, but is not
limited to travel bans, mandatory and self-imposed quarantines and isolations, social distancing, and the
closing of non-essential businesses. Additionally, such actions have resulted in volatility and disruptions in
regular business operations, supply chains and financial markets.
The full extent of the risks surrounding the COVID-19 pandemic is continually evolving. The following risks
disclosed in our Annual Information Form for the year ended March 31, 2022 may be exacerbated as a result
of the COVID-19 pandemic: market risks related to the volatility of oil and gas prices, volatility of foreign
exchange rates, volatility of the market price of common shares, and hedging arrangements; operational
risks related to increasing operating costs or declines in production levels, operator performance and
payment delays, government regulations, ability to obtain additional financing, and variations in foreign
exchange rates; and other risks related to cyber-security as our workforce moves to remote connections,
accounting adjustments, effectiveness of internal controls, and reliance on key personnel, management, and
labour.
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
as a result 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.
-25-
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 the impact of the COVID-19 global pandemic and recent 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 as a result 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 of 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
-26-
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 fund its ongoing activities at all times. From
time to time, Bengal may require additional financing in order 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 as a result 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, 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, provincial 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 Corporation.
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
-27-
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.
ADDITIONAL INFORMATION
Additional information relating to Bengal is filed on SEDAR and can be viewed at www.sedar.com.
Information can also be obtained by contacting the Company at Bengal Energy Ltd., Suite 1110, 715 5th
Avenue SW., Calgary, Alberta T2P 2X6, by email to info@bengalenergy.ca or by accessing Bengal’s website
at www.bengalenergy.ca.
Forward-looking Statements - Certain statements contained within this MD&A constitute forward-looking statements
or 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 pilot;
● The belief that the Cooper Basin assets offer attractive upside potential for oil and gas;
● Timing and re-assessment of restarting the planning and drilling selection for the 2022 multi-well development
and appraisal drilling campaign:
● The timing of the planned injection of produced formation water on the Barta Block PL 303 and the anticipated
resulting production increases, future waterflood expansion phases, and reduced operating costs;
● 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;
● The future development prospects generated by the initial development activities at PL 1110 (previously 114)
Wareena, PL 1109 (previously 157) Ghina, PL 188 Ramses, PL 411 Karnak, PPL 138 pipeline;
-28-
● 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 operation cash flows and alternative forms of financing;
● Bengal’s ability to finance its working capital deficiency and to source funds for the same;
● Treatment under governmental regulatory regimes and tax laws;
● Capital expenditures programs 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 2022 and capital program.
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:
● The continuing adverse impact of COVID-19 on economic activity and demand for oil and natural gas;
● Uncertainties associated with the COVID-19 pandemic;
● Fluctuations in commodity prices, foreign exchange or interest rates;
● Changes in the demand for or supply of Bengal's products;
●
● 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
Liabilities inherent in oil and natural gas operations;
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;
Incorrect assessment of the value of acquisitions;
Inability to meet commitments due to inability to raise funds or complete farm-outs;
● The availability of qualified operating or management personnel;
●
●
● 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.
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 (www.sedar.com) and at Bengal’s website (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, 2022 (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
-29-
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.
-30-
Consolidated Financial Statements
Years Ended
March 31, 2022 and 2021
MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL REPORTING
The accompanying consolidated financial statements are the responsibility of management. The
consolidated financial statements have been prepared by management in accordance with International
Financial Reporting Standards as issued by the International Accounting Standards Board outlined in the
notes to the consolidated financial statements. The consolidated financial statements include certain
estimates that reflect management’s best judgments. Management has determined such amounts on a
reasonable basis in order to ensure that the consolidated financial statements are presented fairly, in all
material respects. In the opinion of management, the consolidated financial statements have been prepared
within acceptable limits of materiality and are in accordance with International Financial Reporting Standards.
The financial information contained in the annual report is consistent with that in the consolidated financial
statements.
Management is also responsible for establishing and maintaining appropriate systems of internal control over
the Company’s financial reporting. The internal control system was designed to provide reasonable
assurance to management regarding the preparation and presentation of the consolidated financial
statements. Management tested and evaluated the effectiveness of its disclosure controls and procedures
and internal controls over financial reporting as at March 31, 2022. During this evaluation, management
identified material weaknesses due to the limited number of finance and accounting personnel at the
Company dealing with complex and non-routine accounting transactions that may arise and due to a lack of
segregation of duties and as a result the controls are not considered effective. All internal control systems,
no matter how well designed, have inherent limitations. Therefore, these systems provide reasonable but
not absolute assurance that financial information is accurate and complete.
KPMG LLP, an independent firm of Chartered Professional Accountants, has been engaged, as approved
by a vote of the shareholders at the Company’s most recent annual general meeting, to examine the
consolidated financial statements in accordance with Canadian generally accepted auditing standards and
provide an independent professional opinion.
The Audit Committee of the Board of Directors with all of its members being independent directors, have
reviewed the consolidated financial statements including notes thereto with management and KPMG LLP.
The consolidated financial statements have been approved by the Board of Directors on the recommendation
of the Audit Committee.
(signed) “Chayan Chakrabarty”
Chayan Chakrabarty
President & Chief Executive Officer
(signed) “Jerrad Blanchard”
Jerrad Blanchard
Chief Financial Officer
-32-
KPMG LLP
205 5th Avenue SW
Suite 3100
Calgary AB T2P 4B9
Tel (403) 691-8000
Fax (403) 691-8008
www.kpmg.ca
INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Bengal Energy Ltd.
Opinion
We have audited the consolidated financial statements of Bengal Energy Ltd. (the
“Company”), which comprise:
–
–
the consolidated statements of financial position as at March 31, 2022 and March 31,
2021
the consolidated statements of income (loss) and comprehensive income (loss) for the
years then ended
the consolidated statements of changes in shareholders’ equity for the years then ended
the consolidated statements of cash flows for the years then ended
–
–
– and notes to the consolidated financial statements, including a summary of significant
accounting policies
(Hereinafter referred to as the “financial statements”).
In our opinion, the accompanying financial statements present fairly, in all material respects,
the consolidated financial position of the Company as at March 31, 2022 and March 31,
2021, and its consolidated financial performance and its consolidated cash flows for the
years then ended in accordance with International Financial Reporting Standards (IFRS) as
issued by the International Accounting Standards Board (IASB).
Basis for Opinion
We conducted our audit in accordance with Canadian generally accepted auditing
standards. Our responsibilities under those standards are further described in the “Auditors’
Responsibilities for the Audit of the Financial Statements” section of our auditors’ report.
We are independent of the Company in accordance with the ethical requirements that are
relevant to our audit of the financial statements in Canada and we have fulfilled our other
ethical responsibilities in accordance with these requirements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide
a basis for our opinion.
KPMG LLP, an Ontario limited liability partnership and member firm of the KPMG global organization of independent
member firms affiliated with KPMG International Limited, a private English company limited by guarantee. KPMG
Canada provides services to KPMG LLP.
Key Audit Matters
Key audit matters are those matters that, in our professional judgment, were of most
significance in our audit of the financial statements for the year ended March 31, 2022.
These matters were addressed in the context of our audit of the financial statements as a
whole, and in forming our opinion thereon, and we do not provide a separate opinion on
these matters.
We have determined the matters described below to be the key audit matters to be
communicated in our auditors’ report.
Assessment of indicators of impairment for the Cuisinier cash-generating unit, which
includes the petroleum and natural gas properties therein
Description of the matter
We draw attention to notes 3 (f), 4 (a), 4 (b) and 8 to the financial statements. The Company
assesses at each reporting date whether there is an indication that petroleum and natural
gas properties within the Cuisinier cash generating unit (the “Cuisinier CGU”) may be
impaired. The Company determined that there were no external or internal indicators of
impairment at March 31, 2022 for the Cuisinier CGU and no impairment tests were required.
Significant management judgment is required to analyze the relevant external and internal
indicators of impairment with the estimate of proved and probable oil and gas reserves and
the related cash flows being significant to the assessment.
The estimate of proved and probable oil and gas reserves and the related cash flows
includes significant assumptions related to:
•
•
•
•
•
Forecasted oil and gas commodity prices
Forecasted production
Forecasted operating costs
Forecasted royalty costs
Forecasted future development costs
The Company engages an independent third-party reserve engineer to estimate the proved
and probable oil and gas reserves and the related cash flows as at March 31, 2022.
Why the matter is a key audit matter
We identified the assessment of indicators of impairment for the Cuisinier CGU, which
includes the petroleum and natural gas properties therein, as a key audit matter. Significant
auditor judgment was required to evaluate the results of our audit procedures with respect
to the internal and external indicators of impairment, including the estimate of proved and
probable oil and gas reserves and the related cash flows.
How the matter was addressed in the audit
The following are the primary procedures we performed to address this key audit matter:
2
We evaluated the Company’s assessment of external and internal indicators of impairment
by considering whether quantitative and qualitative information in the analysis was
consistent with external market and industry data, the Company’s press releases and certain
minutes of the meetings of the Board of Directors and the estimate of proved and probable
oil and gas reserves and the related cash flows.
With respect to the estimate of proved and probable oil and gas reserves and the related
cash flows as at March 31, 2022:
• We evaluated the competence, capabilities and objectivity of the independent third party
reserve engineer engaged by the Company
• We compared forecasted oil and gas commodity prices to those published by other
independent third party reserve engineers
• We compared the fiscal 2022 actual production, operating costs, royalty costs and
development costs of the Company to those estimates used in the prior year’s estimate
of proved oil and gas reserves and the related cash flows to assess the Company’s
ability to accurately forecast
• We evaluated the appropriateness of forecasted production and forecasted operating
costs, royalty costs and future development costs assumptions by comparing to fiscal
2022 historical results. We took into account changes in conditions and events affecting
the Company to assess the adjustments or lack of adjustments made by the Company
in arriving at the assumptions.
Other Information
Management is responsible for the other information. Other information comprises:
–
the information included in Management’s Discussion and Analysis filed with the
relevant Canadian Securities Commissions.
Our opinion on the financial statements does not cover the other information and we do not
and will not express any form of assurance conclusion thereon.
In connection with our audit of the financial statements, our responsibility is to read the other
information identified above and, in doing so, consider whether the other information is
materially inconsistent with the financial statements or our knowledge obtained in the audit
and remain alert for indications that the other information appears to be materially misstated.
We obtained the information included in Management’s Discussion and Analysis filed with
the relevant Canadian Securities Commissions as at the date of this auditors’ report. If,
based on the work we have performed on this other information, we conclude that there is
a material misstatement of this other information, we are required to report that fact in the
auditors’ report.
We have nothing to report in this regard.
3
Responsibilities of Management and Those Charged with Governance for the
Financial Statements
Management is responsible for the preparation and fair presentation of the financial
statements in accordance with International Financial Reporting Standards (IFRS) as issued
by the International Accounting Standards Board (IASB), and for such internal control as
management determines is necessary to enable the preparation of financial statements that
are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, management is responsible for assessing the
Company’s ability to continue as a going concern, disclosing as applicable, matters related
to going concern and using the going concern basis of accounting unless management
either intends to liquidate the Company or to cease operations, or has no realistic alternative
but to do so.
Those charged with governance are responsible for overseeing the Company’s financial
reporting process.
Auditors’ Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements
as a whole are free from material misstatement, whether due to fraud or error, and to issue
an auditors’ report that includes our opinion.
Reasonable assurance is a high level of assurance, but is not a guarantee that an audit
conducted in accordance with Canadian generally accepted auditing standards will always
detect a material misstatement when it exists.
Misstatements can arise from fraud or error and are considered material if, individually or in
the aggregate, they could reasonably be expected to influence the economic decisions of
users taken on the basis of the financial statements.
As part of an audit in accordance with Canadian generally accepted auditing standards, we
exercise professional judgment and maintain professional skepticism throughout the audit.
We also:
–
Identify and assess the risks of material misstatement of the financial statements,
whether due to fraud or error, design and perform audit procedures responsive to those
risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for
our opinion.
The risk of not detecting a material misstatement resulting from fraud is higher than for
one resulting from error, as fraud may involve collusion, forgery, intentional omissions,
misrepresentations, or the override of internal control.
– Obtain an understanding of internal control relevant to the audit in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Company’s internal control.
4
– Evaluate the appropriateness of accounting policies used and the reasonableness of
accounting estimates and related disclosures made by management.
– Conclude on the appropriateness of management’s use of the going concern basis of
accounting and, based on the audit evidence obtained, whether a material uncertainty
exists related to events or conditions that may cast significant doubt on the Company’s
ability to continue as a going concern. If we conclude that a material uncertainty exists,
we are required to draw attention in our auditors’ report to the related disclosures in the
financial statements or, if such disclosures are inadequate, to modify our opinion. Our
conclusions are based on the audit evidence obtained up to the date of our auditors’
report. However, future events or conditions may cause the Company to cease to
continue as a going concern.
– Evaluate the overall presentation, structure and content of the financial statements,
including the disclosures, and whether the financial statements represent the underlying
transactions and events in a manner that achieves fair presentation.
– Communicate with those charged with governance regarding, among other matters, the
planned scope and timing of the audit and significant audit findings, including any
significant deficiencies in internal control that we identify during our audit.
– Provide those charged with governance with a statement that we have complied with
relevant ethical requirements regarding independence, and communicate with them all
relationships and other matters that may reasonably be thought to bear on our
independence, and where applicable, related safeguards.
– Obtain sufficient appropriate audit evidence regarding the financial information of the
entities or business activities within the group Company to express an opinion on the
financial statements. We are responsible for the direction, supervision and performance
of the group audit. We remain solely responsible for our audit opinion.
– Determine, from the matters communicated with those charged with governance, those
matters that were of most significance in the audit of the financial statements of the
current period and are therefore the key audit matters. We describe these matters in our
auditors’ report unless law or regulation precludes public disclosure about the matter or
when, in extremely rare circumstances, we determine that a matter should not be
communicated in our auditors’ report because the adverse consequences of doing so
would reasonably be expected to outweigh the public interest benefits of such
communication.
The engagement partner on the audit resulting in this auditors’ report is David Yung.
Chartered Professional Accountants
Calgary, Canada
June 15, 2022
5
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Thousands of Canadian dollars)
As at March 31,
Assets
Current assets:
Notes
2022
2021
Cash and cash equivalents
5,11
$ 5,413
$ 4,531
Restricted cash
Trade and other receivables
Prepaid expenses and deposits
Exploration and evaluation assets
Property, plant and equipment
Total assets
Liabilities and Shareholders’ Equity
Current liabilities:
Trade and other payables
Current portion of lease liability
Decommissioning and restoration liability
Lease liability
Shareholders’ equity:
Share capital
Contributed surplus
6
7
8
9
12
13
12
14
-
2,646
658
8,717
10,352
29,508
40
1,224
445
6,240
9,890
28,116
$ 48,577
$ 44,246
$ 3,211
$ 1,939
37
3,248
3,379
31
6,658
31
1,970
3,478
68
5,516
118,796
8,015
114,636
7,870
Accumulated and other comprehensive loss
(1,078)
(336)
Deficit
(83,814)
(83,440)
Total liabilities and shareholder’s equity
Commitments (Note 22)
See accompanying notes to the consolidated financial statements.
41,919
38,730
$ 48,577
$ 44,246
-38-
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Thousands of Canadian dollars, except per share amounts)
For the years ended March 31,
Notes
2022
2021
Revenue
Oil sales
Royalties
Realized gain on financial instruments
Unrealized loss on financial instruments
Expenses
General and administrative
Operating
Depletion and depreciation
Impairment
Share-based compensation
Loss (gain) on foreign exchange
Other (income) expense
Gain on settlement of long-term debt
Other
Finance expense
Net (loss) income
Exchange differences on translation of foreign operations
Comprehensive (loss) income
Income (loss) per share – basic & diluted
Weighted average shares outstanding (000s) – basic & diluted
See accompanying notes to the consolidated financial statements.
16
$ 7,650
$ 5,234
(459)
(314)
7,191
-
-
4,920
1,033
(1,539)
7,191
4,414
2,652
3,082
1,067
568
135
2,334
3,199
1,333
-
9
16
(3,694)
7,520
3,181
-
-
45
(374)
(742)
(3,490)
(114)
909
3,928
1,315
$ (1,116)
$ 5,243
$ (0.00)
$ 0.03
436,427
133,073
20
20
8
7
11
19
17
17
-39-
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Thousands of Canadian dollars)
For the years ended March 31,
Share capital
Balance beginning of the year
Issuance of common shares for cash
Share issue costs
Balance at end of year
Contributed surplus
Balance at beginning of year
Share-based compensation - expensed
Share-based compensation – capitalized
Balance at end of year
Accumulated other comprehensive loss
Balance at beginning of year
2022
2021
$ 114,636
$ 98,100
4,185
16,536
(25)
-
118,796
114,636
7,870
135
10
8,015
7,861
9
-
7,870
(336)
(1,651)
Exchange differences translation of foreign operations
(742)
1,315
Balance at end of year
Deficit
Balance at beginning of year
Net (loss) income
Balance at end of year
(1,078)
(336)
(83,440)
(87,368)
(374)
3,928
(83,814)
(83,440)
Total shareholders’ equity
$ 41,919
$ 38,730
See accompanying notes to the consolidated financial statements.
-40-
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Canadian dollars)
For the years ended March 31,
Operating activities:
Net (loss) income for the year
Add (deduct) non-cash items
Depletion and depreciation
Accretion on decommissioning and restoration liability
Accretion on credit facility
Gain on asset sale and other
Gain on settlement of credit facility
Share-based compensation
Interest on lease liability
Impairment
Unrealized loss on financial instruments
Unrealized foreign exchange gain
Funds from (used in) operations
Change in non-cash working capital
Net cash from operating activities
Investing activities:
Exploration and evaluation expenditures
Petroleum and natural gas property expenditures
Change in restricted cash
Change in non-cash working capital
Net cash used in investing activities
Financing activities:
Issuance of common shares, net of issuance costs
Repayment of credit facility
Lease payments
Change in non-cash working capital
Net cash from financing activities
Net increase in cash and cash equivalents
Cash and cash equivalents, beginning of year
Impact of foreign exchange on cash and cash equivalents
Cash and cash equivalents, end of year
See accompanying notes to the consolidated financial statements.
Notes
2022
2021
$ (374)
$ 3,928
1,067
38
-
-
-
135
5
568
-
(7)
1,333
19
215
(15)
(3,490)
9
10
-
1,539
(3,853)
7
1,432
(597)
(305)
606
22
835
301
7
8
22
14
12
22
(1,231)
(3,091)
40
221
(61)
(1,193)
100
474
(4,061)
(680)
4,160
-
(36)
-
16,536
(12,649)
(53)
(6)
4,124
3,828
898
4,531
(16)
$5,413
3,449
998
84
$ 4,531
-41-
BENGAL ENERGY LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years ended March 31, 2022 and 2021
(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 March 31, 2022 and
2021 and for the years then ended are comprised of the Company and its wholly-owned subsidiaries
including Bengal Energy Australia (Pty) Ltd. (“Bengal Pty”) and Bengal Energy International Inc., which are
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 1110, 715 5th Ave SW, Calgary, Alberta, Canada, T2P 2X6.
2.
BASIS OF PREPARATION
These financial statements have been prepared in accordance with International Financial Reporting
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). See Note 3 for
significant accounting policies.
The financial statements were approved and authorized for issuance by the Board of Directors on June 15,
2022.
These financial statements have been prepared on a historical cost basis, except for decommissioning
liabilities commodity contracts as discussed in Notes 13 and 19.
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.
Evolving Demand for Energy
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.
3.
SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently to all periods presented in these
financial statements and have been applied consistently by the Company and its subsidiaries.
-42-
(a) Basis of consolidation
The financial statements incorporate the financial statements of the Company and its wholly-owned
subsidiaries Bengal Energy Australia (Pty) Ltd. and Bengal Energy International Inc.
Subsidiaries are entities controlled by the Company. Control exists when the Company has the
power to govern the financial and operating policies of an entity so as to obtain the benefits from its
activities. In assessing control, potential voting rights that currently are exercisable are taken into
account. The financial statements of subsidiaries are included in the financial statements from the
date that control commences until the date that control ceases.
The Company recognizes in the financial statements its proportionate share of the assets, liabilities,
revenues and expenses of its joint operations.
All intra-group transactions, balances, income and expenses are eliminated in full on consolidation.
(b) Cash and cash equivalents
Cash and cash equivalents include cash and all investments with a maturity of three months or less.
(c) Provisions
A provision is recognized if, as a result of a past event, the Company has a present legal or
constructive obligation that can be estimated reliably, and it is probable that an outflow of economic
benefits will be required to settle the obligation. Provisions are determined by discounting the
expected future cash flows at a pre-tax “risk-free” rate that reflects current market assessments of
the time value of money and the risks specific to the liability. The unwinding of the discount is
recognized as a finance expense. Provisions are not recognized for future operating losses.
Decommissioning and restoration liabilities
The Company’s activities give rise to dismantling, decommissioning and site disturbance
remediation activities. Provision is made for the estimated cost of site restoration and capitalized in
the relevant asset category.
Decommissioning obligations are measured at the present value of management’s best estimate of
the expenditures required to settle the present obligation at the period end date. Subsequent to the
initial measurement, the obligation is adjusted at the end of each period to reflect the passage of
time and changes in the estimated future cash flows underlying the obligation. The increase in the
provision due to the passage of time is recognized as finance costs whereas increases/decreases
due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon
settlement of the asset retirement obligations are charged against the provision to the extent the
provision was established.
(d) Oil and natural gas exploration and evaluation expenditures
Exploration and evaluation assets (“E&E assets”)
All costs incurred prior to obtaining the legal right to explore an area are expensed when incurred.
Generally, costs directly associated with the exploration and evaluation of crude oil and natural gas
reserves are initially capitalized. Exploration and evaluation costs are those expenditures for an
area where technical feasibility and commercial viability have not yet been demonstrated. These
costs generally include unproved property acquisition costs, geological and geophysical costs,
sampling and appraisals, drilling and completion costs and capitalized decommissioning costs.
Costs are held in exploration and evaluation assets until the technical feasibility and commercial
viability of the project is established. Amounts are generally reclassified to petroleum and natural
-43-
gas properties once probable reserves have been assigned to the field. If probable reserves have
not been established through the completion of exploration and evaluation activities and there are
no future plans for activity in that field, then the exploration and evaluation expenditures are
determined to be impaired and the amounts are charged to profit or loss.
(e) Petroleum and natural gas properties
Petroleum and natural gas properties are stated at cost less accumulated depreciation and depletion
and accumulated impairment losses. The initial cost of a petroleum and natural gas property is
comprised of its purchase price or construction cost, any costs directly attributable to bringing the
asset into operation, the initial estimate of the decommissioning obligation, and for qualifying assets,
borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair
value of any other consideration given up to acquire the asset.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability and
the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas
interests only when they increase the future economic benefits embodied in the specific asset to
which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized
oil and natural gas interests generally represent costs incurred in developing proved and/or probable
reserves and bringing in or enhancing production from such reserves, and are accumulated on a
field or geotechnical area basis. The carrying amount of any replaced or sold component is
derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized
in profit or loss as incurred.
Depletion and depreciation
The net book value of producing assets are depleted on a field-by-field basis using the unit of
production method with reference to the ratio of production in the year to the related proved and
probable reserves, taking into account estimated future development costs necessary to bring those
reserves into production. For purposes of these calculations, production and reserves of natural gas
are converted to barrels on an energy equivalent basis.
Other assets are depreciated on a declining basis at rates ranging from 20% to 30% per annum.
Gains and losses on disposal of an item of property, plant and equipment, including oil and natural
gas interests, are determined by comparing the proceeds from disposal with the carrying amount of
property, plant and equipment and are recognized as separate line items in profit or loss.
(f) Impairment
E&E assets and petroleum and natural gas properties
E&E assets are assessed for impairment when facts and circumstances suggest that the carrying
amount exceeds the recoverable amount and when they are reclassified to petroleum and natural
gas properties. For the purpose of impairment testing, E&E assets are grouped by concession or
production field with other E&E assets belonging to the same concession or production field. The
impairment loss will be calculated as the excess of the carrying value over recoverable amount of
the E&E impairment grouping and any resulting impairment loss is recognized in profit or loss.
Recoverable amount is determined as the higher of the value in use or fair value less costs to sell
.
At the end of each reporting period, the Company reviews the petroleum and natural gas properties
for external or internal circumstances that indicate that the petroleum and natural gas properties may
be impaired. For the purpose of impairment testing, assets are grouped together into cash
generating units (“CGU”s) for the purpose of impairment testing, which is the lowest level at which
-44-
there are identifiable cash inflows that are largely independent of the cash flows of other groups of
assets. If any such indication of impairment exists, the Company makes an estimate of its
recoverable amount. A CGU’s recoverable amount is the higher of its fair value less costs to sell
(“FVLCS”) and its value in use (“VIU”). At March 31, 2022, the Company has one producing CGU,
the Cuisinier field located in Australia, in the Cooper Basin.
The FVLCS is determined as the amount that would be obtained from the sale of a CGU in an arm’s
length transaction between knowledgeable and willing parties. The VIU is generally determined as
the net present value of the estimated future cash flows expected to arise from the continued use of
the CGU, including any expansion prospects, and its eventual disposal, using assumptions that an
independent market participant may take into account. The cash flows are discounted by an
appropriate discount rate which would be applied by such a market participant to arrive at a net
present value of the CGU.
An impairment is recognized if the carrying amount of an asset or its CGU exceeds its estimated
recoverable amount. Impairment losses, if any, are recognized on the consolidated statement of
profit or loss and comprehensive profit or loss.
At the end of each subsequent reporting period, impairment losses are assessed for indicators of
impairment reversal. An impairment loss is reversed if there has been a change in the estimates
used to determine the recoverable amount. Where an impairment loss subsequently reverses, the
carrying amount of the asset or CGU is increased to the revised estimate of its recoverable amount,
but so that the increased carrying amount does not exceed the carrying amount that would have
been determined, net of depletion or amortization, had no impairment loss have been recognized for
the asset or CGU in prior years. A reversal of an impairment loss is recognized in the statement of
profit or loss and comprehensive profit or loss.
Financial assets
A financial asset is assessed at each reporting date to determine whether there is any objective
evidence that it is impaired. A financial asset is considered to be impaired if objective evidence
indicates that one or more events have had a negative effect on the estimated future cash flows of
that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the
difference between its carrying amount and the present value of the estimated future cash flows
discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The
remaining financial assets are assessed collectively in groups that share similar credit risk
characteristics.
All impairment losses are recognized in profit or loss.
An impairment loss is reversed if the reversal can be related objectively to an event occurring after
the impairment loss was recognized. For financial assets measured at amortized cost, the reversal
is recognized in profit or loss.
(g) Financial instruments
Financial instruments comprise of cash and cash equivalents, restricted cash, trade and other
receivables, derivative contracts, trade and other payables and credit facility.
i.
Classification and measurement of financial assets:
A financial asset is measured at amortized cost if it meets both of the following conditions and is
-45-
not designated at fair value through profit or loss (“FVTPL”):
-
it is held within a business model whose objective is to hold assets to collect contractual
cash flows; and
its contractual terms give rise on specified dates to cash flows that are solely payments of
principal and interest on the principal amount outstanding.
-
A debt investment is measured at fair value through other comprehensive income (“FVOCI”) if it
meets both of the following conditions and is not designated at FVTPL:
-
-
it is held within a business model whose objective is achieved by both collecting contractual
cash flows and selling financial assets; and
its contractual terms give rise on specified dates to cash flows that are solely payments of
principal and interest on the principal amount outstanding.
On initial recognition of an equity investment that is not held for trading, the Company may
irrevocably elect to present subsequent changes in the investment’s fair value in other
comprehensive income (“OCI”). This election is made on an investment-by-investment basis.
All financial assets not classified as measured at amortized cost or FVOCI as described above
are measured at FVTPL. On initial recognition, the Company may irrevocably designate a
financial asset that otherwise meets the requirements to be measured at amortized cost or at
FVOCI as measured as FVTLP if doing so eliminates or significantly reduces an accounting
mismatch that would otherwise arise.
A financial asset (unless it is a trade receivable without a significant financing component that is
initially measured at the transaction price) is initially measured at fair value plus, for an item not
at FVTPL, transaction costs that are directly attributable to its acquisition.
The following accounting policies apply to the subsequent measurement of financial assets:
a) Financial assets at FVTPL
These assets are subsequently measured at fair value. Net gains and losses, including any
interest or dividend income, are recognized in profit or loss.
b) Financial assets at amortized cost
These assets are subsequently measured at amortized cost using the effective interest
method. The amortized cost is reduced by impairment losses. Interest income, foreign
exchange gains and losses and impairment are recognized in profit or loss. Any gain or loss
on derecognition is recognized in profit or loss.
c) Debt investments at FVOCI
These assets are subsequently measured at fair value. Interest income calculated using the
effective interest method, foreign exchange gains and losses and impairment are recognized
in profit or loss. Other net gains and losses are recognized in OCI. On derecognition, gains
and losses accumulated in OCI are reclassified to profit or loss.
d) Cash and cash equivalents, restricted cash, trade and other receivables, trade and other
payables, and lease liability
The fair values of these financial instruments approximate their carrying amounts due to
their short-term maturity.
ii.
Classification and measurement of financial liabilities:
Financial liabilities are classified and measured at amortized cost or FVTPL. A financial liability
-46-
is classified at FVTPL if it is a derivative, or it is designated as such on initial recognition.
Financial liabilities at FVTPL are measured at fair value and net gains and losses, including any
interest expense, are recognized in profit or loss. Other financial liabilities are subsequently
measured at amortized cost using the effective interest method. Interest expense and foreign
exchange gains and losses are recognized in profit or loss. Any gain or loss on derecognition is
also recognized in profit or loss.
The Company has classified cash and cash equivalents, restricted cash, trade and other
receivables, and trade and other payables as ‘amortized cost’.
iii.
Derivative financial instruments
The Company may enter into certain financial derivative contracts in order to manage the
exposure to market risks from fluctuations in commodity prices. These instruments are not used
for trading or speculative purposes. The Company does not designate its financial derivative
contracts as effective accounting hedges and therefore will not apply hedge accounting, even
though the Company considers all commodity contracts to be economic hedges. As a result, all
derivative contracts are classified as Fair Value Through Profit and Loss (“FVTPL”) and are
recorded on the statement of financial position at fair value. Transaction costs are recognized
in profit or loss when incurred. Subsequent to initial recognition, derivatives are measured at
fair value, and changes therein will be recognized immediately in profit or loss.
The Company may enter into physical delivery sales contracts for the purposes of receipt or
delivery of non-financial items in accordance with its expected purchase, sale or usage
requirements as executory contracts. As such, these contracts are not considered to be
derivative financial instruments and will not be recorded at fair value on the statement of financial
position. Settlements on these physical delivery contracts will be recognized in petroleum and
natural gas revenue in the period of settlement.
iv.
Share capital
Common shares are classified as equity. Incremental costs directly attributable to the issue of
common shares and stock options are recognized as a deduction from equity, net of any tax
effects.
(h) Foreign currency translation
The financial statements are presented in Canadian dollars, which is the Canadian parent entity’s
functional and presentation currency, and the functional currency of the Australian subsidiary is
Australian dollars. For the accounts of foreign operations, assets and liabilities are translated at
period end exchange rates, while revenues and expenses are translated using average rates over
the period. Translation gains and losses relating to the foreign operations are included in
accumulated other comprehensive income, a component of equity. Foreign currency transactions
are translated into the legal entity’s functional currency at the exchange rate in effect at the
transaction; and any gains or losses are recorded in profit or loss.
(i) Share-based compensation
The Company accounts for share-based compensation granted to directors, officers, employees,
and consultants using the Black-Scholes option-pricing model to determine the fair value of the
options at grant date. An estimated forfeiture rate is incorporated into the fair value calculated and
adjusted to reflect the actual number of options that vest. Share-based compensation expense is
recorded and reflected as share-based compensation expense over the vesting period with a
corresponding amount reflected in contributed surplus. At exercise, the associated amounts
previously recorded as contributed surplus are reclassified to share capital.
(j) Revenue recognition
The nature of the Company’s performance obligations, including roles as third parties and partners,
-47-
are evaluated to determine if the Company acts as a principal. The Company recognizes revenue
on a gross basis when it acts as the principal and has primary responsibility for the transaction.
Revenue is recognized on a net basis if the Company acts in the capacity of an agent rather than as
a principal.
Revenue from the sales of crude oil is based on the consideration specified in the Crude Oil Sales
and Purchase Agreement (“COSP Agreement”) with the joint venture operator. The Company
recognizes revenue when it transfers control of the product to the joint venture operator, which is
generally at the time the joint venture operator obtains legal title of the crude oil and when it is
physically delivered to the pipeline at an estimated transaction price based on average US Brent
price and is adjusted for quality and other factors specified in the COSP Agreement once the product
is shipped to the end customer and lifted.
(k) Per share amounts
Basic per share amounts are computed by dividing net income (loss) by the weighted average
number of common shares outstanding for the period. Diluted per share amounts are calculated
giving effect to the potential dilution that would occur if stock options or other dilutive instruments
were exercised into common shares. The treasury stock method assumes that any proceeds upon
the exercise of dilutive instruments, including remaining unamortized compensation costs, would be
used to purchase common shares at the average market price of the common shares during the
period.
(l)
Income taxes
Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit
or loss except to the extent that it relates to items recognized directly in equity, in which case it is
recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted
or substantively enacted at the reporting date, and any adjustments to tax payable in respect of
previous years.
Deferred tax is recognized providing for temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for taxation purposes.
Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is
not a business combination. In addition, deferred tax is not recognized for taxable temporary
differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates
that are expected to be applied to temporary differences when they reverse, based on the laws that
have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities
are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the
same tax authority on the same taxable entity, or on different tax entities, but they intend to settle
current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized
simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be
available against which the temporary difference can be utilized. Deferred tax assets are reviewed
at each reporting date and are reduced to the extent that it is no longer probable that the related tax
benefit will be realized.
(m) Finance income and expenses
Finance income consists of interest earned on term deposits. Finance expenses include letter of
credit charges, interest on the Credit Facility, and accretion of the discount on decommissioning
obligations.
-48-
(n) Determination of fair value
A number of the Company’s accounting policies and disclosures required the determination of fair
value, both for financial and non-financial assets and liabilities. Fair values have been determined
for measurement and/or disclosure purposes based on the following methods. When applicable,
further information about the assumptions made in determining fair values is disclosed in the notes
specific to that asset or liability.
Fair Value Hierarchy
Financial instruments that are measured subsequent to initial recognition at fair value are grouped
into three categories based on the degree to which fair value is observable:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the
reporting date. Active markets are those in which transactions occur in sufficient frequency and
volume to provide pricing information on an ongoing basis;
Level 2 - Valuations are based on inputs other than quoted prices included in Level 1 that are
observable for the asset or liability, either directly or indirectly; including forward prices for
commodities, time value and volatility factors which can be substantially observed or corroborated
in the marketplace;
Level 3 - Inputs that are not based on observable data for the asset or liability.
The Company’s financial instruments comprise cash and cash equivalents, restricted cash, trade
and other receivables, trade and other payables, credit facility and derivatives.
The Company's policy is to recognize transfers in and out of the fair value hierarchy as of the date
of the event or change in circumstances that caused the transfer. There were no such transfers
during the period.
Fair values have been determined for measurement and disclosure purposes as follows:
i. Derivatives
The Company’s commodity contracts (swaps and put options) are measured at level 2 of
the fair value hierarchy. The fair value of the swap component is determined by discounting
the difference between the contracted prices and published forward price curves as at the
period end date, using the remaining contracted oil volumes and a risk-free interest rate.
The fair value of puts are based on option models that use publish information with respect
to volatility, prices, and interest rates.
(o) Leases
A contract is, or contains, a lease if the contract conveys the right to control the use of an identified
asset for a period of time in exchange for consideration. A lease liability is recognized at the
commencement of the lease term at the present value of the lease payments that are not paid at that
date. At the commencement date, a corresponding right-of-use asset is recognized at the amount
of the lease liability, adjusted for lease incentives received, retirement costs and initial direct costs.
Depreciation is recognized on the right-of-use asset over the lease term. Interest expense is
recognized on the lease liability using the effective interest rate method and payments are applied
against the lease liability. Lease terms are based on assumptions regarding extension terms that
allow for operational flexibility and future market conditions.
-49-
(p) Government grants
Government grants related to assets are initially recognized by the Company as deferred income at
fair value if there is reasonable assurance that they will be received, and the Company will comply
with the conditions associated with the grant; they are then recognized in profit or loss as other
income on a systematic basis over the useful life of the asset. Grants that compensate the Company
for expenses incurred are recognized in profit or loss on a systematic basis in the periods in which
the expenses are recognized. During year ended March 31, 2022, the Company recognized $97,776
(2021 - $249,675) as a reduction to operating/administrative expenses related to the Canadian
government wage and rental subsidy.
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 out-
lined below.
During the past 24 months commodity prices have been materially impacted by COVID-19 pandemic,
significant geopolitical conflicts and other factors outside of the Company’s control.
The current volatile 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. The situation is dynamic and
the ultimate duration and magnitude of the impact on the economy and the financial effect on the Company
is not known at this time. Estimates and judgements made by management in the preparation of the financial
statements are increasingly difficult and subject to a higher degree of measurement uncertainty during this
volatile period.
(a) Critical judgments in applying accounting policies
The following are the critical judgments, apart from those involving estimations (see below), that
management has made in the process of applying the Company’s accounting policies and that have
the most significant effect on the amounts recognized in these financial statements.
Identification of cash-generating units
Petroleum and natural gas properties are aggregated into cash-generating units, for the purpose of
assessing recoverability, based on their ability to generate largely independent cash inflows. By
their nature, these estimates and assumptions are subject to measurement uncertainty and may
impact the carrying value of the Company's assets in future periods.
Impairment indicators
The Company assesses at each reporting date whether there is an indication that petroleum and
natural gas properties within the Cuisinier cash generating unit (the “Cuisinier CGU”) may be
impaired. Significant judgment is required to analyze the relevant external and internal indicators of
impairment with the estimate of proved and probable and oil and gas reserves and the related cash
flows being significant to the assessment. If any such indication exists, the asset or the CGU’s
recoverable amount is estimated.
-50-
The application of the Company’s accounting policy for exploration and evaluation, petroleum and
natural gas properties required management to make certain judgments as to future events and
circumstances as to whether economic quantities of reserves have been found.
(b) Key sources of uncertainty
The following are the key assumptions concerning the sources of estimation uncertainty at the end
of the reporting period that have a significant risk of causing adjustments to the carrying amounts of
assets and liabilities.
Decommissioning provisions
The Company estimates future remediation costs of production facilities, wells and pipelines at
different stages of development and construction of assets or facilities. In most instances, removal
of assets occurs many years into the future. This requires judgment regarding abandonment date,
future environmental and regulatory legislation, the extent of reclamation activities, the engineering
methodology for estimating cost, future removal technologies in determining the removal cost and
liability-specific discount rates to determine the present value of these cash flows.
Impairment of petroleum and natural gas assets
Petroleum and natural gas properties are assessed for recoverability at a CGU level. The
determination of CGUs is subject to management judgements. Recoverability is assessed by
comparing the carrying value of the asset to its recoverable amount, which is based on the higher of
FVLCS or VIU.
The significant estimates used in the determination of the recoverable amount include the following:
• proved and probable oil and gas reserves and the related cash flows
• discount rates – the discount rates used to calculate the net present value of proved and
probable oil and gas reserves may be influenced by changes in the economic environment
which could result in significant changes to the estimate
The estimate of proved plus probable oil and gas reserves and the related cash flows requires the
expertise of independent third-party reserve engineers and includes significant assumptions related
to:
• Forecasted oil and gas commodity prices
• Forecasted production
• Forecasted operating costs
• Forecasted royalty costs
• Forecasted future development costs.
Reserves
The estimate of proved and probable oil and gas reserves is integral to the calculation of the amount
of depletion charged to the statement of operations and is also a key determinant in assessing
whether the carrying value of any of the Company’s petroleum and natural gas properties has been
impaired. Changes in reported reserves can impact asset carrying values due to changes in
expected future cash flows.
The Company’s reserves are evaluated and reported on by independent third-party reserve
engineers at least annually in accordance with Canadian Securities Administrators’ National
Instrument 51-101. Reserve estimation is based on a variety of factors including engineering data,
geological and geophysical data, projected future rates of production, forecasted oil and gas
commodity prices, and timing of future expenditures, all of which are subject to significant judgment
and interpretation.
-51-
Share-based payments
The Company measures the cost of its share-based payments to directors, officers, employees, and
certain consultants by reference to the fair value of the equity instruments at the date at which they
are granted. The assumptions used in determining fair value include: share price, expected lives of
options, risk-free rates of return, share price volatility and the estimated forfeiture rate. Changes to
assumptions may have a material impact on the amounts presented.
Liquidity
As part of its capital management process, the Company prepares budgets and forecasts, which are
used by management and the Board of Directors to direct and monitor the strategy and ongoing
operations and liquidity of the Company. Budgets and forecasts are subject to significant judgment
and estimates relating to activity levels, future cash flows and the timing thereof and other factors
which may or may not be within the control of the Company. The current challenging economic
climate may lead to adverse changes in cash flow or working capital levels, which may also have a
direct impact on the Company’s results and financial positions. These and other factors may
adversely affect the Company’s liquidity and the Company’s ability to generate profits in the future.
5.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents at the end of the reporting period as shown in the statement of financial
position are comprised of:
($000s)
Cash and bank balances
Short-term deposits
March 31, 2022
1,412
4,000
5,412
March 31, 2021
4,531
-
4,531
6.
TRADE AND OTHER RECEIVABLES
Bengal’s trade and other receivables are exposed to the risk of financial loss if a counterparty to a financial
instrument fails to meet its contractual obligations. The Company’s trade and other receivables include cash
calls paid to joint venture partners and receivables from petroleum and natural gas marketers.
The Company’s trade and other receivables consist of:
($000s)
Due from joint venture partners
Other receivables
March 31, 2022
2,635
11
2,646
March 31, 2021
1,206
18
1,224
-52-
7.
EXPLORATION AND EVALUATION ASSETS (“E&E ASSETS”)
($000s)
Balance, April 1, 2020
Additions
Exchange adjustments
Balance, March 31, 2021
Additions
Impairment
Capitalized share-based compensation
Exchange adjustments
Balance, March 31, 2022
A summary of E&E assets is shown in the table below:
($000s)
ATP 732P – Tookoonooka
PL 303 – Barta Block Cuisinier (controlling permit ATP 752)
ATP 934 – Barrolka
Other
Balance, March 31, 2021
($000s)
ATP 732P – Tookoonooka
PL 303 – Barta Block Cuisinier (controlling permit ATP 752)
ATP 934 – Barrolka
Other
Balance, March 31, 2022
8,930
61
899
9,890
1,231
(568)
4
(205)
10,352
5,224
2,683
1,983
-
9,890
5,730
2,623
1,972
27
10,352
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 & geophysical work, seismic and drilling, and completion costs until the drilling of wells is
complete and the results have been evaluated.
In December of 2021 the Company recorded $0.6 million of impairment associated with uneconomic
drilling results in the ATP 752 Barta Block.
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8.
PROPERTY, PLANT AND EQUIPMENT (“PP&E”)
($000s)
Petroleum and
natural gas properties
Other
assets
Right-of-use
assets
Total
Cost:
Balance, April 1, 2020
Additions
Disposals
Change in decommissioning and
restoration liability
Exchange adjustments
Balance, March 31, 2021
Additions
Capitalized share-based compensation
Change in decommissioning and
restoration liability
Exchange adjustments
Balance, March 31, 2022
($000s)
43,822
1,193
-
(623)
6,388
50,780
3,089
6
(59)
(1,499)
52,317
344
-
-
-
-
344
2
-
-
-
346
219
-
(76)
44,385
1,193
(76)
-
-
143
-
-
(623)
6,388
51,267
3,091
6
-
-
(59)
(1,499)
143
52,806
Accumulated depletion, depreciation
Petroleum and
natural gas properties
Other
assets
Right-of-use
assets
Total
and impairment losses:
Balance, April 1, 2020
Depletion and depreciation
Disposals
Exchange adjustments
Balance, March 31, 2021
Depletion and depreciation
Exchange adjustments
Balance, March 31, 2022
($000s)
Net carrying amount:
At March 31, 2021
At March 31, 2022
17,727
1,285
-
3,753
22,765
1,033
(920)
22,878
28,015
29,439
319
6
-
-
325
4
-
329
19
17
47
42
(28)
-
61
30
-
91
82
52
18,093
1,333
(28)
3,753
23,151
1,067
(920)
23,298
28,116
29,508
At March 31, 2021 and 2022, the Company determined that there were no external or internal indicators of
impairment. As a result, a quantitative impairment test was not performed. During fiscal 2022, the Company
capitalized $0.1 million general and administrative expense (2021 - $nil). The calculation of depletion for the
year ended March 31, 2022 included $61.5 million for estimated future development costs associated with
proved and probable reserves in Australia (March 31, 2021 - $60.9 million).
-54-
9.
TRADE AND OTHER PAYABLES
($000s)
Trade payables
Accrued liabilities and other payables
March 31, 2022
2,370
841
3,211
March 31, 2021
1,434
505
1,939
10.
INCOME TAXES
The provision for income taxes differs from the amount obtained in applying the combined federal and
provincial income tax rates to the loss for the year. The difference relates to the following items:
($000s)
Year ended March 31
(Loss) Income before taxes
Statutory tax rate
Expected income tax recovery
Change in enacted tax rates
Share-based compensation
Foreign exchange
Effect of tax rate in foreign jurisdiction
Other
Changes in unrecognized tax asset
Income tax recovery
2022
(374)
23.5%
(88)
-
41
6
49
780
(788)
-
2021
3,928
23.5%
923
-
3
1,423
325
140
(2,814)
-
The deductible temporary differences included in the Company’s unrecognized deferred income tax
assets are as follows:
($000s)
Year ended March 31
Non-capital losses
Net capital losses
P&NG properties
2022
45,618
-
8,669
54,287
2021
44,789
5,983
8,728
59,500
-55-
The components of the Company’s and its subsidiaries deferred income tax assets are as follows:
($000s)
Year ended March 31
Property, plant and equipment
Fair value of financial instruments
Foreign exchange
Decommissioning obligations
Non-capital losses
2022
6,206
-
1,331
(1,014)
(6,523)
-
2021
5,763
(5)
1,353
(1,043)
(6,068)
-
At March 31, 2022, the Company had approximately $38.9 million and $28.5 million of non-capital losses
in Canada and Australia respectively (2021 - $29.3 million and $29.0 million, respectively), available to
reduce future taxable income. The Canadian non-capital losses expire at various dates from March 31,
2026 to 2042. The Australian non-capital losses have no term to expiry. The Company’s ongoing drilling
activities continue to generate deferred tax assets related to Petroleum Resource Rent Tax in its
Australian subsidiary, which has not been recognized.
The Company has temporary differences associated with its investments in its foreign subsidiaries,
branches, and interests in joint ventures. At March 31, 2022, the Company has no deferred tax liabilities
in respect of these temporary differences.
11.
CREDIT FACILITY
On February 26, 2021, the Company completed its debt settlement transaction between its wholly-
owned subsidiary Bengal Australia Ltd. Pty and Westpac Banking Corporation (“Westpac”) under its
secured credit facility (the “Credit Facility”) whereby the total balance outstanding of US$ 12.5 million
was settled in exchange for a payment of US $10.0 million resulting in a gain on settlement of $3,490.
In conjunction with this, the Company entered into a recapitalization transaction with Texada Capital
Management Ltd. (“Texada”) (Note 14). The transaction included the issuance of 330,720,000 shares
at a price of $0.05 per share for proceeds of $16.5 million, of which $12.6 million (corresponding to US
$10.0 million at the transaction date) were used as settlement payment to Westpac.
12.
LEASE LIABILITY
The Company incurs lease payments related to the Company’s head office lease in Calgary.
($000s)
Balance, March 31, 2021
Interest
Payments
Balance, March 31, 2022
Current portion of lease liability
Non-current portion of lease liability
99
5
(36)
68
(37)
31
-56-
13.
DECOMMISSIONING AND RESTORATION LIABILITY
Changes to decommissioning and restoration obligations were as follows:
($000s)
Balance, April 1, 2020
Change in estimate
Accretion
Exchange adjustments
Balance, March 31, 2021
Change in estimate
Accretion
Exchange adjustments
Balance, March 31, 2022
3,690
(623)
19
392
3,478
(59)
38
(78)
3,379
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 March 31, 2022 is approximately $3.4 million (March 31, 2021
– $3.5 million) which will be incurred between 2025 and 2059. An inflation factor of 3.05% (March 31,
2021 – 1.1%) and a risk-free discount rate of 3.50% (March 31, 2021 – 1.74%) have been applied to the
decommissioning liability at March 31, 2022.
14.
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:
($000s)
Number of common shares
Amount
Balance at March 31, 2020
Issuance of common shares for cash
Balance at March 31, 2021
Share cancellation
102,266,694
330,720,000
432,986,694
(300)
Issuance of common shares for cash, net of issuance costs
52,317,821
Balance at March 31, 2022
485,304,215
98,100
16,536
114,636
-
4,160
118,796
On February 26, 2021, Bengal issued 330,720,000 common shares at $0.05 per share as part of a private
placement transaction with Texada Capital Management Ltd. (“Texada”), which is controlled by Bill Wheeler,
who acts as a director of the Company. As part of another private placement transaction, on March 7, 2022,
the Company issued 52,317,521 common shares at $0.08 per share, of which 41,067,871 were acquired by
-57-
Texada. Following these transactions, Texada controls approximately 82% of the Company’s outstanding
shares. Issuance costs related to the private placement totaled $25,000.
15.
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.
The Company accounts for its share-based compensation plan using the fair value method. Under this
method, each grant results in three instalments. The fair value of the first instalment is charged to profit or
loss over the first year. The remaining two instalments are charged to profit or loss over two and three
years respectively.
Stock options granted under the plan can be exercised on a cashless basis, whereby the employee
receives a lesser amount 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 employee so elects.
A summary of stock option activity is presented below:
Balance, March 31, 2020
Granted
Expired
Forfeited
Balance, March 31, 2021
Granted
Expired
Forfeited
Balance, March 31, 2022
Options
3,472,500
11,340,000
(1,012,500)
(83,333)
13,716,667
1,050,000
(641,667)
(1,680,000)
12,445,000
Weighted average
exercise price
$
0.12
0.08
0.16
0.11
0.08
0.09
0.10
0.08
0.08
Exercisable, March 31, 2022
5,015,000
0.09
-58-
Options Outstanding Options Exercisable
Exercise Price
Number
Outstanding
Remaining
Life (years)
$0.10
$0.09
$0.08
1,735,000
1,050,000
9,660,000
12,445,000
0.25
4.58
4.00
3.53
Number
Exercisable
1,735,000
-
3,280,000
5,015,000
The fair value of the options granted during fiscal 2022 and 2021 were estimated on the date of grant
using the Black-Scholes option-pricing model with the following weighted average assumptions and
resulting values:
Assumptions:
Fiscal 2022 Fiscal 2021
Risk-free interest rate (%)
Expected life (years)
Expected volatility (%)(1)
Estimated forfeiture rate (%)
Weighted average fair value of options granted
Weighted average share price on date of grant
1.50
5
119
20
$0.07
$0.09
1.00
5
29
20
$0.02
$0.08
(1)
Expected volatility is estimated by considering historic, average share price volatility.
The fair value of the 1,050,000 stock options granted during fiscal 2022 was approximately $78,000. The
fair value of the 11,340,000 stock options granted during fiscal 2021 was approximately $200,000.
16.
REVENUE
Revenue from the sales of crude oil is based on the consideration specified in the Crude Oil Sales and
Purchase Agreement (“COSP Agreement”) with the joint venture operator. The Company recognizes
revenue when it transfers control of the product to the joint venture operator, which is generally at the
time the joint venture operator obtains legal title of the crude oil and when it is physically delivered to
the pipeline at an estimated transaction price based on average US Brent price and is adjusted for
quality and other factors specified in the COSP Agreement once the product is shipped to the end
customer and lifted.
The transaction price as prescribed in the COSP Agreement is a variable price based on the benchmark
US Brent commodity price index, and may be adjusted for quality, location, delivery method or other
factors depending on the agreed upon terms of the contract. The amount of revenue recorded can vary
depending on the grade, quality and quantity of crude oil transferred to the joint venture operator. The
COSP Agreement has an initial term to June 30, 2022, whereby delivery takes place through the
contract period. Revenues are typically collected 60 days following delivery to Port Bonython. The
Cuisinier Joint Venture is currently negotiating a revised COSP Agreement to become effective July 1,
2022 through to December 31, 2023 with terms anticipated to be similar to the current agreement.
-59-
17.
PER SHARE AMOUNTS
Income (loss) per share is calculated based on net income (loss) and the weighted-average number of
common shares outstanding.
($000s except per share amounts)
Year ended March 31
Net (loss) income for the year
Weighted average number of
2022
(374)
common shares – basic and diluted (000s)
436,427
2021
3,928
133,073
Basic and diluted (loss) income per share
For the year ended March 31, 2022, there were 12,445,000 (March 31, 2021 - 13,716,667) options
considered anti-dilutive.
$ (0.00)
$ 0.03
18.
COMPENSATION OF KEY MANAGEMENT PERSONNEL
The Company considers its directors and executives to be key management personnel. The key
management personnel compensation is comprised of the following:
($000s)
Year ended March 31
Salaries and employee benefits
Share-based compensation(1)
2022
666
8
674
2021
706
8
714
(1)
Represents the amortization of share-based compensation expense associated with the Company’s share-based
compensation plans granted to key management personnel.
19.
FINANCE EXPENSE
($000s)
Year ended March 31
Interest income
Accretion on decommissioning
and restoration liability
Interest on lease liability
Interest on credit facility
Interest – other
2022
(7)
38
5
-
9
45
2021
(1)
19
10
881
-
909
20.
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.
-60-
(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
March 31, 2022, Bengal’s receivables consisted of $2.6 million (March 31, 2021 - $1.2 million) from
joint venture partners (all of which has been collected subsequent to year end) and $0.1 million
(March 31, 2020 - $nil) of other receivables.
Bengal has a COSP 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 Company had no accounts considered past due at March 31, 2022 (March 31, 2021 - $nil). Past
due is considered greater than 90 days outstanding.
Bengal did not provide any amounts for doubtful accounts during 2022 nor was it required to write-
off any receivables during 2022
Cash and cash equivalents, when held, consist of cash bank balances and guaranteed investment
certificates redeemable at any time. Bengal manages the credit exposure related to guaranteed
investments by selecting counterparties based on credit ratings and monitors all investments to
ensure a stable return, avoiding complex investment vehicles with higher risk such as asset-backed
commercial paper.
(b) Liquidity risk
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 lease liability and amounted to
$3.2 million at March 31, 2022 (March 31, 2021 - $2.0 million).
At March 31, 2022, the Company had working capital, which the Company defines as total current
assets less total current liabilities, of $5.5 million, including cash and cash equivalents of $5.4 million,
compared to working capital of $4.3 million at March 31, 2021.
In February 2021, the Company raised $16.5 million on the issuance of common shares and
extinguished it’s previously outstanding credit facility. In March 2022, the Company raised $4.2
million on the issuance of common shares. Management anticipates that operating and capital
requirements during fiscal 2023 will be met out of working capital and operating cash flows.
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. To mitigate the net impact of low crude prices, the Company is acting with its joint
venture partners to reduce discretionary spending and focus capital towards lower risk projects with
near-term cash flow upside.
(c) Market risk
Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate
because of changes in market prices. Market risk comprises three types of risk: foreign currency
risk, commodity price risk and interest rate risk. The Company is exposed to market risks resulting
from fluctuations in foreign exchange rates, commodity prices and interest rates in the normal course
of operations. A variety of derivative instruments may be used to reduce exposure to these risks.
Foreign Currency Risk
-61-
Foreign currency risk is the risk that the fair value of future cash flows will fluctuate as a result of
changes in foreign exchange rates. Bengal receives US dollars for Australian oil sales and incurs
expenditures in Australian and Canadian currencies. The Company may enter into derivative foreign
currency contracts in order to manage foreign currency risk but has not done so to date.
The table below shows the Company’s exposure in Canadian dollar equivalent to foreign currencies
for its financial instruments at March 31, 2022:
($000s)
Cash and cash equivalents
Trade and other receivables
Trade and other payables
Lease liability
CAD$
5,359
11
(238)
(68)
5,064
AUS$
39
129
(2,973)
-
(2,805)
Exchange rates as at March 31:
Number of CAD$ for 1 AUS$
Number of CAD$ for 1 US$
Commodity Price Risk
US$
14
2,506
-
-
2,520
2022
0.94
1.25
Total
5,412
2,646
(3,211)
(68)
4,779
2021
0.96
1.26
Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of a
change in commodity prices. Commodity prices for petroleum and natural gas are impacted by not
only the relationship between the Canadian and United States dollar, as outlined above, but also
world economic events that dictate the levels of supply and demand. Australian oil prices are based
on the US Brent reference price, which currently trades at a premium to WTI.
During the 2021 fiscal year, the Company recorded an unrealized loss of $1.5 million on its derivative
contracts. These contracts were settled in Q3 of the fiscal year resulting in a realized gain of $1.0
million. At March 31, 2022 and 2021, the Company had no derivative contracts outstanding and all
unrealized gains booked through fiscal 2021 were effectively realized during the year. During fiscal
2022 there were no realized on unrealized gains recognized.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market
interest rates. The Company’s exposure to interest rate risk on its cash and cash equivalents at
March 31, 2022 is restricted to investments with a maturity of three months or less. The Company
had no interest rate derivatives at March 31, 2022 and 2021.
21.
CAPITAL MANAGEMENT
The Company’s policy is to maintain a strong capital base for the objectives of maintaining financial
flexibility which will allow it to execute on its capital investment program, provide creditor and market
confidence and to sustain future development of the business. Following the February 2021
recapitalization transaction, the Company has materially realigned its capital structure eliminated all
outstanding debt while adding $4.0 million of working capital. The Company raised a further $4.2 million
in March 2022. This provides additional financial and capital flexibility further to the Company’s strategy
described above.
The Company manages its capital structure and makes adjustments by continually monitoring its
business conditions, including: changes in economic conditions, the risk profile of its drilling inventory,
-62-
the efficiencies of past investments, the efficiencies of forecasted investments and the timing of such
investments, the forecasted cash balances, the forecasted commodity prices and resulting cash flow.
In order to maintain or adjust the capital structure, the Company may from time to time issue shares (if
available on reasonable terms), issue debt instruments, sell assets, farm out properties and adjust its
capital spending to manage current and projected cash levels. There can be no assurance that equity
financing will be available or sufficient to meet capital commitments, or for other corporate purposes, or
if equity financing is available, that it will be on terms acceptable to the Company.
22.
SUPPLEMENTAL CASH FLOW INFORMATION
Change in non-cash working capital items
($000s)
Year ended March 31
Trade and other receivables
Prepaid expenses and deposits
Trade and other payables
Effect of change in foreign exchange rates
Attributable to:
Operating
Investing
Financing
2022
(1,422)
(213)
1,272
(13)
(376)
(597)
221
-
(376)
The following represents the cash interest paid and received in each period:
Cash interest paid and received
($000s)
Year ended March 31
Cash interest paid
Cash interest received
2022
9
7
2021
415
(319)
898
80
1,074
606
474
(6)
1,074
2021
623
1
23.
COMMITMENTS
The Queensland Government regulatory authority granted the Company Authority to Prospect 934 ("ATP
934") under a revised work program on March 1, 2015. In Q4 fiscal 2018, the Company consolidated its
ownership of ATP 934 and now holds a 100% and 40% operating interest in the northern and southern
block of this permit respectively. The purchase consideration was AUS$0.3 million cash and potential
future cash payments of up to AUS$1.0 million, which is made up of a AUS$0.2 million on certification by
an independent competent person appointed by Bengal Energy (Australia) Pty Ltd. of not less than 25
billion cubic feet of proved reserves and AUS$0.8 million due upon the delivery of the first shipments of gas
to market. The work program consists of 260 km2 of 3D seismic and up to three wells.
At March 31, 2022, the Company had the following capital work commitments:
-63-
Country and permit
Work program
(1)
Onshore Australia –
ATP 934
260 km2 3D seismic and
up to three wells
Onshore Australia –
ATP 732
Geological and geophysical
studies
Offshore Australia
AC/RL 10
Geological and geophysical
studies
Obligation period Estimated expenditure
ending (net) (millions CAD$)
February 2027
8.3(2)
March 2023
March 2023
0.1
0.1
(1)
(2)
Translated at March 31, 2022 at an exchange rate of AUS$1.00 = CAD$0.9366.
During fiscal 2021, the Company received confirmation that the commitment on ATP 934 was reduced in exchange
for a 50% relinquishment of the non-potential acreage of ATP 934 at the end of the first term expiry date of February
28, 2021.
At March 31, 2022, the contractual obligations for which the Company is responsible are as follows:
($000s)
Contractual obligations
Office lease
Decommissioning and restoration
Total
182
3,379
3,561
Less than
1 year
1-3
years
4-5
years
103
-
103
79
798
877
-
-
-
After
5 years
-
2,581
2,581
24.
SEGMENTED INFORMATION
As at March 31, 2022, the Company has two reportable operating segments being the Australian oil and
gas operations and corporate.
Revenue reported below represents revenue generated from external customers. There were no inter-
segment sales in any of the reported periods.
The accounting policies of the reportable segments are the same as the group’s accounting policies.
Segment profit represents the profit earned by each segment without allocation of directors’ salaries,
finance costs and income tax expense. This is the measure reported to the chief operating decision
maker for the purposes of resource allocation and assessment of segment performance.
-64-
Corporate
-
7
5
34
-
(1,070)
-
-
-
-
5,472
306
Corporate
-
1
10
48
(809)
-
-
-
-
4,162
432
Total
7,650
7
14
1,067
568
(374)
1,231
3,089
10,352
29,508
48,576
6,658
Total
5,234
1
891
1,333
3,928
61
1,193
9,890
28,116
44,246
5,516
($000s)
For the year ended March 31, 2022
Revenue
Interest revenue
Interest expense
Depletion and depreciation
Impairment
Net income (loss)
Exploration and evaluation expenditures
Petroleum and natural gas property
expenditures
($000s)
As at March 31, 2022
Exploration and evaluation assets
Petroleum and natural gas properties
Total assets
Total liabilities
$000s)
For the year ended March 31, 2021
Revenue
Interest revenue
Interest expense
Depletion and depreciation
Net income (loss)
Exploration and evaluation expenditures
Petroleum and natural gas property
expenditures
($000s)
As at March 31, 2021
Exploration and evaluation assets
Petroleum and natural gas properties
Total assets
Total liabilities
Australia
7,650
-
9
1,033
568
696
1,231
3,089
10,352
29,508
43,104
6,352
Australia
5,234
-
881
1,285
4,737
61
1,193
9,890
28,116
40,084
5,084
-65-
CORPORATE INFORMATION
AUDITORS
KPMG LLP • Calgary, Canada
LEGAL COUNSEL
Burnet, Duckworth & Palmer LLP • Calgary, Canada
Piper Alderman • Sydney, Australia
BANKERS
Royal Bank of Canada • Calgary, Canada
WestPac • Sydney, Australia
REGISTRAR AND TRANSFER AGENT
Computershare • Toronto, Canada
DIRECTORS
Chayan Chakrabarty
James B. Howe
Peter Lansom
Dr. Brian J. Moss
Robert D. Steele (Chairman)
W. B. (Bill) Wheeler
DISCLOSURE COMMITTEE
Chayan Chakrabarty
Jerrad Blanchard
AUDIT COMMITTEE
James B. Howe (Chairman)
Robert D. Steele
W. B. (Bill) Wheeler
RESERVES COMMITTEE
Dr. Brian J. Moss (Chairman)
Peter Lansom
Robert D. Steele
COMPENSATION COMMITTEE
Dr. Brian J. Moss (Chairman)
Robert D. Steele
Peter Lansom
GOVERNANCE AND NOMINATING COMMITTEE
W.B. (Bill) Wheeler (Chairman)
Robert D. Steele
James B. Howe
HEALTH, SAFETY AND ENVIRONMENT COMMITTEE
Peter Lansom (Chairman)
Robert D. Steele
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