Appraisal and Exploration Drilling
with High-Impact Upside
Annual Report | 2012
TABLE OF CONTENTS
1 Message to Shareholders
3 Management’s Discussion and Analysis
30 Consolidated Financial Statements
36 Notes to Consolidated Financial Statements
65 Corporate Information
Bengal Energy Ltd.
MESSAGE TO SHAREHOLDERS
We achieved our most active year to date in fiscal 2012 with production from our Cuisinier light oil discovery
and follow-up development wells in the Cooper Basin of Australia. The Cooper Basin continues to drive
revenues for the Company. Cuisinier 2 and 3 began producing at the end of August 2011 and contributed to
Bengal’s overall 33% increase in production over fiscal 2011. Bengal achieved a netback of $49.89 per
barrel of oil equivalent (boe) in Q3 2012, our highest quarterly netback to date. We achieved our highest
average netback overall for the fiscal year ended March 31, 2012 with an average netback of $45.72/boe,
an increase of 114% over the year ended March 31, 2011. Australian netbacks for the year ended March
31, 2012 were $68.81 compared to $48.02 in the prior year.
We were privileged to make key appointments to our executive management team in the Calgary office and
to add three independent directors to our board this year, greatly expanding our resources and knowledge
base. We were pleased to welcome Garret Wilson, Richard Edgar and Gordon MacMahon to our executive
management team in August of 2011. Additionally, in January of 2012, we welcomed Stephen N. Inbusch,
Bill Wheeler and Dr. Brian J. Moss to the Company’s board. These new members of Bengal’s board bring a
wealth of international exploration, development, regulatory and financial experience.
In April 2012, we announced the purchase of an Ideco H-44 drilling rig for use inititally in the upcoming
exploratory drilling program on Bengal’s 100% working interest ATP 732P Tookoonooka permit in the
Cooper/Eromanga Basin of Queensland, Australia. This drilling program is expected to commence in mid
July. The purchase of the rig offers Bengal significant advantages, including, but not limited to, reduced
drilling cost structure, reduced program execution risk, tailored drilling programs with room to explore, and
control over program development. In addition, ownership of the rig allows Bengal to have the rig available,
when not in use by the Company, for future business development opportunities.
Bengal offers a portfolio of low-risk development drilling combined with moderate risk, yet high-impact
exploration drilling opportunities. Operations in 2011 and early 2012 set the stage to embark on the largest
drilling campaign in the Company’s history. This 2012 campaign is expected to include four Cuisinier wells
and three Tookoonooka wells. At Cuisinier, the Company continues to enjoy a 100% drilling success rate
with the first two wells of the 2012 campaign cased as a future oil producers with net pay ranging from 2.0
to 9.1 metres. These wells establish a platform for further future development and revenue generation from
the Barta Block. At Tookoonooka (ATP 732) the company has assembled a portfolio of multi-zone
exploration prospects with 3 drilling locations selected for the initial 2012 drilling program.
In addition to Bengal’s focus on the Cooper Basin, the Company is also exploring two blocks in India’s
Cauvery Basin.Despite being in the early stages of exploration, drilling success by other operators in
offsetting blocks show significant upside potential for the Company in India.
Bengal has a 30% working interest in 946 square kilometres (233,000 acres) onshore at CY-ONN-2005/1
and a 100% interest in 1,362 square kilometres (340,000 acres) offshore at CY-OSN-2009/1.
Bengal and its joint venture partners, Gas Authority of India Ltd. and Gujarat State Petroleum Corporation,
commenced a 3D seismic program of approximately 600 square kilometres in late fiscal 2012 which is
anticipated to be completed in late calendar 2012. A recent gas discovery was made to the immediate west
of the block at Vaderatu. The details of this discovery have not been released but could represent
significant upside potential in this block.
CY-OSN-2009/1, located offshore in India’s Cauvery Basin is 100% owned and operated by Bengal. The
Company is currently evaluating previously recorded 2D and 3D surveys of the block and reprocessing
certain seismic records. The block is ideally located and recent competitor activity in the area includes a
$7.2 billion acquisition by BP of a 30% interest in a number of blocks held by Reliance Industries Limited.
- 1 -
Bengal Energy Ltd.
Message to Shareholders
(approximately 270,000 square kilometres) and recent exploration discoveries by Cairn India provided
encouragement for the acceleration of Bengal’s activity on the block.
The past year was an operational success for Bengal and set the stage for a very active program for the
balance of 2012 and 2013. We entered the year with $27.0 million in cash, no debt and a balanced portfolio
of exploration and appraisal drilling opportunities. We have improved our ability to execute our own drilling
plans through the acquisition of a drilling rig and expect it may provide other growth opportunities in the
Cooper Basin in future years.
Bengal offers world class assets managed by a seasoned team of international exploration professionals.
Our strong balance sheet and our strategy of low-risk development drilling and high-impact exploration
demonstrate our commitment to growing shareholder value over the long-term. We look forward to growing
with our employees, our joint venture partners and our shareholders over the coming years.
Sincerely,
Chayan Chakrabarty
President & CEO
- 2 -
Bengal Energy Ltd.
MANAGEMENT’S DISCUSSION AND ANALYSIS – JUNE 13, 2012
The following Management’s Discussion and Analysis (“MD&A”) as provided by the management of Bengal
Energy Ltd. (“Bengal” or the “Company”) should be read in conjunction with the audited Consolidated
Financial Statements and accompanying notes for the years ended March 31, 2012 and 2011. Additional
information relating to the Company, including detailed reserve disclosures, is included in our Annual
Information Form, which will be filed on SEDAR at www.sedar.com. The reader should be aware that
historical results are not necessarily indicative of future performance.
The Company’s activities are focused in Australia, India and Canada. Over the reporting period, revenue
and expenses were generated and capital expenditures were made in Australia and Canada, and capital
expenditures were made in India. The Company’s activities are carried out primarily in Canadian dollars as
well as the currencies of each country in which the Company operates. The Company reports financial
results in Canadian dollars.
This is the Company’s first annual reporting under International Financial Reporting Standards (“IFRS”).
The effective date of the transition to IFRS was April 1, 2010. The transition to IFRS has been reflected by
restating previously reported financial statements for 2010. Previously, the Company’s financial statements
were prepared under Canadian generally accepted accounting principles (“CGAAP”). The adoption of IFRS
does not impact the underlying economics of the Company’s operations or its cash flows. Note 20 to the
consolidated financial statements for the year ended March 31, 2012 contains detailed descriptions of the
Company’s adoption of IFRS, including reconciliations of the consolidated financial statements previously
prepared under CGAAP to those under IFRS.
FISCAL 2012 HIGHLIGHTS
New Directors – On January 12, 2012, Bengal announced the appointment of three independent
directors to its board – Dr. Brian J. Moss, Mr. Stephen N. Inbusch and Mr. W.B. (Bill) Wheeler. The
new members bring a wealth of international exploration, development and financial experience to
the Company as it advances its operations in Australia and India.
Production averaged 135 barrels of oil equivalent per day (boe/d), an increase of 33% over 101
boe/d for the year ended March 31, 2011
Revenue of $4.3 million, an increase of 131% over the year ended March 31, 2011.
Netback(1) of $47.72/boe, an increase of 114% over $21.34/boe for the year ended March 31, 2011;
Australian netback of $68.81/boe reflects the strength of the Brent benchmark crude oil prices and
is an increase of 43% over $48.02/boe for the previous year.
Reserves – Independent third party year-end reserves evaluation to March 31, 2012 have shown a
9% year-over-year corporate 2P reserves increase, driven by a 32% increase of 2P reserves at
Cuisinier, offset by natural declines and 2P reserves reductions of 4% and 21% respectively at
Toparoa, Australia and Oak, BC., with the latter being a Canadian natural gas and NGL producing
property. Based on 2P reserves additions, the Company replaced over twice its annual production
to March 31 2012. Detailed reserves disclosures will be included in Bengal’s 2012 Annual
Information Form to be filed on SEDAR.
Rig Purchase – On April 5, 2012, the Company announced the purchase of an Ideco H-44 drilling
rig and its associated equipment for initial use in its 2012 operated exploratory drilling program in
the Cooper Basin. The Rig is a 750 HP carrier-mounted double with a depth capability of 3,000m.
The rig provides the Company with an opportunity to reduce the execution risk and cost structure
on its upcoming Tookoonooka drilling campaign as well as increase control and flexibility over the
program so opportunities can be fully evaluated.
Australia Drilling Campaign – On May 20, 2012, the Company commenced its Australian drilling
campaign beginning with three appraisal wells in the Cuisinier field and one step out well Cuisinier
North 1, situated 2.9 km north of Cuisinier 1. This non-operated Cuisinier drilling program will be
followed by Bengal’s 100% operated drilling campaign at Tookoonooka, ATP 732P, which Bengal
expects to commence in July 2012.
- 3 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
OPERATING HIGHLIGHTS
$000s except per share, volumes
and netback amounts
Three Months Ended
Twelve Months Ended
03/31/12
03/31/11
12/31/11
03/31/12
03/31/11
Revenue
Natural gas
Natural gas liquids
Oil
Total
Royalties
% of revenue
Operating & transportation
Netback(1)
Cash from (used in) operations:
Per share ($) (basic & diluted)
Funds used in operations:(2)
Per share ($) (basic & diluted)
Net (loss):
Per share ($) (basic & diluted)
Capital expenditures
Volumes
Natural gas (mcf/d)
Natural gas liquids (boe/d)
Oil (bbl/d)
Total (boe/d @ 6:1)
Netback(1) ($/boe)
Revenue
Royalties
Operating & transportation
Total
$
$
59
16
547
622
56
9.0
312
254
486
0.01
(635)
(0.01)
(1,424)
(0.03)
$ 2,233
$
304
2
50
103
125
17
549
691
67
9.7
295
328
(725)
(0.02)
(669)
(0.02)
(890)
(0.03)
1,879
348
3
56
117
$
$
$
$
92
23
1,213
1,328
121
9.1
486
721
(417)
(0.01)
(402)
(0.01)
(477)
(0.01)
4,327
271
4
108
157
$ 66.62
6.02
33.33
$ 27.27
$
$
65.49
6.38
27.97
31.13
$
$
92.03 $
8.43
33.71
49.89 $
310
68
3,908
4,286
394
9.2
1,636
2,256
(1,142)
(0.02)
(1,459)
(0.03)
(7,209)
(0.14)
10,838
254
3
90
135
86.80
7.97
33.12
45.72
$
$
488
67
1,298
1,853
181
9.8
883
788
(2,523)
(0.10)
(2,582)
(0.10)
(3,340)
(0.13)
3,943
354
3
39
101
$
$
50.13
4.90
23.89
21.34
(1)
(2)
Netback is a non-GAAP measure. Netback per boe is calculated by dividing the revenue and costs in total for the Company
by the total production of the Company measured in boe.
Funds from operations is a non-GAAP measure. The comparable IFRS measure is cash from operations. A reconciliation of
the two measures can be found in the table on page 5.
OUTLOOK
The Company entered fiscal 2013 with a strong balance sheet with $27.0 million in cash, no debt and a
balanced portfolio of exploration and development drilling opportunities on its extensive land base in
Australia and India. The price the Company receives for all of its oil sales in Australia is based on the Dated
Brent reference price which has traded at a US $16 premium to WTI for the three months ended March 31,
2012.
AUSTRALIA – Onshore
Authority to Prospect ("ATP") 752 Barta Block
In the Barta Block on ATP 752, where Bengal owns a 25% working interest, the operating company is
currently drilling three appraisal wells and one exploration well as a follow up to the four successful
exploration and appraisal wells previously drilled. Drilling is expected to be completed by the end of
calendar Q2 2012. The appraisal wells are being drilled directly offsetting existing producing wells within the
Cuisinier field, targeting the Cretaceous Murta member. Each of these three appraisal well locations is
located on 3D seismic in areas where the seismic attributes are consistent with well-developed Murta
sands. The step-out exploration well , Cuisinier North – 1, will be drilled some 2.9 kilometers north of the
Cuisinier 1 discovery on a satellite structure.This well is located on a 4 - way structural closure and in
addition to testing the Murta, the well will also test the Jurassic Birkhead/Hutton formations. These Jurassic
formations are the main producing horizons in the Cook oil field situated 5.9 kilometers to the south east of
Cuisinier North – 1. The Cook field has produced over 2.5 million barrels to date.
- 4 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Cuisinier 4, the first appraisal well in the 2012 drilling campaign, is located approximately 600 meters north-
west of the Cuisinier 1 discovery well and was cased as a future oil producer. The targeted Murta sand
came in high to prognosis with approximately 11.8 meters of DC70 sandstone developed and an estimated
minimum 9.1 meters net pay. Wireline logs have confirmed the presence of a minimum 21.8m oil column in
oil bearing sands of the Murta member. The entire Murta interval was cored by the operator with a total of
51.2 meters of core cut (49.5 meters recovered). There were hydrocarbon indications through the entire
Murta formation, approximately 37 meters in total.
Planning is underway for the shooting of a new 3D seismic survey in early 2013. This seismic is expected to
be acquired north of and adjoining the current 3D seismic data set and Cuisinier wells and development
area, and will be aimed at imaging Murta, Birkhead and Hutton anomalies, both structural and stratigraphic.
The previously equipped Barta North 1 Murta oil well will be tied into the existing Cuisinier 1 facility via 4.5
kilometers of pipeline. Construction is set to commence in early calendar Q3, with commissioning planned
for the end of Q3 2012.
The Operator also plans to tie any successful Murta producers from the 2012 campaign into the existing
Cuisinier 1 facility. Engineering work is underway to convert the Cuisinier 1 site to a field satellite where all
well production will be produced to and metered. Planning work is also underway to connect the
downstream group production from the Cuisinier 1 facility to the neighboring and existing Cook production
facility via a new 7.5 km emulsion pipeline. Expected to be operational in early 2013, this new facility
configuration and group pipeline will eliminate field and sales oil trucking and is expected to increase run-
times and netbacks for the Cuisinier field.
The Cuisinier 1 well has been operating through an Extended Production Test (EPT) as required under the
framework of an ATP, and, with the timeframe of the current EPT having expired on December 17, 2011, an
extension was applied for on December 9, 2011 by the operating company to the Queensland Regulator,
DEEDI (Department of Employment, Economic Development and Innovation). On January 13, 2012,
DEEDI advised the Operator that the application to extend the EPT was being reviewed, but asked that the
Cuisinier 1 well be shut-in temporarily until the extension was approved or a Cuisinier Production License
(PL) granted. The original PL application and accompanying Initial Development Plan were submitted to
DEEDI by the Operator in October 2009. Subsequent negotiations followed with DEEDI as to the areal
extent of the application area, and as a result, a revised PL was submitted on January 13, 2012. The
Cuisinier well remains shut-in and the current net impact to Bengal is 70 bopd. The application for a
production license is a routine regulatory requirement which the Company is confident will be approved and
the well back on stream in July 2012..
ATP 732 Tookoonooka Block
The acquisition of approximately 422 line kilometers of 2D and 50 square kilometers of 3D seismic data at
ATP 732 (Tookoonooka Block) has been completed and the preliminary interpretation is complete. In
conjunction with this seismic data acquisition, an evaluation of aeromagnetic and gravity data has also been
carried out and has been integrated with the seismic data. This has allowed for the selection of drill
locations and the initiation of field work for location evaluation/surveying and also the commencement of the
subsequent process of Regulatory and Environmental approvals with the Queensland and Australian
Governments. The Company currently plans to commence exploratory drilling with an initial three-well
campaign starting in calendar Q3 2012 after the end of the wet season and upon the receipt of all
Regulatory and Environmental approvals from the State and Federal Governments. There is also an
existing gas pipeline crossing the permit.
The three drill locations selected are targeting Cretaceous and Jurassic oil as well as Permian gas. All three
locations have been chosen based on their multi-zone potential with as many as three or four prospective
targets on each location. The primary target is oil on two locations and both gas and oil on a third location.
- 5 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
The Cretaceous targets are Wyandra and Murta Formation sandstones. The Jurassic targets are Hutton,
Birkhead and Westbourne Formation sandstones. These Cretaceous and Jurassic targets are established
producers in existing fields located both southwest and northeast of the Tookoonooka block. Cretaceous
reservoirs are deposited in fluvial environments with wells exhibiting porosity ranging from 12% to 33%.
Similarly, Jurassic sandstone reservoirs also demonstrate well developed porosities which average around
25% and with very good permeability.
The main Permian aged reservoir of interest is the Toolachee Formation sandstone. These sandstones are
multi-zone, fluvial (and overbank) deposits that range from poor to moderate quality reservoirs in the vicinity
of ATP 732P. Sands are stacked and interbedded with coals and shales. Porosities in area wells range from
9% to 21%. Good evidence of the Permian gas potential is seen in the Wareena-1 well which tested over 11
MMCFD from the Toolachee sequence. Wareena-1 is located approximately 32 kilometers west of ATP732.
The planning, regulatory and procurement work associated with the drilling, equipping and facility
components of the exploration campaign are well underway. Based on the project advancement to date the
Company plans to spud the initial exploratory well early in calendar Q3.
The Company is seeking a joint venture partner to participate in the exploration of this permitTo facilitate the
Company’s drilling plans, Bengal has purchased an Ideco H-44 drilling rig and associated equipment for
initial use in the 2012 exploratory drilling program on ATP 732P - the Tookoonooka permit. Operations are
currently underway to complete the shipment of the rig and support equipment to Brisbane, Queensland,
where along with the final inspections; the maintenance work to bring the rig to a drill-ready stage will be
conducted. In parallel with the equipment preparatory work, the process of procuring, training and certifying
the drilling crews has also been initiated.
ATP 934 Barrolka Block
Final application for grant of the permit at ATP 934 (Barrolka Block) has been filed with the Queensland
Government regulatory authority. No further activity is planned on this permit until the Ministerial Grant of
the tenement is received. The Company holds a 50% operating interest in this 361,268 acre permit.
Australia - Offshore
AC/P 47 Block
The time period in which to complete the seismic work program for the AC/P 47 permit expired on March 2,
2012. At June 13, 2012 the permit has not been relinquished. Bengal has been in communication with the
National Offshore Petroleum Tenure Administrator (NOPTA) in regards to the permit tenure and how to
proceed with both suspension and extension applications. Concurrently, the company is in conversation
with parties interested in a potential joint venture on the block. If an extension is applied for and received,
the Company, along with a joint venture partner, would then shoot, process and interpret a minimum of 750
square km of 3D seismic on this permit during 2012 and Q1 2013. The results of this seismic program will
give Bengal the option of either committing to drill an exploration well or, if no acceptable prospects are
identified from the seismic interpretation, relinquishing the permit. If the permit is relinquished, $0.8 million
of historical exploration and evaluation costs plus the Company’s share of any seismic program costs will
be impaired in the following year.
AC/P 24 Block
Bengal has been advised by the operator of the permit at AC/P 24 that an extension request has been filed
for and received for the Kingtree prospect for one year and that initial applications for a retention lease for
the Katandra discovery have been made.
Analysis of gas encountered while drilling the Kingtree well indicates the presence of a residual oil column
evidencing trap leakage. A northern and separate fault bound closure will be further reviewed for potential
future drilling. Bengal has taken an impairment charge against all costs incurred on the block.
- 6 -
Bengal Energy Ltd.
India - Onshore
CY-ONN-2005/1 Block
Management’s Discussion and Analysis
On Bengal’s 30% working interest, 233,000 gross acre Block CY-ONN-2005/1 located in onshore Cauvery
Basin, Bengal and its joint venture partners, Gas Authority of India Ltd. and Gujarat State Petroleum
Corporation, have commenced a 3D seismic program of approximately 600 square km. Weather -related
delays in the acquisition program have slowed progress; however, the operator has now completed 55% of
this planned seismic data acquisition, with the rest of the program to be completed later in 2012 after the
monsoon season subject to weather conditions. As well, airborne magnetometry work was carried out over
the permit in association with the seismic program. The seismic and airborne magnetometry work are
intended to help the joint venture define drilling locations on the permit. A recent gas discovery was made
immediately west of the block at Vadateru; however, details of this discovery have not yet been released.
India - Offshore
CY-OSN-2009/1 Block
Evaluation work is continuing on this 340,000 acre, 100% owned and operated Block CY-OSN-2009/1 in
India’s offshore Cauvery basin. Activity includes acquiring 2D and 3D surveys previously recorded on the
block and in this region and reprocessing of certain available seismic records. Interpretation of the various
seismic data sets is nearing completion with several play types and prospects emerging. This has now
allowed planning to progress on a new seismic data program. The acquisition of additional seismic data in
late 2012 or early 2013 is designed to accelerate the timing of the drilling of an exploration well. Recent
competitor activity in the local area, including the $7.2 billion acquisition by BP of a 30% interest in a
number of blocks held by Reliance and the recently announced exploration discoveries by Cairn India in
nearby Sri Lankan waters provide encouragement for acceleration of the Bengal activity.
SUMMARY
The Company believes it is sufficiently capitalized to undertake its nearer term accelerated exploration
plans and fulfill near-term work program commitments for the large acreage position the Company holds.
The Company has an attractive and large portfolio of both lower-risk and high-impact drilling opportunities.
Development and exploratory drilling planned for the first half of calendar 2012 at Cuisinier on the Barta
permit should drive near term and increasingly positive operating income for the Company and set the
stage for future development. Potential near-term exploration drilling success on permit ATP 732P, planned
for 2012, could create further momentum. Longer term plays in India and in the Timor Sea are designed to
potentially add value in 2013 and onward. The Company will continue to evaluate accretive production
acquisition, exploration and corporate transaction opportunities, as and where they arise, within and around
the Company’s core areas.
Basis of Presentation - This MD&A and accompanying financial statements and notes are for the three-
months and year ended March 31, 2012. The terms “current quarter” and “the quarter” are used throughout
the MD&A and in all cases refer to the period from January 1, 2012 through March 31, 2012. The terms
“prior year’s quarter” and “2011 quarter” are used throughout the MD&A for comparative purposes and refer
to the period from January 1, 2011 through March 31, 2011.
For the purpose of calculating unit costs, natural gas volumes have been converted to barrels of oil
equivalent (“boe”) using a conversion ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel
(“bbl”) of oil. The following abbreviations are used in this MD&A: boe/d means barrels of oil equivalent per
day; bbl/d means barrels per day and mcf/d means thousand cubic feet of natural gas per day.
Non-GAAP Measurements - Within the MD&A references are made to terms commonly used in the oil and
gas industry. Funds from operations, funds from operations per share and netbacks do not have any
standardized meaning under IFRS and previous GAAP and are referred to as non-GAAP measures. Funds
- 7 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
from operations per share is calculated based on the weighted average number of common shares
outstanding consistent with the calculation of net income (loss) per share. Netbacks equal total revenue
less royalties and operating and transportation expenses calculated on a boe basis. Management utilizes
these measures to analyze operating performance. Funds from operations is not intended to represent
operating profit for the period nor should it be viewed as an alternative to operating profit, net income, cash
flow from operations or other measures of financial performance calculated in accordance with IFRS. Funds
from operations is commonly referred to as cash flow by research analysts, is used to value and compare
oil and gas companies and is frequently included in published research when providing investment
recommendations. Total boes are calculated by multiplying the daily production by the number of days in
the period.
The following table reconciles cash flow from operations to funds from operations, which is used in the
MD&A:
Twelve Months Ended
03/31/11
(2,523)
3/31/12
(1,142)
3
(320)
(1,459)
−
(59)
(2,582)
$000s
Cash flow from (used in) operations
Abandonment expenditures
Changes in non-cash working capital
Funds used in operations
03/31/12
486
3
(1,124)
(635)
Three Months Ended
12/31/11
03/31/11
(417)
(725)
−
−
15
56
(402)
(669)
- 8 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
RESULTS OF OPERATONS
Production
The following table outlines Bengal’s production volumes for the periods indicated:
Production
Three Months Ended
Twelve Months Ended
Natural gas (mcf/d) ¹
NGLs (boe/d) ¹
Oil (bbls/d) ²
Total (boe/d)
03/31/12
304
2
50
103
03/31/11
348
3
56
117
12/31/11
271
4
108
157
03/31/12
254
3
90
135
03/31/11
354
3
39
101
(¹)
(²)
Natural gas and NGL volumes are from the Company’s Oak property in Canada
Oil volumes are from the Company’s Cooper Basin permits in Australia
For the year ended March 31, 2012, production averaged 135 boe/d, up from 101 boe/d in the prior year.
The increase is due to a commencement of production from the Cuisinier 2 and 3 wells in August 2011
partially offset by natural reservoir declines at the Company’s Oak British Columbia gas property.
For the three months ended March 31, 2012, production averaged 103 boe/d, down from the 117 boe/d
produced in the prior year comparable quarter. The decrease in natural gas production is due to natural
declines from the Company’s Oak B.C. gas property.
Despite the start up of production from Cuisinier 2 and 3 in August 2011, oil production in the current
quarter was 50 b/d compared to 108 b/d in the three months ending December 31, 2011 due to shut-in of
the Cuisinier 1 well on January 13, 2012. The well was shut-in at the request of the Department of
Employment, Economic Development and Innovation (“DEEDI”) while they review the application for a
Production License (PL). Production is expected to re-commence in July 2012. The current net impact to
Bengal of the shut-in Cuisinier 1 production is 70 b/d.
Pricing
The following table outlines benchmark prices compared to Bengal’s realized prices:
Prices and Marketing
Three Months Ended
Twelve Months Ended
03/31/12
03/31/11
12/31/11
03/31/12
03/31/11
Average Benchmark Prices
AECO 30 day firm ($/mcf)
Dated Brent oil ($US/bbl)
Number of CAD$ for 1 AUD$
Number of CAD$ for 1 USD$
WTI oil ($US/bbl)
Bengal’s Realized Price ($CAD)
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total ($/boe)
$
$
$
$
$
2.52
118.44
1.06
1.00
102.76
2.14
121.06
77.37
66.62
$
$
$
$
$
3.77
105.32
0.99
0.99
94.17
3.96
109.06
60.40
65.49
$
$
$
$
$
3.47
108.90
1.04
1.02
97.43
3.68
122.62
60.45
92.03
$
$
$
$
$
3.36
113.84
1.04
0.99
97.94
$
$
$
3.33 $
119.18
63.72
86.80
$
3.50
87.45
0.96
1.02
83.33
3.77
92.29
50.15
50.13
Bengal’s total realized price on a boe basis increased 73% or $36.67/boe to $86.80 on a year over year
basis as a result of higher oil prices and an increased proportion of sales from oil volumes. The increased
price is partially offset by a decline in gas prices. Current quarter prices decreased by $25.41 to $66.62
compared to the December 31, 2011 quarter due to further declines in gas prices and a temporary increase
in lower priced gas sales volumes relative to total sales volumes while the Cuisinier 1 well is shut in.
Bengal’s realized price for its Australian oil production had been based on the Asia Petroleum Price Index
(APPI) Tapis Crude benchmark price. Effective January 1, 2011 the price received for Bengal’s Australian
oil sales is based on Dated Brent quotes as published by Platts Crude Oil Marketwire for the month in which
- 9 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
the Bill of Lading occurs plus a Platts Tapis premium. Brent typically has traded at a premium to West
Texas Intermediate (WTI) and the Platts Tapis premium averaged US $7.21/bbl over Brent for the three
month period ended March 31, 2012.
Oak, British Columbia gas sales are marketed by the operator and the price received is based on the
reference price at British Columbia’s Station 2 plus $0.03 per mcf.
NGLs include condensate, pentane, butane and propane. While prices for condensate and pentane have a
relatively strong correlation to oil prices, prices for butane and propane trade at varying discounts due to the
market conditions of local supply and demand.
Petroleum and Natural Gas Sales
The following table outlines Bengal’s production sales by category for the periods indicated below:
Petroleum and Natural Gas
Sales ($000s)
Natural gas¹
NGLs¹
Oil²
Total
$
$
03/31/12
Three Months Ended
12/31/11
03/31/11
Twelve Months Ended
03/31/11
03/31/12
59
16
547
622
$
$
125
17
549
691
$
$
92
23
1,213
1,328
$
$
310
68
3,908
4,286
$
$
488
67
1,298
1,853
(¹)
(²)
Natural gas and NGL sales are from the Company’s Oak property in Canada
Oil sales are from the Company’s Cooper Basin permits in Australia
Revenue for the 2012 fiscal year was $4,286,000, an increase of 131% or $2,433,000 over the prior fiscal
year. The increase in revenue was due to higher oil production ($2,217,000) and oil prices ($396,000) in
2012 as compared to 2011. The increase in oil revenues was partially offset by lower gas revenue due to
lower volumes ($123,000) and gas prices ($57,000).
Petroleum and natural gas sales for the fourth quarter of the 2012 fiscal year were $622,000, down from
$691,000 in the prior year comparable period due to lower gas volumes and prices partially offset by higher
oil prices. The decline in revenue of $706,000 to $622,000 in the current quarter compared to $1,328,000 in
the quarter ended December 31, 2011 is mainly due to lower oil volumes resulting from the shut-in of the
Cuisinier 1 well.
Royalties
Royalty payments are made by oil and natural gas producers to the owners of the mineral rights on the
leases. These owners include governments (Crown) and freehold landowners as well as other third parties
that may receive contractual overriding royalties.
In Australia, oil royalties are based on a government-established rate of 10% plus a Native Title royalty
which is typically 1%. The royalty rate is applied to gross revenues after deducting an allowance for
transportation and operating costs resulting in an effective rate of less than 10%.
In British Columbia, royalties are calculated based on average daily production from a well multiplied by a
reference price. Bengal also pays a gross overriding royalty (“GORR”) to the landholder of between 7.5%
and 10% on its Oak, BC gas wells.
- 10 -
Bengal Energy Ltd.
Royalties by Type
($000s)
Canada Crown
Canada gross overriding
Australian Government
Total
$/boe
% of revenue
Royalties by
Commodity
Natural gas
$000s
$/mcf
% of revenue
Oil
$000s
$/bbl
% of revenue
NGLs
$000s
$/bbl
% of revenue
$
$
$
$
$
03/31/12
2
4
50
56
6.02
9.0
03/31/12
2
0.09
4.1
50
11.10
9.2
4
17.77
23.0
$
$
$
$
$
Management’s Discussion and Analysis
Three Months Ended
Twelve Months Ended
$
12/31/11
03/31/11
6
12
8
8
107
47
121
67
8.51
6.38
9.7
9.1
Three Months Ended
12/31/11
03/31/11
$
16
0.50
12.7
47
9.43
8.6
4
13.92
23.1
$
$
$
10
0.41
11.2
107
10.85
8.9
4
15.84
17.0
$
$
$
$
$
$
03/31/12
20
21
353
394
7.97
9.2
03/31/11
34
29
118
181
4.90
9.8
Twelve Months Ended
12/31/11
03/31/12
$
26
0.28
8.4
353
10.75
9.0
15
13.65
21.4
$
$
$
49
0.38
10.1
118
8.40
9.1
14
10.42
20.8
For fiscal 2012, total royalties increased by $213,000 over the prior fiscal year to $394,000 due to higher oil
sales volumes and prices partially offset by lower gas volumes and prices. Royalties per boe increased to
$7.97/boe from $4.90/boe due to increased oil volumes and prices which attract a higher royalty charge per
boe.
Operating & Transportation Expenses
Operating and transportation expenses in the 2012 fiscal year increased by 85% or $753,000 to
$1,636,000, compared to $883,000 in the prior year. The increase is due to higher oil volumes from the
commencement of production from Cuisinier 2 and 3 in Australia.
In March 2012 the Department of Transport, Energy and Infrastructure for Australia reached a settlement of
a longstanding dispute regarding Wharfage costs per barrel with the Buyers group representing the Crude
Oil Sale and Purchase Agreement under which Bengal sells its oil. The settlement resulted in an increase
from $0.12/bbl to $0.82/bbl for wharfage on all barrels sold since 2002. The impact to Bengal is a charge of
$118,000 or $3.60/bbl ($25.93/bbl for the current quarter) on Australian production for the year. This
amount is reflected in Australia transportation costs in the table below.
Canadian operating costs increased from $16.53/bbl to $20.27/bbl as fixed costs related to well site
personnel and the compressor station are allocated over declining volumes.
Operating costs in Australia for the current quarter are lower due to shut in of the Cuisinier 1 well in January
2012 and lower than forecast road maintenance costs.
Transportation costs in Australia are incurred to transport Bengal’s oil production through pipelines from
various processing facilities to the centralized Moomba facility which accepts production from 115 gas fields
and 39 oil fields through approximately 5,600 km of pipelines. The oil is then sent through a pipeline to Port
Bonython, South Australia.
- 11 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Operating Expenses ($000s)
Three Months Ended
Twelve Months Ended
03/31/12
03/31/11
12/31/11
03/31/12
03/31/11
Australia
Operating
Transportation
Canada – Operating costs
Total
Australia
Operating – ($/boe)
Transportation – ($/boe)
Canada – ($/boe)
Total ($boe)
$
$
$
37
192
229
83
312
$
$
7.86
42.69
17.18
33.33
$
119
87
206
89
295
$
$
23.70
17.21
16.14
27.97
$
222
177
399
87
486
$
$
22.41
17.93
19.24
33.71
$
607
693
1,300
336
1,636
18.47
21.15
20.27
33.12
$
$
$
269
236
505
378
883
19.13
16.73
16.53
23.89
General and Administration (G&A) Expenses
For the fiscal year 2012, G&A expenses increased $327,000 or 10% to $3,585,000 compared to $3,258,000
in the prior fiscal year. The increase is due to cost of living salary increases, higher professional fees on tax
advice on foreign operations and audit fees on changeover to IFRS and higher travel costs as operational
activity increases in Australia and India.
In the current quarter, G&A expenses decreased by $162,000 or 15% to $944,000 from $1,104,000 in the
prior year comparable quarter. Prior year costs include higher professional fees for resource reports on
certain Australian properties.
General and Administrative
Expenses ($000s)
G&A
Share-Based Compensation
Three Months Ended
Twelve Months Ended
03/31/12
944
$
$
3/31/11
1,104
12/31/11
853
03/31/12
3,585
$
03/31/11
3,258
$
$
The Company uses the Black-Scholes pricing model to estimate the fair value of the options on the date of
grant and amortizes the estimated expense over the vesting period with a corresponding increase to
contributed surplus.
Bengal recognized share-based compensation (“SBC”) expense of $1,031,000 before capitalization for
fiscal 2012 compared to $531,000 in the prior year. The increase is primarily due to two new hires receiving
options in August and September of 2011 and two companywide option grants in fiscal 2012 compared to
one in fiscal 2011. The options expire five years from the grant date; they vest one-third on the grant date
and one-third on each of the following two annual anniversaries,
Share-Based Compensation ($000s)
Three Months Ended
Twelve Months Ended
SBC - options
SBC - warrants
SBC – capitalized
Share-based compensation
03/31/12
345
−
345
(34)
311
$
$
$
$
3/31/11
80
10
90
−
90
$
$
12/31/11
169
−
169
−
169
$
$
$
03/31/12
1,031
−
1,031
(34)
997
$
$
$
3/31/11
463
68
531
−
531
$
$
$
In June 2011, 750,000 stock options were granted to employees, directors and selected consultants and
have an exercise price of $1.32 per option which was the market price of the Company’s shares at the time
of the grant. The fair value of the options was estimated to be $597,000 using the Black-Scholes option
pricing model.
In August 2011, 200,000 stock options were granted to a new employee and have an exercise price of
$1.05 per option which was the market price of the Company’s shares at the time of the grant. The fair
value of the options was estimated to be $126,000 using the Black-Scholes option pricing model.
- 12 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
In September 2011, 200,000 stock options were granted to a new employee and have an exercise price of
$1.25 per option which was the market price of the Company’s shares at the time of the grant. The fair
value of the options was estimated to be $148,000 using the Black-Scholes option pricing model.
In March 2012, 1,270,000 stock options were granted to employees, directors and selected consultants and
have an exercise price of $1.15 per option which was the market price of the Company’s shares at the time
of the grant. The fair value of the options was estimated to be $839,000 using the Black-Scholes option
pricing model.
In the current year 300,000 options were exercised, 470,667 options expired and 208,335 were forfeited
that had not vested.
For the year ended March 31, 2012, Bengal recorded share-based compensation related to outstanding
warrants of $nil (2011 - $68,000) and $nil for the three months ended March 31, 2012 (2011 – $nil). At
March 31, 2011 the fair value of the warrants had been fully amortized. The warrants expired on August 13,
2011.
Bengal recognized share-based compensation expense before capitalization of $345,000 in the current
quarter compared to $90,000 in the comparable prior year’s quarter. The increase in expense in the current
quarter is primarily due to the grant of 1,270,000 options compared to none in the prior year comparable
quarter.
Depletion and Depreciation
Depletion and depreciation increased by $77,000 to $420,000 in the year ended March 31, 2012 from
$343,000 in the prior year. The increase in Australia is due to higher production volumes partially offset by a
lower depletion rate per barrel. In Canada depletion declined due to lower production volumes at the
Company’s Oak, B.C. gas property. Depletion per boe declined due to the increases in proved plus
probable reserves in Australia as per the March 31, 2012 reserve report prepared by DeGolyer and
MacNaughton Canada Limited compared to the prior year.
Depletion per boe increased from $7.35 to $9.93 in the current quarter compared to the prior year
comparable quarter. The increase is due to increased depletable costs in Australia from the transfer of the
Cuisinier 2, 3 and Barta North 1 well costs from E&E assets to D&P assets without equivalent reserve
additions when compared to the Cuisinier 1 discovery well and lower gas reserves due to lower prices.
DD&A Expenses ($000s)
DD&A – Australia
DD&A – Canada
Total
$/boe – Australia
$/boe – Canada
$/boe – Total
03/31/12
Three Months Ended
12/31/11
03/31/11
Twelve Months Ended
03/31/11
03/31/12
$
$
$
51
42
93
11.11
9.45
9.93
$
$
$
34
44
78
6.74
7.90
7.35
$
91 $
35
$
126 $
9.18
7.71
8.72
$
$
280
140
420
8.51
8.47
8.50
$
$
$
155
188
343
11.05
8.20
9.28
In the year ended March 31, 2012 the Company reported a $4,194,000 (2011 - $nil) impairment loss
relating to E&E assets. The impairment mainly relates to costs on offshore Australia permit AC/P 24 which
were determined to be impaired after drilling and abandoning the Kingtree well in October 2011 and final
drilling costs charged by the operator in the current year for the dry and abandoned Hudson well which was
drilled in 2008.
In the current year an impairment loss related to D&P assets of $311,000 (2011 - $nil) was also recognized
for the Company’s Oak, B.C. gas property. The loss is due to lower forecast gas prices which resulted in the
carrying value of the cash generating unit exceeding the fair value less costs to sell of the CGU.
- 13 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Funds from (used in) Operations and Net Loss
For the year ended March 31, 2012 funds used in operations decreased to ($1,459,000) or ($0.03) per
basic and diluted share compared to funds used in operations of ($2,582,000) or ($0.10) per basic and
diluted share in the prior period. The improvement in funds flow of $1,138,000 is due to higher oil production
from the Cuisinier field in Australia and higher oil prices partially offset by lower gas production and gas
prices. The changes in non-cash working capital and abandonment expenditures are removed from the
GAAP measure cash flow from (used in) operations to arrive at the non-GAAP measure funds from (used
in) operations (see reconciliation on page 8).
The loss for the year ended March 31, 2012 was $7,209,000 or $0.14 per basic and diluted share compared
to a loss of $3,340,000 or $0.13 per basic and diluted share in the prior fiscal year. The increased loss was
due to impairment of certain offshore and onshore Australian E&E assets in the amount of $4,194,000 and
Canadian D&P assets of $311,000.
CAPITAL EXPENDITURES
Fiscal 2012 capital expenditures of $10,838,000 include $5,664,000 to shoot 400 km of 2D and 50 square
km of 3D seismic on onshore Australia permit ATP 732P, $1,527,000 for seismic and geological and
geophysical work on the Company’s two India permits, $1,173,000 to drill the Kingtree well offshore
Australia in the Timor Sea and $702,000 in charges from the operator of the Hudson well which was drilled
in 2008. Fiscal 2012 completion costs of $1,580,000 were to complete and equip Cuisinier 2, 3 and Barta
North 1 and to tie-in Cuisinier 2 and 3.
Capital Expenditures ($000s)
Land
Geological and geophysical
Drilling
Completions
Total oil & gas expenditures
Office
Total expenditures
Exploration & evaluation
expenditures
Development & production
expenditures
Total net expenditures
Tax Pools
03/31/12
−
1,984
62
82
2,128
105
2,233
$
$
$
$
$
$
$
$
$
$
Three Months Ended
12/31/11
−
4,416
(251)
100
4,265
−
4,265
03/31/11
991
251
736
−
1,978
−
1,978
$
$
$
$
$
$
$
$
Twelve Months Ended
03/31/11
3/31/12
−
991
7,277
886
1,876
1,824
1,580
129
10,733
3,830
105
−
10,838
3,830
$
$
2,047
186
2,233
$
1,615
363
1,978
$
4,174
91
4,265
$
10,213
625
10,838
$
$
3,338
492
3,830
Bengal has the following tax pools available to deduct against future earnings:
Years ended March 31 ($000s)
Canada
Canadian exploration expense
Canadian development expense
Undepreciated capital cost
Canadian foreign exploration & development
Non-capital losses carry forward
Net capital losses
Share issue costs
Total Canada
Australia
Non-capital losses carry forward
Undepreciated capital cost
Total Australia
Total
$
$
- 14 -
2012
64
1,075
435
5,882
15,655
5,878
1,147
30,136
24,590
56
24,646
54,782
2011
64
1,530
640
2,903
11,387
5,878
1,545
23,947
18,213
56
18,269
42,318
$
$
Bengal Energy Ltd.
Management’s Discussion and Analysis
No tax benefit has been reflected in the financial statements as the Company does not meet the probable
criteria to utilize the pools and realize the benefit.
At March 31, 2012, the Company had approximately $15.6 million and $24.6 million of non-capital losses in
Canada and Australia respectively (2011 - $11.2 million and $18.3 million), available to reduce future
taxable income. The Canadian losses expire at various dates from March 31, 2014 to 2032. The Australian
non-capital losses have no expiry date.
SHARE CAPITAL
Bengal has an unlimited number of common shares authorized for issuance. On June 13, 2012, there were
52,110,177 common shares issued and outstanding.
In April 2011, the Company issued 14,166,800 common shares at a price of $1.80 per share. Proceeds of
the offering, net of share issue costs of $2,022,000, were $23,478,000.
In June 2011, 750,000 options were granted with an exercise price of $1.32. In August 2011, 200,000
options were granted with an exercise price of $1.05 and in September 2011, 200,000 options were granted
with an exercise price of $1.25 per share. In March 2012, 1,270,000 options were granted with an exercise
price of $1.15 per share.
In the year ended March 31, 2012, 225,000 options were exercised on a cashless basis resulting in the
issuance of 73,828 common shares, 75,000 options were exercised for cash resulting in the issuance of
75,000 shares, 470,667 options expired and 208,335 options were forfeited. There has been no option
activity from the year ended March 31, 2012 to the date of this report.
Share-based compensation of $146,000 (2011 - $15,000) has been transferred from contributed surplus to
equity as a result of the option exercises.
At June 13, 2012, there were 3,611,665 employee stock options outstanding with an average exercise price
of $1.14 per share. Of these, 1,895,002 are exercisable at an average price of $1.08 per share. These
options expire between 2012 and 2017 with an average remaining life of 3.5 years.
Trading History
$
High
Low
Close
Volume (000s)
Shares outstanding
Basic and diluted
Weighted average shares outstanding
Basic and diluted
$
03/31/12
1.20
0.78
0.95
3,742
$
$
Three Months Ended
12/31/11
1.48
0.72
0.80
5,070
03/31/11
2.33
1.22
1.95
14,266
$
$
Twelve Months Ended
03/31/11
2.33
0.92
1.95
24,783
03/31/12
2.06
0.72
0.95
19,144
$
$
$
$
52,110
52,110
37,795
52,110
35,532
52,088
52,110
51,488
37,795
25,800
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2012 the Company had working capital of $25.7 million, including cash and short term
deposits of $26.9 million and restricted cash of $0.1 million, compared to working capital of $14.1 million,
including cash and short term deposits of $14.6 million and restricted cash of $1.2 million at March 31,
2011.
The Company currently has sufficient funds to meet its portion of expenditure obligations as per the
approved fiscal 2013 work programs. To finance its future acquisition, exploration, development and
operating costs, Bengal may require financing from external sources, including issuance of new shares or
executing working interest farmout arrangements. The Company is actively marketing the opportunity for
interested parties to farm in to its operated oil and gas permits in India and Australia but there is no
- 15 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
assurance these efforts will be successful. There can be no assurance that such financing will be available
to the Company or, if available, that it will be offered on terms acceptable to Bengal.
CONTRACTUAL ARRANGEMENTS
Pursuant to current production sharing contracts (“PSC”), the Company is required to perform minimum
exploration activities that include various types of surveys, acquisition and processing of seismic data and
drilling of exploration wells. The costs of these activities are based on minimum work budgets included in
bid documents and have not been provided for in the financial statements. Actual costs will vary from
budget.
Country and
Permit
Offshore Australia –
AC/P47
Work Program
Obligation
Period Ending
Estimated
Expenditure (net)
(millions CAD$)(1)
750km2 3D seismic
March 2, 2012(2)
Onshore India – CY-
ONN-2005/1
625km2 3D seismic + 75km2 high
resolution 3D seismic + 3 wells
March 3, 2014
Offshore India – CY-
OSN-2009/1
310km 2D seismic & 81km2
3D seismic
August 15, 2014
Onshore Australia –
ATP 752
Drill 3 appraisal wells & 1 exploration
well
July 31, 2014
Onshore Australia –
ATP 732
Scouting, cultural heritage & drilling
preparation. Drill 3 exploration wells
March 31, 2015
Onshore Australia –
ATP 934P
Awaiting completion of Native Title
before granting of ATP(3)
4 years after grant of
ATP
Onshore Australia –
Ideco H-44 Rig
N/A
Purchase and Sale
Agreement signed
April 4, 2012
$7.2
$5.5
$5.3
$4.9
$7.8
$12.1
$2.7
(1) Translated at March 31, 2012 exchange rate of US $1.000 = CAD $0.997 and AUD $1.000 = CAD $1.0354
(2) Bengal has applied for an extension to the time period to complete the scheduled work commitment for this offshore permit to
the National Offshore Petroleum Titles Administrator (NOPTA) to June 2, 2013. The Company has not relinquished the permit
as of the date of these financial statements.
(3) Final application for grant of the permit has been filed with the Queensland Government regulatory authority. No further
activity is planned on this permit until the final Ministerial Grant of the tenement is received. Potential legislative changes may
result in a lower commitment than shown in the table above. The Company holds a 50% operating interest in this permit.
Work program consists of 500 km of 2D seismic and up to seven wells.
- 16 -
Bengal Energy Ltd.
Guarantees – India Permits
($000s) CAD
CY-ONN-2005/1 – Onshore India – year 1
CY-OSN-2005/1 – Onshore India – year 2
CY-OSN-2005/1 – Onshore India – year 3
CY-OSN-2009/1 – Offshore India
Total Guarantees
Management’s Discussion and Analysis
Year Ended
March 31, 2012
03/31/12
−
1,104
820
151
2,075
$
$
Year ended
March 31, 2011
03/31/11
485
1,077
−
152
1,714
$
$
These performance guarantees are based on a percentage of the capital commitments shown in the table
above and are not reflected in the statement of financial position as they are secured by Export
Development Canada. These guarantees are cancelled when the Company completes the work program
commitment required for the applicable exploration period.
Other
At March 31, 2012, the contractual obligations for which the Company is responsible for are as follows:
Contractual Obligations ($000s)
Office lease
Decommissioning obligations
Total
1,263
228
Less than
1 Year
266
−
$
1-3
Years
491
−
4-5
Years
506
−
$
$
After
5 Years
−
$
228
$
Total contractual obligations
$
1,491
$
266
$
491
$
506
$
228
RELATED PARTY TRANSACTIONS
The Company paid $73,050 in consulting fees to a former director of the Company and to a company
controlled by the director. The fees were paid in the ordinary course of business based on market rates and
were for international consulting services including business development, partner meetings and regulatory
matters. At March 31, 2012, the Company has an accounts payable balance of $5,089 (March 31, 2011 -
$41,328) payable to this former director. At the Company’s Annual General Meeting on September 14,
2011, this director did not stand for re-election and has been appointed as Executive Vice President of the
Company.
SUBSEQUENT EVENTS
On April 5, 2012 the Company announced the purchase of an Ideco H-44 drilling rig. The purchase price of
the Rig is US $1.75 million plus additional costs of approximately US $1.0 million to buy certain ancillary
equipment required for drilling operations. At March 31, 2012 CAD 230,000 in costs had been incurred in
relation to the Rig.
OFF BALANCE SHEET TRANSACTIONS
The Company does not have any off balance sheet transactions.
- 17 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
SELECTED ANNUAL FINANCIAL INFORMATION
The following table sets forth certain annual information of the Company and has been prepared in
accordance with Canadian GAAP.
($000s except per share data and prices)
Year End March 31
Total production volumes (boe/d)
Natural gas prices ($/mcf)
Oil and liquids prices ($/boe)
Total production revenue
Net loss
Per share – basic and diluted
Cash from operations
Per share – basic and diluted
Funds from operations (1)
Per share – basic and diluted
Total assets
Working capital(2)
(1) See “Non-GAAP Measurements” on page 7 of this MD&A.
(2) Calculated as current assets minus current liabilities.
(3) The Company has no non-current financial liabilities.
SELECTED QUARTERLY INFORMATION
2012
135
3.33
117.41
4,286
(7,209)
(0.14)
(1,142)
(0.02)
(1,459)
(0.03)
43,696
25,722
2011
101
3.77
89.00
1,853
(3,340)
(0.13)
(2,523)
(0.10)
(2,582)
(0.10)
25,829
14,063
2010
134
4.00
67.05
1,772
(4,991)
(0.27)
(1,650)
(0.09)
(1,556)
(0.08)
7,413
1,272
(000s, except per
share amounts
Petroleum and
03/31/12
12/31/11
09/30/11
06/30/11
03/31/11 12/31/10 09/30/10
06/30/10
Quarter Ended
natural gas sales
$ 622
$ 1,328
$ 1,017 $ 1,319
$
691
$
430
$ 383
$
349
Cash from
(used-in) operations
Per share
Basic and diluted
Funds from (used in)
operations(1)
Per share
Basic and diluted
Net loss
Per share
Basic and diluted
Additions to capital
assets, net
Working capital
Total assets
Shares outstanding
Basic and diluted
Operations
Average daily
production
Natural gas (mcf/d)
Oil and NGLs
(bbls/d)
Combined (boe/d)
Netback ($/boe)
486
(417)
159
(1,371)
(725)
(681)
(455)
(570)
0.01
(0.01)
0.00
(0.03)
(0.02)
(0.02)
(0.02)
(0.03)
(635)
(402)
(430)
7
(669)
(808)
(467)
(546)
(0.01)
(1,424) $
$
0.00
(477)
(0.01)
0.00
$ (4,247) $ (1,061)
$
(0.02)
(890)
(0.03)
(0.02)
$ (1,094) $ (634)
(0.03)
(722)
$
(0.03)
(0.01)
(0.08)
(0.02)
(0.03)
(0.04)
(0.04)
(0.04)
$ 2,233 $ 4,265 $
25,722
43,696
28,798
44,899
2,407 $ 1,933
35,691
51,072
33,109
45,696
$ 1,978
14,063
25,829
$ 1,797
8,571
17,799
$ 174
11,019
17,538
$
93
631
6,693
52,110
52,110
51,961
51,961
37,795
30,262
30,238
18,238
304
271
196
249
348
327
366
381
52
103
112
157
$ 27.27 $ 49.89
97
130
110
152
$ 51.42 $ 48.92
59
117
39
94
$ 31.31 $ 22.69
41
102
31
94
$ 13.33 $ 16.65
(1) See “Non-GAAP Measurements” on page 5 and 6 of this MD&A.
- 18 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Beginning in the quarter ended June 30, 2010 and continuing through to the quarter ended December 31,
2011, oil volumes were increasing due to commencement of production from the Cuisinier 1 well in the
Cooper Basin of Australia in May 2010 and the Cuisinier 2 and 3 wells in the quarter ended September
2011. Oil sales increased in the quarter ended June 30, 2011 due to improvement in truck access to the
Cuisinier 1 well which had been restricted due to flooding. Oil sales in the most recent quarter have been
impacted from the temporary shut in of Cuisinier 1 on January 13, 2012 while the Company waits for
approval of a Production License. Gas volumes declined in the quarter ended September 30, 2011 due to a
plant turnaround at the Oak B.C. property and are in a general decline due to natural reservoir declines.
The loss in the quarter ended June 30, 2011 includes an impairment charge of $0.7 million related to
exploration and evaluation assets in Australia. The quarter ended September 30, 2011 includes impairment
charges of $3.6 million for the AC/P 24 permit which was considered impaired after drilling and abandoning
the Kingtree well offshore Australia in the Timor Sea. The current quarter loss includes impairment losses of
$367,000 mainly related to the Oak B.C. gas property.
FINANCIAL INSTRUMENTS
Financial instruments comprise cash, restricted cash and short term deposits, accounts receivable and
accounts payable and accrued liabilities. The fair values of these financial instruments approximate their
carrying amounts due to their short-term maturities.
The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange
rates and interest rates in the normal course of operations. A variety of derivative instruments may be used
by the Company to reduce its exposure to fluctuations in commodity prices, foreign exchange rates and
interest rates. The Company does not use derivative instruments at this time.
DISCLOSURE CONTROLS & PROCEDURES AND INTERNAL CONTROL OVER
FINANCIAL REPORTING (ICFR)
Disclosure Controls and Procedures
Disclosure controls and procedures are designed to provide reasonable assurance that information required
to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it
under securities legislation is recorded, processed, summarized and reported within the time periods
specified in the securities legislation and includes controls and procedures designed to ensure that
information required to be disclosed by the Company in its annual filings, interim filings or other reports filed
or submitted under securities legislation is accumulated and communicated to the Company’s management,
including its certifying officers, as appropriate to allow timely decisions regarding required disclosure.
The Chief Executive Officer and Chief Financial Officer oversee this evaluation process and have
concluded that the design and operation of these disclosure controls and procedures are not effective due
to the material weaknesses identified in internal controls over financial reporting as noted below. The Chief
Executive Officer and Chief Financial Officer have individually signed certifications to this effect.
Internal Controls over Financial Reporting
The Chief Executive Officer and Chief Financial Officer of Bengal are responsible for designing and
ensuring the operating effectiveness of internal controls over financial reporting (“ICFR”) or causing them to
be designed and operating effectively under their supervision in order to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with Canadian GAAP. 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 ineffective at March 31, 2012 due to the material weaknesses noted below.
- 19 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
During the year ended March 31, 2012 the Company put restrictions in place to limit access to all
accounting files, spreadsheets and systems to select accounting personnel. This change has eliminated the
general control deficiencies over information systems which had been previously disclosed as a material
ICFR weakness. 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;
Bengal does not have full-time in-house personnel to address all complex and non-routine financial
accounting issues and tax matters that may arise. It is not deemed as economically feasible at this
time to have such personnel. Bengal relies on external experts for review and advice on complex
financial accounting issues 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 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 preparation of financial statements in accordance with IFRS requires that management make
appropriate decisions with respect to the selection of accounting policies and in formulating estimates and
assumptions that affect the reported amount of assets, liabilities, revenues and expenses. The following is
included in the MD&A to aid the reader in assessing the critical accounting policies and practices of the
Company. The information will also aid in assessing the likelihood of materially different results being
reported depending on management’s assumptions and changes in prevailing conditions which affect the
application of these policies and practices. Significant accounting policies are disclosed in Note 3 of the
Consolidated Financial Statements.
Oil and Gas Reserves
Bengal’s Proved and Probable oil and gas reserves are 100% evaluated and reported on by independent
reserve evaluators to the Reserves Committee comprised of independent directors. The estimation of
reserves is a subjective process. Forecasts are based on engineering data, projected future rates of
production, estimated commodity price forecasts and the timing of future expenditures, all of which are
subject to numerous uncertainties and various interpretations. The Company expects that its estimates of
reserves will change to reflect updated information. Reserve estimates can be revised upward or downward
based on the results of future drilling, testing, production levels and economics of recovery based on cash
flow forecasts.
- 20 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Property and Equipment and Intangible Exploration and Evaluation Assets
Recognition and measurement
The Company accounts for exploration and evaluation (“E&E”) costs, in accordance with the requirements
of IFRS 6: “Exploration for and Evaluation of Mineral Resources.” E&E costs related to each
license/prospect are initially capitalized within “intangible exploration and evaluation assets.” Such E&E
costs may include costs of license acquisition, technical services and studies, seismic acquisition,
exploration drilling and testing, directly attributable expenses, including remuneration of production
personnel and supervisory management, and the projected costs of retiring the assets (if any), but do not
include pre-licensing costs incurred prior to having obtained the legal rights to explore an area, which are
expensed directly to earnings as they are incurred.
Exploration and evaluation assets are not depleted. They are carried forward until technical feasibility and
commercial viability of extracting a mineral resource is considered to be determined. The technical
feasibility and commercial viability is considered to be determined when proved and/or probable reserves
are determined to exist or they can be empirically supported with actual production data or conclusive
formation tests. A review of each concession agreement is carried out at least annually. Intangible
exploration and evaluation assets are transferred to petroleum properties as development and production
(“D&P”) assets upon determination of technical feasibility and commercial viability.
Petroleum properties and other assets are measured at cost less accumulated depletion, depreciation, and
amortization, and accumulated impairment losses. The initial cost of an asset comprises its purchase price
or construction cost, any costs directly attributable to bringing the asset into operation, including qualifying
E&E costs on reclassification from intangible exploration and evaluation assets, and for qualifying assets,
where applicable, borrowing costs. When significant parts of an item of property and equipment have
different useful lives, they are accounted for as separate items.
As at April 1, 2010, the date of transition to IFRS, the cost of petroleum properties and other assets was
determined by reference to IFRS 1: “First-time Adoption of International Financial Reporting Standards”.
The methodology adopted for initial recognition of these costs at transition was the cost model, whereby all
non-petroleum assets and all E&E assets were measured at the amount recognized under the Company’s
previous accounting framework, Canadian GAAP, and assets in the development and production phases
were measured at the amount determined for the cost centre to which they relate. The adopted process
allocated the development and production asset amounts to the underlying assets pro rata based on proved
plus probable reserves as at the date of transition.
Gains and losses on disposal of items of property and equipment are determined by comparing the
proceeds from disposal with the carrying amount of property and equipment and are recognized in earnings
immediately.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability and the
costs of replacing parts of property and equipment are recognized as petroleum properties or other assets
only when they increase the future economic benefits embodied in the specific asset to which they relate.
All other expenditures are recognized in earnings as incurred. Such capitalized property and equipment
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.
- 21 -
Bengal Energy Ltd.
Impairment
Management’s Discussion and Analysis
Estimated future recoverable value of property, plant and equipment and any related impairment charges or
recoveries are assessed for impairment when circumstances suggest the carrying amount may exceed its
recoverable amount. The recoverable amount calculation requires the use of estimates which are subject to
change as new information becomes available. Changes in assumptions used in determining the
recoverable amount could affect the carrying value of the related assets.
Depletion, depreciation and amortization
The depletion, depreciation and amortization of petroleum properties and other assets, and any eventual
reversal thereof, are recognized in earnings.
The net carrying value of D&P assets included in petroleum properties is depleted using the unit of
production method by reference to the ratio of production in the year to the related proved and probable
reserves using estimated future prices and costs. Costs subject to depletion include estimated future
development costs necessary to bring those reserves into production. These estimates are reviewed by
independent reserve engineers at least annually.
Proved and probable reserves are estimated using independent reserve evaluator reports and represent the
estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and
engineering data demonstrate with a specified degree of certainty to be recoverable in future years from
known reservoirs and which are considered commercially viable. The specified degree of certainty must be
a minimum 90% statistical probability that the actual quantity of recoverable reserves will be more than the
amount estimated as proved and a minimum 50% statistical probability for proved and probable reserves to
be considered commercially viable.
Other assets are depreciated at declining balance rates of 20% to 30%.
Depreciation methods, useful lives and residual values are reviewed at each reporting date.
Accruals
Estimated accruals for revenues, royalties and operating costs where actual revenues and costs have not
been received.
Estimated capital expenditures where actual costs have not been received or for projects that are in
progress.
Decommissioning Obligations
The Company is required to set up a provision for future removal and site restoration costs. The Company
must estimate these costs in accordance with existing laws, contracts or other policies. These estimated
costs are charged to property, plant and equipment and the appropriate liability account over the expected
service life of the assets. The estimate of future removal and site restoration costs involves a number of
estimates related to timing of abandonment, determination of the economic life of the asset, costs
associated with abandonment and site restoration, discount rates and review of potential abandonment
methods.
Stock-Based Compensation
In order to recognize stock-based compensation costs, the Company estimates the fair value of stock
options granted using assumptions related to interest rates, expected life of the option, forfeitures and
volatility of the underlying security. These assumptions vary over time.
- 22 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Production Sharing Agreements
International operations conducted pursuant to PSAs are reflected in the Consolidated Financial Statements
based on the Company’s working interest in such operations. Under the PSAs, the Company and other
non-governmental partners pay all operating and capital costs for exploring and developing the
concessions. Each PSA establishes specific terms for the Company to recover these costs (Cost Recovery
Oil) and to share in the production sharing oil. Cost Recovery Oil is determined in accordance with a
formula that is generally limited to a specified percentage of production during each fiscal year. Production
sharing oil is that portion of production remaining after Cost Recovery Oil and is shared between the joint
venture partners and the government of each country, varying with the level of production. Production
sharing oil that is attributable to the government includes an amount in respect of all income taxes payable
by the Company under the laws of the respective country.
NEW ACCOUNTING STANDARDS AND PRONOUNCEMENTS
International Financial Reporting Standards (“IFRS”)
The adoption of IFRS required the restatement, for comparative purposes, of amounts reported by the
Company for the year ended March 31, 2011, including the opening balance sheet as at April 1, 2010. The
Company’s first annual financial statements prepared under IFRS are the financial statements for the year
ended March 31, 2012. These financial statements include reconciliations of the previously disclosed
comparative period financial statements prepared in accordance with Canadian GAAP to IFRS, as set out in
Note 20.
The following standards and interpretations have not been adopted as they apply to future periods. They
may result in changes to the Company’s existing accounting policies and other note disclosures:
IFRS 7 (revised) “Financial Instruments: Disclosures”
In October 2010, the International Accounting Standards Board (“IASB”) issued amendments to IFRS 7 to
provide additional disclosure on the transfer of financial assets including the possible effects of any residual
risks that the transferring entity retains. These amendments are effective for annual periods beginning after
July 1, 2011; therefore, the Company will adopt them for the year ending March 31, 2013. The Company is
currently evaluating the impact of these amendments to its Consolidated Financial Statements, but the
impact, if any, is not expected to be material.
IFRS 9 (revised) “Financial Instruments: Classification and Measurement”
In November 2009, the IASB issued IFRS 9 as part of its project to replace IAS 39 “Financial Instruments:
Recognition and Measurement”. In October 2010, the IASB updated IFRS 9 to include the requirements for
financial liabilities. IFRS 9 replaces the multiple rules in IAS 39 with a single approach to determine whether
a financial asset is measured at amortized cost or fair value. The approach in IFRS 9 is based on how an
entity manages its financial instruments in the context of its business model and the contractual cash flow
characteristics of the financial assets. IFRS 9 is effective for annual periods beginning on or after January 1,
2013. The Company is currently evaluating the impact of this standard on its Consolidated Financial
Statements.
IFRS 10 (new) “Consolidated Financial Statements”
In May 2011, the IASB issued IFRS 10 to replace SIC-12, “Consolidation – Special Purpose Entities”, and
parts of IAS 27, “Consolidated and Separate Financial Statements”. IFRS 10 establishes principles for the
presentation and preparation of consolidated financial statements when an entity controls one or more other
entities. IFRS 10 is effective for annual periods beginning on or after January 1, 2013. The Company is
currently evaluating the impact of this standard on its Consolidated Financial Statements.
- 23 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
IFRS 11 (new) “Joint Arrangements”
In May 2011, the IASB issued IFRS 11 to replace IAS 31, “Interests in Joint Ventures”, and SIC-13, “Jointly
Controlled Entities – Non-monetary Contributions by Venturers”. IFRS 11 requires entities to follow the
substance rather than legal form of a joint arrangement and removes the choice of accounting method.
IFRS 11 is effective for annual periods beginning on or after January 1, 2013. The Company is currently
evaluating the impact of this standard on its Consolidated Financial Statements.
IFRS 12 (new) “Disclosure of Interests in Other Entities”
In May 2011, the IASB issued IFRS 12, which aggregates and amends disclosure requirements included
within other standards. IFRS 12 requires entities to provide disclosures about subsidiaries, joint
arrangements, associates and unconsolidated structured entities. IFRS 12 is effective for annual periods
beginning on or after January 1, 2013. The Company is currently evaluating the impact of this standard on
its Consolidated Financial Statements.
IFRS 13 (new) “Fair Value Measurement”
In May 2011, the IASB issued IFRS 13 to clarify the definition of fair value and provide guidance on
determining fair value. IFRS 13 amends disclosure requirements included within other standards and
establishes a single framework for fair value measurement and disclosure. IFRS 13 is effective for annual
periods beginning on or after January 1, 2013. The Company is currently evaluating the impact of this
standard on its Consolidated Financial Statements.
IAS 1 (revised) “Presentation of Financial Statements”
In June 2011, the IASB issued amendments to IAS 1 to require separate presentation for items of other
comprehensive income that would be reclassified to profit or loss in the future from those that would not.
These amendments are effective for annual periods beginning on or after July 1, 2012. The Company is
currently evaluating the impact of these amendments to its Consolidated Financial Statements.
IAS 12 (revised) “Income Taxes”
In December 2010, the IASB issued amendments to IAS 12 to remove subjectivity in determining on which
basis an entity measures the deferred tax relating to an asset. The amendments introduce a presumption
that entities will assess whether the carrying value of an asset will be recovered through the sale of the
asset. These amendments are effective for annual periods beginning on or after January 1, 2012. The
Company is currently evaluating the impact of these amendments to its Consolidated Financial Statements,
but the impact, if any, is not expected to be material.
IAS 28 (revised) “Investments in Associates and Joint Ventures”
In May 2011, the IASB issued amendments to IAS 28 to prescribe the accounting for investments in
associates and set out the requirements for applying the equity method when accounting for investments in
associates and joint ventures. These amendments are effective for annual periods beginning on or after
January 1, 2013. The Company is currently evaluating the impact of these amendments to its Consolidated
Financial Statements, but the impact, if any, is not expected to be material.
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
- 24 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
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.
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.
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.
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
- 25 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
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
widely in recent years. 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 to prospective buyers. The marketability and price of oil and
natural gas which may be acquired or discovered by Bengal will 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 will 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 will affect Bengal’s ability to expend the necessary capital to replace its reserves
or to maintain its production. If Bengal’s funds from operations are not sufficient to satisfy its capital
- 26 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
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.
Insurance
Bengal’s involvement in the exploration for and development of oil and gas properties may result in the
Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other
hazards. Although Bengal has insurance in accordance with industry standards to address such risks, such
insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In
addition, such risks may not, in all circumstances be insurable or, in certain circumstances, Bengal may
elect not to obtain insurance to deal with specific risks due to the high premiums associated with such
insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to
Bengal. The occurrence of a significant event that Bengal is not fully insured against, or the insolvency of
the insurer of such event, could have a material adverse effect on Bengal’s financial position, results of
operations or prospects.
Competition
Bengal actively competes for reserve acquisitions, exploration leases, licenses and concessions and skilled
industry personnel with a substantial number of other oil and gas companies, many of which have
significantly greater financial and personnel resources than Bengal. Bengal's competitors include major
integrated oil and natural gas companies and numerous other independent oil and natural gas companies
and individual producers and operators.
Bengal’s ability to successfully bid on and acquire additional property rights, to discover reserves, to
participate in drilling opportunities and to identify and enter into commercial arrangements with customers
will be dependent upon developing and maintaining close working relationships with its future industry
partners and joint operators and its ability to select and evaluate suitable properties and to consummate
transactions in a highly competitive environment.
- 27 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
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 1810, 801 6th
Avenue SW., Calgary, Alberta T2P 3W2, by email to info@bengalenergy.ca or by accessing Bengal’s
website at www.bengalenergy.ca.
Forward-looking Statements - Certain statements contained within the Management’s Discussion and Analysis, and
in certain documents incorporated by reference into this document, constitute forward-looking statements. 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, or incorporated by reference into, this MD&A should not be
unduly relied upon.
In particular, this Management’s Discussion and Analysis, and the documents incorporated by reference, contain
forward-looking statements pertaining to the following:
●
●
●
●
●
●
●
●
●
●
●
●
●
●
Oil and natural gas production levels;
The size of the oil and natural gas reserves;
Projections of market prices and costs;
Expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and
development;
Treatment under governmental regulatory regimes and tax laws;
Capital expenditures programs and estimates of costs;
Expectations that Bengal’s future realized gas and oil prices will coincide with the B.C Station 2 and Brent daily
index prices;
Funding of working capital requirements, commitments and other planned expenses will be by cash on hand,
cashflows, farm-outs, joint ventures or share issues and funds will be sufficient to meet requirements;
Continuation of exploration and development activities on Block CY-ONN-2005/1 and whether identified play
types on this Block will be prospective;
Commencement of exploration and development activities on Block CY-OSN-2009/1;
Continuation of exploration, development activities on Permit AC/P 47 offshore Australia and whether the
Company will be granted an extension to the time period to complete the work program on this permit to June
2, 2013 and whether a farm-out partner will be found on acceptable terms to the Company and if not, whether
the Company will shoot seismic on this permit;
Obtaining Native Title Agreement on ATP 934P in Australia and commencement of exploration activities;
That drilling activities on ATP 732P will occur;
That drilling of three wells will occur on ATP 752P in calendar Q2 and Q3 of 2012 and seismic activity will
follow drilling and that production from Cuisinier 2 and 3 will continue as expected and that a production
license will be granted for Cuisinier 1 and it will re-commence production and that Cuisinier 4 will produce oil
and that transportation of the oil will occur.
- 28 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
With respect to the forward looking statements contained in the MD&A, Bengal has made assumptions regarding: future
commodity prices; the impact of royalty regimes; the timing and the amount of capital expenditures; production of new
and existing wells and the timing of new wells coming on stream; future operating expenses including processing and
gathering fees; the performance characteristics of oil and natural gas properties; the size of oil and natural gas
reserves; the ability to raise capital; the continued availability of undeveloped land and skilled personnel; the ability to
obtain equipment in a timely manner to carry out exploration and development activities; the ability to obtain financing
on acceptable terms; the ability to add production and reserves through exploration and development activities; and the
continued stability of political, regulatory; tax and fiscal regimes in which the Company has operations.
The actual results could differ materially from those anticipated in these forward-looking statements as a result of the
risk factors set forth below and elsewhere in this Management’s Discussion and Analysis:
●
●
●
●
●
●
●
●
●
●
Volatility in market prices for oil and natural gas;
Liabilities inherent in oil and natural gas operations;
Uncertainties associated with estimating oil and natural gas reserves;
Competition
for, among other
things: capital, acquisitions of
reserves, undeveloped
lands and
skilled personnel;
Incorrect assessment of the value of acquisitions;
Unable to meet commitments due to inability to raise funds or complete farm-outs;
Geological, technical, drilling and processing problems;
Changes in income tax laws or changes to royalty and environmental regulations relating to the oil and
gas industry;
The risk that Bengal may not be successful in raising funds by an equity issue; 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, that 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 and the documents incorporated by reference herein 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).
These statements speak only as of the date of this MD&A or as of the date specified in the documents incorporated by
reference into this Management’s Discussion and Analysis, as the case may be.
- 29 -
Bengal Energy Ltd.
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 outlined in the notes to the consolidated financial statements. The
consolidated financial statements include certain estimates that reflect the 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, 2012. During this evaluation Management
identified weaknesses due to the limited number of finance and accounting personnel at the Corporation
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 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.
Chayan Chakrabarty
President & Chief Executive Officer
Bryan Goudie
Chief Financial Officer
June 13, 2012
Calgary, Alberta
-30-
Bengal Energy Ltd.
Consolidated Financial Statements
AUDITORS’ REPORT TO THE SHAREHOLDERS
To the Shareholders of Bengal Energy Ltd.
We have audited the accompanying consolidated financial statements of Bengal Energy Ltd., which
comprise the consolidated statements of financial position as at March 31, 2012, March 31, 2011 and April
1, 2010, the consolidated statements of loss and comprehensive loss, changes in equity and cash flows for
the years ended March 31, 2012 and March 31, 2011, and notes, comprising a summary of significant
accounting policies and other explanatory information.
Management’s responsibility for the consolidated financial statements
Management is responsible for the preparation and fair presentation of these consolidated financial
statements in accordance with International Financial Reporting Standards, and for such internal control as
management determines is necessary to enable the preparation of consolidated financial statements that
are free from material misstatement, whether due to fraud or error.
Auditors’ responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those
standards require that we comply with ethical requirements and plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are free from material
misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on our judgment, including the
assessment of the risks of material misstatement of the consolidated financial statements, whether due to
fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s
preparation and fair presentation of the consolidated financial statements 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 entity’s internal control. An audit also includes evaluating the appropriateness of
accounting policies used and the reasonableness of accounting estimates made by management, as well
as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a
basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated
financial position of Bengal Energy Ltd. as at March 31, 2012, March 31, 2011 and April 1, 2010, and its
consolidated financial performance and its consolidated cash flows for the years ended March 31, 2012 and
March 31, 2011 in accordance with International Financial Reporting Standards.
Chartered Accountants
June 13, 2012
Calgary, Canada
-31-
Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Thousands of Canadian dollars)
As at
ASSETS
Current assets:
Notes
March 31, 2012 March 31, 2011
Note 20
April 1, 2010
Note 20
Cash and cash equivalents
Restricted cash
Accounts receivable
Prepaid expenses and deposits
4
$
Non-current assets:
Property, plant and equipment
Petroleum and natural gas properties
Exploration and evaluation assets
18
5
6
Total assets
$
26,934
135
1,009
127
28,205
230
4,735
10,526
15,491
43,696
$
$
14,600
1,227
817
91
16,735
−
2,030
7,064
9,094
25,829
$
$
1,055
510
273
100
1,938
−
1,922
3,553
5,475
7,413
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities
$
2,483
$
2,672
$
666
8
9
9
Non-current liabilities:
Decommissioning liability
Shareholders’ equity:
Share capital
Warrants
Contributed surplus
Accumulated other comprehensive income
Deficit
Total liabilities and shareholders’ equity
Commitments (note 15)
Subsequent event (note 18)
See accompanying notes to the consolidated financial statements.
228
159
115
$
$
86,246
−
5,779
717
(51,757)
40,985
43,696
$
$
62,595
705
4,189
57
(44,548)
22,998
25,829
$
$
43,460
490
3,890
−
(41,208)
6,632
7,413
On behalf of the Board:
Director
Chayan Chakrabarty
Director
James B. Howe
-32-
Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
(Thousands of Canadian dollars, except per share amounts)
For the years ended March 31,
Income
Petroleum and natural gas revenue
Royalties
Operating expenses
General and administrative
Operating and transportation
Depletion and depreciation
Impairment
Pre-licensing and E&E expenses
Share-based compensation
Operating loss
Other income (expenses)
Finance income
Finance expenses
Foreign exchange loss
Notes
2012
2011
(Note 20)
$
$
4,286
(394)
3,892
3,585
1,636
420
4,505
292
997
11,435
1,853
(181)
1,672
3,258
883
343
−
82
531
5,097
(7,543)
(3,425)
613
(68)
(211)
334
119
(20)
(14)
85
10
5
5,6
11
Net Loss
(7,209)
(3,340)
Exchange differences on translation of foreign operations
660
57
Total comprehensive loss for the year
$
(6,549)
$
(3,283)
Loss per share
- Basic & Diluted
Weighted average number of shares outstanding (000s)
9
9
$
(0.14) $
(0.13)
- Basic & Diluted
51,488
25,800
See accompanying notes to the consolidated financial statements.
-33-
Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Thousands of Canadian dollars)
Share
capital Warrants
Contributed
surplus
Accumulated
other
comprehensive
income
Total
shareholders’
equity
Deficit
Balance at
April 1, 2010
Net loss for the year
Comprehensive
income for the
year
Issue of share
capital (Note 9)
Share based
payments
Balance at
March 31, 2011
$ 43,460
$ 490
$
3,890
$
$ (41,208)
$
6,632
−
−
−
−
19,135
−
−
(17)
−
215
316
−
(3,340)
(3,340)
−
−
57
−
−
57
19,118
531
$ 62,595
$
705 $
4,189
$
57 $ (44,548)
$
22,998
Shares outstanding
37,794,549
Balance at
April 1, 2011
Net loss for the year
Comprehensive
income for the
year
Issue of share
capital (Note 9)
Expiry of warrants
Share based
payments -
expensed
Share based
payments -
capitalized
Balance at
March 31, 2012
$ 62,595
$
705 $
4,189
$
57 $ (44,548)
$
22,998
−
−
23,651
−
−
−
−
−
−
(705)
−
−
−
−
(146)
705
997
34
−
(7,209)
(7,209)
660
−
−
−
−
−
−
−
−
−
660
23,505
−
997
34
$ 86,246
$
−
$
5,779
$
717 $ (51,757)
$
40,985
Shares outstanding
52,110,177
See accompanying notes to the consolidated financial statements.
-34-
Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Canadian dollars)
For the periods ended March 31,
Notes
2012
2011
Operating activities
Net loss for the year
Non-cash items:
Depletion and depreciation
Impairment
Pre-licensing and E&E expenses
Accretion of decommissioning liability
Share-based compensation
Unrealized foreign exchange gain
Abandonment expenditures
Change in non-cash working capital
Net cash used in operating activities
Investing activities
Exploration and evaluation expenditures
Petroleum and natural gas properties
Property, plant and equipment
Change in restricted cash
Changes in non-cash working capital
Net cash used in investing activities
Financing activities
Proceeds from issuance of shares,
net of issuance costs
Changes in non-cash working capital
Net cash from financing activities
Impact of foreign exchange
on cash and cash equivalents
Net increase in cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
See accompanying notes to consolidated financial statements.
$
(7,209)
$
(3,340)
420
4,505
−
5
997
(177)
(3)
320
(1,142)
(10,213)
(625)
(230)
1,092
(326)
(10,302)
23,505
(82)
23,423
355
14
14
14
$
$
12,334
14,600
26,934
$
$
343
−
82
5
531
(203)
−
59
(2,523)
(3,338)
(492)
−
(717)
1,334
(3,213)
19,118
77
19,195
86
13,545
1,055
14,600
-35-
Bengal Energy Ltd.
BENGAL ENERGY LTD.
Notes to Consolidated Financial Statements (the “financial statements”)
Three and twelve months ended March 31, 2012 and 2011
(Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)
1.
INCORPORATION:
Bengal Energy Ltd (the “Company” or “Bengal”) is incorporated under the laws of the Province of
Alberta and is involved in the exploration for and development of oil and gas reserves in Australia, India
and Canada.
Bengal’s registered office is located at 1810, 801 6th Ave SW, Calgary, Alberta.
2. BASIS OF PREPARATION
a) Statement of compliance
These consolidated financial statements as at March 31, 2012, 2011, and the opening statement
of financial position at April 1, 2010, are the Company’s first annual consolidated financial
statements to be issued under International Financial Reporting Standards (“IFRS”). As a result,
IFRS 1 “First-time Adoption of Internal Financial Reporting Standards” has been applied.
An explanation of how the transition to IFRS has affected the reported consolidated financial
position, financial performance and cash flows of the Company is provided in Note 20. That note
includes reconciliations as at April 1, 2010, March 31, 2011 and for the year ended March 31,
2011.
The consolidated financial statements were authorized for issuance by the Board of Directors on
June 13, 2012.
b) Basis of measurement
These consolidated financial statements have been prepared on a historical cost basis.
c) Functional and presentation currency
The Company’s presentation currency is Canadian dollars ($). The functional currency of the
Canadian parent entity is Canadian dollars, the functional currency of the India subsidiary is U.S.
dollars and the functional currency of the Australian subsidiary is Australian dollars.
d) Use of Estimates and judgments
The timely preparation of the financial statements requires management to make judgements,
estimates and assumptions that affect the application of accounting policies and reported amounts
of assets and liabilities and income and expenses. Accordingly, actual results may differ from
these estimates. 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.
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.
-36-
Bengal Energy Ltd.
i) Reserves
Notes to Consolidated Financial Statements
The estimate of petroleum and natural 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 development and production assets 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.
Reserve estimation is based on a variety of factors including engineering data, geological and
geophysical data, projected future rates of production, commodity pricing and timing of future
expenditures, all of which are subject to significant judgment and interpretation.
ii)
Identification of Cash-generating Units
Bengal’s assets are aggregated into cash-generating units, for the purpose of calculating
impairment, 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.
iii) 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: 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.
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
the assets and liabilities.
i) 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.
ii) Impairment of petroleum and natural gas assets
For the purposes of determining whether impairment of petroleum and natural gas assets occurred, and
the extent of any impairment or its reversal, the key assumptions the Company uses in estimating future
cash flows are future petroleum and natural gas prices, expected production volumes and anticipated
recoverable quantities of proved and probable reserves. These assumptions are subject to change as
new information becomes available. Changes in economic conditions can also affect the rate used to
discount future cash flow estimates. Changes in the aforementioned assumptions could affect the
carrying amount of assets, and impairment charges and reversal will affect profit or loss.
iv) Income Taxes
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could
affect amounts recognized in profit or loss both in the period of change, which would include any
impact on cumulative provisions, and in future periods. Deferred tax assets (if any) are recognized
-37-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
only to the extent it is considered probable that those assets will be recoverable. This involves an
assessment of when those deferred tax assets are likely to reverse and a judgment as to whether
or not there will be sufficient taxable profits available to offset the tax assets when they do reverse.
This requires assumptions regarding future profitability and is therefore inherently uncertain. To the
extent assumptions regarding future profitability change, there can be an increase or decrease in
the amounts recognized in respect of deferred tax assets as well as the amounts recognized in
profit or loss in the period which the change occurs.
3. SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently to all periods presented in these
consolidated financial statements, and have been applied consistently by the Company and its
subsidiaries.
In addition to the quantitative adjustments from previous GAAP to IFRS, certain comparative amounts
have been reclassified to conform to the current years presentation as presented in note 20.
(a) Basis of consolidation:
The consolidated interim financial statements incorporate the financial statements of the Company
and it’s wholly and majority owned subsidiaries, Bengal Energy Australia (Pty) Ltd., Bengal Energy
International Inc., Avery Resources (Northern Ireland) Ltd. and Northstar Energy Pty Ltd.
respectively.
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 consolidated financial
statements from the date that control commences until the date that control ceases.
The Company recognizes in its financial statements its proportionate share of the assets, liabilities,
revenues, and expenses of the joint operation.
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 balance sheet 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
finance costs whereas
the provision due
the passage of
recognized as
time
to
is
-38-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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 costs (“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 has 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 until the technical feasibility and commercial viability of
the project is established. Amounts are generally reclassified to petroleum and natural 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
Carrying value
Costs incurred subsequent to the determination of technical feasibility and commercial viability are
recognized as petroleum and natural gas properties in the specific asset to which they relate.
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%.
-39-
Bengal Energy Ltd.
(f) Impairment
Notes to Consolidated Financial Statements
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 Development and
Production (“D&P”) assets. For the purpose of impairment testing, E&E assets are grouped by
concession or field with other E&E and D&P assets belonging to the same concession or 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 circumstances that indicate that the assets may be impaired. Assets are grouped together into
CGUs for the purpose of impairment testing, which is the lowest level at which there are identifiable
cash flows 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
CGUs recoverable amount is the higher of its fair value less selling costs and its value in use. In
assessing value in use, the estimated future cash flows are discounted to their present value using
a pre-tax discount rate that reflects current market assessments of the time value of money and the
risks specific to the asset. Value in use is generally computed by reference to the present value of
future cash flows expected to be derived from the production of proved and probable reserves.
Fair value less cost to sell 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 fair value less
cost to sell of oil and gas assets 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. These 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. Where the carrying
amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written
down. Consideration is given to acquisition metrics or recent transactions completed on similar
assets to those contained with the relevant CGU.
When the recoverable amount is less than the carrying amount, the asset or CGU is impaired. For
impairment losses identified based on a CGU, the loss is allocated on a pro rata basis to the assets
within the CGU(s). The impairment loss is recognized as an expense in profit or loss.
At the end of each subsequent reporting period these impairments are assessed for indicators of
reversal. 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 had no
impairment loss have been recognized for the asset or CGU in prior years. A reversal of an
impairment loss is recognized immediately in profit or loss.
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.
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.
-40-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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 assets and liabilities are classified as either financial assets or liabilities at fair value
through profit and loss (“FVTPL”), loans and receivables, held to maturity investments, available for
sale financial assets, or other liabilities, as appropriate. Financial assets and liabilities are
recognized initially at fair value.
Subsequent measurement of financial instruments is based on their initial classification. FVTPL
financial assets and liabilities are measured at fair value and changes in fair value are recognized in
profit or loss. Available-for-sale financial instruments are measured at fair value with changes in fair
value recorded in other comprehensive loss until the instrument is derecognized or impaired. The
remaining categories of financial instruments are recognized at amortized cost using the effective
interest rate method.
The transaction costs that are directly attributable to the acquisition or issue of a financial asset or
financial liability classified as FVTPL are expensed immediately. For a financial asset or financial
liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the
asset or liability are added to or deducted from the fair value on initial recognition and amortized
through profit or loss income over the term of the financial instrument.
(i) Non-derivative financial instruments
Cash and cash equivalents, restricted cash as well as accounts receivable are classified as loans
and receivables, which are measured at amortized cost. Accounts payable and accrued liabilities
are classified as other financial liabilities, which are measured at amortized cost.
(ii) 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 will not be used for trading
or speculative purposes. The Company will 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 will be classified as FVTPL and will be recorded on the statement of financial position at
fair value. Transaction costs will be recognized in profit or loss when incurred. Subsequent to initial
recognition, derivatives will be 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 nonfinancial 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.
-41-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
At March 31, 2012 the Company does not have any derivative financial instruments.
Fair value
The fair value of financial instruments that are actively traded in organized financial markets is
determined by reference to quoted market bid prices at the valuation date. For financial instruments
that have no active market, fair value is determined using valuation techniques including the use of
recent arm’s length market transactions, reference to the current market value of equivalent
financial instruments and discounted cash flow analysis.
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 consolidated financial statements are presented in Canadian dollars, which is the Company’s
functional and presentation currency. 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 stock-based compensation granted to directors, officers, employees and
consultants using the Black-Scholes option-pricing model to determine the fair value of the plan 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. Stock-based compensation expense is recorded and
reflected as stock-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 common share capital.
(j) Revenue recognition:
Revenue from the sale of natural gas, natural gas liquids and crude oil is recognized when the
significant risks and rewards of ownership is transferred, which is when title passes to the customer
in accordance with the terms of the sales contract. This generally occurs when the product is
physically transferred into a pipe, truck or other delivery mechanism.
(k) Earnings (loss) per share:
Basic per share amounts are computed by dividing net earnings (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.
-42-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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
previos 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 reverese, 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 fees on
Performance Security Guarantees issued by Export Development Canada, bank fees on Bank
Guarantees issued to the Governement of India and accretion of the discount on decommissioning
obligations.
(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.
1) Property, plant and equipment are recognized at fair value in a business combination. The fair
value of property, plant and equipment is the estimated amount for which the property, plant
and equipment could be exchanged on the acquisition date between a willing buyer and a
willing seller in an arm’s length transaction after proper marketing wherein the parties had each
acted knowledgeably, prudently and without compulsion. The fair value of oil and natural gas
interests (included in property, plant and equipment) is estimated with reference to the
discounted cash flows expected to be derived from oil and gas production based on externally
prepared reserve reports. The risk-adjusted discount rate is specific to the asset with reference
to general market conditions.
The market value of other items of property, plant and equipment is based on the quoted market
prices for similar items.
2) The fair value of cash and cash equivalents, accounts receivable and accounts payable and
accrued liabilities is estimated as the present value of future cash flows, discounted at the
market rate of interest at the reporting date. At March 31, 2012 and March 31, 2011 the fair
value of these balances approximated their carrying value due to their short term to maturity.
3) The fair value of employee stock options is measured using a Black Scholes option pricing
model. Measurement inputs include share price on measurement date, exercise price of the
-43-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
instrument, expected volatility (based on weighted average historic volatility adjusted for
changes expected due to publicly available information), weighted average expected life of the
instruments (based on historical experience and general option holder behavior), expected
dividends, and the risk-free interest rate (based on government bonds).
(o) Future changes to accounting policies:
The IASB has issued the following new standards and amendments, all of which are effective for
annual periods beginning on or after January 1, 2013. Although early adoption is permintted, the
Company has not done so as of March 31, 2012.
IFRS 7 (revised) “Financial Instruments: Disclosures”
In October 2010, the International Accounting Standards Board (“IASB”) issued amendments to
IFRS 7 to provide additional disclosure on the transfer of financial assets including the possible
effects of any residual risks that the transferring entity retains. These amendments are effective for
annual periods beginning after July 1, 2011; therefore, the Company will adopt them for the year
ending March 31, 2013. The Company has not transferred any financial assets and there is no
impact to its Consolidated Financial Statements.
IFRS 9 (revised) “Financial Instruments: Classification and Measurement”
In November 2009, the IASB issued IFRS 9 as part of its project to replace IAS 39 “Financial
Instruments: Recognition and Mearsurement”. In October 2010, the IASB updated IFRS 9 to include
the requirements for financial liabilities. IFRS 9 replaces the multiple rules in IAS 39 with a single
approach to determine whether a financial asset is measured at amortized cost or fair value. The
approach in IFRS 9 is based on how an entity manages its financial instruments in the context of its
business model and the contractual cash flow characteristics of the financial assets. IFRS 9 is
effective for annual periods beginning on or after January 1, 2013. The Company is currently
evaluating the impact of this standard on its Consolidated Financial Statements.
IFRS 10 (new) “Consolidated Financial Statements”
In May 2011, the IASB issued IFRS 10 to replace SIC-12, “Consolidation – Special Purpose
Entities”, and parts of IAS 27, “Consolidated and Separate Financial Statements”. IFRS 10
establishes principles for the presentation and preparation of consolidated financial statements
when an entity controls one or more other entities. IFRS 10 is effective for annual periods beginning
on or after January 1, 2013. The Company is currently evaluating the impact of this standard on its
Consolidated Financial Statements.
IFRS 11 (new) “Joint Arrangements”
In May 2011, the IASB issued IFRS 11 to replace IAS 31, “Interests in Joint Ventures”, and SIC-13,
“Jointly Controlled Entities – Non-monetary Contributions by Venturers”. IFRS 11 requires entities to
follow the substance rather than legal form of a joint arrangement and removes the choice of
accounting method. IFRS 11 is effective for annual periods beginning on or after January 1, 2013.
The Company is currently evaluating the impact of this standard on its Consolidated Financial
Statements.
IFRS 12 (new) “Disclosure of Interests in Other Entities”
In May 2011, the IASB issued IFRS 12, which aggregates and amends disclosure requirements
included within other standards. IFRS 12 requires entities to provide disclosures about subsidiaries,
joint arrangements, associates and unconsolidated structured entities. IFRS 12 is effective for
annual periods beginning on or after January 1, 2013. The Company is currently evaluating the
impact of this standard on its Consolidated Financial Statements.
-44-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
IFRS 13 (new) “Fair Value Measurement”
In May 2011, the IASB issued IFRS 13 to clarify the definition of fair value and provide guidance on
determining fair value. IFRS 13 amends disclosure requirements included within other standards
and establishes a single framework for fair value measurement and disclosure. IFRS 13 is effective
for annual periods beginning on or after January 1, 2013. The Company is currently evaluating the
impact of this standard on its Consolidated Financial Statements.
IAS 1 (revised) “Presentation of Financial Statements”
In June 2011, the IASB issued amendments to IAS 1 to require separate presentation for items of
other comprehensive income that would be reclassified to profit or loss in the future from those that
would not. These amendments are effective for annual periods beginning on or after July 1, 2012.
The Company is currently evaluating the impact of these amendments to its Consolidated Financial
Statements.
IAS 12 (revised) “Income Taxes”
In December 2010, the IASB issued amendments to IAS 12 to remove subjectivity in determining on
which basis an entity measures the deferred tax relating to an asset. The amendments introduce a
presumption that entities will assess whether the carrying value of an asset will be recovered
through the sale of the asset. These amendments are effective for annual periods beginning on or
after January 1, 2012. The Company is currently evaluating the impact of these amendments to its
Consolidated Financial Statements, but the impact, if any, is not expected to be material.
IAS 28 (revised) “Investments in Associates and Joint Ventures”
In May 2011, the IASB issued amendments to IAS 28 to prescribe the accounting for investments in
associates and set out the requirements for applying the equity method when accounting for
investments in associates and joint ventures. These amendments are effective for annual periods
beginning on or after January 1, 2013. The Company is currently evaluating the impact of these
amendments to its Consolidated Financial Statements, but the impact, if any, is not expected to be
material.
4. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash on hand and in banks and investments with an original
maturity date of 90 days or less. Cash and cash equivalents at the end of the reporting period as shown
in the statement financial position are comprised of:
As at ($000s)
Cash and bank balances
Short-term deposits
$
March 31, 2012
3,864
23,070
26,934
$
$
March 31, 2011
1,880
12,720
14,600
$
-45-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
5. PETROLEUM AND NATURAL GAS PROPERTIES
Cost:
Balance at April 1, 2010
Additions
Change in asset retirement obligation
Exchange adjustments
Balance at March 31, 2011
Additions
Capitalized share based compensation
Change in asset retirement obligation
Transfers from E&E assets
Exchange adjustments
Balance at March 31, 2012
Accumulated depletion, depreciation and
impairment losses:
Balance at April 1, 2010
Depletion and depreciation charge
Exchange adjustments
Balance at March 31, 2011
Depletion and depreciation charge
Exchange adjustments
Impairment expense
Balance at March 31, 2012
Net carrying value
At April 1, 2010
At March 31, 2011
At March 31, 2012
Petroleum and
Natural Gas
Properties
$000s
Corporate
Assets
$000s
$
1,726
492
$
196
$
(4)
(46)
2,168
520
2
67
2,705
35
5,497
$
−
196
105
−
−
$
301
$
Petroleum
and Natural
Gas
Properties
$000s
Corporate
Assets
$ 000s
$
$
$
$
$
−
292
(9)
283
383
(2)
311
975
1,726
1,885
4,522
$
$
$
$
$
−
51
51
37
88
196
145
213
Total
$000s
1,922
492
(4)
(46)
2,364
625
2
67
2,705
35
5,798
Total
$000s
−
343
(9)
334
420
(2)
311
1,063
1,922
2,030
4,735
$
$
$
$
$
During the year the Cuisinier 2 and 3 wells were determined by management to be technically feasible
and commercially viable and costs attributed to the wells were transferred from E&E assets to
Development and Production (“D&P”) assets within petroleum and natural gas properties.
The depletion expense calculation included $758,000 in Australia and $684,000 in Canada (March 31,
2011 - $1,288,000 and $699,000) for estimated future development costs associated with proved and
probable reserves.
In the year ended March 31, 2012 there were indicators of impairment for certain Cash Generating
Units (“CGUs”) due to changes in forecasted commodity prices used by the Company’s independent
qualified reserves evaluators when compared to March 31, 2011. Accordingly, the Company tested
certain CGUs for impairment and determined that the aggregate carrying value of the Canadian gas
property at Oak. B.C. was $311,000 higher than the recoverable amount and an impairment was
recorded.
-46-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
The impairment test was based on the net present value of cashflows from oil and gas reserves of the
Oak B.C. CGU at a discount rate of 15%. Consideration was also given to acquisition metrics of recent
transactions on similar assets.
An impairment test was carried out for the Company’s Oak B.C. CGU and was based on the fair value
less costs to sell calculations using the following commodity price estimates.
March 31-2012 Table
B.C. Canwest Plantgate -
($Cdn/mcf)
$
2013
3.00 $
2014
3.68 $
2015
4.20
$
2016
4.59 $
2017
5.07
6. EXPLORATION AND EVALUATION ASSETS (E&E ASSETS)
Percent
increase
per year
to 2023
~5.0%
Balance at April 1, 2010
Additions
Exchange adjustments
Balance at March 31, 2011
Additions
Capitalized share based compensation
E&E impairment loss
Transfer to petroleum and natural gas properties
Exchange adjustments
Balance at March 31, 2012
Exploration and Evaluation
Expenditures
$
$
$
3,553
3,338
173
7,064
10,213
29
(4,194)
(2,705)
119
10,526
Exploration and evaluation assets consist of the Company’s exploration projects in Australia and India
which are pending the determination of technical feasibility and commercial viability. Costs primarily
consist of acquisition costs, geological & geophysical work, seismic and drilling costs.
Exploration and Evaluation Assets
ATP 732P – Tookoonooka
ATP 752P – Barta Block
AC/P 24 – offshore
AC/P 47 – offshore
CY-ONN-2005/1 – onshore
CY-OSN-2009/1 − offshore
Other
March 31, 2011 ($000)
ATP 732P – Tookoonooka
AC/P 47 – offshore
CY-ONN-2005/1 – onshore
CY-OSN-2009/1 − offshore
Other
March 31, 2012 ($000)
India
Total
$
$ 1,183
1,906
2,021
715
490
259
490
$ 7,064
Exploration and Evaluation Assets
490
259
749
$
India
Total
Australia
$ 1,183
1,906
2,021
715
490
$ 6,315
Australia
$ 6,847
810
$
1,751
544
$ 6,847
810
1,751
544
574
$ 10,526
574
$ 8,231
$ 2,295
-47-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
During the year ended March 31, 2012 impairment recognized in profit and loss relates to the
following (2011 - $nil):
AC/P 24
Hudson well Australia
Wompi Block Australia
E&E Impairment charge for year ended March 31, 2012
D&P Impairment charge for the year ended March 31, 2012
Impairment charge for the year ended March 31, 2012
Impairments
3,194
702
298
4,194
311
4,505
$
$
$
The Kingtree well, located on the AC/P 24 permit off the north coast of Australia in the Timor Sea, was
drilled in October of 2011 to evaluate a potential oil target. No commercial hydrocarbons were
encountered and the well has been plugged and abandoned. Due to the result of the Kingtree well, an
assessment was made of all costs attributable to the AC/P24 permit on which the Kingtree well was
drilled. An impairment loss of $3.2 million, equal to all costs associated with the AC/P24 permit, has
been recorded in the year ended March 31, 2012.
In addition to the impairment loss on the AC/P24 permit, impairment losses of $0.7 million have been
recorded in the year ended March 31, 2012 for final costs of an abandoned well drilled in 2008.
The time period in which to complete the seismic work program on the offshore Australia AC/P 47
permit expired on March 2, 2012. At March 31, 2012, the permit has not been relinquished. The
Company has requested an extension to the time period for completing the work progarm from the
National Offshore Petroleum Titles Administrator (NOPTA) to June 2, 2013. If the title to the permit is
relinquished, $0.8 million of exploration and evaluation assets will be impaired in the following year.
7.
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:
Years Ended March 31 ($000s)
Loss before taxes
Statutory tax rate
Expected income tax recovery
Foreign exchange
Stock-based compensation
Effect of change in tax rate & other
Changes in unrecognized tax asset
2012
7,209
26.13%
1,883
74
(261)
(251)
(1,445)
−
$
$
$
2011
3,340
27.63%
923
(307)
(177)
386
(825)
−
$
$
$
-48-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
The temporary deductible differences included in the Company’s unrecognized deferred income tax assets
are as follows:
As of March 31 ($000s)
Non-capital losses
Net capital losses
P&NG properties
Share issue costs
Decommissioning obligations
2012
26,978
5,878
3,566
1,147
228
37,797
$
$
2011
23,150
5,878
1,675
1,546
97
32,346
$
$
Income tax rates changed from 27.63 percent in fiscal 2011 to 26.13 percent in fiscal 2012 due to a
reduction in federal statutory income tax rates.
The components of the Company’s and its subsidiaries deferred income tax liabilities are as follows:
As of March 31 ($000s)
Property, plant & equipment
Foreign exchange
Non-capital losses
2012
3,530
339
(3,869)
−
$
$
2011
1,372
572
(1,944)
−
$
$
At March 31, 2012, the Company had approximately $15.6 million and $24.6 million of non-capital
losses in Canada and Australia respectively (2011 - $11.2 million and $18.3 million), available to reduce
future taxable income. The Canadian non-capital losses expire at various dates from March 31, 2013 to
2032. The Australian non-capital losses have no term to expiry.
The Company has temporary differences associated with its investments in its foreign subsidiaries,
branches, and interests in joint ventures. At March 31, 2012, the Company has no deferred tax liabilities
in respect of these temporary differences.
8. DECOMMISSIONING AND RESTORATION LIABILITY
The total decommissioning and restoration obligations were estimated by management based on the
estimated costs to reclaim and abandon the wells, well sites and certain facilities based on the
Company’s contractual requirements.
Changes to decommissioning and restoration obligations were as follows:
Decommissioning liabilities, beginning of year
Revision
Additions
Expenditures
Accretion
Decommissioning liabilities, end of year
$
$
March 31, 2012 March 31, 2011
115
(4)
43
−
5
159
159
67
−
(3)
5
228
$
$
The Company’s decommissioning liabilities result from ownership interests in petroleum and natural gas
properties. The Company estimates the total inflation adjusted undiscounted amount of cash flows
required to settle its decommissioning and restoration costs at March 31, 2012 is approximately
$283,000 (March 31, 2011 – $204,000) which will be incurred between 2019 and 2026. An inflation
factor ranging between 2.0% and 3.25% and a risk free discount rate ranging between 2.0% and 3.0%
have been applied to the decommissioning liability at March 31, 2012.
-49-
Bengal Energy Ltd.
9. SHARE CAPITAL
(a) Authorized:
Notes to Consolidated Financial Statements
Unlimited number of common shares with no par value.
Unlimited number of preferred shares, of which none have been issued.
(b) Issued:
The following provides a continuity of share capital:
($000s)
Balance at April 1, 2010
Issued on cashless exercise of stock options
Issued on exercise of stock options for cash
Transfer from Contributed Surplus
Shares issued for cash
Share issue costs
At March 31, 2011
Shares issued for cash
Issued on cashless exercise of stock options
Issued on exercise of stock options for cash
Transfer from Contributed Surplus
Share issue costs
$
$
Number of Shares
18,212,783
51,766
5,000
−
19,525,000
37,794,549
14,166,800
73,828
75,000
−
At March 31, 2012
52,110,177
$
Amount
43,460
−
2
17
21,030
(1,914)
62,595
25,500
−
27
146
(2,022)
86,246
In April 2011, the Company issued 14,166,800 common shares at a price of $1.80 per share.
Proceeds of the offering, net of share issue costs of $2,022,000, were $23,478,000.
In October 2011, 75,000 stock options were exercised for $0.36 per share whereby 75,000 common
shares were issued for proceeds of $27,000.
In October 2011, 100,000 stock options with an exercise price of $0.36 and 125,000 stock options
with an exercise price of $1.26 were exercised based on a cashless exercise whereby 73,778
common shares were issued based on a market share price of $1.28 per share on the date of
exercise.
The weighted average share price at the date of exercise in 2012 was $1.28 (2011 - $1.36).
(c) Stock-based compensation - warrants:
The table below provides details of common share purchase warrant activity:
($000s)
Balance April 1, 2010
Share-based compensation expense
Balance March 31, 2011
Transfer to contributed surplus on warrant
expiry
Balance March 31, 2012
Number of Warrants
940,000
-
940,000
(940,000)
-
Amount
490
215
705
(705)
-
$
$
$
These warrants expired on August 13, 2011.
(d) Share-based compensation – stock options:
The Company has a share option plan for directors, officers, employees and consultants 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 three to
five years and vest one-third immediately 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.
-50-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
Bengal 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 immediately. The remaining two instalments are charged to profit or loss over their
respective vesting period of one and two 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:
Outstanding at April 1, 2010
Granted
Expired
Forfeited
Exercised
Outstanding at March 31, 2011
Granted
Forfeited
Expired
Exercised
Outstanding at March 31, 2012
Exercisable at March 31, 2012
Options
1,802,000
660,000
(149,667)
(58,333)
(83,333)
2,170,667
2,420,000
(208,335)
(470,667)
(300,000)
3,611,665
1,895,002
$
Weighted Average
Exercise Price
1.37
1.41
2.19
0.75
0.45
$
$
$
1.38
1.20
1.35
2.68
0.74
1.14
1.08
Options Outstanding
Options Exercisable
Option Price (1)
$ 0.36–1.25
$ 1.26–2.25
Total
Number
Outstanding
2,071,665
1,540,000
3,611,665
Exercise
Price (2)
$ 1.00
$ 1.34
$ 1.14
Remaining
Life (3)
4.3
2.5
3.5
Number
Exercisable
958,334
936,668
1,895,002
Exercise
Price (2)
$ 0.82
$ 1.34
$ 1.08
(1) Range of option exercise prices
(2) Weighted average exercise price of options
(3) Weighted average remaining contractual life of options in years
The fair value of options granted were estimated on the date of grant using the Black-Scholes
option-pricing model with the following weighted average assumptions and resulting values:
For the Year Ended
Assumptions:
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
March 31,
2012
March 31,
2011
2% to 4%
5 yr
68%
6.0%
$0.71
$1.20
2.0%
5 yr
72%
6.4%
$0.70
$1.41
(1)
Expected volatility is estimated by considering historic average share price volatility.
The fair value of stock options granted during the year and quarter ended March 31, 2012 was
$1,710,000 (2011 - $450,000).
-51-
Bengal Energy Ltd.
(e) Loss per share:
Notes to Consolidated Financial Statements
Earnings (loss) per share is calculated based on net loss and the weighted-average number of
common shares outstanding. The Company has recorded a loss in each of the years presented and
therefore any addition to basic shares outstanding is anti-dilutive.
At March 31, 2012, there were 3,611,665 (March 31, 2011 – 2,170,667) options considered anti-
dilutive and at March 31, 2012 there were nil warrants (March 31, 2011 – 940,000) considered anti-
dilutive.
10. 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:
Year ended March 31 ($000s)
Salaries & employee benefits
Stock-based compensation(1)
General & administrative expenses
$
$
2012
905
829
1,734
$
$
2011
913
386
1,299
(1)
Represents the amortization of share based payment expense associated with the Company’s share based compensation
plans granted to key management personnel.
Salaries and benefits for the year ended March 31, 2012 include a non-recurring retirement payment to
former employees of $245,582 (2011 - $230,834).
11. FINANCE EXPENSES
Year ended March 31 ($000s)
Accretion on decommissioning obligations
Performance Security Guarantee fee (1)
Finance expenses
$
$
2012
5
63
68
$
$
2011
5
15
20
(1) Fee paid to Export Development Canada for security guarantee for onshore and offshore India work programs.
12. FINANCIAL RISK MANAGEMENT
The Company has exposure to credit, liquidity and market risk from its use of financial instruments. This
note presents information about the Company’s exposure to these risks, the Company’s objectives and
policies and processes for measuring and managing risk.
The Board of Directors has overall responsibility for identifying the principal risks of the Company and
ensuring the policies and procedures are in place to appropriately manage these risks. Bengal’s
management identifies, analyzes and monitors risks and considers the implication of the market
condition in relation to the Company’s activities.
(a) Fair value of financial instruments:
Financial instruments comprise cash and cash equivalents, restricted cash, accounts receivable
and accounts payable and accrued liabilities. The fair values of these financial instruments
approximate their carrying amounts due to their short-term maturities.
(b) 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, 2012, Bengal’s receivables consisted of $0.6 million (March 31, 2011 - $0.6 million) from
joint venture partners and $0.4 million (March 31, 2011 - $0.2 million) of other trade receivables.
-52-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
Production from the Canadian operations is marketed by the operator. Bengal has not experienced
any collection issues with the operator of the property.
In Australia, production is purchased by a consortium led by one of Australia’s largest public oil and
gas companies which is also the operator of Bengal’s production. Bengal has a Crude Oil Purchase
Agreement with this 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.
At March, 2012, the Company had $0.1 million that were considered past due (past due is
considered greater than 90 days outstanding). Bengal does not have any reason to believe these
receivables will not be collected.
The carrying amount of accounts receivable and cash and cash equivalents represents the
maximum credit exposure. Bengal establishes an allowance for doubtful accounts as determined by
management based on their assessment of collection. Bengal does not have an allowance for
doubtful accounts as at March 31, 2012 and did not provide for any doubtful accounts nor was it
required to write-off any receivables during the year ended March 31, 2012.
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.
(c) 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 accounts payable and
accrued liabilities and amounted to $2.5 million at March 31, 2012 (March 31, 2011 - $2.7 million).
Bengal had $26.9 million in cash (March 31, 2011 - $14.6 million), $0.1 million in restricted cash
(March 31, 2011 - $1.2 million) and working capital of $25.7 million at March 31, 2012 (March 31,
2011 - $14.1 million). All accounts payable and accrued liabilities are payable within one year.
As the Company is in the early stages of exploration and development, and although it is
generating operating revenue, funding of most activities to date has been supplemented through
the issuance of share capital. It is expected that further equity financings, as well as joint ventures
and farm-ins when appropriate, will be used to fund ongoing operations and the Company’s
projected capital program, supplemented by cash flow from operations, working capital and debt,
when the level of operations provides borrowing capacity.
(d) Market risk:
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate
because of changes in market prices. Market risk comprises three types of risk: currency risk,
interest rate risk and other price risk. The Company is exposed to market risks resulting from
fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of
operations. A variety of derivative instruments may be used to reduce exposure to these risks.
-53-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
Foreign Currency Risk
Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate
as a result of changes in foreign exchange rates. Bengal receives Canadian dollars for sales in
Canada, U.S. dollars for Australian oil sales and incurs expenditures in Australian, Canadian and
U.S. currencies. Having sales and expenditures denominated in three currencies spreads the
impact of individual currency fluctuations.
The Company may enter into derivative foreign currency contracts in order to manage foreign
currency exchange rate risk, but has not done so to date.
The table below shows the Company’s exposure to foreign currencies for its financial instruments:
As at March 31, 2012 ($000s)
Cash and short-term deposits
Restricted cash
Accounts receivable
Accounts payable and accrued liabilities
CAD
AUD
U.S.D
17,423
135
158
(1,006)
4,967
4,381
231
(1,432)
623
(17)
A 5% strengthening or (weakening) of the CAD as compared to the AUD and USD would have
increased or (decreased) profit or loss by $10,000 respectively.
Commodity Price Risk
Commodity price risk is the risk that the fair value or 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 Daily Brent reference price, which trades at a premium to WTI. There were no financial
instruments in place to manage commodity prices during the year ended March 31, 2012.
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 is exposed to interest rate risk on its cash and cash equivalents that
have a floating interest rate. The Company is receiving 1.3% interest on its CAD guaranteed
investment certificates at a Canadian chartered bank, 4.9% to 5.6% on AUD term deposits in
Australia and 0.50% to 1.75% on its USD term deposits at ICICI Canada. A 1.0% decrease in
interest rates would have resulted in a $316,000 increase to net loss and cash outflow from
operating activities in the year ended March 31, 2012 and a 1.0% increase in interest rates would
decrease net loss and cash flow used in operating activities by $316,000 over the same period. The
Company had no interest rate derivatives at March 31, 2012.
13. 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.
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,
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.
The Company currently has no debt.
-54-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
In order to maintain or adjust the capital structure, the Company may from time to time issue shares (if
available on reasonable terms), 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. The Company presently does
not have a credit facility in place but based on project viability may arrange separate project financing.
There has been no change in capital management and no externally imposed capital restrictions during
the year.
14. CHANGES IN NON-CASH WORKING CAPITAL
Year ended March 31 ($000s)
Accounts receivable
Prepaid expenses and deposits
Accounts payable and accrued liabilities
Total
Relating to:
Operating
Financing
Investing
Total
$
$
$
$
2012
137
(36)
(189)
(88)
320
(82)
(326)
(88)
$
$
$
$
2011
(544)
8
2,006
1,470
59
77
1,334
1,470
Note – changes in working capital include elements of unrealized foreign exchange differences on
assets and liabilities denominated in a foreign currency.
The following represents the cash interest received in each period.
Year ended March 31 ($000s)
Cash interest received
$
2012
541
$
2011
11
-55-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
15. COMMITMENTS AND CONTINGENCIES
Pursuant to current production sharing contracts (“PSC”), the Company is required to perform minimum
exploration activities that include various types of surveys, acquisition and processing of seismic data
and drilling of exploration wells. The costs of these activities are based on minimum work budgets
included in bid documents and have not been provided for in the financial statements. Actual costs will
vary from budget.
Country and
Permit
Offshore Australia –
AC/P47
Work Program
Obligation
Period Ending
Estimated
Expenditure (net)
(millions CAD$)(1)
750km2 3D seismic
March 2, 2012(2)
Onshore India – CY-
ONN-2005/1
625km2 3D seismic + 75km2 high
resolution 3D seismic + 3 wells
March 3, 2014
Offshore India – CY-
OSN-2009/1
310km 2D seismic & 81km2
3D seismic
August 15, 2014
Onshore Australia –
ATP 752
Drill 3 appraisel wells & 1 exploration
well
July 31, 2014
Onshore Australia –
ATP 732
Scouting, cultural heritage & drilling
preparation. Drill 3 exploration wells
March 31, 2015
Onshore Australia –
ATP 934P
Awaiting completion of Native Title
before granting of ATP(3)
4 years after grant of
ATP
Onshore Australia –
Ideco H-44 Rig
N/A
Purchase and Sale
Agreement signed
April 4, 2012
$7.2
$5.5
$5.3
$4.9
$7.8
$12.1
$2.7
(1) Translated at March 31, 2012 exchange rate of US $1.000 = CAD $0.997 and AUD $1.000 = CAD $1.0354
(2) Bengal has applied for an extension to the time period to complete the scheduled work commitment for this offshore permit to
the National Offshore Petroleum Titles Administrator (NOPTA) to June 2, 2013. The Company has not relinquished the permit
as of the date of these financial statements.
(3) Final application for grant of the permit has been filed with the Queensland Government regulatory authority. No further activity
is planned on this permit until the final Ministerial Grant of the tenement is received. Potential legislative changes may result in
a lower commitment than shown in the table above, The Company holds a 50% operating interest in this permit. Work
program consists of 500 km of 2D seismic and up to seven wells.
At March 31, 2012 the Company had the following lease commitment for office space in Canada and an
equipment yard in Darra, Queensland, Australia:
($000s)
April 2012 to March 2017
Office lease
Darra yard lease
Total
1,242
21
1,263
$
$
$
Less than
1 Year
245
21
266
$
$
$
1-3
Years
491
−
$
$
4-5
Years
506
−
506
$
$
$
After
5 Years
$ −
$ −
$ −
Effective April 1, 2012 the Company has entered into a new head lease in Calgary, Canada for a term
of five years. Effective May 14, 2012 the Company has entered into a equipment yard lease in Darra,
Australia for a term of six months.
16. SUPPLEMENTAL DISCLOSURE
Bengal’s consolidated statement of loss and comprehensive loss is prepared primarily by nature of
expense. All salaries for the Company are included in general and administrative expenses and for the
year ended March 31, 2012 amount to $1,093,000 (2011 - $997,000).
-56-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
17. RELATED PARTY TRANSACTIONS
During the year ended March 31, 2012 the Company paid $73,050 (2011 - $67,260) in consulting fees
to a former director of the Company and to a company controlled by the director. The fees were paid in
the ordinary course of business based on market rates and were for international consulting services
including business development, partner meetings and regulatory matters. At March 31, 2012, the
Company has an accounts payable balance of $5,089 (March 31, 2011 - $41,328) payable to this
former director. At the Company’s Annual General Meeting on September 14, 2011, this director did not
stand for re-election and has been appointed as Executive Vice President of the Company.
18. SUBSEQUENT EVENT
On April 5, 2012 the Company purchased an Ideco H-44 drilling rig. The purchase price of the Rig is US
$1.75 million plus additional costs of approximately US $1.0 million to buy certain ancillary equipment
required for drilling operations. At March 31, 2012 CAD $230,000 in costs had been incurred in relation
to the Rig.
19. SEGMENTED INFORMATION
As at March 31, 2012, the Company has three reportable operating segments being the Australian,
Canadian and India oil and gas operations.
Revenue reported below represents revenue generated from external customers. There were not 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 central administration
costs and 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.
For the year ended March 31, 2012 ($000)
Revenue
Interest revenue
Depletion and depreciation
Net loss
Petroleum and natural gas property
expenditures
Drilling rig expenditures
Exploration and evaluation
expenditures
Impairment losses
March 31, 2012 ($000)
Petroleum and natural gas properties
Cost
Impairment loss
Accumulated depletion,
depreciation and accretion
Net book value
Australia
$ 3,908
291
280
(3,277)
Canada
$
378
292
140
(2,994)
India
$
30
−
(938)
Total
$ 4,286
613
420
(7,209)
$
$
520
−
$
$
105
−
$
$ 230
$
$
625
230
8,667
(4,194)
(311)
1,546
10,213
(4,505)
4,603
−
(405)
4,198
1,195
(311)
(347)
537
−
−
−
2,295
5,798
(311)
(752)
4,735
14,720
(4,194)
10,526
$
$
2,295
$
Exploration and evaluation assets
Accumulated impairment losses
Net book value
12,425
(4,194)
8,231
$
-57-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
For the year ended March 31, 2011 ($000)
Revenue
Interest revenue
Depletion and depreciation
Net loss
Petroleum and natural gas property
expenditures
Exploration and evaluation expenditures
As at March 31, 2011 ($000)
Petroleum and natural gas properties
Cost
Accumulated depletion, depreciation
and accretion
Net book value
Australia
$ 1,298
70
155
(447)
$
Canada
555
46
188
(2,653)
$
India
−
3
−
(240)
Total
$ 1,853
119
343
(3,340)
$
455
3,109
$
37
$
−
229
$
492
3,338
1,328
1,036
(146)
(188)
1,182
848
−
−
−
2,364
(334)
2,030
Exploration and evaluation cost
$ 6,315
$ − $ 749 $ 7,064
20. TRANSITION TO IFRS
These are the Company’s first annual consolidated financial statements prepared in accordance with
IFRS. The impact that the transition from Canadian GAAP to IFRS has had on the Company’s financial
position, financial performance and cash flow is set out in this note.
The significant accounting policies in Note 3 have been applied in the preparaing the consolidated
financial statements for the year ended March 31, 2012, the comparative information presented in these
consolidated financial statements for the year ended March 31, 2011 and in preparation of the opening
IFRS statement of financial position at April 1, 2010 except where certain IFRS 1 exemptions have
been applied as described below.
Exemptions Applied
IFRS 1 First-time Adoption of International Financial Reporting Standards allows first-time adopters
certain exemptions from the general requirement to retrospectively apply IFRS that were effective as at
April 1, 2010. The Company has applied the following exemptions:
IFRS 3 Business Combinations has not been applied to acquisitions that occurred before April 1,
2010.
IFRS 2 Share-based Payment has not been applied to equity instruments which vested before the
Company’s transition date to IFRS.
The deemed cost of exploration and evaluation assets are the amount determined under Canadian
GAAP. For assets in the development or production phases the deemed cost is the amount
determined for the cost centre under Canadian GAAP, allocated to the cost centre’s underlying
assets pro rata using reserve volumes as of April 1, 2010. As a result, the Company measured
asset retirement obligations (“ARO”) in accordance with IAS 37 Provisions, Contingent Liabilities
and Contingent Assets and recognized directly into retained earnings the difference between that
amount and the carrying amount of ARO under Canadian GAAP.
IAS 21 The Company set cumulative translation differences for its foreign operations to zero at
transition.
IFRS 1 also requires that an entity’s estimates under IFRS at the date of transition be consistent
with estimates made under its Canadian GAAP for the same date, unless there is objective
-58-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
evidence that those estimates were made in error. The Company’s IFRS estimates at April 1, 2010
are consistent with the estimates made under Canadian GAAP for that same date.
Reconciliations from Canadian GAAP to IFRS
An explanation of how the transition from Canadian GAAP to IFRS has affected the Company’s
consolidated statements of financial position, statements of operations and comprehensive loss for year
ended March 31, 2011 is set out in the following reconciliations and in the notes that accompany the
reconciliations. Certain amounts on the statements of financial position and the statements of
operations and comprehensive loss have been reclassified to conform to the presentation adopted
under IFRS.
-59-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
Reconciliation of Assets, Liabilities and Equity as reported under Canadian GAAP to IFRS
ASSETS
Current assets
Cash & cash equivalents
Restricted cash
Accounts receivable
Prepaid expenses & deposits
Non-current assets
Petroleum and natural gas properties
Exploration & evaluation assets
Total assets
LIABILITIES & SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable & accrued liabilities
Non-current liabilities
Decommissioning liability
Shareholders’ equity
Share capital
Warrants
Contributed surplus
Accumulated other comprehensive income
Deficit
Total liabilities & shareholders’ equity
Note
CDN GAAP
($)
April 1, 2010
Adj
($)
A
B
B
C
D
1,055
510
273
103
1,941
5,427
7,368
666
666
93
93
43,460
490
3,871
A to D
(41,212)
6,609
7,368
$
$
(3)
(3)
(3,505)
3,553
45
22
22
19
4
23
45
IFRS
($)
1,055
510
273
100
1,938
1,922
3,553
7,413
666
666
115
115
43,460
490
3,890
(41,208)
6,632
7,413
$
-60-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
ASSETS
Current assets
Cash & cash equivalents
Restricted cash
Accounts receivable
Prepaid expenses & deposits
Non-current assets
Petroleum and natural gas properties
Exploration & evaluation assets
Total assets
LIABILITIES & SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable & accrued liabilities
Non-current liabilities
Decommissioning liability
Shareholders’ equity
Share capital
Warrants
Contributed surplus
Accumulated other comprehensive income
Deficit
Total liabilities & shareholders’ equity
Note
A
A
A
A & B
A & B
C
D
A
A to D
CDN GAAP
($)
March 31, 2011
Adj
($)
IFRS
($)
14,623
1,212
817
95
16,747
8,777
25,524
2,672
2,672
138
138
62,595
705
4,280
(44,866)
22,714
$ 25,524
$
(23)
15
(4)
(12)
(6,747)
7,064
305
21
21
14,600
1,227
817
91
16,735
2,030
7,064
25,829
2,672
2,672
159
159
62,595
705
4,189
57
(44,548)
22,998
$ 25,829
(91)
57
318
284
305
-61-
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
Reconciliation of Net Loss for the Year Ended
March 31, 2012
Petroleum and natural gas
Royalties
Revenue
Operating expenses
General and administrative 1
Operating and transportation
Depletion and depreciation B
Pre-licensing and E&E expense B
Share-based compensation D
Total expenses
Operating loss
Other income (expenses)
Finance income
Finance expense 1,C
Foreign exchange gain (loss)
CDN GAAP
$000s
1,853
(181)
1,672
3,277
883
610
641
5,411
Adj
$000s
(19)
(267)
82
(110)
(314)
IFRS
$000s
1,853
(181)
1,672
3,258
883
343
82
531
5,097
(3,739)
314
(3,425)
119
(34)
85
(20)
20
119
(20)
(14)
85
Net Loss
(3,654)
314
(3,340)
Exchange differences on translation of foreign
operations
A
Total comprehensive loss for the year
57
57
(3,654)
371
(3,283)
(1)
For the year ended March 2011 letter of credit charges of $19,000 have been reclassified as finance expenses.
A. Changes in functional currency
Under IAS 21 - The Effects of Changes in Foreign Exchange Rates, the method of determining
functional currency takes into account a broader range of factors than under GAAP. This has
resulted in the functional currency of Avery Resources Australia (Pty) Ltd. changing from the
Canadian dollar to the Australian dollar and the functional currency of Bengal Energy International
Inc. (India) from the Canadian dollar to the U.S. dollar.
As such the value of a number of balance sheet accounts have been revalued with the resulting
impact at April 1, 2010 of a decrease in prepaid expenses and deposits of $3,000 and an increase
in Development and Production (“D&P”) assets of $48,000, offset by a decrease in deficit of
$45,000.
At March 31, 2011, the impact of foreign currency translation resulted in a decrease in cash of
$23,000; increase in restricted cash of $15,000; decrease in prepaid expenses and deposits of
$4,000; increase in Exploration and Evaluation (“E&E”) assets of $83,000 and an increase in D&P
assets of $53,000.
Differences arising from the translation of financial statements that are prepared under a currency
other than the presentation currency of the consolidated financial statements are recognized as a
separate component of equity. The Company has made use of the exemption in IFRS 1 that such
translation differences were deemed zero at the date of transition.
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Bengal Energy Ltd.
Notes to Consolidated Financial Statements
For the year ended March 31, 2011, IFRS transition differences resulted in an exchange gain on
translation of foreign operations of $57,000.
B. Exploration and evaluation assets (“E&E”) (Note the changes in this section must be added
to the changes identified in Note A in order to reconcile to the tables on the prior pages)
IFRS 1 – Deemed Cost. The Company applied the IFRS 1 exemption whereby the value of its
opening plant, property and equipment at April 1, 2010 was deemed to be equal to the net book
value as determined under Canadian GAAP and the corresponding Cash Generating Units
(“CGU’s”) were tested for impairment. The Company chose to allocate its costs to its CGU’s based
on proved plus probable reserve volumes.
Under Canadian GAAP the Company followed the full cost method of accounting for oil and gas
properties whereby all costs associated with the exploration for and the development of oil and gas
reserves were capitalized in country-based cost centers. Under IFRS, pre-exploration costs are
recognized in the statement of operations as incurred. Costs incurred after the legal right to explore
has been obtained and before technical feasibility and commercial viability have been determined
are capitalized as E&E assets. Once an exploration area has been deemed to be technically
feasible and commercially viable, E&E costs are reclassified to development and production assets,
a separate category of property and equipment.
The following reclassifications were made from D&P assets under Canadian GAAP:
At April 1, 2010, $3,553,000 was reclassified from D&P to E&E assets offset by a $48,000 foreign
exchange gain.
At March 31, 2011, a reduction in D&P assets of $7,091,000 with a corresponding increase in E&E
assets of $7,064,000 and $82,000 was charged to the statement of operations relating to pre-
licensing costs.
Depletion and depreciation:
Upon transition to IFRS, the Company adopted a policy of depleting and depreciating oil and
natural gas interests on a unit of production basis over proved plus probable reserves taking into
account the future development costs required to bring those reserves into production. The
depletion and depreciation policy under Canadian GAAP was based on unit of production over
proved reserves.
There was no impact of this difference on adoption of IFRS at April 1, 2010 as a result of the IFRS 1
exemption taken. For the year ended March 31, 2011 the use of proved plus probable reserves
resulted in a decrease to depletion of $267,000 with a corresponding increase to D&P assets.
C. Decommissioning liabilities
Consistent with IFRS, decommissioning obligations (asset retirement obligations under Canadian
GAAP) were measured under Canadian GAAP based on
the
decommissioning, discounted to their net present value upon initial recognition. Under Canadian
GAAP, asset retirement obligations were discounted at a credit adjusted risk free rate of seven to
ten percent. Under IFRS, the estimated cash flow to abandon and remediate the wells and facilities
has been risk adjusted; therefore the provision is discounted at a risk free rate of four percent.
Decommissioning obligations are also required to be re-measured based on changes in estimates
including discount rates.
the estimated cost of
The IFRS 1 exemption was utilized for decommissioning obligation associated with oil and gas
properties and the Company re-measured asset retirement obligations as at April 1, 2010 under IAS
37 with a corresponding adjustment to opening retained deficit. Upon transition to IFRS this resulted
in a $22,000 increase in the decommissioning obligations with a corresponding increase in deficit.
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Bengal Energy Ltd.
Notes to Consolidated Financial Statements
At March 31, 2011, using a risk free rate of four percent the Company increased its
decommissioning obligations by $21,000 from the previous GAAP amount offset by an increase to
D&P assets of $21,000.
The change in accretion expense under IFRS compared with GAAP was not significant. Under
IFRS, accretion of the discount is included in finance expenses whereas under GAAP it is included
in depletion and depreciation.
D. Share-based payment transactions
The Company issues certain share-based awards in the form of stock options that vest one-third on
the grant date and one-third on each of the next two anniversaries of the grant date. Under IFRS,
the fair value of each instalment of the award is considered a separate grant based on the vesting
period with the fair value of each instalment determined separately and recognized as
compensation expense over the term of its respective vesting period (“graded vesting”).
Accordingly, this will result in the amounts of each grant being recognized in income at a faster rate
than under GAAP.
Under GAAP, the Company accounts for forfeited stock options in the period in which the forfeiture
occurred. Under IFRS, the Company estimated forfeitures at the grant date with revised estimates
reflected in each subsequent reporting period. Accordingly, this will result in the amounts of each
grant being recognized in income at a slower rate than under GAAP partially offsetting the impact of
the graded vesting discussed above.
IFRS 1 First-time Adoption of International Financial Reporting Standards (“IFRS 1”) provides an
elective exemption which does not require first-time adopters to apply IFRS 2 Share-based
Payment to equity instruments that were granted on or before November 7, 2002, or equity
instruments that were granted subsequent to November 7, 2002 and vested before the later of the
date of transition to IFRS and January 1, 2005. The Company has used this election.
As a result of this election an increase of $19,000 has been made to contributed surplus with an
offsetting increase in the deficit at April 1, 2010.
Share based compensation decreased by $110,000 for the year ended March 31, 2011. An
increase of $36,000 in share based compensation expense is offset by a decrease in warrant
amortization of $146,000 for the year ended March 31, 2011. These adjustments were offset by a
$110,000 decrease to contributed surplus at March 31, 2011.
E.
Cash flow statement
The transition from Canadian GAAP to IFRS did not have a material impact on the consolidated
statement of cash flows.
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CORPORATE INFORMATION
AUDITORS
KPMG LLP • Calgary, Canada
LEGAL COUNSEL
Burnet, Duckworth & Palmer LLP • Calgary, Canada
Allens Arthur Robinson • Brisbane, Australia
BANKERS
Royal Bank of Canada • Calgary, Canada
West Pac Bank • Brisbane, Australia
Commonwealth Bank • Brisbane, Australia
ICICI Bank Ltd. • Calgary, Canada and Mumbai, India
REGISTRAR AND TRANSFER AGENT
Valiant Trust Corporation • Calgary, Canada
INVESTOR RELATIONS
Bryan Mills Iradesso • Calgary, Canada
DIRECTORS
Chayan Chakrabarty
Peter D. Gaffney
James B. Howe
Stephen N. Inbusch
Dr. Brian J. Moss
Robert D. Steele
Ian J. Towers (Chairman)
W.B.(Bill) Wheeler
DISCLOSURE COMMITTEE
All Directors are members of the Committee
AUDIT COMMITTEE
James B. Howe (Chairman)
Stephen N. Inbusch
Robert D. Steele
W.B.(Bill) Wheeler
RESERVES COMMITTEE
Peter D. Gaffney (Chairman)
Stephen N. Inbusch
Dr. Brian J. Moss
GOVERNANCE AND COMPENSATION COMMITTEE
Peter D. Gaffney
Dr. Brian J. Moss
Robert D. Steele (Chairman)
Ian J. Towers
OFFICERS
Chayan Chakrabarty, President & Chief Executive Officer
Richard N. Edgar, Executive Vice President
Bryan C. Goudie, Chief Financial Officer
D. Garrett Wilson, Vice President, Engineering and Operations
Gordon R. MacMahon, Vice President, Exploration
Bruce Allford, Secretary
STOCK EXCHANGE LISTING – TSX:BNG
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Bengal Energy Ltd.
Suite 1810, 801 – 6th Avenue SW
Calgary, Alberta T2P 3W2
Canada
T: 403.205.2526 F: 403.263.3168
TSX: BNG