Appraisal and Exploration Drilling
with High-Impact Upside
Annual Report | 2013
TABLE OF CONTENTS
1 Message to Shareholders
4
Fiscal 2013 Highlights
5 Management’s Discussion and Analysis
28 Consolidated Financial Statements
34 Notes to Consolidated Financial Statements
61 Corporate Information
Bengal Energy Ltd.
MESSAGE TO SHAREHOLDERS
The 2013 fiscal year was an active and successful period for Bengal, evidenced by the continued
growth in our production, reserves and revenue, as well as the achievement of several important
milestones which further advance our progress and set the stage for expanded development.
In Australia, Bengal continued to focus efforts and capital appraising the Cuisinier oil pool located
on the Barta block in the Cooper Basin, in which we hold a 25% non-operated working interest.
Drilling success continued in Cuisinier through calendar 2012 and into the first half of calendar
2013, with a 100% success rate achieved on all 13 wells drilled to date. This area is an important
driver for the company, offering near-term production volumes and revenue, as well as extensive
future drilling locations to support growth longer term.
Net production volumes averaged 325 barrels of oil equivalent per day (‘boepd’) for the quarter
ending March 31, 2013, an increase of over 215% compared to the same period in 2012, and an
increase of 60% over the 203 boe/d produced in the preceding quarter. The vast majority of those
volumes are from oil production in Cuisinier.
It is anticipated that production volumes will continue
to grow through the balance of calendar 2013, as the five wells drilled in the current year Cuisinier
campaign are tied in. Longer term, production growth is supported by two achievements that
occurred subsequent to the end of the fiscal year. The first was Bengal’s receipt of final approval
of the required lease for the Cuisinier oil pool, which occurred in April 2013, which permits all
current and future Cuisinier wells to produce for up to 21 years. Secondly, the Cuisinier to Cook
liquids pipeline was commissioned in June 2013 and enables production to be delivered to sales
points through a pipeline, rather than trucking, which expands the area’s productive capacity and
facilitates more stable production volumes. These position Bengal very well for future
development and production growth in Cuisinier.
A key driver of value for oil and gas companies stems from their booked reserves. As we
continue to drill, appraise and develop our assets, we anticipate seeing additional activity reflected
in positive revisions to our reserve report. Since our year end falls on March 31, our reserve
evaluation is performed as at that date, which means that none of the 2013 Cuisinier drilling which
occurred subsequent to March 31 will be reflected in the independent evaluation of proved plus
probable reserves performed as at that date. However, we do anticipate undertaking another
reserve evaluation in the fall which will capture that activity. Despite this timing difference,
Bengal’s year-end 2013 corporate proved plus probable (2P) reserves increased 167% relative to
fiscal year end 2012. Based on 2P reserves additions, we successfully replaced approximately
18 times our annual production for the year ending March 31, 2013.
In addition to production and reserves growth, we also realized growth in our revenue, and
importantly, operating netbacks. Netback is an important measure because it helps demonstrate
how much operating cash flow can be generated from each barrel of oil produced. One of the
features that differentiates Bengal from many of our Canadian peers is our realized oil price. Not
only is our oil production in Australia a light, sweet crude which commands the highest price, but
oil prices in Australia are benchmarked off of Brent pricing, rather than the North American
standard of West Texas Intermediate (WTI). During our fiscal year ended March 31, 2013, the
Brent reference price traded at a premium to WTI of nearly US$18, which contributed to attractive
netbacks on our Australian oil production, including netbacks of just under CAD$70/bbl
in the
fourth quarter. The favourable royalty regime in Australia also contributes to higher netbacks, and
Bengal’s royalties are expected to decline on a per boe basis from 2013 levels during the 2014
fiscal year.
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Bengal Energy Ltd.
Message to Shareholders
At Bengal’s Tookoonooka property in Australia, the Company has a 100% working interest in the
block, which offers a portfolio of multi-zone exploration prospects. During the 2013 fiscal year, the
first exploration well in the Tookoonooka drilling campaign, Caracal-1, was drilled and resulted in
a new light oil discovery. Subsequent to the end of the fiscal year, we signed a Binding Letter of
Intent to form a strategic joint venture for the exploration and development of the Tookoonooka
Permit with Australia-based Beach Energy Ltd., a leader in Cooper Basin oil and gas exploration,
development and production. Under the terms of the agreement, Beach will fund the drilling of
two wells and the acquisition of an additional 300 km2 of 3D seismic up to a maximum of
AUD$11.5 million, in return for a 50% interest in the property. This is a significant development
for Bengal, as it will enable us to accelerate exploration and appraisal work in Tookoonooka while
preserving balance sheet strength and benefiting from the experience and expertise of a premium
player in the Cooper Basin.
Bengal also has assets on two blocks in India’s Cauvery Basin, which represent longer term,
future opportunity. Bengal has a 30% working interest in 946 km2 (233,000 acres) onshore at CY-
ONN-2005/1, and a 100% interest in 1,362 km2 (340,000 acres) offshore at CY-OSN-2009/1.
Onshore, Bengal and our joint venture partners, Gas Authority of India Ltd. and Gujarat State
Petroleum Corporation, completed the acquisition of a 3D seismic program of approximately 600
km2 during the 2013 fiscal year and various prospects have been identified. Plans call for the
drilling of three wells on the CY-ONN-2005/1 onshore block to commence before the end of
calendar 2013.
Offshore in the Cauvery basin, evaluation work continues with several play types and prospects
emerging following interpretation of the various 2D and 3D seismic data sets. To accelerate
timing of the drilling of an offshore exploration well, additional seismic data may be acquired in
late 2013 or early 2014. Recent competitor activity in the local area and on offsetting blocks
provides encouragement for Bengal to consider accelerating our activity. As such, Bengal is
seeking a joint venture partner to continue the exploration and appraisal of this asset. We will
continue to closely monitor developments occurring in offsetting blocks for additional activity,
which could include competitors drilling up to three wells by mid calendar 2014, which would
provide data and information that facilitates Bengal’s understanding of the asset.
With the completion of a $3.5 million financing of convertible and non-convertible notes in January
2013, the completion of a $5.7 million equity financing in April 2013, the recent farmout of the
Tookoonooka block, and our growing production and resultant cash flow stream, we believe
Bengal is well positioned to move forward with our near term exploration plans and work program
commitments. Bengal’s sizeable land positions in both Australia and India provide our
shareholders with exposure to oil and gas opportunities that span the spectrum: pure exploration
through to production, booked reserves and cash flow. Not only are Bengal’s assets in politically,
fiscally and economically stable jurisdications, Australia and India both operate under British
Common Law. This means that although Bengal is an interational oil and gas company, many of
the risks that are inherent with so many other junior international operators have been minimized
in Bengal.
Bengal’s growth and evolution is being led by a team of seasoned international exploration
professionals, governed by a top tier board of directors offering a vast array of relevant skills and
experience. Going forward, we are excited by our large portfolio of lower-risk and high-impact
drilling opportunities that have historically produced very attractive netbacks. We will continue
development and appraisal drilling at Cuisinier which is expected to drive near-term and
increasingly positive operating income and set the stage for expanded development. Our recent
exploration success at Tookoonooka has enhanced our confidence about the prospectivity of this
area and our joint venture with Beach has created further momentum. We believe that drilling
activity on our onshore permit in India in late 2013 could lead to additional value creation in 2014
and beyond. While keeping a sharp focus on furthering development of our existing asset base,
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Bengal Energy Ltd.
Message to Shareholders
we will also continue to evaluate potential accretive transactions that may arise in and around
those core areas.
We are pleased to have this opportunity to report on our progress to our shareholders, joint
venture partners and employees, and we thank you once again for your continued support of our
vision.
Sincerely,
Chayan Chakrabarty
President & CEO
Note: this Message to Shareholders contains forward-looking statements and is subject to the forward
looking statement disclaimer in the Management’s Discussion & Analysis for the Years Ended March 31,
2013 and 2012.
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Bengal Energy Ltd.
FISCAL 2013 HGHLIGHTS
During the period the Company experienced the following significant highlights and events:
(cid:120) Cuisinier Drilling 2012 – The Company drilled four oil producers in calendar 2012, resulting in a
cumulative drilling success rate of eight for eight in the non-operated Cuisinier Field in the Cooper
Basin of Australia.
(cid:120)
Petroleum License - On April 8, 2013 the final approval of Petroleum Lease 303 (“PL303”) for the
Cuisinier oil pool was granted. This license allows all current and future Cuisinier wells to produce
for up to 21 years.
(cid:120) Cuisinier Drilling Campaign 2013 – On March 20, 2013, the Company commenced its calendar
2013 Cuisinier drilling program comprising five development and appraisal wells and one contingent
well. This program is designed to optimize pool productivity and to further define ultimate pool size,
with each well targeting the Murta Formation. As of June 14, 2013, all five wells have been drilled
with all being successful and continuing Bengal’s 100% success rate in its Cuisinier drilling
campaign. The most recent Cuisinier well makes it the 13th successful well of 13 drilled to date.
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
The Cuisinier to Cook liquids pipeline was commissioned in June 2013 and production from all
eight Cuisinier wells is flowing through the pipeline at a rate of 350-375 bpd (barrels of oil per day)
net to Bengal. The Operator indicated that further optimization of the system may be available
which could potentially add incremental barrels.
Tookoonooka Drilling – The Company’s first exploration well in the Tookoonooka drilling
campaign, Caracal-1, resulted in a new oil discovery. This discovery established light oil on a new
and unexplored trend on the large 654,335 acre permit. Seismic mapping has defined a large
structure, with the Caracal closure alone estimated to cover an area of 5.5 miles2.
Tookoonooka Farmout – On May 23, 2013, the Company announced that it has signed a Binding
Letter of Intent to form a joint venture for the exploration and development of the Tookoonooka
Permit with Australia-based Beach Energy Ltd. Under the terms of this agreement, Beach will fund
the drilling of two wells in addition to the acquisition of an additional 300 km2 of 3D seismic with a
spending cap of AUD $11.5 million. One of these wells will be a second well in the Caracal area,
with the second well to be situated on the new 3D seismic.
Production averaged 325 boepd in the quarter ending March 31, 2013 and is expected to increase
as the wells drilled in the current year Cuisinier campaign are tied in.
Financial:
Funds flow (non-IFRS measure – see note 2 on page 6) – Funds flow of $1.2 million in the
quarter ended March 31, 2013 compared to a deficiency of $(0.6) million in the prior year
quarter.
Revenue of $3.0 million in the quarter ended March 31, 2013 compared to $0.6 million in the
prior year quarter.
Netback– (non-IFRS measure – see note 2 on page 6) - Australian netback of $72.59/boe
reflects the strength of the Brent benchmark crude oil prices and is an increase of 6% over
$68.81/boe for the previous year.
(cid:120) Reserves – Independent third party year-end reserves evaluation to March 31, 2013 have shown a
167% year-over-year corporate 2P reserves increase, driven by a 260% increase of 2P reserves at
Cuisinier. Based on 2P reserves additions, the Company replaced approximately 18 times its
annual production to March 31 2013. These reserve additions do not reflect the five recently drilled
wells at Cuisinier. Detailed reserves disclosures will be included in Bengal’s 2013 Annual
Information Form to be filed on SEDAR.
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Bengal Energy Ltd.
Management’s Discussion and Analysis
MANAGEMENT’S DISCUSSION AND ANALYSIS – JUNE 14, 2013(cid:71)(cid:71)
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, 2013 and 2012. Bengal’s
financial statements were prepared under International Financial Reporting Standards (“IFRS”). Additional
information relating to the Company, including detailed reserve disclosures, is included in the Company’s
Annual Information Form, which is available on SEDAR at www.sedar.com. The reader should be aware
that historical results are not necessarily indicative of future performance.
Bengal’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.
OUTLOOK
The Company entered fiscal 2014 with increasing production and cash flow, a carried work program on our
Tookoonooka Permit in the Cooper Basin of Australia and a balanced portfolio of exploration and
development drilling opportunities on its extensive land base in Australia and India.
The Company is able to differentiate itself from its Canadian peers in that the netback received for its
Australian oil production has consistently been over $70/bbl. The Brent reference price the Company
receives for its oil sales has traded at an approximate US $18 premium to WTI for the year ended March
31, 2013.
AUSTRALIA – Onshore
Authority to Prospect ("ATP") 752 Barta Block - Cuisinier
In the Barta Block on ATP 752, where Bengal owns a 25% working interest, the Company has drilled five of
six appraisal wells to date as part of its 2013 drilling program. This is as a follow up to the eight successful
exploration and appraisal wells previously drilled. The appraisal wells were drilled directly offsetting existing
producing wells within the Cuisinier field, targeting the Cretaceous Murta member. Each of these well
locations is located on 3D seismic in areas where the seismic attributes are consistent with well-developed
Murta sands.
During the period August to September 2012, all four wells from the 2012 drill campaign were completed as
oil wells and tested. All of these wells as well as the previously equipped Barta North 1 well were tied into
the existing Cuisinier 1 facility. The Cuisinier 1 site was converted to a field satellite where all well
production is produced to and metered. A pipeline from the Cuisinier 1 facility to the neighbouring and
existing Cook production facility was completed, and commissioned in June 2013.
This additional infrastructure allows all fluids to be pipelined to the Cook infrastructure and is expected to
increase run-times for the Cuisinier field.
On April 8, 2013, the final approval of Petroleum Lease 303 (“PL303”) was granted. The Department of
Natural Resources and Mines has granted PL 303 for a term of 21 years commencing on April 8, 2013 and
will allow production from all current and future wells in the Cuisinier oil pool (the “Cuisinier Pool”). PL 303
is 64.4 km
in size.
2
On March 20, 2013, the Company commenced its calendar 2013 Cuisinier drilling program comprising five
development and appraisal wells and one contingent well. Cuisinier 7, the first appraisal well in the 2013
drilling campaign, is located approximately 1,700 metres north 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 10.6
metres of DC70 sandstone developed and an estimated minimum 6.8 metres net pay. The Murta interval
- 5 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
was cored with a total of 23.5 metres of core cut (11.34 metres recovered). As of June 14, 2013, all five
wells have been drilled with all being successful and continuing Bengal’s 100% success rate in its Cuisinier
drilling campaign
In December of 2012 the Operator completed the acquisition of approximately 220 km2 of 3D seismic
immediately north of Cuisinier. This Cuisinier North 3D is intended to evaluate additional Murta formation
targets as well as deeper Jurassic Birkhead and Hutton formations. The Birkhead and Hutton produce at
the Cook field, which is situated 5.9 kilometres to the south east of the Cuisinier field. The Cook Field has
produced over 2.5 million barrels to date.
ATP 732 Tookoonooka Block
The acquisition of approximately 422 line kilometres of 2D and 50 km2 of 3D seismic data at ATP 732
(Tookoonooka Block) was completed early in 2012 with the detailed geological and geophysical
interpretation completed mid-year 2012.
From the seismic interpretation, drill location selection and drilling location preparation were progressed
along with the acquisition of regulatory and environmental approvals from the Queensland and Australian
Governments.
All drill locations were chosen based on their multi-zone potential with as many as three or four prospective
targets per location. The primary target is oil on two locations and both gas and oil on a third location. 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.
The main Permian aged reservoir of interest is the Toolachee Formation sandstone. 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 kilometres west of ATP 732.
The Company initiated exploratory drilling at Tookoonooka in calendar Q3 2012 with the drilling of Caracal
1. The Caracal 1 well was spud on October 5, 2012. Caracal 1 was drilled into a Wyandra Sandstone
amplitude anomaly identified by 3D seismic on a 4-way structural closure up-dip of a hydrocarbon show at
the offsetting Triodia 1. The Wyandra came in 26 metres high to prognosis and 47.4 metres high to the
Triodia well. Good hydrocarbon fluorescence and gas shows were encountered in the upper part of the
Wyandra, along with bleeding oil from the cored interval through in the Wyandra. Logs showed 24.9 metres
gross Wyandra sand with log analysis results indicating 9.5 metres net pay with average 19.1% porosity
and 59.8% water saturation.
Based on the results of oil shows in drill cuttings, gas readings, coring and logging information, Caracal 1
was cased as a potential Wyandra oil well. Subsequent perforation and production testing resulted in a total
swabbed fluid recovery of 5.01 barrels of oil (52° API oil) and 6.3 barrels of completion fluid from the
Wyandra Sandstone. Caracal 1 has been suspended as a future Wyandra oil producer.
In order to accelerate Caracal appraisal and to understand the deeper exploration potential of this very
large block, the Company began looking for a suitable joint venture partner.
On May 23, 2013, the Company announced the signing of a Binding Letter of Intent to form a joint venture
arrangement with Australia-based Beach Energy Ltd. Under the terms of this agreement, Beach will fund
the drilling of two wells as well as the acquisition of an additional 300 km2 of 3D seismic with a cap of AUD
$11.5 million on costs. One of these wells will be a second well in the Caracal area, on the existing 3D with
the second well to be situated on the newly acquired 3D seismic.
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Bengal Energy Ltd.
ATP 934 Barrolka Block
Management’s Discussion and Analysis
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
After extensive technical review internally and technical review by potential farm-in partners, the Company
will not proceed with further exploration capital expenditures. The Company has begun negotiations with
the National Offshore Petroleum Tenure Administrator (NOPTA) in regards to the permit tenure and
effective February 2013 has lodged an application to relinquish this property.
AC/P 24 Block
Bengal has been advised by the operator of the permit at AC/P 24 that an extension request has been
received for the Kingtree prospect and that a retention lease on the Katandra discovery has been received.
A multi-year work program application to commercialize this discovery has been lodged with NOPTA.
India - Onshore
CY-ONN-2005/1 Block
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 completed the acquisition of a 3D seismic program of approximately 600 km2. As well,
airborne magnetometry work was carried out over the permit in association with the seismic program. The
seismic and airborne magnetometry work were intended to help the joint venture define drilling locations on
the permit. A new field oil and gas discovery at North Kovilkalappal approximately 10 kilometres north of
the permit highlights the potential in that northeast part of the permit.
Various prospects have been tabled by the joint venture partners with location selection now being finalized.
Plans call for the drilling of three wells starting in Q3 2013.
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
Interpretation of the various 2D and 3D seismic data sets has been
India’s offshore Cauvery basin.
completed 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 2013 or early 2014 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. In addition, the offsetting block (OIL India Ltd. & ONGC) has seen the acquisition of 3D
seismic over the entire permit (CYN-OSN-2009/2). Further exploration of this block is dependent upon
Bengal acquiring a joint venture partner and a carried interest in this high reward but high cost prospect.
SUMMARY
With the issuance of $3.5 million in Notes in January 2013, completion of a $5.7 million equity financing in
April 2013 and the recent farmout of the Tookoonooka block, the Company believes it is sufficiently
capitalized to undertake its nearer-term exploration plans and fulfill near-term work program commitments
but may require further external capital to fully evaluate the large acreage position the Company holds. The
Company has an attractive and large portfolio of both lower-risk and high-impact drilling opportunities.
- 7 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Development and appraisal drilling planned for the first half of calendar 2013 at Cuisinier on the Barta
permit should drive near-term and increasingly positive operating income for the Company and set the
stage for future expanded development. Recent exploration drilling success on the Tookoonooka Permit
has enhanced the Company’s confidence about the prospectivity on this permit and created further
momentum; with a new joint venture partner, activity will resume later in 2013 on two separate areas of this
large permit. Drilling activity on the Company’s onshore permit in India in late 2013 is designed to
potentially add value in 2014 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.
OPERATING HIGHLIGHTS
$000s except per share, volumes
and netback amounts
Revenue
Oil
Natural gas
Natural gas liquids
Total
Royalties
% of revenue
Operating & transportation
Netback(1)
Cash from (used in) operations:
Per share ($) (basic & diluted)
Funds from (used in) operations:(2)
Per share ($) (basic & diluted)
Net (loss):
Per share ($) (basic & diluted)
Capital expenditures
Volumes
Oil (bpd)
Natural gas (mcfd)
Natural gas liquids (boepd)
Total (boepd @ 6:1)
$
$
$
$
$
$
$
$
2013
2,946
67
-
3,013
271
9.0
694
2,048
119
(0.00)
1,151
0.02
(592)
(0.01)
1,280
287
229
-
325
Three Months Ended
March 31
%
Change
2012
547
59
16
622
56
9.0
312
254
486
0.01
(635)
(0.01)
(1,424)
(0.03)
2,233
50
304
2
103
$
439
14
-
$
$
384
384
-
122
706
(109)
(100)
(270)
(300)
(56)
(67)
(23) $
474
(25)
(100)
216
Twelve Months Ended
March 31
%
Change
2012
3,908
310
68
4,286
394
9.2
1,636
2,256
(1,142)
(0.02)
(1,459)
(0.03)
(7,209)
(0.14)
10,838
90
254
3
135
45
(45)
(35)
37
34
(3)
6
61
(24)
-
(170)
(167)
(75)
(71)
166
53
(29)
(33)
26
$
$
$
$
2013
5,669
172
44
5,885
526
8.9
1,726
3,633
(703)
(0.01)
1,099
0.02
(1,799)
(0.03)
28,381
138
180
2
170
Netback(1) ($/boe)
Revenue
Royalties
Operating & transportation
Total
(1) Netback is a non-IFRS measure. Netback per boe is calculated by dividing the revenue and costs in total for the Company
102.88
9.25
23.70
69.93
86.80
7.97
33.12
45.72
94.95
8.49
27.85
58.61
66.62
6.02
33.33
27.27
54
54
(29)
156
9
7
(16)
28
$
$
$
$
$
$
$
$
by the total production of the Company measured in boe.
(2) Funds from operations is a non-IFRS measure. The comparable IFRS measure is cash from operations. A reconciliation of
the two measures can be found in the table on page 7.
Basis of Presentation
This MD&A and accompanying financial statements and notes are for the twelve months ended March 31,
2013 and 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, 2013 through March 31, 2013. The terms “prior year’s quarter”
and “2012 quarter” are used throughout the MD&A for comparative purposes and refer to the period from
January 1, 2012 through March 31, 2012.
The fiscal year for the Company is the twelve-month period ended March 31, 2013. The terms “fiscal
2013,” “current year” and “the year” are used in the MD&A and in all cases refer to the period from April 1,
2012 through March 31, 2013. The terms “previous year,” “prior year” and “fiscal 2012” are used in the
MD&A for comparative purposes and refer to the period from April 1, 2011 through March 31, 2012. The
term YTD means year-to-date.
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Bengal Energy Ltd.
Management’s Discussion and Analysis
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. This conversion ratio of 6:1 is based on an energy equivalency conversion for the individual
products, primarily at the burner tip, and is not intended to represent a value equivalency at the wellhead.
Such disclosure of boe may be misleading, particularly if used in isolation.
The following abbreviations are used in this MD&A: boepd means barrels of oil equivalent per day; bpd
means barrels per day; mcfd means thousand cubic feet of natural gas per day; $/boe means Canadian
dollars per boe; and NGL means natural gas liquids.
Non-IFRS 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 are referred to as non-IFRS measures. Funds from operations represents cash from operating
activities as presented in the consolidated statement of cash flows and adding back changes in non-cash
working capital and the settlement of decommissioning liabilities. Funds 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 from operations or other
measures of financial performance calculated in accordance with IFRS. Funds from operations, 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 boe is
calculated by multiplying the daily production by the number of days in the period.
The following table reconciles cash flow from operations to funds flow from operations, which is used in the
MD&A:
$000s
Cash flow from (used in) operating activities
Abandonment expenditures
Changes in non-cash working capital
Funds from (used in) operations
RESULTS OF OPERATONS
Production
Three Months Ended
March 31
2012
486
3
(1,124)
(635)
2013
119
-
1,032
1,151
Twelve Months Ended
March 31
2012
(1,142)
3
(320)
(1,459)
2013
(703)
-
1,802
1,099
The following table outlines Bengal’s production volumes for the periods indicated:
Production
Natural gas (mcfd)
NGLs (boepd)
Oil (bbls/d)
Total (boepd)
Three Months Ended
March 31
% Change
2012
304
2
50
103
(25)
(100)
474
216
2013
229
-
287
325
Twelve Months Ended
March 31
% change
2012
254
3
90
135
(29)
(33)
53
26
2013
180
2
138
170
(1) Natural gas and NGL volumes are from the Company’s Oak property in Canada
(2) Oil volumes are from the Company’s Cooper Basin permits in Australia
- 9 -
Bengal Energy Ltd.
Oil production background:
Management’s Discussion and Analysis
(cid:120)
For the twelve months ended March 31, 2012: oil production was mainly from Cuisinier 1, 2 and 3
(C1, C2 and C3).
(cid:120) C1 was shut in January 2012 and C2 and C3 were shut in during August and September of 2012
due to the expiry of their Extended Production Test licenses (EPT).
(cid:120) Cuisinier 4, 5, 6 and Cuisinier North 1 and Barta North 1 all commenced production in late October
2012 (C4, C5, C6, CN1 and BN1).
Oil production increased to 287 bpd in the current quarter compared to 50 bpd in the prior year quarter due
to commencement of production from the current year wells, partially offset by shut in of the C1, C2 and C3.
On April 8, 2013, the final approval of Petroleum Lease 303 (“PL 303”) was granted which will allow all
current and future Cuisinier wells to produce for up to 21 years. Construction of the pipeline from the
Cuisinier 1 facility to the neighbouring and existing Cook production facility has been completed and the
pipeline has been commissioned.
Oil production increased to 138 bpd in the twelve months ended March 31, 2013 compared to 90 bpd in the
prior year period. C1, C2 and C3 produced for most of the prior year period whereas the current year wells
only commenced production in late October 2012 but at higher combined rates than C1, C2 and C3.
The decline in the Company’s Oak B.C. non-operated gas production for the three and twelve months
ended March 31, 2013 is due to natural reservoir declines and shut in of the wells on September 1, 2012,
due to low gas prices. The wells recommenced production on December 3, 2012.
Pricing
The following table outlines average benchmark prices compared to Bengal’s realized prices:
Prices and Marketing
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 ($/mcf)
NGLs ($/bbl)
Oil ($/bbl)
Total ($/boe)
Three Months Ended
March 31
2012 % Change
Twelve Months Ended
March 31
% Change
2012
2013
$
2.52
118.44
1.06
1.00
102.76
$
28
(5)
(1)
-
(7)
$
2.57
110.03
1.03
1.00
$
3.36
113.84
1.04
0.99
$92.22 $ 97.94
(24)
(3)
(1)
1
(6)
2013
$ 3.22
112.43
1.05
1.00
95.76
$ 3.25
-
114.02
102.88
$
2.14
77.37
121.06
66.62
52
331
(6)
54
$ 2.61
57.37
112.84
$ 94.95 $
$
3.33
63.72
119.18
86.80
(22)
(10)
(5)
9
Although realized product prices for the twelve months ended March 31, 2013 decreased, the total
Company realized price on a boe basis increased due to product mix differences (higher gas volumes and
lower oil volumes in the prior period).
Bengal’s total realized price on a boe basis for the twelve months ended March 31, 2013, increased as a
result a higher proportion of oil production in the current year.
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 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 received
has averaged USD $5.14/bbl over Brent for the twelve months ended March 31, 2013.
- 10 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
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. This has resulted in a realized price to
the Company of $2.61/mcf and $3.25/mcf over the last twelve and three months, respectively.
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)
Oil
Natural gas
NGLs
Total
Three Months Ended
March 31
2012 % Change
547
59
16
622
439
14
-
384
2013
2,946
67
-
3,013
Twelve Months Ended
March 31
2012 % Change
3,908
310
68
4,286
45
(45)
(35)
37
2013
5,669
172
44
5,885
(1) Natural gas and NGL sales are from the Company’s Oak property in Canada
(2) Oil sales are from the Company’s Cooper Basin permits in Australia
Petroleum and natural gas sales increased by $2,391,000 in the current quarter to $3,013,000 compared to
$622,000 in the prior year quarter due to increased oil production volumes partially offset by lower gas
production.
YTD revenues increased from the prior year period due to higher oil volumes and offset by lower gas
production and prices.
Royalties
Royalties by Type
($000s)
Canada Crown
Can. gross overriding
Australia
Total
$/boe
% of revenue
Royalties by
Commodity
Natural gas
$000s
$/mcf
% of revenue
Oil
$000s
$/bbl
% of revenue
NGLs
$000s
$/bbl
% of revenue
Three Months Ended
March 31
2012 % Change
(150)
75
430
384
54
-
Three Months Ended
March 31
2012 % Change
2
4
50
56
6.02
9.0
2
0.09
4.1
50
11.10
9.2
4
17.77
23.0
200
289
154
436
(8)
(2)
-
1040
117
2013
(1)
7
265
271
9.25
9.0
2013
6
0.35
10.4
268
10.25
9.0
(1)
202.56
50.0
2013
2
14
510
526
8.49
8.9
2013
7
0.11
4.1
510
10.15
9.0
9
11.54
20.5
2012
20
21
353
394
7.99
9.2
Twelve Months Ended
March 31
% Change
(90)
(33)
45
34
6
(3)
Twelve Months Ended
March 31
% Change
2012
26
0.28
8.4
353
10.75
9.0
15
13.65
21.4
(73)
(61)
(51)
45
(6)
-
(40)
(16)
(4)
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.
- 11 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
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 some of its Oak gas wells.
Royalties have increased in the current quarter compared to the prior year quarter both on a total dollar and
on a boe basis due to increased revenues and a larger proportion of higher royalty rate oil sales in the
overall sales mix.
YTD royalties have also increased both on a total dollar and on a boe basis due to increased revenue and
larger proportion of higher royalty rate oil sales in the overall sales mix, but less than for the current quarter.
Operating & Transportation Expenses
Operating Expenses
($000s)
Australia
Operating
Transportation
Canada – Oper. costs
Total
Australia
Operating - $/boe
Transp. - $/boe
Canada - $/boe
Total ($boe)
2013
92
531
623
71
694
3.56
20.54
20.70
23.70
Three Months Ended
March 31
2012 % Change
37
192
229
83
312
7.86
42.69
17.18
33.33
149
177
172
(15)
122
(55)
(52)
21
(29)
Twelve Months Ended
March 31
% Change
2012
607
693
1,300
336
1,636
18.47
21.15
20.27
33.12
(15)
44
16
(36)
6
(44)
(6)
(10)
(16)
2013
516
996
1,512
214
1,726
10.27
19.83
18.22
27.85
Operating and transportation expenses increased in the current quarter compared to the prior year quarter
mainly as a result of increased oil volumes. Australian operating costs on a boe basis decreased as fixed
operating costs declined per boe as production volumes increased. Canadian operating costs declined due
to lower gas volumes and increased slightly on a per boe basis.
YTD operating and transportation expenses increased compared to the prior year mainly as a result of
increased oil volumes. Australian operating costs on a boe basis decreased as fixed operating costs
declined per boe as production volumes increased. Canadian operating costs declined due to lower gas
volumes.
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 throughout
the Cooper Basin in Australia. The oil is then sent through a pipeline to Port Bonython, South Australia.
General and Administrative (G&A) Expenses
General and Admin.
Expenses ($000s)
G&A
Capitalized G&A
Net G&A
Three Months Ended
March 31
2012
944
-
944
% Change
10
-
(3)
2013
1,036
(120)
916
Twelve Months Ended
March 31
2012
3,585
-
3,585
% Change
13
-
(1)
2013
4,043
(504)
3,539
For the quarter, gross G&A expenses increased $92,000 or 10% to $1,036,000 compared to $944,000 in
the 2012 quarter. The increase is due to higher rents in the current quarter as the Company moved on April
1, 2012 from lower cost sub-let space to new space due to the expiry of the sub-lease, partially offset by
recruiting and IFRS transition costs reflected in the prior year quarter.
- 12 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
YTD gross G&A has increased $458,000 or 13% from the prior YTD period. The increase is due to higher
rent and increased salaries from hiring a Vice President, Engineering and Operations, a Senior Geologist
and a Senior Geophysicist part way through the prior YTD period.
Beginning the second quarter fiscal 2013, the Company initiated capitalizing G&A expenses related to
geological, geophysical and engineering expenses associated with exploration and development activities
concurrent with the Company being operator for the first time and similar expenses associated with its
newly acquired drilling rig.
Share-based Compensation (SBC)
Share-Based Compensation
($000s)
SBC – options
SBC – capitalized
Share-based compensation
Three Months Ended
March 31
2012 % Change
(50)
35
(59)
345
(34)
311
2013
173
(46)
127
2013
687
(200)
487
Twelve Months Ended
March 31
% Change
2012
1,031
(34)
997
(33)
488
(51)
The Company uses the Black-Scholes pricing model to estimate the fair value of options on the date of
grant and amortizes the estimated expense over the vesting period with a corresponding increase to
contributed surplus. Options expire three to 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. Effective with the option grant on
December 21, 2012, vesting occurs one third after the first year and one third on each of the two
subsequent anniversaries.
Capitalized share-based compensation is based on the portion of capitalized fees/salaries to total
fees/salaries paid to consultants and employees that have been granted options.
The decrease in share-based compensation, before capitalization, from $1,031,000 to $687,000 YTD and
$345,000 to $173,000 in the current quarter is a result of having 2,450,000 options granted in the twelve
months ended March 31, 2012 with one third vesting immediately and therefore having one third of their fair
value expensed immediately, whereas for the 1,150,000 options granted in the twelve months ended March
31, 2013, the first one third vest after one year.
Depletion and Depreciation (DD&A)
DD&A Expenses
($000s)
PNG – Australia
PNG – Canada
Subtotal
Rig - Canada
Total
$/boe – PNG Australia
$/boe – PNG Canada
$/boe – Total PNG
Three Months Ended
March 31
Twelve Months Ended
March 31
2012
51
42
93
-
93
% Change
1288
(29)
694
-
694
2013
1,255
120
1,375
73
1,448
11.11
9.45
9.93
146
(7)
154
24.98
10.22
22.18
2012
280
140
420
-
420
8.51
8.47
8.50
% Change
348
(14)
227
-
245
194
21
161
2013
708
30
738
-
738
27.38
8.75
25.20
Depletion per boe increased in Australia due to increases in petroleum and natural gas properties and
future development costs associated with proved and probable reserves at March 31, 2013.
The drilling rig was not utilized in the current quarter and therefore there is no depreciation charge.
- 13 -
Bengal Energy Ltd.
Impairment
Impairment
($000s)
Management’s Discussion and Analysis
Three Months Ended
March 31
2012
416
% Change
99
Twelve Months Ended
March 31
2013
81
2012
4,505
% Change
(98)
2013
829
In the twelve months ended March 31, 2013 the Company reported an $847,000 impairment recovery
against a previously impaired Australian exploration well. This was offset by $103,000 final costs billed for
the Kingtree well drilled and abandoned in October 2011 and $825,000 in costs impaired pursuant to the
surrender of permit AC/P 47.
In the twelve months ended March 31, 2012 the Company reported a $4,194,000 impairment loss against
exploration and evaluation assets and a $311,000 impairment loss against Canadian development and
production assets. The impairment against exploration and evaluation assets related to $3,194,000 of costs
incurred on permit AC/P24 (which were determined to be impaired after drilling the Kingtree well in October
2011), $702,000 of final costs of the abandoned Hudson well drilled in 2008 and $298,000 of costs
pertaining to the Wompi Block.
Finance Income
Finance
Income
($000s)
Three Months Ended
March 31
% Change
(99)
2012
131
2013
167
Twelve Months Ended
March 31
% Change
2012
613
(73)
2013
2
The Company is receiving interest on guaranteed investment certificates and term deposits. The decrease
in interest income is primarily attributable to reduced principal amount of short-term deposits from the prior
year periods.
Finance Expenses
Finance Expenses ($000s)
Accretion expense on
decommissioning liabilities
Accretion expense on notes
Performance Security
Guarantee fee
Interest on notes payable
Finance expenses
Three Months Ended
March 31
Twelve Months Ended
December 31
2013
2012 % Change
2013
2012 % Change
2
59
16
38
115
1
-
18
-
19
100
100
(11)
-
505
7
59
43
38
147
5
-
63
-
68
40
100
(32)
-
116
The Performance Security Guarantee fee is paid to Export Development Canada for security guarantee for
onshore and offshore India work programs. The reduced fee is a result of the work program being partially
fulfilled.
Interest on notes and accretion expense relate to the amortization of the discount on the $3.5 million
convertible and non-convertible notes issued in January 2013.
Funds from (used in) Operations and Net Loss
For the three months ended March 31, 2013 funds from operations were $1,151,000 or $0.02 per basic and
diluted share compared to funds used in operations of $635,000 or $0.01 per basic and diluted share in the
2012 quarter. Funds from operations were $1,099,000 or $0.02 per basic and diluted share for the year
ended March 31, 2013 compared to funds used in operations of $1,462,000 or $0.03 per basic and diluted
share in the prior year. The changes in non-cash working capital are removed from the IFRS measure cash
- 14 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
flow from (used in) operations to arrive at the non-IFRS measure funds from (used in) operations (see
reconciliation on page 7).
The net loss for the three months ended March 31, 2013 was $592,000 or $0.01 per basic and diluted share
compared to a loss of $1,424,000 or $0.03 per basic and diluted share in the 2012 quarter. The reduced
loss was due to increased production in the current quarter. The net loss for the year ended March 31, 2013
was $1,799,000 or $0.03 per basic and diluted share compared to $7,209,000 in the prior year. The prior
year loss included impairment charges of $4,505,000 compared to only $80,000 in the current year.
CAPITAL EXPENDITURES
Capital Expenditures
($000s)
Geological and geophysical
Drilling
Drilling Rig
Completions
Total oil & gas expenditures
Office
Total expenditures
Exploration & evaluation
expenditures
Development & production
expenditures
Property, plant and
equipment
Total net expenditures
$
2013
190
672
23
395
1,280
-
1,280
$
$
$
303
954
23
1,280
Three Months Ended
March 31
% Change
2012
$ 1,984
62
-
82
2,128
105
$ 2,233
(90) $
1,682
NA
382
(20)
NA
(23)
$
Twelve Months Ended
March 31
% Change
(42)
754
NA
155
168
(82)
166
2012
7,277
1,876
-
1,580
10,733
105
10,838
$
2013
4,232
15,595
4,511
4,023
28,362
19
28,381
$ 2,047
(64)
$
16,017
$
10,213
61
186
413
7,853
625
1,156
-
2,233
NA
(23)
4,511
28,381
$
-
$
8,605
NA
186
In the year ended March 31, 2013, the Company incurred seismic expenditures on its onshore India permit
CY-ONN-2005/1 to complete a 575 km2 3D seismic shoot and a 75 square kilometer high resolution 3D
seismic shoot and in Australia to shoot a 220 km2 3D program to the north of the Cuisinier pool on the Barta
Block permit ATP 752.
In the year ended March 31, 2013, drilling and completion expenditures were incurred to drill 5 Cuisinier
appraisal wells and complete, equip and tie-in four of these wells on the Company’s ATP 752 permit. Costs
were also incurred to prepare for the Company’s first operated drilling activities in Australia including
regulatory, health, safety and environmental costs for ATP 732, the Company’s 100% owned permit in the
Cooper Basin. A three well drilling program was initially planned with the first well, Caracal-1, being drilled
and completed at March 31, 2013. On May 23, 2013, the Company announced that it has signed a Binding
Letter of Intent to form a joint venture for the exploration and development of the Tookoonooka Permit with
Australia-based Beach Energy Ltd. Under the terms of this agreement, Beach will fund the drilling of two
wells as well as the acquisition of an additional 300 km2 of 3D seismic up to a maximum cost of AUD $11.5
million to earn a 50% interest in the permit. One of the wells will be a second well in the Caracal area, with
the next well to be situated on the new 3D seismic.
Expenditures of $1,751,000 were incurred to purchase an Ideco H-44 drilling rig. The Company spent a
further $2,760,000 in the year to transport the rig to Australia from its point of purchase, to clear customs, to
buy certain ancillary equipment required for drilling operations and to make the rig ready for use. The rig
was used to drill the Caracal 1 well. The Company continues to work on ways to utilize or monetize the
drilling rig.
CONVERTIBLE AND NON-CONVERTIBLE NOTES
On January 25, 2013 the Company closed a non-brokered private placement (the “Private Placement”) of
$3.5 million short-term, unsecured convertible and non-convertible notes (the “Notes”). The Private
Placement consists of the placement of: (i) $1,750,000 aggregate principal amount of non-convertible notes
- 15 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
(the "Non-Convertible Notes") bearing an interest rate of prime plus 3% per annum and having a term of
180 days; and (ii) $1,750,000 aggregate principal amount of convertible notes (the "Convertible Notes")
bearing an interest rate of prime plus 3% per annum and having a term of 180 days.
SHARE CAPITAL
Bengal has an unlimited number of common shares authorized for issuance. At June 14, 2013, there were
61,610,843 common shares issued and outstanding.
At June 14, 2013, there were 4,030,001 employee stock options outstanding with an average exercise price
of $0.97 per share. Of these, 1,820,000 have vested and are exercisable at an average price of $1.09 per
share. These options expire between December 31, 2013 and December 20, 2017 with an average
remaining life of 3.2 years.
Trading History
High
Low
Close
Volume (000s)
Shares outstanding (000s)
Basic and diluted
Weighted average shares
outstanding (000s)
Basic and diluted
Three Months Ended
March 31
% Change
(33)
(36)
(26)
(5)
2012
1.20
0.78
0.95
3,742
Twelve Months Ended
March 31
% Change
(47)
(32)
(26)
(1)
2012
2.06
0.72
0.95
19,144
2013
1.09
0.49
0.70
18,932
2013
0.80
0.50
0.70
3,560
52,110
52,110
52,110
52,110
-
-
52,110
52,110
52,110
51,488
-
1
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2013 the Company had a working capital deficiency of $1.6 million, including cash and short-
term deposits of $2.6 million and restricted cash of $0.1 million, compared to working capital of $25.7
million, including cash and short term deposits of $26.9 million and restricted cash of $0.1 million at March
31, 2012.
On April 16, 2013, the Company announced that it had closed a brokered private placement (the "Private
Placement") of 9,500,666 common shares of the Company (“Common Shares”) at a price of $0.60 per
Common Share for aggregate gross proceeds of approximately $5,700,400. The Company paid the agents
a cash commission of approximately $282,000, being 6.0% of the gross proceeds of the offering excluding
$1,000,000 of President's list subscriptions.
Certain directors, who are shareholders of the Company, acquired 2,400,300 common shares issued
pursuant to the Private Placement.
Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including work
commitments, as they are due. The Company’s existing cash and cash equivalents and operating cash
flows are expected to be sufficient to meet all of its working capital requirements for the next twelve months
and its commitments under its capital program (see Commitments below).
The Company expects cash generation to increase throughout the coming year as production from
Cuisinier ramps up, although predicting future events, some of which are beyond the Company’s control,
carries uncertainty. Despite the expected increase in cash flow, some external financing would be prudent
to help meet partner drilling commitments and strengthen the Company’s balance sheet. Management is
pursuing a number of alternatives simultaneously that could provide additional capital while, at the same
time, maintaining or enhancing the underlying per share value. These initiatives include farm out
discussions and potential sale of some non-core assets.
- 16 -
Bengal Energy Ltd.
COMMITMENTS
Management’s Discussion and Analysis
Pursuant to current production sharing contracts (“PSC”), the Company is required to perform minimum
exploration activities in its Indian permits that include various types of surveys, acquisition and processing
of seismic data and drilling of exploration wells. Additional commitments are reflected where the Company
has agreed with joint venture partners to proceed with activities (e.g. onshore Australia ATP 752 Cuisinier).
The costs of these activities are based on minimum work budgets included in bid documents and
agreements among joint venture parties, and have not been provided for in the financial statements. Actual
costs will vary from budget.
Country and Permit
Work Program
Obligation
Period Ending
Estimated
Expenditure (net)
(millions CAD$)(1)
Onshore Australia – ATP 752
Cuisinier
Cuisinier to Cook pipeline, facilities
upgrade, drill 5 appraisal wells
April 2013 to March,
2014
Onshore India – CY-ONN-
2005/1
3 wells
March 3, 2014(2)
Offshore India – CY-OSN-
2009/1
310km 2D seismic & 81km2
3D seismic
August 15, 2014(3)
$5.9
$ 4.2
$ 5.3
(1) Translated at March 31, 2013 at an exchange rate of US $1.0000 = CAD $1.0171 and AUD $1.0000 = CAD $1.0594
.
(2) If the Company did not participate in the drilling of 3 wells, costs of $4,312,000 would be impaired and the Company’s interest
in the permit would decline.
(3) The Company is looking for a partner to participate in this permit and share the costs.
Guarantees – India Permits
($000s) CAD
CY-ONN-2005/1 – Onshore India – year 2
CY-OSN-2005/1 – Onshore India – year 3
CY-OSN-2005/1 – Onshore India – year 4
CY-OSN-2009/1 – Offshore India
Total Guarantees
Year Ended
March 31, 2013
(cid:237)
$
836
735
154
1,725
$
Year ended
March 31, 2012
1,104
820
-
151
2,075
$
$
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, 2013, the contractual obligations for which the Company is responsible are as follows:
Contractual Obligations ($000s)
Office lease
Decommissioning obligations
Total contractual obligations
CONTINGENCIES
Total
996
320
Less than
1 Year
245
-
$
1,316
$
245
$
$
1-3
Years
498
64
562
$
$
4-5
Years
253
(cid:237)
After
5 Years
$ (cid:237)
256
253
$
256
$
$
Final application for grant of permit ATP 934 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 below.
The Company holds a 50% operating interest in this permit. Work program consists of 500 kilometres of 2D
seismic and up to seven wells.
- 17 -
Bengal Energy Ltd.
Country and
Permit
Management’s Discussion and Analysis
Work Program
Obligation Period
Ending
Estimated
Expenditure (net)
(millions CAD$)
Onshore Australia –
ATP 934P
Awaiting Ministerial approval before
granting of ATP
4 years after grant of ATP
$ 12.4
RELATED PARTY TRANSACTIONS
On January 25, 2013, the Company closed a non-brokered private placement (the "Private Placement") of
$3.5 million of short-term, convertible and non-convertible notes. Members of the Board of Directors of the
Company subscribed for approximately 85% of the principal amount of the notes issued pursuant to the
Private Placement.
SUBSEQUENT EVENTS
On April 16, 2013 the Company announced that it has closed a brokered private placement of common
shares. The Company issued a total of 9,500,666 Common Shares at a price of $0.60 per Common Share
for aggregate gross proceeds of approximately $5,700,400. The Company paid the Agents a cash
commission of approximately $282,000, being 6.0% of the gross proceeds of the Offering excluding
$1,000,000 of President's list subscriptions. A total of 2,400,300 shares of the Offering were purchased by
insiders of the Company.
On April 18, 2013, the term of the Company’s non-convertible notes was extended from July 24, 2013 to
January 24, 2014. As consideration for the extension of the maturity date, the interest rate payable under
the non-convertible notes was increased to a 10.0% fixed rate per annum from prime plus 3% effective July
25, 2013.
On May 23, 2013, Bengal entered into a Binding Letter of Intent to form a joint venture for the exploration
and development of its 100%-owned Tookoonooka Block (“ATP 732”) in the Cooper Basin of Australia with
Beach Energy Ltd. Beach will fund Bengal’s share of a two-well drilling and 3D seismic exploration and
appraisal work program to a maximum of AUD$11.5 million, in order to acquire a 50% interest in ATP 732.
OFF BALANCE SHEET TRANSACTIONS
The Company does not have any off balance sheet transactions.
SELECTED ANNUAL FINANCIAL INFORMATION
($000s except per share data and prices)
Year Ended March 31
Total production volumes (boepd)
Natural gas prices ($/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 (deficiency)(2)
(1) See “Non-IFRS 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.
- 18 -
2013
170
2.61
112.01
5,885
(1,799)
(0.03)
(703)
(0.01)
1,099
0.02
49,143
(1,647)
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
Bengal Energy Ltd.
Management’s Discussion and Analysis
SELECTED QUARTERLY INFORMATION
(000s, except per
share amounts)
Petroleum and
Mar 31
2013
Dec. 31
2012
Sep. 30
2012
Jun. 30
2012
Mar. 31
2012
Dec. 31
2011
Sep. 30
2011
Jun. 30
2011
natural gas sales
$
3,013
$ 1,937
$
437
$
498
$
622
$ 1,328
$ 1,017
$
1,319
$
$
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
Capital expenditures
Working capital
(deficiency)
Total assets
Shares outstanding
Basic and diluted
Operations
Average daily
production
Natural gas (mcfd)
Oil and NGLs
(bbls/d)
Combined (boepd)
Netback ($/boe)
119
(378)
(0.00)
(0.01)
315
0.01
(759)
(0.01)
486
(417)
159
(1,371)
0.01
(0.01)
0.00
(0.03)
1,151
481
(471)
(62)
(635)
(402)
(430)
7
0.02
(592)
$
0.01
(151) $
(0.01)
(845) $
0.00
(211)
(0.01)
$ (1,424) $
0.00
(477)
(0.01)
0.00
$ (4,247) $ (1,061)
(0.01)
1,281
(0.00)
$ 9,475
(0.02)
$ 10,299
0.00
$ 7,326
(0.03)
(0.01)
2,233 $ 4,265
$
$
(0.08)
2,407
$
(0.02)
1,933
(1,647)
49,143
(1,436)
47,584
7,578
46,557
18,425
44,484
25,722
43,696
28,798
44,899
33,109
45,696
35,691
51,072
52,110
52,110
52,110
52,110
52,110
52,110
51,961
51,961
229
287
325
69.93
110
159
225
185
203
$ 60.92
38
65
$ 40.07
51
89
$ 24.51
304
52
103
$ 27.27 $
271
196
249
112
157
49.89
97
130
$ 51.42
$
110
152
48.92
(1) See “Non-IFRS Measurements” on page 7 of this MD&A.
Beginning in the quarter ended March 31, 2011 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 beginning in January 2012 were impacted by the temporary shut in of Cuisinier 1 on
January 13, 2012 and Cuisinier 2 and 3 in August and September 2012 while the Company waited for
approval of a Production License. Oil volumes increased in the quarter ended December 31, 2012 due to
commencement of production from Cuisinier 4, 5, 6 and Cuisinier North 1 and Barta North 1 in October
2012 and continued into the quarter ended March 31, 2013. These wells were drilled in mid 2012 and
started producing under a six month Extended Production Test in October 2012. On April 8, 2013 a
production license was obtained for all current and future Cuisinier wells for a 21 year production period. In
early June 2013 the Cuisinier to Cook pipeline commenced operation allowing for all eight Cuisinier to
produce.
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. Gas volumes also declined in the
quarter ended June 30, 2012 due to the removal of a rental screw compressor (due to low gas prices and
the cost of the rental plus associated maintenance) and an unscheduled plant shutdown at the Oak property
due to a leak in the line to the flare stack. Gas volumes declined in the quarter ended September 30, 2012
as the Company’s Oak B.C. gas property was shut in due to low gas prices. This property recommenced
production in December 2012.
- 19 -
Bengal Energy Ltd.
FINANCIAL INSTRUMENTS
Management’s Discussion and Analysis
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 IFRS. Bengal’s certifying officers have assessed the design and operating
effectiveness of internal controls over financial reporting and concluded that the Company’s ICFR were not
effective at March 31, 2013 due to the material weaknesses noted below.
No changes in internal controls over financial reporting were identified during the period that have materially
affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.
While Bengal’s Chief Executive Officer and Chief Financial Officer believe the Company’s internal controls
and procedures provide a reasonable level of assurance that they are reliable, an internal control system
cannot prevent all errors and fraud. It is management’s belief that any control system, no matter how well
conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the
control system are met.
During the design and operating effectiveness assessment certain material weaknesses in internal controls
over financial reporting were identified, as follows:
(cid:120) 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;
- 20 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
(cid:120)
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 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.
a)
Identification of Cash-generating Units
Bengal’s assets are aggregated into cash-generating units, for the purpose of calculating impairment, based
these estimates and
on their ability to generate largely independent cash flows. By their nature,
assumptions are subject to measurement uncertainty and may impact the carrying value of the Company's
assets in future periods.
b)
Impairment Indicators
Judgements are required to assess when impairment indicators exist and impairment testing is required.
The application of the Company’s accounting policy for exploration and evaluation assets required
management to make certain judgements as to future events and circumstances as to whether economic
quantities of reserves have been found.
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.
a) 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.
- 21 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
b)
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.
c)
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 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.
d) Reserves
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.
e) 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.
NEW ACCOUNTING STANDARDS AND PRONOUNCEMENTS
Standards that are issued but not yet effective and that the Company reasonably expects to be applicable
at a future date are listed below.
IFRS 9 – Financial Instruments. IFRS 9, as issued, reflects the first phase of the IASB’s work on the
replacement of IAS 39 and applies to classification and measurement of financial assets as defined in IAS
39. The standard is effective for annual periods beginning on or after January 1, 2015. In subsequent
phases, the IASB will address classification and measurement of financial liabilities, hedge accounting and
derecognition.
IFRS 10 – Consolidated Financial Statements. IFRS 10 requires an entity to consolidate an investee when it
is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to
affect those returns through its power over the investee. IFRS 10 replaces SIC-12 Consolidation – Special
- 22 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Purpose Entities and parts of IAS 27 Consolidated and Separate Financial Statements. The standard is
effective for annual periods beginning on or after January 1, 2013.
IFRS 11 – Joint Arrangements. IFRS 11 requires a venture to classify its interest in a joint arrangement as a
joint venture or a joint operation. Joint ventures will be accounted for using the equity method of accounting
whereas for a joint operation a venture will recognize its share of the assets, liabilities, revenue and
expenses of the joint operation. IFRS 11 supersedes IAS 31 Interests in Joint Ventures and SIC-13 Jointly
Controlled Entities – Non-Monetary Contributions by Venturers. The standard is effective for annual periods
beginning on or after January 1, 2013.
IFRS 12 – Disclosure of Interests in Other Entities. IFRS 12 applies to entities that have an interest in a
subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. This standard is
effective for annual periods beginning on or after January 1, 2013.
IFRS 13 – Fair Value Measurements. IFRS 13 defines fair value, sets out a single IFRS framework for
measuring value and requires disclosure about fair value measurements. IFRS 13 applies to IFRS’s that
require or permit fair value measurements or disclosures about fair value measurement, except in specified
circumstances. The standard is effective for annual periods beginning on or after January 1, 2013.
RISK FACTORS
Companies engaged in the oil and gas industry are exposed to a number of business risks which can be
described as operational, financial and political risks, many of which are outside of the Company’s control.
More specifically, these include risks of economically finding reserves and producing oil and gas in
commercial quantities, marketing the production, commodity prices, environmental and safety risks, and
risks associated with the foreign jurisdiction in which the Company operates. In order to mitigate these risks,
the Company has an experienced base of qualified technical and financial personnel in both Canada and
Australia. Further, the Company has focused its foreign operations and plans to target future foreign
operations in known and prospective hydrocarbon basins in jurisdictions that have previously established
long-term oil and gas ventures with foreign oil and gas companies.
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.
- 23 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that
are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other
costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and
operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of
operations, and various field operating conditions may adversely affect the production from successful
wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of
connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or
other geological and mechanical conditions. While diligent well supervision and effective maintenance
operations can contribute to maximizing production rates over time, production delays and declines from
normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and
cash flow levels to varying degrees.
In addition, oil and gas operations are subject to the risks of exploration, development and production of oil
and natural gas properties, including encountering unexpected formations or pressures, premature declines
of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence
of any of these risks could have a materially adverse effect on future results of operations, liquidity and
financial condition.
Bengal attempts to minimize exploration, development and production risks by utilizing a high-end technical
team with extensive experience and multidisciplinary skill sets to assure the highest probability of success
in its drilling efforts. Bengal’s collaboration of a team of seasoned veterans in the oil and gas business, each
with a unique expertise in the various upstream to downstream technical disciplines of prospect generation
to operations, provides the best assurance of competency, risk management and drilling success. A full
cycle economic model is utilized to evaluate all hydrocarbon prospects. Detailed geological and geophysical
techniques are regularly employed including 3D seismic, petrography, sedimentology, petrophysical log
analysis and regional geological evaluation.
Risks Associated with Foreign Operations
International operations are subject to political, economic and other uncertainties, including, among others,
risk of war, risk of terrorist activities, border disputes, expropriation, renegotiations or modification of
existing contracts, restrictions on repatriation of funds, import, export and transportation regulations and
tariffs, taxation policies, including royalty and tax increases and retroactive tax claims, exchange controls,
limits on allowable levels of production, currency fluctuations, labor disputes, sudden changes in laws,
government control over domestic oil and gas pricing and other uncertainties arising out of foreign
government sovereignty over the Company's international operations. With respect to taxation matters, the
governments and other regulatory agencies in the foreign jurisdictions in which Bengal operates and
intends to operate in the future may make sudden changes in laws relating to taxation or impose higher tax
rates, which may affect Bengal’s operations in a significant manner. These governments and agencies may
not allow certain deductions in calculating tax payable that Bengal believes should be deductible under
applicable laws or may have differing views as to values of transferred properties. This can result in
significantly higher tax payable than initially anticipated by Bengal. In many circumstances, readjustments to
tax payable imposed by these governments and agencies may occur years after the initial tax amounts
were paid by Bengal, which can result in the Company having to pay significant penalties and fines.
Furthermore, in the event of a dispute arising from international operations, the Company may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the
jurisdiction of courts in Canada.
Prices, Markets and Marketing of Crude Oil and Natural Gas
Oil and natural gas are commodities that have prices determined based on world demand, supply and other
factors, all of which are beyond the control of Bengal. World prices for oil and natural gas have fluctuated
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
- 24 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
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
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
- 25 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
Bengal. The occurrence of a significant event that Bengal is not fully insured against, or the insolvency of
the insurer of such event, could have a material adverse effect on Bengal’s financial position, results of
operations or prospects.
Competition
Bengal actively competes for reserve acquisitions, exploration leases, licenses and concessions and skilled
industry personnel with a substantial number of other oil and gas companies, many of which have
significantly greater financial and personnel resources than Bengal. Bengal's competitors include major
integrated oil and natural gas companies and numerous other independent oil and natural gas companies
and individual producers and operators.
Bengal’s ability to successfully bid on and acquire additional property rights, to discover reserves, to
participate in drilling opportunities and to identify and enter into commercial arrangements with customers
will be dependent upon developing and maintaining close working relationships with its future industry
partners and joint operators and its ability to select and evaluate suitable properties and to consummate
transactions in a highly competitive environment.
ADDITIONAL INFORMATION
is filed on SEDAR and can be viewed at www.sedar.com.
Additional information relating to Bengal
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:
(cid:129)
(cid:404)
(cid:404)
(cid:404)
(cid:404)
(cid:404)
(cid:404)
(cid:404)
(cid:404)
(cid:404)
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 and whether 3 wells will be drilled on this block by March 2014;
Commencement of exploration and development activities on Block CY-OSN-2009/1;
- 26 -
Bengal Energy Ltd.
Management’s Discussion and Analysis
(cid:404)
(cid:404)
(cid:404)
Obtaining Ministerial Grant of the tenement on ATP 934P in Australia and commencement of exploration
activities;
That Beach Energy will perform the work agreed to under the Farm-out and that further drilling activities on
ATP 732P will occur;
That the five wells drilled on ATP 752P in calendar Q1 and Q2 of 2013 will be completed and tied-in and that
these wells will commence production and that production from all wells will continue as expected and that a
sixth Cuisinier well will be drilled as part of the current year drilling program.
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:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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.
- 27 -
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, 2013. 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
- 28 -
Bengal Energy Ltd.
Consolidated Financial Statements
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, 2013 and March 31, 2012, the
consolidated statements of loss and comprehensive loss, changes in equity and cash flows for the years
then ended, 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, 2013 and March 31, 2012, and its consolidated
financial performance and its consolidated cash flows for the years ended March 31, 2013 and March 31,
2012 in accordance with International Financial Reporting Standards.
Chartered Accountants
June 17, 2013
Calgary, Canada
- 29 -
Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Thousands of Canadian dollars)
As at March 31,
Notes
2013
2012
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Prepaid expenses and deposits
Non-current assets:
Exploration and evaluation assets
Petroleum and natural gas properties
Property, plant and equipment
Total assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Convertible & non-convertible notes payable
Non-current liabilities:
Decommissioning liability
Shareholders’ equity:
Share capital
Contributed surplus
Equity component convertible debenture
Accumulated other comprehensive income
Deficit
Total liabilities and shareholders’ equity
5
6
7
8
10
11
12
10
$
$
$
$
$
$
2,614
140
3,550
110
6,414
26,416
11,630
4,683
42,729
49,143
4,622
3,439
320
86,246
6,466
25
1,581
(53,556)
40,762
49,143
$
$
$
$
$
26,934
135
1,009
127
28,205
10,526
4,735
230
15,491
43,696
2,483
(cid:237)
228
86,246
5,779
-
717
(51,757)
40,985
43,696
Commitments and contingencies (note 18)
Subsequent event (note 8, 21)
See accompanying notes to the consolidated financial statements.
On behalf of the Board:
Director
Chayan Chakrabarty
Director
James B. Howe
- 30 -
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,
Notes
Income
Petroleum and natural gas revenue
Royalties
Operating expenses
General and administrative
Operating and transportation
Depletion and depreciation
Pre-licensing & impairment
Exploration & evaluation expenses
Share-based compensation
Operating loss
Other income (expenses)
Finance income
Finance expenses
Foreign exchange gain (loss)
Loss before income tax
Deferred income tax recovery
Net loss
Exchange differences on translation of foreign operations
Total comprehensive loss for the year
Loss per share
- Basic & Diluted
Weighted average number of shares outstanding (000s)
- Basic & Diluted
See accompanying notes to the consolidated financial statements.
7,8
6
14
10
12
12
2013
5,885
(526)
5,359
3,466
1,726
1,448
80
(cid:237)
487
7,207
(1,848)
167
(133)
7
41
(1,807)
8
(1,799)
864
(935)
(0.03)
$
$
$
2012
4,286
(394)
3,892
3,585
1,636
420
4,505
292
997
11,435
(7,543)
613
(68)
(211)
334
(7,209)
-
(7,209)
660
(6,549)
(0.14)
$
$
$
52,110
51,488
- 31 -
Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Thousands of Canadian dollars)
Shares
outstanding
Share
capital Warrants
Contributed
surplus
Equity
component of
convertible
debentures
Accumulated
other
comprehensive
income
Total
shareholders’
equity
Deficit
37,794,549
$
62,595
$ 705
$
4,189
$
(cid:237)
$
57
$
(44,548)
$22,998
-
-
-
-
14,315,628
23,651
-
-
-
-
-
-
-
-
-
(705)
-
-
-
(146)
705
997
34
-
-
-
-
-
-
-
(7,209)
(7,209)
660
-
-
-
-
-
-
660
23,505
-
997
34
52,110,177
$
86,246
$
(cid:237)
$
5,779
$
(cid:237)
$
717
$ (51,757)
$
40,985
52,110,177
$
86,246
$
(cid:237)
$
5,779
$
(cid:237)
$
717
$ (51,757)
$ 40,985
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
487
200
-
-
-
-
-
25
-
(1,799)
(1,799)
864
-
-
-
864
487
200
25
-
-
-
52,110,177
$
86,246
$
(cid:237)
$
6,466
$
25
$
1,581
$ (53,556)
$ 40,762
Balance at
April 1, 2011
Net loss for the period
Comprehensive loss for
the period
Issue of share capital
(Note 12)
Expiry of warrants
Share-based
compensation –
expensed
Share-based
compensation –
capitalized
Balance at
March 31, 2012
Balance at
April 1, 2012
Net loss for the period
Comprehensive income
for the period
Share-based
compensation –
expensed
Share-based
compensation –
capitalized
Convertible notes issued
Balance at
March 31, 2013
See accompanying notes to the consolidated financial statements.
- 32 -
Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Canadian dollars)
For the years ended March 31,
Notes
2013
2012
Operating activities
Net loss for the year
Non-cash items:
Depletion and depreciation
Pre-licensing & impairment
Accretion on decommissioning liability
Accretion on note payable
Share-based compensation
Deferred income tax recovery
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
Proceeds from issuance of Notes
Changes in non-cash working capital
Net cash from financing activities
Impact of foreign exchange
on cash and cash equivalents
$
(1,799)
$
(7,209)
1,448
927
7
45
487
(8)
(8)
1,099
(cid:237)
(1,802)
(703)
(16,017)
(7,853)
(4,511)
(5)
1,107
(27,279)
(cid:237)
3,461
38
3,499
163
17
17
17
420
4,505
5
-
997
-
(177)
(1,459)
(3)
320
(1,142)
(10,213)
(625)
(230)
1,092
(326)
(10,302)
23,505
(cid:237)
(82)
23,423
355
12,334
14,600
26,934
Net (decrease) 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.
$
(24,320)
26,934
2,614
$
$
$
- 33 -
Bengal Energy Ltd.
BENGAL ENERGY LTD.
Notes to Consolidated Financial Statements (the “financial statements”)
Three and twelve months ended March 31, 2013 and 2012
(Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)
1.
REPORTING ENTITY:
Bengal Energy Ltd (the “Company” or “Bengal”) is incorporated under the laws of the Province of
Alberta and is involved in the exploration for and development of oil and gas reserves in Australia,
India and Canada. The consolidated financial statements (the “financial statements”) of the Company
as at March 31, 2013 and 2012 and for the years ended March 31, 2013 and 2012 are comprised of
the Company and its wholly owned subsidiaries Bengal Energy International Inc. and Bengal Energy
(Australia) Pty Ltd. which are incorporated in Canada and Australia respectively. The Company
conducts many of its activities jointly with others; these financial statements reflect only the
Company’s proportionate interest in such activities.
Bengal’s principal place of business and registered office is located at 1810, 801 6th Ave SW,
Calgary, Alberta, Canada, T2P 3W2.
2. BASIS OF PREPARATION
a) Statement of compliance
These consolidated financial statements have been prepared in accordance with International
Financial Reporting Standards (IFRS) as issued by the International Accounting Standards
Board (IASB).
The consolidated financial statements were approved and authorized for issuance by the Board
of Directors on June 14, 2013.
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.
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.
(a) Basis of consolidation:
The consolidated interim financial statements incorporate the financial statements of the
Company and its 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.
- 34 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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 period end date. Subsequent to
the initial measurement, the obligation is adjusted at the end of each period to reflect the passage
of time and changes in the estimated future cash flows underlying the obligation. The increase in
finance costs whereas
the provision due
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.
is recognized as
the passage of
time
to
(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
- 35 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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%.
(f) Property and equipment – drilling rig
Recognition and measurement
Initial costs related to the acquisition or construction of property and equipment are capitalized
and accumulated by rig or a component thereof.
Subsequent to initial recognition, items of property and equipment are measured at cost less
accumulated depreciation and accumulated impairment losses. When significant parts of an item
- 36 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
of property and equipment have different useful lives, they are accounted for as separate items
(major components).
Subsequent costs are included in the related asset’s carrying amount or recognized as a separate
asset, as appropriate, only when is it probable that future economic benefits associated with the
item will flow to the group and the cost of the item can be measured reliably. All other repairs and
maintenance are recorded in profit and loss.
Gains and losses on disposal of an item of property and equipment are determined by comparing
the proceeds from disposal with the carrying amount of property and equipment and are
recognized in profit and loss.
Depreciation
The net carrying value of drilling and workover rig components is depreciated using the unit of
production method so as to depreciate the cost, less an estimated residual value of 5%, over the
days in which the rig components are expected to be utilized during its useful life. Utilization days
for depreciation purposes exclude initial mobilization, inter-well moves and final demobilization.
The estimated useful lives for certain rig components:
Mast and substructure
Draw works, rig & carrier power, genset, small wellsite office, storage containers
Mud tanks & mud pumps, vehicles, various small tools & handling tools,
HSE equipment
Rebuild, inspections, re-certifications
6,500 days
5,000 days
3,000 days
1,000 days
Useful lives and the depreciation methods are examined on an annual calendar basis and
adjustments, where applicable, are made on a prospective basis.
(g) Impairment
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 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.
- 37 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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.
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.
(h) 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
- 38 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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.
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
- 39 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
common shares and stock options are recognized as a deduction from equity, net of any tax
effects.
(i) Convertible redeemable note:
Convertible notes can be converted into share capital at the option of the holder and the number
of shares to be issued is dependent on the conversion price. The conversion price is equal to the
lower of the market price of the Common Shares as of the date of issuance of the Convertible
Note ($0.56/share) and the market price of the Common Shares as of the applicable Conversion
Date. The liability component of the convertible note is recognized initially at the fair value of a
similar liability that does not have an equity conversion option. The equity component is
recognized initially as the difference between the fair value of the convertible note as a whole and
the fair value of the liability component. Any transaction costs are allocated to the liability and
equity components in proportion to their initial carrying amounts. The liability component accretes
up to the principal balance at maturity with accretion expense included in finance cost on the
statement of loss and comprehensive loss. The equity component will be reclassified to share
capital on conversion. Any balance in equity that remains after the settlement of the liability is
transferred to contributed surplus. The equity portion is recognized net of deferred taxes. The
equity component is not re-measured subsequent to initial recognition.
(j) 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.
(k) 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.
(l) 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.
(m) 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
- 40 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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.
(n) Income taxes:
Income tax expense comprises current and deferred tax. Income tax expense is recognized in
profit or loss except to the extent that it relates to items recognized directly in equity, in which
case it is recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates
enacted or substantively enacted at the reporting date, and any adjustments to tax payable in
respect of previous years.
Deferred tax is recognized providing for temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for taxation purposes.
Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that
is not a business combination. In addition, deferred tax is not recognized for taxable temporary
differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates
that are expected to be applied to temporary differences when they reverse, based on the laws
that have been enacted or substantively enacted by the reporting date. Deferred tax assets and
liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes
levied by the same tax authority on the same taxable entity, or on different tax entities, but they
intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will
be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be
available against which the temporary difference can be utilized. Deferred tax assets are reviewed
at each reporting date and are reduced to the extent that it is no longer probable that the related
tax benefit will be realized.
(o) 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 Government of India and accretion of the discount on decommissioning
obligations.
(p) 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) 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, 2013 and March 31, 2012 the fair
value of these balances approximated their carrying value due to their short term to maturity.
- 41 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
2) 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
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).
(q) New standards and interpretations not yet adopted:
Standards that are issued but not yet effective and that the Company reasonably expects to be
applicable at a future date are listed below.
IFRS 9 – Financial Instruments. IFRS 9, as issued, reflects the first phase of the IASB’s work on
the replacement of IAS 39 and applies to classification and measurement of financial assets as
defined in IAS 39. The standard is effective for annual periods beginning on or after January 1,
2015. In subsequent phases, the IASB will address classification and measurement of financial
liabilities, hedge accounting and derecognition.
IFRS 10 – Consolidated Financial Statements. IFRS 10 requires an entity to consolidate an
investee when it is exposed, or has rights, to variable returns from its involvement with the
investee and has the ability to affect those returns through its power over the investee. IFRS 10
replaces SIC-12 Consolidation – Special Purpose Entities and parts of IAS 27 Consolidated and
Separate Financial Statements. The standard is effective for annual periods beginning on or after
January 1, 2013.
IFRS 11 – Joint Arrangements. IFRS 11 requires a venture to classify its interest in a joint
arrangement as a joint venture or a joint operation. Joint ventures will be accounted for using the
equity method of accounting whereas for a joint operation a venture will recognize its share of the
assets, liabilities, revenue and expenses of the joint operation. IFRS 11 supersedes IAS 31
Interests in Joint Ventures and SIC-13 Jointly Controlled Entities – Non-Monetary Contributions
by Venturers. The standard is effective for annual periods beginning on or after January 1, 2013.
IFRS 12 – Disclosure of Interests in Other Entities. IFRS 12 applies to entities that have an
interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity.
This standard is effective for annual periods beginning on or after January 1, 2013.
IFRS 13 – Fair Value Measurements. IFRS 13 defines fair value, sets out a single IFRS
framework for measuring value and requires disclosure about fair value measurements. IFRS 13
applies to IFRS’s that require or permit fair value measurements or disclosures about fair value
measurement, except in specified circumstances. The standard is effective for annual periods
beginning on or after January 1, 2013.
4. MANAGEMENT JUDGEMENTS AND ESTIMATES
The timely preparation of the financial statements requires management to make judgements,
estimates and assumptions that affect the application of accounting policies and reported
amounts of assets and liabilities and income and expenses. Accordingly, actual results may
differ from these estimates. 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.
- 42 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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.
i.
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.
ii.
Impairment Indicators
Judgements are required to assess when impairment indicators exist and impairment testing is
required. The application of the Company’s accounting policy for exploration and evaluation
assets required management to make certain judgements as to future events and circumstances
as to whether economic quantities of reserves have been found.
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.
- 43 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
iii) 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 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.
iv) Reserves
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.
v) 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.
- 44 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
5. 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, 2013
2,614
-
2,614
$
$
March 31, 2012
3,864
23,070
26,934
$
6. EXPLORATION AND EVALUATION ASSETS (E&E ASSETS)
($000s)
Exploration and Evaluation
Expenditures
Balance at April 1, 2011
Additions
Capitalized share based compensation
E&E impairment loss
Transfer to petroleum and natural gas properties
Exchange adjustments
Balance at March 31, 2012
Additions
Capitalized share based compensation
E&E impairment loss
Exchange adjustments
Balance at March 31, 2013
$
$
$
7,064
10,213
29
(4,194)
(2,705)
119
10,526
16,017
166
(927)
634
26,416
Exploration and evaluation assets consist of the Company’s exploration projects in Australia and India
which are pending the determination of proved or probable reserves. Costs primarily consist of
acquisition costs, geological & geophysical work, seismic and drilling and completion costs until the
drilling of wells is complete and the results have been evaluated.
The original time period in which to complete the seismic work program on the offshore Australia
AC/P 47 permit expired on March 2, 2012. On October 19, 2012, the Company was granted an
extension to January 2, 2013 for the time period for completing the work program from the National
Offshore Petroleum Titles Administrator (NOPTA). A meeting between the Company and NOPTA
occurred in March 2013 to discuss the future of this permit. Subsequent to the March 2013 meeting,
the Company made an application to NOPTA to surrender this permit and $0.8 million in costs has
been impaired.
As a result of the execution of a final settlement agreement, $0.8 million of previously impaired costs
for the drilling of the abandoned Hudson well in a prior year were recovered in the year ended March
31, 2013.
- 45 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
During the year ended March 31, 2013 E&E impairment recognized in profit and loss relates to the
following (2012 - $4,194):
($000s)
AC/P 24 – Kingtree Well offshore Australia
AC/P 47 – Offshore Australia
E&E Impairment - current year E&E assets
Hudson Well (recovery of prior year impairment)
Impairment charge for the year ended March 31, 2013
A summary of E&E assets is shown in the table below:
Impairments
103
824
927
(847)
80
$
$
$
Exploration and Evaluation Assets
($000s)
ATP 732P – Tookoonooka
AC/P 47 – offshore
CY-ONN-2005/1 – onshore
CY-OSN-2009/1 (cid:237) offshore
Other
March 31, 2012 ($000)
ATP 732P – Tookoonooka
CY-ONN-2005/1 – onshore
CY-OSN-2009/1 (cid:237) offshore
Other – Note 1
$
Total
Australia
$ 6,847
810
-
-
574
$ 8,231
India
-
-
1,751
544
-
$ 2,295
$ 6,847
810
1,751
544
574
$ 10,526
Exploration and Evaluation Assets
Australia
$ 19,385
-
-
1,886
$ 21,271
$
India
-
4,312
833
-
$ 5,145
Total
$ 19,385
4,312
833
1,886
$ 26,416
March 31, 2013 ($000)
Note 1: Other includes ATP 934P, capitalized G&A and stock-based compensation and foreign exchange effects on assets
denominated in foreign currencies.
- 46 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
7. PETROLEUM AND NATURAL GAS PROPERTIES
Cost:
Balance at April 1, 2011
Additions
Capitalized share based compensation
Change in decommissioning obligation
Transfers from E&E assets
Exchange adjustments
Balance at March 31, 2012
Additions
Capitalized share based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2013
Accumulated depletion, depreciation and
impairment losses:
Balance at April 1, 2011
Depletion and depreciation charge
Exchange adjustments
Impairment expense
Balance at March 31, 2012
Depletion and depreciation charge
Exchange adjustments
Balance at March 31, 2013
Net carrying value
At April 1, 2011
At March 31, 2012
At March 31, 2013
Petroleum and
Natural Gas
Properties
$000s
Corporate
Assets
$000s
196
105
-
-
-
-
301
126
-
-
-
427
$
$
$
2,168 $
520
2
67
2,705
35
5,497
7,727
19
85
482
13,810 $
$
Petroleum and
Natural Gas
Properties
$000s
Corporate
Assets
$ 000s
Total
$000s
2,364
625
2
67
2,705
35
5,798
7,853
19
85
482
14,237
Total
$000s
$ 283
383
(2)
311
975
1,300
172
2,447
1,885
4,522
$
$
$
$ 11,363
$
51
37
-
-
88
75
(3)
160
145
213
267
$
$
$
$
$ 334
420
(2)
311
1,063
1,375
169
2,607
$
$
$
2,030
4,735
$ 11,630
The calculation of depletion for the year ended March 31, 2013 included $31.1 million and $0.5 million
for estimated future development costs associated with proved and probable reserves in Australia
and Canada respectively (March 31, 2012 - $0.8 million and $0.7 million).
In the year ended March 31, 2013 there were indicators of impairment for the Canadian Cash
Generating Unit (“CGU”) due to changes in forecasted commodity prices used by the Company’s
independent qualified reserves evaluators when compared to March 31, 2012. Accordingly, the
Company tested certain CGUs for impairment and determined that there was no impairment in the
aggregate carrying value of the Canadian gas property at Oak. B.C. The Company estimated the
recoverable amount based on a fair value less costs to sell methodology using estimated cash flows
based on both proved plus probable reserves discounted at a pre-tax discount rate of 10%.
- 47 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
8. PROPERTY, PLANT AND EQUIPMENT
($000s)
Rig Equipment
Balance at March 31, 2011
Additions
Balance at March 31, 2012
Additions
Capitalized share-based compensation
Balance at March 31, 2013
Accumulated depletion, depreciation and impairment losses:
Balance at March 31, 2012
Depreciation charge
Balance at March 31, 2013
Net book value
Balance at March 31, 2012
Balance at March 31, 2013
$
$
(cid:237)
230
230
4,511
15
$ 4,756
$
$
$
$
(cid:237)
73
73
230
4,683
On April 5, 2012 the Company purchased an Ideco H-44 drilling rig. The purchase price of the Rig
was US $1.75 million. Additional costs have been incurred to transport the rig from its point of
purchase, prepare the rig and acquire certain ancillary equipment required for drilling operations. This
rig was used to drill, case and test the Caracal-1 well on permit ATP 732.
At March 31, 2013, the Company identified a trigger of impairment relating to the drilling rig being idle
at March 31, 2013. The Company estimated the recoverable amount based on a fair value less costs
to sell methodology using recent market transactions as a fair value estimate. It was determined that
the fair value less costs to sell exceeded the net book value of the drilling rig at March 31, 2013.
On May 23, 2103 the Company entered into a Binding Letter of Intent with a leading Australian oil and
gas company to Farm-in to permit ATP 732in Australia. Under the terms the Farm-in Agreement,
currently being finalized, the Farmee will spend up to $11.5 million AUD to drill two wells and shoot
300 square kilometers of 3D seismic to earn a 50% interest in the permit. Upon completion of the
Farm-in terms, the Farmee also has the option to become operator of the permit.
9.
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
Income tax recovery
2013
(1,807)
25%
452
(14)
(124)
(118)
(188)
8
$
$
$
2012
7,209
26.13%
1,883
74
(261)
(251)
(1,445)
(cid:237)
$
$
$
- 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
2013
28,144
5,998
3,939
765
320
39,166
$
$
2012
26,978
5,878
3,566
1,147
228
37,797
$
$
Income tax rates changed from 26.13 percent in fiscal 2012 to 25.0 percent in fiscal 2013 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
2013
9,668
339
(10,007)
(cid:237)
$
$
2012
3,530
339
(3,869)
(cid:237)
$
$
At March 31, 2013, the Company had approximately $18.5 million and $43.0 million of non-capital
losses in Canada and Australia respectively (2012 - $15.6 million and $24.6 million), available to
reduce future taxable income. The Canadian non-capital losses expire at various dates from March
31, 2014 to 2033. 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, 2013, the Company has no deferred tax
liabilities in respect of these temporary differences.
10. CONVERTIBLE AND NON-CONVERTIBLE NOTES
On January 25, 2013 the Company closed a non-brokered private placement (the “Private
Placement”) of $3.5 million short-term, unsecured convertible and non-convertible notes (the “Notes”).
The Private Placement consists of the placement of: (i) $1,750,000 aggregate principal amount of
non-convertible notes (the "Non-Convertible Notes") bearing an interest rate of prime plus 3% per
annum and having a term of 180 days; and (ii) $1,750,000 aggregate principal amount of convertible
notes (the "Convertible Notes") bearing an interest rate of prime plus 3% per annum and having a
term of 180 days.
The Convertible Notes are convertible at any time up to maturity into common shares ("Common
Shares") in the capital of the Company at the option of the holder at a conversion price equal to the
lower of the five day volume weighted average price of the Common Shares as at: (A) the issue date
of the Convertible Notes ($0.56/share), and (B) the date of conversion of some or all of the principal
amount of the Convertible Notes; provided that the conversion price shall not be lower than that
conversion price that would require the Company to seek shareholder approval of the issuance of
Common Shares on conversion of some or all of the principal amount of the Convertible Notes
pursuant to the policies of the Toronto Stock Exchange ("TSX").
- 49 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
All interest payable under the Notes is payable in cash. The principal amount of the Notes shall be
redeemable, at the Company's option, in whole or in part, at any time and from time to time, for cash,
provided that any partial redemption is subject to a minimum redemption in the amount of $50,000 of
aggregate principal amount outstanding and subject to the Holder’s rights to convert the principal
amount of any Convertible Notes called for redemption. Certain directors of the Company acquired
approximately $1,500,000 principal amount of the Convertible Notes and $1,500,000 principal amount
of the Non-Convertible Notes issued pursuant to the Private Placement.
Upon the issuance of the Notes, the liability component of the Convertible Note was recognized
initially at the fair value of a similar liability that does not have an equity conversion option. The
market interest rate of 10% was used for the calculation of the liability component of the Convertible
Note. The difference between the estimated future cash flows discounted at 6% (prime + 3%) and
10%, of $33,000, net of transaction fees, was recorded as equity, with the remaining $1,697,000 net
of transaction fees being recorded as a liability. The discount on the notes is being accreted such that
the liability at maturity will equal the face value of the note issuance of $1,750,000.
Convertible Note
Gross proceeds
Total cash fees
Accretion on debt
Deferred tax impact
Balance at March 31, 2013
Total
$000s
$ 1,750
(20)
1,730
22
(8)
1,744
$
$
Liability
component
$ 000s
1,716
(19)
1,697
22
-
1,719
$
Equity
Component
$000s
$ 34
(1)
33
-
(8)
25
$
The Non-Convertible note was issued with an interest rate considered below market rate. The market
interest rate of 10% was used to calculate the implied discount on the Non-Convertible note. The
difference between the estimated future cash flows discounted at 6% (prime + 3%) and 10% of
$34,000 was recorded as a reduction to the face value of the debt with the remaining $1,697,000 net
of transaction fees being recorded as a liability.
Non-Convertible Note
Gross proceeds
Total cash fees
Implied Discount on Note
Accretion on debt
Balance at March 31, 2013
Total
$000s
$ 1,750
(19)
(34)
1,697
23
$ 1,720
- 50 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
11. 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:
($000s)
Decommissioning liabilities, beginning of year
Revision
Additions
Expenditures
Accretion
Decommissioning liabilities, end of year
$
$
March 31, 2013 March 31, 2012
159
67
(cid:237)
(3)
5
228
228
(55)
140
(cid:237)
7
320
$
$
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, 2013 is approximately
$421,000 (March 31, 2012 – $283,000) which will be incurred between 2014 and 2038. An inflation
factor ranging between 1.0% and 2.0% and a risk free discount rate ranging between 1.5% and
2.75% have been applied to the decommissioning liability at March 31, 2013.
12. SHARE CAPITAL
(a) Authorized:
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, 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
At March 31, 2012 and 2013
Number of Shares
37,794,549
14,166,800
73,828
75,000
-
-
52,110,177
$
$
Amount
62,595
25,500
(cid:237)
27
146
(2,022)
86,246
(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. Effective with the option grant on December 21, 2012, vesting
occurs one third after the first year and one third on each of the two subsequent anniversaries.
- 51 -
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. For options that vest one-third each
year after the first year anniversary, the fair value of the options are charged to profit and loss
over the three year vesting period. 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, 2011
Granted
Expired
Forfeited
Exercised
Outstanding at March 31, 2012
Granted
Forfeited
Expired
Outstanding at March 31, 2013
Exercisable at March 31, 2013
Options
2,170,667
2,420,000
(208,335)
(470,667)
(300,000)
3,611,665
1,150,000
(148,333)
(416,667)
4,196,665
1,986,667
$
Weighted Average
Exercise Price
1.38
1.20
1.35
2.68
0.74
1.14
0.58
1.11
1.30
0.98
1.09
$
$
$
Options Outstanding
Options Exercisable
Option Price (1)
$ 0.36–1.25
$ 1.26–2.25
Total
Number
Outstanding
3,075,000
1,121,665
4,196,665
Exercise
Price (2)
$ 0.84
$ 1.36
$ 0.98
Remaining
Life (3)
3.8
2.2
3.4
Number
Exercisable
1,090,000
896,667
1,986,667
Exercise
Price (2)
$ 0.86
$ 1.37
$ 1.09
(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,
2013
March 31,
2012
2.0%
5 yr
86%
6.5%
$0.40
$0.58
2% to 4%
5 yr
68%
6.0%
$0.71
$1.20
(1)
Expected volatility is estimated by considering historic average share price volatility.
- 52 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
The fair value of stock options granted during the year and quarter ended March 31, 2013 was
$454,000 (2012 - $1,710,000).
(e) Loss per share:
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, 2013, there were 4,196,665 (March 31, 2012 – 3,611,665) options considered anti-
dilutive.
13. 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
(1) Represents the amortization of share based payment expense associated with the Company’s share based compensation
2013
822
496
1,318
$
$
$
$
plans granted to key management personnel.
Salaries and benefits for the year ended March 31, 2013 include a non-recurring retirement payment to
former employees of $nil (2012 - $245,582).
14. FINANCE EXPENSES
Year ended March 31 ($000s)
Accretion on decommissioning obligations
Performance Security Guarantee fee (1)
Interest on Notes payable
Accretion on Notes payable
Finance expenses
$
$
2013
7
43
38
45
133
$
$
2012
5
63
-
-
68
(1) Fees paid to Export Development Canada and ICICI Bank for security guarantees for onshore and offshore India work
programs.
15. 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, cash equivalents, restricted cash, accounts receivable,
accounts payable and accrued liabilities and convertible and non-convertible notes. The fair
- 53 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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, 2013, Bengal’s receivables consisted of $3.4 million (March 31, 2012 - $0.6 million)
from joint venture partners and $0.2 million (March 31, 2012 - $0.4 million) of other trade
receivables.
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, 2013, 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, 2013 and did not provide for any doubtful accounts nor was it
required to write-off any receivables during the year ended March 31, 2013.
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, accrued liabilities and Notes payable and amounted to $8.1 million at March
31, 2013 (March 31, 2012 - $2.5 million). Bengal had $2.6 million in cash (March 31, 2012 - $26.9
million), $0.1 million in restricted cash (March 31, 2012 - $0.1 million) resulting in a working
capital deficit of $1.6 million at March 31, 2013 (March 31, 2012 - $25.7 million). All accounts
- 54 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
payable, accrued liabilities and notes payable are due within one year. Subsequent to March 31,
2013 the Company closed a $5.7 million private placement of common shares (see Note 21)
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.
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, 2013 ($000s)
Cash and short-term deposits
Restricted cash
Accounts receivable
Accounts payable and accrued liabilities
Notes payable
Commodity Price Risk
CAD
AUD
U.S.D
$ 2,030
140
45
(364)
(3,439)
$ 274
-
3,298
(10)
-
$ (1,588) $ (3,577) $ 3,562
$ 288
-
142
(4,007)
-
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,
2013.
- 55 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
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 not exposed to interest rate risk on its cash and cash equivalents
at March 31, 2013 as the funds are not invested in an interest bearing instrument. The Company
is exposed to interest rate risk on its Notes Payable. A 1% increase in the Prime rate would
increase interest expense on the Notes by $17,500. The Company had no interest rate
derivatives at March 31, 2013.
16. 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.
In order to maintain or adjust the capital structure, the Company may from time to time issue shares
(if available on reasonable terms), issue debt instruments, sell assets, farm out properties and adjust
its capital spending to manage current and projected cash levels. There can be no assurance that
equity financing will be available or sufficient to meet capital commitments, or for other corporate
purposes, or if equity financing is available, that it will be on terms acceptable to the Company. 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.
17. 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
$
$
$
$
2013
(2,813)
17
2,139
(657)
(1,802)
38
1,107
(657)
$
$
$
$
2012
137
(36)
(189)
(88)
320
(82)
(326)
(88)
Note – changes in working capital include elements of unrealized foreign exchange differences on
assets and liabilities denominated in a foreign currency.
- 56 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
The following represents the cash interest received in each period.
Year ended March 31 ($000s)
Cash interest received
$
2013
274
$
2012
541
18. COMMITMENTS AND CONTINGENCIES
Commitments:
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. Additional commitments are reflected where the
Company has agreed with joint venture partners to proceed with activities. 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
Work Program
Obligation
Period Ending
Estimated
Expenditure (net)
(millions CAD$)(1)
Onshore Australia –
ATP 752 Cuisinier
Cuisinier to Cook pipeline, facilities
upgrade, drill five appraisal wells
April 2013 to March,
2014
Onshore India – CY-
ONN-2005/1
Three wells
March 3, 2014(2)
Offshore India – CY-
OSN-2009/1
310km 2D seismic & 81km2
3D seismic
August 15, 2014(3)
$ 5.9
$ 4.2
$ 5.3
(1) Translated at March 31, 2013 at an exchange rate of US $1.0000 = CAD $1.0171 and AUD $1.0000 = CAD $1.0594
(2) If the Company did not participate in the drilling of three wells, costs of $4,312,000 would be impaired and the Company’s
interest in the permit would decline.
(3) The Company is looking for a partner to participate in this permit and share the costs.
At March 31, 2013 the Company had the following lease commitment for office space in Canada.
($000s)
April 2013 to March 2017
Office lease
Total
$ 996
Less than
1 Year
245
1-3
Years
498
4-5
Years
253
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.
Contingencies:
Final application for the grant of permit ATP 934 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 below; The Company holds a 50% operating interest in this permit. The Work program
consists of 500 km of 2D seismic and up to seven wells.
- 57 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
Country and
Permit
Work Program
Obligation
Period Ending
Estimated
Expenditure (net)
(millions CAD$)
Onshore Australia –
ATP 934P
Awaiting Ministerial approval before
granting of ATP
4 years after grant of
ATP
$ 12.4
19. 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, 2013 amount to $1,003,000 (2012 - $1,093,000).
20. RELATED PARTY TRANSACTIONS
On January 25, 2013, the Company closed a non-brokered private placement (the "Private
Placement") of $3.5 million of short-term, convertible and non-convertible notes. Members of the
Board of Directors of the Company subscribed for approximately 85% of the principal amount of the
notes issued pursuant to the Private Placement.
21. SUBSEQUENT EVENT
On April 16, 2013 the Company announced that it has closed a brokered private placement of
common shares. The Company issued a total of 9,500,666 Common Shares at a price of $0.60 per
Common Share for aggregate gross proceeds of approximately $5,700,400. The Company paid the
Agents a cash commission of approximately $282,000, being 6.0% of the gross proceeds of the
Offering excluding $1,000,000 of President's list subscriptions. A total of 2,400,300 shares of the
Offering were purchased by insiders of the Company.
On April 18, 2013, the term of the Company’s non-convertible notes was extended from July 24, 2013
to January 24, 2014. As consideration for the extension of the maturity date, the interest rate payable
under the non-convertible notes was increased to 10.0% per annum from prime plus 3% effective July
25, 2013.
On May 23, 2013 Bengal Energy Ltd entered into a Binding Letter of Intent to enter into a Farm-out
Agreement on its 100% owned Tookoonooka Block (“ATP 732”) in the Cooper Basin of Australia with
a leading Australian oil and gas company. The Farmee will fund Bengal’s share of a two well drilling
and 3D seismic exploration and appraisal work program (the “Work Program”) to a maximum of
AUD$11.5 million, in order to acquire a 50% interest in ATP 732.
22. SEGMENTED INFORMATION
As at March 31, 2013, 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.
- 58 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
For the year ended March 31, 2013 ($000)
Revenue
Interest revenue
Interest expense
Depletion and depreciation
Net loss
Exploration and evaluation
expenditures
Petroleum and natural gas property
expenditures
Property, plant & equipment
expenditures
Impairment losses (recovery)
March 31, 2013 ($000)
Australia
5,669
$
82
-
1,255
1,266
Canada
$
216 $
87
38
193
(2,251)
India
-
(2)
-
-
(814)
Total
$
5,885
167
38
1,448
(1,799)
13,167
-
2,850
16,017
$ 7,876
$
(23)
$
-
80
$ 4,511
-
$
$
-
$
7,853
-
-
-
-
-
-
$
4,511
80
$
14,237
(311)
(2,296)
11,630
$
Petroleum and natural gas properties
Cost
Impairment loss
Accumulated depletion,
depreciation and accretion
Net book value
$ 13,065
-
$
1,172 $
(311)
(1,828)
11,237
$
(468)
393
$
$
Exploration and evaluation assets
Accumulated impairment losses
Net book value
$ 26,393
(5,122)
21,271
$
$
-
-
-
$
$
5,145
-
5,145
$
31,538
(5,122)
26,416
Property, plant & equipment
$
(cid:237)
$
4,756
$
(cid:237)
$
4,756
Accumulated depletion, depreciation
and accretion
Net book value
(cid:237)
$ (cid:237)
$
(73)
4,683
(cid:237)
$ (cid:237)
$
(73)
4,683
- 59 -
Bengal Energy Ltd.
Notes to Consolidated Financial Statements
For the year ended March 31, 2012 ($000)
Revenue
Interest revenue
Depletion and depreciation
Net loss
Exploration and evaluation
expenditures
Petroleum and natural gas property
expenditures
Drilling rig 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
(cid:237)
(938)
Total
$ 4,286
613
420
(7,209)
8,667
-
1,546
10,213
$
$
520
(cid:237)
(4,194)
$
$
105
230
(311)
$
4,603
(cid:237)
(405)
4,198
1,195
(311)
(347)
537
-
-
-
(cid:237)
(cid:237)
(cid:237)
-
$
$
625
230
(4,505)
5,798
(311)
(752)
4,735
Exploration and evaluation assets
Accumulated impairment losses
Net book value
Property, plant & equipment (net)
$
$
12,425
(4,194)
8,231
$
-
-
-
$
2,295
-
2,295
$
14,720
(4,194)
10,526
(cid:237)
$
230
$
(cid:237)
$
230
- 60 -
CORPORATE INFORMATION
AUDITORS
KPMG LLP • Calgary, Canada
LEGAL COUNSEL
Burnet, Duckworth & Palmer LLP • Calgary, Canada
Johnson Winter Slattery • 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
Cindy Gray - 5 Quarters Investor Relations, Inc. • 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
Gordon R. MacMahon, Vice President, Exploration
Bruce Allford, Secretary
STOCK EXCHANGE LISTING – TSX:BNG
- 61 -
Bengal Energy Ltd.
Suite 1810, 801 – 6th Avenue SW
Calgary, Alberta T2P 3W2
Canada
T: 403.205.2526 F: 403.263.3168
TSX: BNG