Financial Highlights
international exploration & production
2014 Annual Report
TABLE OF CONTENTS
Message to Shareholders
Fiscal 2014 Highlights
Management’s Discussion and Analysis
Consolidated Financial Statements
Notes to the Consolidated Financial Statements
Corporate Information
1
5
6
29
35
60
BENGAL ENERGY LTD.
MESSAGE TO SHAREHOLDERS
I am pleased to report that through this past fiscal year ending March 31, 2014, Bengal Energy continued to
execute on our focused strategy resulting in numerous key milestones being met.
Bengal’s world-class assets are located in politically, fiscally and economically stable jurisdictions, featuring
industry-leading netbacks bolstered by high potential impact exploration. This unique combination affords
shareholders exposure to a growing and oil-weighted company with exciting exploration potential that will
be largely funded through our cash flow. Building on the success we realized in our last fiscal year, Bengal
commenced the largest drilling and capital program in the Company’s history in March of 2014, which will
be undertaken through fiscal 2015.
Over the past year, we have achieved numerous operational milestones across our Cooper Basin, Australia
assets, particularly in our Cuisinier (Barta sub Block of ATP 752) and Tookoonooka (ATP 732) areas. In
light of the sizeable potential of Cuisinier for longer term development as well as its ability to generate an
attractive cash flow stream, Bengal elected to purchase an additional 5.4% working interest in the permit in
June 2013, bringing our total interest up to 30.4%, and allowing us to realize a greater proportion of the
production and booked reserves from Cuisinier.
BENGAL ENERGY LTD.
We continued to develop Cuisinier through the year, and completed a six well drilling program with 100%
success, as all wells were brought on stream as oil producers, contributing to overall production volumes for
the year. Our corporate production averaged 504 boepd for the fourth quarter of fiscal 2014, an increase of
55% over the fourth quarter of fiscal 2013. Since our Cuisinier production is all ultra-light oil, our Australian
netbacks are very strong, averaging $83.00 / bbl, which is significantly higher than the average netback of a
producer in Western Canada. In addition to the production and cash flow that was generated, the success
of this program helped to further expand the boundaries of the pool, enhance our technical team’s
understanding of the geological features in the area, and resulted in record reserves and value bookings for
Bengal in our year end reserves evaluation.
As a direct result of our ongoing activities in Cuisinier, at fiscal year end 2014 Bengal’s independent reserve
evaluators assessed the net present value of our proved plus probable (2P) reserves discounted at 10%
(NPV10), at $101 million, an increase of 149% over the prior year. This value is a step change above the
Company’s enterprise value at fiscal year end 2014, and reflects an opportunity for substantial value
expansion in the market. We successfully booked 2P reserves of 3.8 million boe, an increase of 122%
relative to 2013, and our total proved (1P) booked reserves of 1.7 million boe were equal to last year’s 2P
reserves. Based on our 1P and 2P reserves additions, we replaced ~6.4X & 13.2X our annual production,
respectively. This is an incredible achievement for Bengal, and underpins the value of our company.
Our team’s technical strength, persistent effort and value-focused mindset have been demonstrated
emphatically through the growth in Cuisinier pool size and its asset value net to Bengal Energy. Based on
our independent reserves evaluators’ assessments, the pool size has grown from 0.5 million barrels (2P,
gross pool oil in place) in 2010 to just under 50 million barrels in 2014, reflecting a compound annual growth
rate (CAGR) of over 210%. On a proved plus probable plus possible basis, the gross pool oil in place in this
year’s independent reserves evaluation was assessed to be over 100 million barrels. Our working interest
reserves in this field has shown a dramatic 249% CAGR from 2010 to 2014, and the NPV10 value of our
share of Cuisinier reserves has shown a 203% CAGR in the same time period. These growth metrics
highlight the significant and sustained achievements that our team has been able to make in terms of
growing our fundamental asset value for the benefit of our shareholders.
Prior to the finalization of our year end reserves report, Bengal took steps to secure a reserves based credit
facility, to backstop the funding of our ongoing Australian development program. In late May, 2014 we
signed an indicative term sheet for a US $20 million secured credit facility with a leading Australian
commercial bank, contemplating a three year term at attractive fixed income market rates tied to USD
LIBOR. Consistent with our conservative approach to financing, we conducted a thorough stress test on
our existing production base to ensure that such a facility along with our existing unsecured debt will be fully
serviceable under several commodity price scenarios. Finalization of the facility is subject to the lender
completing their due diligence, as well as the possibility that competing offers may be received by
alternative vendors, and is expected in late June, 2014. This facility will free up internally generated cash
flows for the funding of our exploration activities, including three exploration wells in Australia and three in
India. Bengal is committed to securing the lowest cost source of funding with the highest level of flexibility,
which offers room for expansion based on current and future reserves bookings, which have not been
factored into the proposed facility terms.
2
Message To Shareholders
With a secured source of financing, coupled with the reserve and production increases that have been
realized to date in Cuisinier, we are well positioned for ongoing development. Bengal began an aggressive
two-phase drilling program in March 2014, which will run through the fiscal 2015 year. During which we will
drill eight development wells and two exploration wells on the Barta sub Block (in Cuisinier and other
areas), plus one exploration well in a separate area called the Wompi sub Block of ATP 572. The first four
development wells under Phase One were drilled in Cuisinier throughout April / May 2014, and all have
been cased as future oil producers, with completion of the wells anticipated before the end of June, 2014.
As part of our program, we committed to the drilling of two exploration wells in the Barta sub Block, Koki-1
and Wicho East, which are located in Barta North, an area four km to the North of Cuisinier, in which Bengal
has identified six independent structures on 3D for multi-zone exploration drilling. The Koki-1 well was
drilled in early June and failed to identify commercial hydrocarbons and has been plugged and abandoned.
Wicho East is expected to spud in August, 2014 and will target the Hutton zone in an independent structural
closure within the Cuisinier North area. These exploration wells are intended to provide us with valuable
insights regarding the future prospectivity of areas outside our core Cuisinier field. In Barta West, an area
situated to the west of Cuisinier, Bengal has identified strong exploration leads from our 2D seismic
interpretation, and we plan to supplement this with the acquisition of 3D seismic in 2015.
The third of our upcoming exploration wells is located in Wompi, an area Bengal holds a 38% working
interest, and is situated within a well-established, oil producing fairway and offers a moderate-risk, multi-
zone opportunity. Offsetting pools around Wompi have been developed targeting a deeper formation called
the Hutton, which have resulted in some prolific, high impact wells. We anticipate our Wompi exploration
well will spud towards the end of calendar 2014.
Also during fiscal 2014, Bengal secured an agreement with a premier Cooper Basin operator, Beach
Energy Ltd, for the development of our Tookoonooka asset, which is located on the Eastern Flank of the
Cooper Basin. In exchange for a 50% interest in Tookoonooka, Beach agreed to fund the drilling of two
wells and the acquisition of 300 km2 of 3D seismic for up to a maximum of AUD$11.5 million. Our strategic
partnership with Beach not only provides funding for the development of Tookoonooka, but it also allows us
to benefit from working with one of the Cooper Basin’s largest and most experienced operators. The first of
the two wells was drilled late in calendar 2013, and although it was not commercial, it provided us with
critical data, information and learnings from which to plan for the second well. Beach has now successfully
completed the acquisition of the 3D seismic, and plans to select the second location from the seismic
interpretation in the first quarter of calendar 2015.
In our onshore India block, our local partners have been actively advancing the regulatory and permitting
aspects in order to commence drilling, and are confident that the first of three wells will spud by mid-third
quarter, calendar 2014. Onshore India offers Bengal and our shareholders exposure to another potential
high impact exploration play in a fiscally and politically stable country.
3
BENGAL ENERGY LTD.
The past year was a pivotal one for Bengal, as our technical success significantly expanded the underlying
reserves and the value in Australia, and we demonstrated our ability to grow production, reserves, cash flow
and long-term value for shareholders. As a result of our technical development to date and conservative
approach to financing, Bengal is stronger than ever, and poised to continue proving up the value of our
world-class assets. I want to thank our strong and supportive Board, our hard-working and skilled technical
team, as well as each of our shareholders for your support as we grow and further enhance the value of
Bengal Energy.
Sincerely,
(signed) “ Chayan Chakrabarty”
Chayan Chakrabarty
President & CEO
Note: this Message to Shareholders contains forward-looking statements and is subject to the forward-
looking statement disclaimer in the Management’s Discussion & Analysis for the Years Ended March 31,
2014 and 2013.
4
Financial Highlights
Financial Highlights:
•
Increased Production Resulted in Record Revenue – Bengal’s
revenue
of
approximately
$5.3
million
in
the
fourth
quarter
was
4%
lower
than
the
$5.5
million
generated
in
the
preceding
quarter
due
to
lower
realized
commodity
prices,
but
was
75%
higher
than
the
$3.0
million
generated
during
fourth
quarter
of
2013.
For
the
full
year
2014,
Bengal
generated
revenue
of
approximately
$19.8
million,
which
is
a
237%
increase
over
fiscal
2013.
The
gain
was
driven
by
a
55%
increase
in
production
compared
to
the
previous
year,
and
strong
pricing
for
the
high
quality
crude
oil
produced.
• Funds Flow from Operations(1) Significantly Grow Year over Year – Bengal
generated
funds
flow
from
operations
of
$2.2
million
in
the
quarter
ended
March
31,
2014
a
23%
decrease
from
the
$2.9
million
generated
in
the
preceding
quarter,
due
to
lower
netbacks
and
the
impact
of
foreign
exchange
as
the
Australian
dollar
appreciated
against
the
US
dollar;
however
this
reflects
a
93%
increase
over
the
$1.2
million
recorded
in
the
fourth
quarter
of
2013.
Full
year
2014
funds
flow
from
operations
was
$8.2
million
or
645%
higher
than
the
$1.1
million
generated
during
the
twelve
months
ended
March
31,
2013.
• Reserves Growth Continue – Independent third party year-end reserves evaluation to March 31,
2014 show a 122% year-over-year corporate proven and probable (2P) reserves increase, driven
by significant increase of 2P reserves at Cuisinier. Based on proven (1P) and 2P reserves
additions, Bengal has replaced approximately 6.4 times and 13.2 times its annual production,
respectively.
• Net Income Demonstrates Continuing Profitability – Bengal reported net income of $150
thousand for the year compared to a loss of $1.8 million in the prior year. Before factoring in
impairments of approximately $3.1 million, Bengal would have generated net income of
approximately $3.2 million (EPS $0.05/share).
2014 Operational Highlights:
• Production Volumes – Production in the fourth quarter averaged 504 barrels of oil equivalent per
day (“boepd”), an increase of 8% over the 468 boepd in the previous quarter and a 55% increase
over the 325 boepd produced in Q4 2013. For the full year, Bengal’s production averaged 468
boepd, a significant increase of 175% over the 170 boepd produced in 2013.
• Cuisinier Drilling 2013 – On March 20, 2013, the Company commenced its fiscal 2014 Cuisinier
drilling program, comprised of six Murta focused oil wells. The program successfully aimed to
optimize the overall pool productivity and better define the ultimate pool size. All six wells were
drilled and extended Bengal’s 100% success rate in its Cuisinier drilling history.
• Expanded ownership interest of Cuisinier Oil Field and the ATP 752P – Bengal exercised its
pre-emptive right to purchase an additional interest in the ATP 752P permit, bringing the
Company's total ownership to 30.357% of the Cuisiner field and 38% in the Wompi block.
1.
Funds
flow
from
operations
is
an
additional
generally
accepted
account
principle
(“GAAP
measure”).
The
comparable
International
Financial
Reporting
Standards
(“IFRS”)
measure
is
cash
from
operations.
A
reconciliation
of
the
two
measures
can
be
found
in
the
table
on
page
6
of
Bengal’s
Annual
MD&A.
5
BENGAL ENERGY LTD.
• Receipt of Petroleum License - Final approval of Petroleum Lease 303 (“PL303”) for the Cuisinier
oil pool was granted in April 2013, allowing Bengal’s past and future Cuisinier wells to produce for
up to 21 years.
• 2014 Phase 1 Cuisinier Drilling Campaign – Commencing in March 2014, four development wells
were drilled through May 2014 at Cuisiner with a 100% success rate. The wells have been cased
and are awaiting completion, which is anticipated to run from mid-July through early August 2014.
The Company expects tie-ins to be completed by the end of September 2014, with cash flow from
the new production volumes being reflected in the first quarter of calendar 2015.
• Onshore India Drilling Plan - The Company continues to work with the operator of Bengal’s
onshore block in India’s Cauvery Basin to finalize the necessary regulatory approvals for the drilling
of three exploration wells.
Recent Developments:
• Current Production Volumes – Production rates in Cuisinier have been impacted by natural
declines as well as operational issues encountered in the field’s largest producing well. The
Cuisinier 6 well has experienced a sudden and unusual increase in water-cut as well as an increase
in measured well head pressure since April 2014. Bengal, along with the operator is currently
investigating the source of the water to determine a remediation strategy aimed at increasing oil
production to offset this decline.
• Extending Financial Flexibility – Subsequent to year-end, Bengal signed an indicative term sheet
for a US $20.0 million secured credit facility with a leading Australian commercial bank. Once
finalized, the facility is expected to fully fund Bengal’s Australian development through March 2015,
allowing the Company to fund future planned exploration activities in India and Australia with
internally generated cash flows.
MANAGEMENT’S DISCUSSION AND ANALYSIS – JUNE 13, 2013
Bengal’s producing assets are predominantly situated in Australia’s Cooper Basin, a region featuring large
hydrocarbon pools. The Company’s core Australian assets – Cuisinier and Tookoonooka – are situated
within an area of the Basin in its infancy in terms of appraisal and development, and Bengal believes these
assets offer attractive upside potential. Australia features a stable political, fiscal and economic environment
in which to operate, with a favourable royalty regime for oil and gas production.
With oil pricing benchmarked to Brent, Bengal’s realized operating netbacks from Australia have averaged
over C $83/bbl for the twelve months ending March 31, 2014. This strong pricing environment coupled with
a growing production base contributed to the Company’s increased revenues and funds flow from
operations through fiscal 2014.
AUSTRALIA
Cuisinier ("ATP") 752 Barta Block
From late March 2014 to early May 2014, Bengal carried out the first of its calendar 2014 two-phase drilling
campaign in Cuisinier. The four Phase One development wells were drilled with 100% success and have
now been cased and suspended awaiting completion and tie-in.
The wells targeted the oil-bearing Cretaceous Murta formation, and Bengal’s preliminary petrophysical
analysis of the well logs show results comparable with Bengal’s six best Cuisinier wells drilled to date. This
6
Management’s Discussion & Analysis
success rate and corresponding log data further validates Bengal’s 3D seismic interpretation and its team’s
unique understanding of the Murta reservoir.
Completion of the four development wells is anticipated to run from mid-July through early August 2014,
with the wells expected to be tied in through September 2014. Bengal anticipates the cash flow from the
new production volumes to begin in the fourth quarter of calendar 2014.
The drilling program continued with the drilling of the Koki-1 exploration well in June. While the Koki-1 well
failed to define a commercial hydrocarbon accumulation, a second exploration location is scheduled to be
drilled in August, 2014 that will target the Hutton formation on an independent structural closure within the
Cuisinier North 3D area. Following this exploration drilling, four Phase Two development / appraisal wells
are expected to be drilled during the fourth quarter of calendar 2014. The timing will enable Bengal and its
partners to benefit from data obtained in Phase One and to high-‐grade locations for the Second Phase with
a view to enhance productivity and expand the boundaries of the pool.
ATP 732 Tookoonooka Block
In May 2013, the Corporation formed a joint venture (the "JV") with Beach, an Australian energy company,
for the exploration and development of its 100% owned Tookoonooka Block ATP 732P in the Cooper Basin
of Australia. Beach agreed to 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, to acquire a 50% interest in ATP 732. The first
of these two planned wells was drilled in December 2013 and was not deemed commercial.
Acquisition of 300 km2 of 3D seismic has been completed and processing / interpretation is ongoing.
Based on the results of this work the selection and drilling of a second location within the newly expanded
seismic area is anticipated for the second half of calendar 2014.
Wompi (ATP 752 – WI 38%)
The Wompi JV is planning to drill one exploration well in calendar Q3 2014 targeting Birkhead, Westbourne
and Adori formations known to produce in the offsetting Bowen Field located immediately north of the
proposed location. Wompi offers Bengal moderate risk exploration in a well-established, oil-producing
fairway featuring multi-zone potential.
India
Bengal’s onshore India block is situated within the Cauvery Basin (CY-‐ONN 2005/1 30% WI). The Company
continues to coordinate with its partners, Gas Authority of India Ltd. (“GAIL”) and Gujarat State Petroleum
Corporation (“GSPC”) for the drilling of three exploration wells. The wells are expected to be drilled by
GAIL, the operator, during calendar 2014. The delays that the Company has experienced with respect to
this project have stemmed from regulatory and permitting issues, which are aggressively being addressed
by the operator. Bengal continues to work with its partners and the relevant government bodies to advance
drilling.
The Company made wrote-down its offshore block in light of continued uncertainty regarding the future
work plan and the inability to secure a joint interest partner to date. Bengal is engaged in discussions with
the regulatory authorities as to how it might proceed if a partner is not found.
SUMMARY
With the recently announced signing of indicative term sheet with a leading Australian bank, the Company
believes it is sufficiently capitalized to undertake its planned Cuisiner development plans and work program
commitments and utilize internally generated cash flows and existing working capital to fund future planned
7
BENGAL ENERGY LTD.
exploration activities in India and Australia.
OPERATING HIGHLIGHTS
$000s except per share, volumes
and netback amounts
Revenue
Oil
Natural gas
Natural gas liquids
Total
Royalties
% of revenue
Operating & transportation
Operating netback(1)
Cash from (used in) operations:
Per share ($) (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)
Netback(1) ($/boe)
Revenue
Royalties
Operating & transportation
Total
Three Months Ended
March 31
%
Change
2013
Twelve Months Ended
March 31
2014
2013
%
Change
2014
$ 5,174 $
2,946
76
$ 19,480
$
5,669
244
87
11
67
-
30
N/A
274
68
$ 5,272 $
3,013
75
$ 19,822
$
407
7.7
1,496
3,369 $
2,106
0.03
2,218
0.03
(1,804)
(0.03)
271
9.0
694
2,048
119
(0.00)
1,151
0.02
(592)
(0.01)
50
(14)
116
65
1670
93
50
(205)
200
1,334
6.7
5,290
13,198
$
7,591
0.12
8,183
0.13
150
.00
172
44
5,885
526
8.9
1,726
3,633
(703)
(0.01)
1,099
0.02
(1,799)
(0.03)
2,048 $
1,280
60 $ 16,647
$
28,381
472
180
2
504
287
229
-
325
116.24 $
8.97
32.99
102.88
9.25
23.70
74.28 $
69.93
64
(21)
N/A
55
433
201
2
468
13
(3)
39
$ 115.94
7.80
30.94
$
6
$ 77.20
$
138
180
2
170
94.95
8.49
27.85
58.61
59
55
237
154
(25)
206
263
N/A
N/A
645
550
N/A
N/A
(41)
214
12
-
175
22
(8)
11
32
(1) Operating netback is a non-IFRS measure. Netback per boe is calculated by dividing the revenue and costs in total for the
Company by the total production of the Company measured in boe.
(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 6.
Basis of Presentation
This MD&A and accompanying financial statements and notes are for the twelve months ended March 31,
2014 and 2013. The terms “current quarter” and “the quarter” are used throughout the MD&A and in all
cases refer to the period from January 1, 2014 through March 31, 2014. The terms “prior year’s quarter”
and “2013 quarter” are used throughout the MD&A for comparative purposes and refer to the period from
January 1, 2013 through March 31, 2013.
The fiscal year for the Company is the twelve-month period ended March 31, 2014. The terms “fiscal
2014,” “current year” and “the year” are used in the MD&A and in all cases refer to the period from April 1,
2013 through March 31, 2014. The terms “previous year,” “prior year” and “fiscal 2013” are used in the
MD&A for comparative purposes and refer to the period from April 1, 2013 through March 31, 2014. The
term YTD means year-to-date.
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
8
Management’s Discussion & Analysis
(“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:
$000s
Cash flow from (used in) operating activities
Changes in non-cash working capital
Funds from (used in) operations
RESULTS OF OPERATIONS - AUSTRALLIA
Production, Commodity Pricing and Sales
Three Months Ended
March 31
2013
119
1,032
1,151
2014
2,106
112
2,218
Twelve Months Ended
March 31
2013
(703)
1,802
1,099
2014
7,591
592
8,183
The following table outlines Bengal’s production volumes for the periods indicated:
Production
Oil Production
(bbls/d)
Realized oil prices
($/bbl)
Oil Sales
Three Months Ended
March 31
2013 % Change
325
55
2014
504
Twelve Months Ended
March 31
2014
468
2013
170
121.68
114.02
8
123.31
112.84
5,174
2,946
76
19,480
5,669
% change
175
9
244
Oil sales in Australia are derived from its producing Cuisiner production license. Increased sales revenue
for the both the quarter and year ended March 31, 2014 compared to the corresponding periods in 2014
was due to an increased production base and higher realized commodity prices.
9
BENGAL ENERGY LTD.
Production
Production gains are attributed to the Cuisiner development programs which have continued to add
production throughout fiscal 2014 as detailed below:
• The Cuisiner 1, 2 and 3 wells were offline for most of fiscal 2013 and were brought back on-stream
in May of 2013, which added incremental production of approximately 36 bpd.
• Cuisiner 4, 5 and 6 were brought on-stream in October of 2012 adding an average of 94 bpd in
fiscal 2013 compared to 201 bpd contributed to fiscal 2014 during which all of these wells were on-
stream for the entire year.
• Production gains from the Company’s 2013 drilling campaign were realized in July to December of
2013 when the Cuisinier 7 through 12 wells were brought on-stream adding incremental production
of approximately 153 bpd for the five wells net to Bengal.
• 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).
Pricing
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 $6.34/bbl over Brent for the twelve months ended March 31, 2014 (2013 – USD $5.14).
Realized crude oil prices increased by 7% for the year and 9% for the quarter ended March 31, 2014
relative to the prior year and quarter despite a decrease to benchmark prices due to a significant increase in
the value of the US dollar relative to the Canadian dollar. The Company’s oil sales are based on a premium
to Brent benchmark pricing denominated in US dollars.
The following table outlines average benchmark prices compared to Bengal’s realized prices:
Prices and Marketing
Average Benchmark Price
Bengal realized crude oil price
($CAD/bbl)
Dated Brent oil ($CAD/bbl)(1)
Dated Brent oil ($US/bbl)
Number of CAD$ for 1 AUD$
Number of CAD$ for 1 USD$
Royalties
Royalties ($000s)
Royalty Expense
$/boe
% of revenue
Three Months Ended
March 31
Twelve Months Ended
March 31
2014
2013 % Change
2014
2013
% Change
121.68
118.81
108.14
0.99
1.10
114.02
112.43
112.43
1.05
1.00
7
6
(4)
(6)
10
123.31
112.917
107.54
.98
1.05
112.84
110.03
110.03
1.03
1.00
9
3
(2)
(5)
5
Three Months Ended
March 31
2013 % Change
49
265
(18)
9.25
(15)
9
2014
396
8.26
8
Twelve Months Ended
March 31
2013
510
8.49
9
% Change
156
(4)
(22)
2014
1,305
8.73
7
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%.
10
Management’s Discussion & Analysis
Royalties have decreased in the quarter and year ended March 31, 2014 compared to the prior year and
quarter both on a total dollar and on a boe basis due to the operating and transportation costs allowances,
which has increased on a per boe basis by 6% and 28% for the year and quarter respectively.
Operating & Transportation Expenses
Operating Expenses
($000s)
Operating
Transportation
Operating - $/boe
Transp. - $/boe
Three Months Ended
March 31
2013 % Change
92
531
623
3.56
20.54
24.10
212
114
128
90
30
39
2014
287
1,135
1,422
6.75
26.69
33.44
Twelve Months Ended
March 31
2013 % Change
516
996
1,512
10.27
19.83
30.10
87
310
234
(41)
30
6
2014
965
4,084
5,049
6.11
25.85
31.96
The increase in operating and transportation costs for the current year and quarter were due primarily to
increased production volumes.
Operating costs per barrel stabilized during the year which resulted in an increase of 90% for Q4 2014
compared to the prior year and a decrease of 41% for the 2014 fiscal year compared to the previous year.
Development and appraisal drilling has continued to develop the Cuisinier field which was awarded a
production license during fiscal 2014. This has resulted in increasing operator’s charges for enhanced field
operations, which are partially offset by increasing production.
Transportation costs on a boe basis have increased from prior period due to commissioning of the Cuisinier
to Cook pipeline and subsequent connection of this line to the Cook facility and the Cook to Merrimelia
pipeline, connecting Cuisinier oil from wellhead to tanker to ensure deliverability. The pipeline costs are
marginally higher than costs incurred previously to truck the oil; however this ensures continuous
deliverability.
RESULTS OF OPERATIONS - CANADA
Canadian Operating
Results
Natural Gas Sales
Production(mcf/d)
Realized commodity
prices ($/mcf)
NGL Sales
Production(bbl/d)
Realized commodity
prices ($/bbl)
Royalties
($/boe)
Operating Expenses
($/boe)
Operating Netback
($/boe)
Three Months Ended
March 31
2013 % Change
67
229
3.25
-
-
-
6
1.37
71
18.22
(10)
(2.92)
30
(21)
66
N/A
N/A
N/A
83
61
-
2
N/A
N/A
2014
87
180
5.38
11
2
79.14
11
2.21
71
18.56
16
5.56
2014
274
201
3.74
68
2
87.29
29
3.82
241
26.13
72
5.48
Twelve Months Ended
March 31
2013
172
180
2.61
44
2
57.37
16
1.75
214
20.69
(14)
(1.20)
% change
59
12
43
55
-
52
81
118
13
26
N/A
N/A
Canadian operations are comprised entirely of the Company’s non-operated Oak natural gas field in British
Columbia. This asset is considered non-core and therefore no significant expenditures were allocated to
the Oak field in fiscal 2014, however increased benchmark natural gas prices resulted in marginal
profitability for the asset.
11
BENGAL ENERGY LTD.
General and Administrative (G&A) Expenses and Share Based Compensation (“SBC”)
General and Admin.
Expenses ($000s)
based
G&A - cash
Share
Compensation
Total G&A
Capitalized G&A
Capitalized SBC
Three Months Ended
March 31
2013
863
173
1,036
120
127
% Change
83
(31)
64
8
(20)
2014
1,579
119
1,698
130
101
2014
3,964
650
4,614
421
509
Twelve Months Ended
March 31
2013
3,356
687
4,043
504
487
% Change
18
(5)
14
(16)
5
The 18% increase in cash G&A expenditures for the year and part of the quarterly increase, reflects
increased overhead costs required to manage the Company’s growing exploration and production
portfolios. For the quarter, cash G&A expenses increased $83% due to expansion, the timing of hiring and
salary increase and consulting fees recognized in the fourth quarter of 2014.
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. The decrease in share-based
compensation expense reflects a lower calculated value per option averaged for the year and the quarter
ended March 31, 2014.
Transaction costs of $261,000 (2013 – nil) were incurred during fiscal 2014 relating to the execution of the
Farm-in agreement at ATP 732.
Depletion and Depreciation (DD&A)
DD&A Expenses
($000s)
PNG – Australia
PNG – Canada
Total
$/boe – PNG Australia
$/boe – PNG Canada
$/boe – Total PNG
Three Months Ended
March 31
2013 % Change
77
(30)
73
708
30
738
27.38
8.75
25.20
8
(15)
11
Twelve Months Ended
March 31
2013 % Change
253
(19)
230
1,255
120
1,375
24.98
10.22
22.18
12
(27)
19
2014
4,434
97
4,531
28.07
7.47
26.50
2014
1,253
21
1,274
29.47
7.42
28.09
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, 2014.
The drilling rig was not utilized in the current quarter and therefore there is no depreciation charge.
Impairment
Impairment
($000s)
Three Months Ended
March 31
2013
829
% Change
155
2014
3,101
Twelve Months Ended
March 31
2013
% Change
81
3728
2014
2,111
At March 31, 2014, the Company’s wholly owned Ideco H-44 drilling rig was idle for more than 12 months,
which has been identified as a trigger for impairment. The Company estimated the recoverable amount of
$3.5 million based on a fair value less costs-to-sell methodology using recent market transactions as a fair
value estimate. As a result, the Company recognized a $1.9 million impairment charge during Q4 2014
related to the drilling rig.
12
Management’s Discussion & Analysis
The off-shore India permit, CY-OSN2009/1 is scheduled to expire on August 15, 2014. Management has
no capital allocated to this asset in its current budget and has not been successful in attracting a partner to
share exploration costs, therefore an impairment to exploration and evaluation assets of $1.2 million, which
represents the entire carrying value of this assets and, in addition, a provision for expected costs of
relinquishment, has been recorded.
Finance Income
Finance
Income
($000s)
Three Months Ended
March 31
2013
2
% Change
150
Twelve Months Ended
March 31
2013
% Change
167
(56)
2014
74
2014
5
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
Accretion of VARs
Guarantee fee
Interest on notes payable
Finance expenses
Three Months Ended
March 31
Twelve Months Ended
December 31
2014
2013 % Change
2014
2013 % Change
(3)
52
(64)
71
241
297
2
59
-
16
38
115
(250)
(12)
N/A
344
534
158
(13)
217
(123)
71
777
929
7
59
-
43
38
147
(286)
268
N/A
65
1945
532
The Performance Security Guarantee fee is paid to Export Development Canada and ICICI Bank of India
for security guarantee for onshore and offshore India work programs, to be cancelled on completion or
relinquishment. The increased fee is a result of the budgeted 2014 work program.
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 and the $8.0 million note issued in July of
2013.
13
BENGAL ENERGY LTD.
CAPITAL EXPENDITURES
Capital Expenditures
($000s)
Geological and geophysical
Drilling
Drilling Rig
Completions
Acquisitions
Total oil & gas expenditures
Office
Total expenditures
Exploration & evaluation
Expenditures
Development & production
Expenditures
Property, plant and
equipment
Total net expenditures
Three Months Ended
March 31
Twelve Months Ended
March 31
2013 % Change
$ 190
672
23
395
-
1,280
-
$ 1,280
2014
273 $ 3,137
2,601
(42)
371
N/A
3,574
359
6,964
N/A
16,647
117
-
-
117 $ 16,647
2013
$ 4,232
15,595
4,511
4,023
-
28,361
19
$ 28,380
% Change
(26)
(83)
(92)
(11)
N/A
(41)
N/A
(41)
2014
$ 708
389
371
376
204
2,048
-
$ 2,048
$ 672
$ 303
121 $ 1,963
$ 16,017
1,005
954
5
14,313
7,853
371
$ 2,048
23
$ 1,280
1513
371
60 $ 16,647
4,511
$ 28,381
(88)
82
(92)
(41)
During the year, the Indian seismic program was completed culminating in the selection of three drilling
locations expected to begin drilling in 2014. Geological and geophysical costs also include participation in
the Cuisinier North 3D seismic survey and ongoing seismic interpretation instrumental in selection two
exploration locations expected to be drilled in Cuisinier during 2014.
During fiscal 2014, Cuisinier drilling and completion operations relating to the prior year’s program were
finalized and preliminary work was performed in preparation for Phase One of the 2014 Cuisinier drilling
program, which commenced near the end of March 2014.
In December of 2013, the Company completed the acquisition of additional working interest in production oil
assets located in Cuisinier (Part of the Barta block in Australia).
CONVERTIBLE AND NON-CONVERTIBLE NOTES
The Company issued $1,750,000 in convertible notes and $1,750,000 in non-convertible notes in January
2013 for a term of 180 days. The convertible notes were converted / repaid in July 2013 as further
described in the Related Party section on page 13. The interest rate was prime plus 3% through July 2013.
The non-convertible notes were extended to January 24, 2014 at a rate of 10%.
On July 5, the Company issued $8,000,000 of 10% non-convertible notes with warrants or value
appreciation rights. Each unit consists of $1,000 principal amount of 10% unsecured non-convertible
redeemable notes and either: (i) 156.25 common share purchase warrants, in the case of subscriptions by
non-insiders, or (ii) 156.25 value appreciation rights ("VARs"), in the case of subscriptions by insiders. The
notes bear interest at a rate of 10% per annum, payable quarterly, and have a term of 36 months.
Following the first anniversary of the closing date of the private placement, the Company shall be required
to make quarterly repayments of the outstanding principal of Notes in an amount equal to 6.25% of the
principal amount of notes outstanding on the last day of each applicable quarter. Each whole warrant
entitles the holder thereof, for a period of 36 months following the closing date, to acquire one common
share in the capital of the Company at a purchase price equal to $0.75 per share. Each whole VAR entitles
the holder thereof, for a period of 36 months following the closing date, to exercise the VAR and thereby
receive a cash payment equal to the difference between the market price of one common share on the
exercise date and $0.75. Certain insiders of the Company purchased 3,500 Units and received 546,875
VARs, and 4,500 Units were purchased by non-insiders who received 703,125 warrants.
14
Management’s Discussion & Analysis
SHARE CAPITAL
Bengal has an unlimited number of common shares authorized for issuance. At June 16, 2014, there were
64,692,082 common shares issued and outstanding.
At June 13, 2014, there were 3,623,334 employee stock options outstanding with an average exercise price
of $0.89 per share. Of these, 2,486,672 have vested and are exercisable at an average price of $1.04 per
share. These options expire between June 2016 and January 22, 2019 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
Diluted
Three Months Ended
March 31
2013
0.80
0.50
0.70
3,560
% Change
(23)
(20)
(31)
86
Twelve Months Ended
March 31
2013
1.09
0.49
0.70
18,932
% Change
(28)
(18)
(31)
(45)
2014
0.79
0.40
0.48
10,323
2014
0.62
0.40
0.48
6,621
64,667
52,110
63,446
63,446
52,110
52,110
22
22
22
64,667
52,110
63,134
63,209
52,110
52,110
22
22
22
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2014 the Company had 3.1 million of working capital, including cash and short-term deposits
of $6.0 million and restricted cash of $0.1 million, compared to a working capital deficit of $1.6 million,
including cash and short term deposits of $2.6 million and restricted cash of $0.1 million at March 31, 2013.
Subsequent to year-end, Bengal signed an indicative term sheet for a US $20.0 million secured credit
facility with a leading Australian commercial bank. Once finalized the facility is expected to fully fund
Bengal’s Australian development through March 2015; allowing the Company to fund future planned
exploration activities in India and Australia with internally generated cash flows. In the unlikely event that
this facility is not closed within its expected timeframe, the Company may need to seek additional sources
for financing including other sources of debt, equity or effective dilution of its joint venture interests.
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 supplemented by funds expected upon closing of a secured credit facility are expected to be sufficient
to meet all of its working capital requirements for at least 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.
COMMITMENTS
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
15
BENGAL ENERGY LTD.
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)
Cuisinier (ATP 752 – Barta
permit)
Onshore India – CY-ONN-
2005/1
Two well exploration program
September 30, 2014
$1.7
3 wells
March 3, 2014
(2)
$ 4.2
Offshore India – CY-OSN-
2009/1(3)
310km 2D seismic & 81km
3D seismic
2
August 15, 2014
$ 5.3
(1) Translated at March 31, 2014 at an exchange rate of US $1.0000 = CAD $1.10; AUS $1.00 = CAD $1.02
(2)
If the Company did not participate in the drilling of 3 wells, costs of $5.2 million would be impaired and the Company’s
interest in the permit would decline.
(3) The Company expects to relinquish this permit on or before its expiry date, resulting in an impairment of 100% of the asset’s
carrying value and a provision for expected penalties.
GUARANTEES – INDIA PERMITS
($000s) CAD
CY-OSN-2005/1 – Onshore India
CY-OSN-2009/1 – Offshore India
Total Guarantees
Year Ended
March 31, 2014
1,570
166
$ 1,736
Year ended
March 31, 2013
735
154
889
$
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, 2014, the contractual obligations for which the Company is responsible are as follows:
Contractual Obligations ($000s)
Office lease
Decommissioning obligations
Total
775
358
Less than
1 Year
258
-
$
1-3
Years
517
-
4-5
Years
After
5 Years
$
-
$ −
−
358
$
$
Total contractual obligations
$
1,170
$
258
$
517
$
63
$ 358
CONTINGENCIES
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 kilometers of 2D
seismic and up to seven wells.
Country and Permit
Work Program
Onshore Australia –
ATP 934P
Awaiting Ministerial approval before
granting of ATP
Obligation Period
Ending
4 years after grant of
ATP
Estimated Expenditure
(net) (millions CAD$)
$ 12.4
16
Management’s Discussion & Analysis
RELATED PARTY TRANSACTIONS
On July 5, the Company issued $8.0 million of 10% non-convertible notes with warrants or value
appreciation rights. Members of the Board of Directors of the Company subscribed for approximately 86%
of the principal amount of the notes issued pursuant to the Private Placement.
On January 24, 2014 the Company extended its $1.8 million note payable to January 23, 2015. Members
of the Board of Directors of the Company hold 100% of this facility.
SUBSEQUENT EVENTS
On May 27, 2014 Bengal announced it had entered into an indicative term sheet for a US $20.0 million
secured credit facility (the “Facility”) with a leading Australian commercial bank (the “Lender”). The Facility
contemplates a borrowing base of up to US $20 million, over a three year term at attractive fixed income
market rates tied to USD LIBOR to fund its ongoing Australian development. The Facility remains subject to
the completion of due diligence by the Lender and the entering into of a final Offer to Finance with Bengal
and will remain open for a fixed period to allow Bengal to review other competitive lending proposals that
may be received.
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 income (loss)
Per share – basic and diluted
Cash from operations
Per share – basic and diluted
Funds from operations (1)
Per share – basic and diluted
Notes payable – long term
Total assets
Working capital (deficiency)(2)
(1) See “Non-IFRS Measurements” on page 6 of this MD&A.
(2) Calculated as current assets minus current liabilities.
(3) The Company has no non-current financial liabilities.
2014
468
3.74
123.13
19,822
150
0.00
7,591
0.12
8,183
0.13
6,085
62,425
3,104
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
17
BENGAL ENERGY LTD.
SELECTED QUARTERLY INFORMATION
(000s, except per share amounts)
Mar 31
2014
Dec. 31
2013
Sep. 30
2013
Jun. 30
2013
Mar 31
2013
Dec. 31
2012
Sep. 30
2012
Jun. 30
2012
Petroleum and
natural gas sales
$5,272
$ 5,516
$ 5,312
$ 3,722
$ 3,013 $ 1,937
$
437
$ 498
Cash from
(used in) operations
Per share
Basic and diluted
Funds from (used in)
operations(1)
Per share
Basic and diluted
Net (loss) income
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)
2,106
2,170
2,066
1,249
119
(378)
315
(759)
0.03
0.03
0.03
0.02
(0.00)
(0.01)
0.01
(0.01)
2,218
2,862
2,063
1,732
1,151
481
(471)
(62)
0.03
(1,804)
0.04
573
0.03
0.02
0.03
$ 545 $ 836 $ (592) $
0.01
(151)
(0.01)
0.00
(845) $ (211)
$
(0.03)
2,048
0.01
$6,462
0.01
$ 2,702
0.01
$ 5,435
(0.01)
(0.00)
$ 1,281 $ 9,475
(0.02)
0.00
$ 10,299 $ 7,326
3,104
62,425
3,590
61,353
7,737
62,361
(279)
54,556
(1,647) (1,436)
49,143 47,584
7,578
46,557
18,425
18,425
64,446
64,315
64,315
61,611
52,110 52,110
52,110
52,110
180
474
504
184
200
240
229
110
159
225
465
496
485
518
316
356
72.51 $ 79.82
287
325
$ 69.93
185
203
$ 60.92
38
65
$ 40.07 $
51
89
24.51
74.28 $ 83.13
$
(1) See “Non-IFRS Measurements” on page 7 of this MD&A. The bottom line of this table pops out showing a hefty decline in
netback from the December quarter perhaps we should explain this in the text.
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. These wells were drilled in mid 2012 and started
producing under a six month Extended Production Test in October 2012. The Cuisinier 1, 2 and 3 wells
came back onto production in May 2013 after approval of the Production License. Production started from
Cuisinier 7, 8 and 10 in July 2013 and from Cuisinier 9 and 11 in August 2013 contributing to production
increases. In December of 2013, the Company finalized the acquisition of an additional 5% interest in the
Cuisinier license and this increased production share offset natural declines through March 2014.
The decrease in netbacks from the fiscal third to fourth quarter of 2014 are due primarily to decreased
benchmark crude prices and an increase in the value of the Australian vs. Canadian dollar in which the
Company pays the majority of its royalties and operating costs.
FINANCIAL INSTRUMENTS
Financial instruments comprise cash, restricted cash and short term deposits, accounts receivable and
accounts payable and accrued liabilities. The fair values of these financial instruments approximate their
carrying amounts due to their short-term maturities.
The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange
rates and interest rates in the normal course of operations. A variety of derivative instruments may be used
by the Company to reduce its exposure to fluctuations in commodity prices, foreign exchange rates and
interest rates. The Company does not use derivative instruments at this time.
Financial assets and liabilities are classified as either financial assets or liabilities at fair value through profit
and loss (“FVTPL”), loans and receivables, held to maturity investments, available for sale financial assets,
18
Management’s Discussion & Analysis
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 and notes
payable 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 common
shares and stock options are recognized as a deduction from equity, net of any tax effects.
19
BENGAL ENERGY LTD.
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:
• Management is aware that there is a lack of segregation of duties due to the small number of
employees dealing with general and administrative and financial matters. However, management
believes that at this time the potential benefits of adding employees to clearly segregate duties do
not justify the costs;
• Bengal does not have full-time in-house personnel to address all complex and non-routine financial
accounting issues and tax matters that may arise. It is not deemed as economically feasible at this
time to have such personnel. Bengal relies on external experts for review and advice on complex
financial accounting issues and for tax planning, tax provision and compilation of corporate tax
returns.
These material weaknesses in internal controls over financial reporting result in a reasonable possibility that
a material misstatement will not be prevented or detected on a timely basis. Management and the Board of
20
Management’s Discussion & Analysis
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 judgments, estimates and
assumptions that affect the application of accounting policies and reported amounts of assets and liabilities
and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and
underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are
recognized in the period in which the estimates are revised and in any future periods affected. Significant
estimates and judgments made by management in the preparation of these financial statements are out-
lined below.
Critical judgments in applying accounting policies
The timely preparation of the financial statements requires management to make judgments, estimates and
assumptions that affect the application of accounting policies and reported amounts of assets and liabilities
and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and
underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are
recognized in the period in which the estimates are revised and in any future periods affected. Significant
estimates and judgments made by management in the preparation of these financial statements are out-
lined below.
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.
iii.
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.
iv.
Impairment Indicators
Judgments 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, petroleum and natural gas
properties and PP&E assets required management to make certain judgments 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,
21
BENGAL ENERGY LTD.
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.
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.
NEW ACCOUNTING STANDARDS AND PRONOUNCEMENTS
On April 1, 2013, the Company adopted the following new standards that were effective for annual periods
beginning on or after January 1, 2013. The adoption of these standards resulted in certain additional
disclosure but otherwise had no impact on the amounts recorded in the financial statements as at March 31,
2014 or on the comparative periods.
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
22
Management’s Discussion & Analysis
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.
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.
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.
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.
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 covers the classification and measurement of financial assets as
part of its project to replace IAS 39 “Financial Instruments: Recognition and Measurement.” In October
2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this
guidance, entities have the option to recognize financial liabilities at fair value through earnings. If this
option is elected, entities would be required to reverse the portion of the fair value change due to a
company’s own credit risk out of earnings and recognize the change in other comprehensive income. The
effective date for IFRS 9 has been deferred. Early adoption will still be available and the standard is
required to be applied retrospectively. The Company is currently evaluating the impact of adopting this new
standard
IFRIC 21 - Interpretation of IAS 37 Provisions, contingent liabilities and assets. IAS 37 sets out criteria for
the recognition of a liability, one of which is the requirement for the entity to have a present obligation as a
result of a past event. The interpretation clarifies that the obligation that gives rise to the liability to pay a
levy is the activity described in the relevant legislation that triggers the payment of the levy. The Company is
currently evaluating the impact of this standard.
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
23
BENGAL ENERGY LTD.
natural gas in foreign countries, and its current stage of development. An investor should consider carefully
the risk factors set out below and consider all other information contained herein and in the Company's
other public filings before making an investment decision. Additional risks and uncertainties not currently
known to the management of the Company may also have an adverse effect on Bengal’s business and the
information set out below does not purport to be an exhaustive summary of the risks affecting Bengal.
Exploration, Development and Production Risks
Oil and natural gas exploration involves a high degree of risk, for which even a combination of experience,
knowledge and careful evaluation may not be able to overcome. There is no assurance that expenditures
made on future exploration by Bengal will result in new discoveries of oil or natural gas in commercial
quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the
inherent uncertainties of drilling in unknown formations, the costs associated with encountering various
drilling conditions such as over-pressured zones, tools lost in the hole and changes in drilling plans and
locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.
The long-term commercial success of Bengal will depend on its ability to find, acquire, develop and
commercially produce oil and natural gas reserves. No assurance can be given that Bengal will be able to
locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations
are identified, Bengal may determine that current markets, terms of acquisition and participation or pricing
conditions make such acquisitions or participations uneconomic.
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that
are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other
costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and
operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of
operations, and various field operating conditions may adversely affect the production from successful
wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of
connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or
other geological and mechanical conditions. While diligent well supervision and effective maintenance
operations can contribute to maximizing production rates over time, production delays and declines from
normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and
cash flow levels to varying degrees.
In addition, oil and gas operations are subject to the risks of exploration, development and production of oil
and natural gas properties, including encountering unexpected formations or pressures, premature declines
of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence
of any of these risks could have a materially adverse effect on future results of operations, liquidity and
financial condition.
Bengal attempts to minimize exploration, development and production risks by utilizing a high-end technical
team with extensive experience and multidisciplinary skill sets to assure the highest probability of success
in its drilling efforts. Bengal’s collaboration of a team of seasoned veterans in the oil and gas business, each
with a unique expertise in the various upstream to downstream technical disciplines of prospect generation
to operations, provides the best assurance of competency, risk management and drilling success. A full
cycle economic model is utilized to evaluate all hydrocarbon prospects. Detailed geological and geophysical
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
24
Management’s Discussion & Analysis
existing contracts, restrictions on repatriation of funds, import, export and transportation regulations and
tariffs, taxation policies, including royalty and tax increases and retroactive tax claims, exchange controls,
limits on allowable levels of production, currency fluctuations, labor disputes, sudden changes in laws,
government control over domestic oil and gas pricing and other uncertainties arising out of foreign
government sovereignty over the Company's international operations. With respect to taxation matters, the
governments and other regulatory agencies in the foreign jurisdictions in which Bengal operates and
intends to operate in the future may make sudden changes in laws relating to taxation or impose higher tax
rates, which may affect Bengal’s operations in a significant manner. These governments and agencies may
not allow certain deductions in calculating tax payable that Bengal believes should be deductible under
applicable laws or may have differing views as to values of transferred properties. This can result in
significantly higher tax payable than initially anticipated by Bengal. In many circumstances, readjustments to
tax payable imposed by these governments and agencies may occur years after the initial tax amounts
were paid by Bengal, which can result in the Company having to pay significant penalties and fines.
Furthermore, in the event of a dispute arising from international operations, the Company may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the
jurisdiction of courts in Canada.
Prices, Markets and Marketing of Crude Oil and Natural Gas
Oil and natural gas are commodities that have prices determined based on world demand, supply and other
factors, all of which are beyond the control of Bengal. World prices for oil and natural gas have fluctuated
widely in recent years. Any material decline in prices could result in a reduction of net production revenue.
Certain wells or other projects may become uneconomic as a result of a decline in world oil prices and
natural gas prices, leading to a reduction in the volume of Bengal’s oil and gas reserves. Bengal might also
elect not to produce from certain wells at lower prices. All of these factors could result in a material
decrease in Bengal’s future net production revenue, causing a reduction in its oil and gas acquisition and
development activities. In addition to establishing markets for its oil and natural gas, Bengal must also
successfully market its oil and natural gas to prospective buyers. The marketability and price of oil and
natural gas, which may be acquired or discovered by Bengal, will be affected by numerous factors beyond
its control. The ability of Bengal to market its natural gas may depend upon its ability to acquire space on
pipelines that 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
25
BENGAL ENERGY LTD.
if the risk profile dictates that Bengal wishes to hold a lesser working interest position. Equity, if available
and if on favorable terms, may be utilized to help fund Bengal’s capital program.
Health, Safety and Environment
All phases of the oil and natural gas business present environmental risks and hazards and are subject to
environmental regulation pursuant to a variety of federal, provincial and local laws and regulations.
Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases
or emissions of various substances produced in association with oil and natural gas operations. The
legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to
the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant
expenditures and a breach of applicable environmental legislation may result in the imposition of fines and
penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement,
larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of
oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and
third parties and may require the Company to incur costs to remedy such discharge.
Insurance
Bengal’s involvement in the exploration for and development of oil and gas properties may result in the
Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other
hazards. Although Bengal has insurance in accordance with industry standards to address such risks, such
insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In
addition, such risks may not, in all circumstances be insurable or, in certain circumstances, Bengal may
elect not to obtain insurance to deal with specific risks due to the high premiums associated with such
insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to
Bengal. The occurrence of a significant event that Bengal is not fully insured against, or the insolvency of
the insurer of such event, could have a material adverse effect on Bengal’s financial position, results of
operations or prospects.
Competition
Bengal actively competes for reserve acquisitions, exploration leases, licenses and concessions and skilled
industry personnel with a substantial number of other oil and gas companies, many of which have
significantly greater financial and personnel resources than Bengal. Bengal's competitors include major
integrated oil and natural gas companies and numerous other independent oil and natural gas companies
and individual producers and operators.
Bengal’s ability to successfully bid on and acquire additional property rights, to discover reserves, to
participate in drilling opportunities and to identify and enter into commercial arrangements with customers
will be dependent upon developing and maintaining close working relationships with its future industry
partners and joint operators and its ability to select and evaluate suitable properties and to consummate
transactions in a highly competitive environment.
ADDITIONAL INFORMATION
Additional information relating to Bengal is filed on SEDAR and can be viewed at www.sedar.com.
Information can also be obtained by contacting the Company at Bengal Energy Ltd., Suite 1810, 801 6th
Avenue SW., Calgary, Alberta T2P 3W2, by email to info@bengalenergy.ca or by accessing Bengal’s
website at www.bengalenergy.ca.
26
Management’s Discussion & Analysis
Forward-looking Statements - Certain statements contained within the Management’s Discussion and Analysis, and
in certain documents incorporated by reference into this document, constitute forward-looking statements. These
statements relate to future events or Bengal’s future performance. All statements other than statements of historical fact
may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of
words such as "seek,” "anticipate,” "budget,” "plan,” "continue,” "estimate,” "expect,” "forecast,” "may,” "will,” "project,”
"predict,” "potential,” "targeting,” "intend,” "could,” "might,” "should,” "believe" and similar expressions. These statements
involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ
materially from those anticipated in such forward-looking statements. Bengal believes the expectations reflected in
those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to
be correct and such forward-looking statements included in, or incorporated by reference into, this MD&A should not be
unduly relied upon.
In particular, this Management’s Discussion and Analysis, and the documents incorporated by reference, contain
forward-looking statements pertaining to the following:
●
●
●
●
•
●
●
●
●
●
●
●
●
●
●
Oil and natural gas production levels;
The size of the oil and natural gas reserves;
Projections of market prices and costs;
Expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and
development;
Expectations that cash generation to increase throughout the coming year
Treatment under governmental regulatory regimes and tax laws;
Capital expenditures programs and estimates of costs;
Completion of the four development wells is anticipated to run from mid-July through early August 2014, with
the wells expected to be tied in through September 2014.
Funding of working capital requirements, commitments and other planned expenses will be by cash on hand,
cash flows, farm-outs, joint ventures or share issues and funds will be sufficient to meet requirements;
Expectations that cash flow from the new production volumes to begin in the fourth quarter of calendar 2014;
Expectation of the drilling of a exploration at ATP 752 well in calendar Q3 2014;
Obtaining Ministerial Grant of the tenement on ATP 934P in Australia and commencement of exploration
activities;
Expectation that the selection of three drilling locations in India expected to begin drilling in 2015
That Beach Energy will perform the work agreed to under the Farm-out and that further drilling activities on
ATP 732P will occur in the second half of calendar 2014;
That the wells drilled on ATP 752P will be completed and tied-in and that these wells will commence
production and that production from all wells will continue as expected.
With respect to the forward looking statements contained in the MD&A, Bengal has made assumptions regarding: future
commodity prices; the impact of royalty regimes; the timing and the amount of capital expenditures; production of new
and existing wells and the timing of new wells coming on stream; future operating expenses including processing and
gathering fees; the performance characteristics of oil and natural gas properties; the size of oil and natural gas
reserves; the ability to raise capital; the continued availability of undeveloped land and skilled personnel; the ability to
obtain equipment in a timely manner to carry out exploration and development activities; the ability to obtain financing
on acceptable terms; the ability to add production and reserves through exploration and development activities; and the
continued stability of political, regulatory; tax and fiscal regimes in which the Company has operations.
The actual results could differ materially from those anticipated in these forward-looking statements as a result of the
risk factors set forth below and elsewhere in this Management’s Discussion and Analysis:
●
●
●
Volatility in market prices for oil and natural gas;
Liabilities inherent in oil and natural gas operations;
Uncertainties associated with estimating oil and natural gas reserves;
27
BENGAL ENERGY LTD.
●
●
●
●
●
●
●
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.
28
Consolidated Financial Statements
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, 2014. 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
The consolidated
recommendation of the Audit Committee.
financial statements have been approved by
the Board of Directors on
(signed) “ Chayan Chakrabarty”
Chayan Chakrabarty
President & Chief Executive Officer
(signed) “ Jerrad Blanchard”
Jerrad Blanchard
Chief Financial Officer
29
BENGAL ENERGY LTD.
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, 2014 and March 31, 2013, the
consolidated statements of income (loss) and comprehensive income (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, 2014 and March 31, 2013, and its consolidated
financial performance and its consolidated cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered Accountants
June 13, 2014
Calgary, Canada
30
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Thousands of Canadian dollars)
Consolidated Financial Statements
As at March 31,
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
Current portion of notes payable
Non-current liabilities:
Decommissioning liability
Notes payable
Other long-term liabilities
Shareholders’ equity:
Share capital
Contributed surplus
Warrants
Equity component convertible debenture
Accumulated other comprehensive income
Deficit
Total liabilities and shareholders’ equity
Commitments and contingencies (note 18)
Subsequent event (note 21)
Notes
2014
2013
5
6
7
8
10
11
10
10
12
10
10
$
$
$
5,984
140
3,821
490
10,435
26,821
21,669
3,500
51,990
62,425
4,174
3,158
7,332
358
6,085
61
6,504
$
$
$
2,614
140
3,550
110
6,414
26,416
11,630
4,683
42,729
49,143
4,622
3,439
8,061
320
-
-
320
93,151
7,141
167
-
1,536
(53,406)
48,589
62,425
$
86,246
6,466
-
25
1,581
(53,556)
40,762
49,143
$
See accompanying notes to the consolidated financial statements.
On behalf of the Board:
Director
Chayan Chakrabarty
Director
James B. Howe
31
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Thousands of Canadian dollars, except per share amounts)
For the years ended March 31,
Notes
2014
2013
5,885
(526)
5,359
3,466
-
1,726
1,448
80
487
7,207
(1,848)
167
(133)
7
41
(1,807)
8
(1,799)
864
(935)
19,822
(1,334)
18,488
3,822
261
5,290
4,531
3,101
498
17,503
985
74
(929)
(35)
(890)
95
55
150
(45)
105
0.00
(0.03)
63,134
63,209
52,110
52,110
Income
Petroleum and natural gas revenue
Royalties
Operating expenses
General and administrative
Transaction costs
Operating and transportation
Depletion and depreciation
Pre-licensing & impairment
Share-based compensation
Operating income (loss)
Other income (expenses)
Finance income
Finance expenses
Foreign exchange (loss) gain
Net income (loss) before income tax
Deferred income tax recovery
Net income (loss)
Exchange differences on translation of foreign operations
Total comprehensive income (loss) for the year
Earnings (loss) per share
- Basic & Diluted
7,8
6,8
14
9
12
Weighted average number of shares outstanding (000s)
12
- Basic
- Diluted
See accompanying notes to the consolidated financial statements.
32
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Thousands of Canadian dollars)
Consolidated Financial Statements
Shares
outstanding
Share
capital Warrants
Contributed
surplus
Equity
component of
convertible
debentures
Accumulated
other
comprehensive
income
Total
shareholders’
equity
Deficit
52,110,177
$
86,246
$
−
$
5,779
$
−
$
717
$
(51,757)
$ 40,985
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
487
200
-
-
-
-
-
25
-
(1,799)
(1,799)
864
-
864
-
-
-
-
-
-
487
200
25
52,110,177
$
86,246
$
−
$
6,466
$
25
$ 1,581 $
(53,556)
$ 40,762
52,110,177
$
86,246
$
−
$
6,466
$
25
$ 1,581 $
(53,556)
$ 40,762
12,556,905
7,327
(422)
498
152
167
25
64,667,082
93,151
167
7,141
(25)
-
150
(45)
150
(45)
7,327
(422)
498
152
167
1,536
53,406
48,589
Balance at
April 1, 2012
Net loss for the year
Comprehensive income
for the year
Share-based
compensation –
expensed
Share-based
compensation –
capitalized
Convertible notes issued
Balance at
March 31, 2013
Balance at
April 1, 2013
Net loss for the year
Comprehensive income
(loss) for the year
Issuance of common
shares
Share issue costs
Share-based
compensation –
expensed
Share-based
compensation –
capitalized
Warrants
Balance at
March 31, 2014
See accompanying notes to the consolidated financial statements.
33
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Canadian dollars)
For the years ended March 31
Notes
2014
2013
Operating activities
Net income (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
Change in non-cash working capital
Net cash from (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 debt, net of issuance costs
Repayment of convertible debt
Changes in non-cash working capital
Net cash from financing activities
Impact of foreign exchange
on cash and cash equivalents
Net increase (decrease) in cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
See accompanying notes to consolidated financial statements.
$
150
$
(1,799)
4,531
3,101
(8)
93
498
(55)
(127)
8,183
(592)
7,591
(1,963)
(14,313)
(371)
-
(808)
(17,455)
5,405
7,743
(250)
(5)
12,893
341
1,448
927
7
45
487
(8)
(8)
1,099
(1,802)
(703)
(16,017)
(7,853)
(4,511)
(5)
1,107
(27,279)
−
3,461
-
38
3,499
163
$
$
3,370
$
(24,320)
2,614
5,984
$
26,934
2,614
17
17
12
10
10
17
34
Notes to Consolidated Financial Statements (the “financial statements”)
Years ended March 31, 2014 and 2013
(Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)
Notes to Consolidated Financial Statements
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 and production of oil and gas reserves in
Australia, India and Canada. The consolidated financial statements (the “financial statements”) of the
Company as at March 31, 2014 and 2013 and for the years ended March 31, 2014 and 2013 are
comprised of the Company and its wholly owned subsidiaries Bengal Energy International Inc., Bengal
Energy Australia (Pty) Ltd., Avery Resources (Northern Ireland) Ltd. and Northstar Energy Pty Ltd.
respectively 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 13, 2014.
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.
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.
35
BENGAL ENERGY LTD.
The Company recognizes in its financial statements its proportionate share of the assets, liabilities,
revenues, and expenses of its joint operations.
All intra-group transactions, balances, income and expenses are eliminated in full on consolidation.
(b) Cash and cash equivalents
Cash and cash equivalents include cash and all investments with a maturity of three months or
less.
(c) Provisions
A provision is recognized if, as a result of a past event, the Company has a present legal or
constructive obligation that can be estimated reliably, and it is probable that an outflow of economic
benefits will be required to settle the obligation. Provisions are determined by discounting the
expected future cash flows at a pre-tax “risk-free” rate that reflects current market assessments of
the time value of money and the risks specific to the liability. The unwinding of the discount is
recognized as a finance expense. Provisions are not recognized for future operating losses.
Decommissioning and restoration liabilities:
The Company’s activities give rise to dismantling, decommissioning and site disturbance
remediation activities. Provision is made for the estimated cost of site restoration and capitalized in
the relevant asset category.
Decommissioning obligations are measured at the present value of management’s best estimate of
the expenditures required to settle the present obligation at the period end date. Subsequent to the
initial measurement, the obligation is adjusted at the end of each period to reflect the passage of
time and changes in the estimated future cash flows underlying the obligation. The increase in the
provision due to the passage of time is recognized as finance costs whereas increases/decreases
due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon
settlement of the asset retirement obligations are charged against the provision to the extent the
provision was established.
(d) Oil and natural gas exploration and evaluation expenditures
Exploration and evaluation costs (“E&E” assets”)
All costs incurred prior to obtaining the legal right to explore an area are expensed when incurred.
Generally, costs directly associated with the exploration and evaluation of crude oil and natural gas
reserves are initially capitalized. Exploration and evaluation costs are those expenditures for an
area where technical feasibility and commercial viability has not yet been demonstrated. These
costs generally include unproved property acquisition costs, geological and geophysical costs,
sampling and appraisals, drilling and completion costs and capitalized decommissioning costs.
Costs are held in exploration and evaluation until the technical feasibility and commercial viability of
the project is established. Amounts are generally reclassified to petroleum and natural gas
properties once probable reserves have been assigned to the field. If probable reserves have not
been established through the completion of exploration and evaluation activities and there are no
future plans for activity in that field, then the exploration and evaluation expenditures are
determined to be impaired and the amounts are charged to profit or loss.
(e) Petroleum and natural gas properties
Carrying value
36
Notes to Consolidated Financial Statements
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 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.
(g) Impairment
E&E and Petroleum and Natural Gas Properties
E&E assets are assessed for impairment when facts and circumstances suggest that the carrying
amount exceeds the recoverable amount and when they are reclassified to Development and
37
BENGAL ENERGY LTD.
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 inflows that are largely independent of the cash flows of other groups of assets. If any such
indication of impairment exists, the Company makes an estimate of its recoverable amount. A
CGUs recoverable amount is the higher of its fair value less selling costs and its value in use. In
assessing value in use, the estimated future cash flows are discounted to their present value using
a pre-tax discount rate that reflects current market assessments of the time value of money and the
risks specific to the asset. Value in use is generally computed by reference to the present value of
future cash flows expected to be derived from the production of proved and probable reserves.
Fair value less cost to sell is determined as the amount that would be obtained from the sale of a
CGU in an arm’s length transaction between knowledgeable and willing parties. The fair value less
cost to sell of oil and gas assets is generally determined as the net present value of the estimated
future cash flows expected to arise from the continued use of the CGU, including any expansion
prospects, and its eventual disposal, using assumptions that an independent market participant may
take into account. These cash flows are discounted by an appropriate discount rate, which would be
applied by such a market participant to arrive at a net present value of the CGU. Where the carrying
amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written
down. Consideration is given to acquisition metrics or recent transactions completed on similar
assets to those contained with the relevant CGU.
When the recoverable amount is less than the carrying amount, the asset or CGU is impaired. For
impairment losses identified based on a CGU, the loss is allocated on a pro rata basis to the assets
within the CGU(s). The impairment loss is recognized as an expense in profit or loss.
At the end of each subsequent reporting period these impairments are assessed for indicators of
reversal. Where an impairment loss subsequently reverses, the carrying amount of the asset or
CGU is increased to the revised estimate of its recoverable amount, but so that the increased
carrying amount does not exceed the carrying amount that would have been determined had no
impairment loss have been recognized for the asset or CGU in prior years. A reversal of an
impairment loss is recognized immediately in profit or loss.
Gains and losses on disposal of an item of property, plant and equipment, including oil and natural
gas interests, are determined by comparing the proceeds from disposal with the carrying amount of
property, plant and equipment and are recognized as separate line items in profit or loss.
Property and Equipment
At the end of each reporting period, the Company reviews property and equipment for
circumstances that indicate that the assets may be impaired. If any such indication of impairment
exists, the Company makes an estimate of its recoverable amount, which is the higher of its fair
value less selling costs and its value in use.
Fair value less cost to sell is determined as the amount that would be obtained from the sale of an
asset in an arm’s length transaction between knowledgeable and willing parties. Consideration is
given to recent transactions related to similar assets.
When the recoverable amount is less than the carrying amount, the asset is impaired and the
38
Notes to Consolidated Financial Statements
resulting 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 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 in prior years. A reversal of an impairment loss is
recognized immediately 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 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
and notes payable are classified as other financial liabilities, which are measured at amortized cost.
(ii)
Derivative
financial
instruments
39
BENGAL ENERGY LTD.
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
common shares and stock options are recognized as a deduction from equity, net of any tax effects.
(i) 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.
(j) 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.
(k) 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
40
Notes to Consolidated Financial Statements
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.
(l) Per share amounts:
Basic per share amounts are computed by dividing net income (loss) by the weighted average
number of common shares outstanding for the period. Diluted per share amounts are calculated
giving effect to the potential dilution that would occur if stock options or other dilutive instruments
were exercised into common shares. The treasury stock method assumes that any proceeds upon
the exercise of dilutive instruments, including remaining unamortized compensation costs, would be
used to purchase common shares at the average market price of the common shares during
the period.
(m) 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.
(n) 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.
(o) 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.
41
BENGAL ENERGY LTD.
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, 2014 and March 31, 2013 the fair
value of these balances approximated their carrying value due to their short term to maturity.
2) The fair value of employee stock options, warrants, and value appreciation rights are 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 behaviour), expected dividends, and the risk-free interest rate (based on
government bonds).
3) The fair value of notes payable is estimated as the present value of future cash flows,
discounted at the market rate of interest at the reporting date. At March 31, 2014 and March 31,
2013 the fair value of these balances approximated their carrying value due to their short term
to maturity
(p) Adoption of new accounting policies
On April 1, 2013, the Company adopted the following new standards that were effective for annual
periods beginning on or after January 1, 2013. The adoption of these standards resulted in certain
additional disclosure but otherwise had no impact on the amounts recorded in the financial
statements as at March 31, 2014 or on the comparative periods.
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.
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 Ventures.
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.
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.
(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 covers the classification and measurement of financial
assets as part of its project to replace IAS 39 “Financial Instruments: Recognition and
Measurement.” In October 2010, the requirements for classifying and measuring financial liabilities
42
Notes to Consolidated Financial Statements
were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities
at fair value through earnings. If this option is elected, entities would be required to reverse the
portion of the fair value change due to a company’s own credit risk out of earnings and recognize
the change in other comprehensive income. The effective date for IFRS 9 has been deferred. Early
adoption will still be available and the standard is required to be applied retrospectively. The
Company is currently evaluating the impact of adopting this new standard
IFRIC 21 - Interpretation of IAS 37 Provisions, contingent liabilities and assets. IAS 37 sets out
criteria for the recognition of a liability, one of which is the requirement for the entity to have a
present obligation as a result of a past event. The interpretation clarifies that the obligation that
gives rise to the liability to pay a levy is the activity described in the relevant legislation that triggers
the payment of the levy. The Company is currently evaluating the impact of this standard.
4. MANAGEMENT JUDGMENTS AND ESTIMATES
The timely preparation of the financial statements requires management to make judgments,
estimates and assumptions that affect the application of accounting policies and reported amounts
of assets and liabilities and income and expenses. Accordingly, actual results may differ from these
estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to
accounting estimates are recognized in the period in which the estimates are revised and in any
future periods affected. Significant estimates and judgments made by management in the
preparation of these financial statements are out-lined below.
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
Judgments 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,
petroleum and natural gas properties and PP&E assets required management to make certain
judgments 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
43
BENGAL ENERGY LTD.
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.
iii) Current and Deferred 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.
Judgments are made by management to determine the likelihood of whether deferred tax assets at
the end of the reporting period will be realized from future taxable earnings.
The deferred tax asset is based on estimates as to the timing of the reversal of temporary
differences, substantively enacted tax rates and the likelihood of assets being realized.
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: share price, expected lives of
options, risk-free rates of return, share price volatility and the estimated forfeiture rate. Changes to
assumptions may have a material impact on the amounts presented.
44
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:
Notes to Consolidated Financial Statements
As at ($000s)
Cash and bank balances
Short-term deposits
$
March 31, 2014
5,164
820
5,984
$
$
March 31, 2013
2,614
-
2,614
$
6. EXPLORATION AND EVALUATION ASSETS (E&E ASSETS)
($000s)
Balance at April 1, 2012
Additions
Capitalized share based compensation
E&E impairment loss
Exchange adjustments
Balance at March 31, 2013
Additions
Capitalized share based compensation
E&E impairment loss
Exchange adjustments
Balance at March 31, 2014
Exploration and Evaluation
Expenditures
$
$
10,526
16,017
166
(927)
634
26,416
1,963
59
(1,367)
(250)
26,821
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 off-shore India permit, CY-OSN2009/1 is scheduled to expire on August 15, 2014. Management
has no capital allocated to this asset and has not been successful in attracting a partner to share
exploration costs, therefore an impairment to exploration and evaluation assets of $1.0 million, which
represents the entire carrying value of this assets and a provision for expected costs of relinquishment,
has been recorded.
45
BENGAL ENERGY LTD.
A summary of E&E assets is shown in the table below:
($000s)
ATP 732P – Tookoonooka – Note 1
CY-ONN-2005/1 – onshore
CY-OSN-2009/1 − offshore
Other – Note 2
March 31, 2013 ($000)
ATP 732P – Tookoonooka – Note 1
CY-ONN-2005/1 – onshore
CY-OSN-2009/1 − offshore
Other – Note 2
March 31, 2014 ($000)
Australia
$ 19,385
-
-
1,886
$ 21,271
Australia
$ 20,126
-
-
1,423
$ 21,549
$
India
-
4,312
833
-
$ 5,145
Exploration and Evaluation Assets
Total
$ 19,385
4,312
833
1,886
$ 26,416
Exploration and Evaluation Assets
Total
$ 20,126
5,272
-
1,423
$ 26,821
India
-
5,272
-
-
$ 5,272
$
Note 1: The Company entered into a farm-out agreement that requires a 2 well drilling program of which one remains to be
drilled at March 31, 2014. Once the final well is drilled, the joint venture partner will earn a 50% interest in this permit and the
Company will record a gain or loss on this 50% disposition.
Note 2: Other includes ATP 934P, capitalized G&A and stock-based compensation and foreign exchange effects on assets
denominated in foreign currencies.
46
7. PETROLEUM AND NATURAL GAS PROPERTIES
Notes to Consolidated Financial Statements
$000s
Cost:
Balance at April 1, 2012
Additions and acquisitions
Capitalized share based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2013
Additions
Acquisitions
Capitalized share based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2014
Accumulated depletion, depreciation and
impairment losses:
Balance at April 1, 2012
Depletion and depreciation charge
Exchange adjustments
Balance at March 31, 2013
Depletion and depreciation charge
Exchange adjustments
Balance at March 31, 2014
Net carrying value
At March 31, 2013
At March 31, 2014
Petroleum and
Natural Gas
Properties
Corporate
Assets
$000s
$
5,497
7,727
19
85
482
13,810
7,448
6,964
93
38
51
28,404
$
$
301
126
-
-
-
427
(99)
-
(10)
318
Total
$000s
5,798
7,853
19
85
482
14,237
7,349
6,964
93
120
41
28,722
Petroleum and
Natural Gas
Properties
$000s
Corporate
Assets
$ 000s
$
975
1,300
172
2,447
4,455
(83)
6,819
$
88
75
(3)
160
76
(2)
234
Total
$000s
1,063
1,375
169
2,607
4,531
(85)
7,053
$
$ 11,363
$ 21,585
$
$
267
84
$ 11,630
$ 21,669
The calculation of depletion for the year ended March 31, 2014 included $83.5 million and $0.5 million
for estimated future development costs associated with proved and probable reserves in Australia and
Canada respectively (March 31, 2013 - $31.1 million and $0.5 million).
Bengal closed its agreement to acquire an incremental 5.357% working interest in the Cuisinier oil field
on December 18, 2013 for a purchase price of AUS $7.5 million / C$ 7.2 million less final closing
adjustments currently estimated at $0.6 million. The Acquisition also includes a further 8.08% interest
in the Wompi Block (ATP 752), resulting in working interests in those two projects of 30.357% and
38.08% respectively. The acquisition was accounted for as a business combination under IFRS 3 –
“Business Combinations” and had the acquisition closed on April 1, 2013, the Company estimates that
its pro forma revenue and earnings before tax for the nine month period ended December 31, 2013
would have been $17.4 million and $3.9 million respectively. Between the acquisition closing date and
December 31, 2013, approximately $44,000 of production revenue and $13,000 of earnings before tax
were recognized relating to the acquired properties.
47
BENGAL ENERGY LTD.
$000s
Net assets acquired
Decommissioning liabilities
Total net assets acquired
Consideration
6,760
(44)
6,716
6,716
$
8. PROPERTY, PLANT AND EQUIPMENT
($000s)
Rig Equipment
Balance at March 31, 2012
Additions
Capitalized share-based compensation
Balance at March 31, 2013
Additions
Balance at March 31, 2014
Accumulated depletion, depreciation and impairment losses:
Balance at March 31, 2013
Impairment
Balance at March 31, 2014
Net book value
Balance at March 31, 2013
Balance at March 31, 2014
$
230
4,511
15
$ 4,756
371
5,127
$
73
1,557
$ 1,627
$
$
4,683
3,500
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 were 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, 2014, the drilling rig had been idle for more than 12 months, which has been identified as
a potential trigger for impairment. The Company estimated the recoverable amount of $3.5 million
based on a fair value less costs-to-sell methodology using recent market transactions as a fair value
estimate. As a result, the Company recognized a $1.6 million impairment charge during Q4 2014
related to the drilling rig.
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)
Income (loss) before taxes
Statutory tax rate
Expected income tax (expense) recovery
Foreign exchange
Stock-based compensation
Effect of change in tax rate & other
Changes in unrecognized tax asset
Income tax recovery
48
2014
95
25%
(24)
83
(121)
(311)
428
55
2013
(1,807)
25%
452
(14)
(124)
(118)
(188)
8
$
$
$
The temporary deductible differences included in the Company’s unrecognized deferred income tax
assets are as follows:
Notes to Consolidated Financial Statements
As of March 31 ($000s)
Non-capital losses
Net capital losses
P&NG properties
Share issue costs
Decommissioning obligations
2014
$ 26,395
6,033
5,033
720
358
$ 38,539
2013
28,144
5,998
3,939
765
320
39,166
$
$
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
2014
12,737
331
(13,068)
$ -
2013
9,668
339
(10,007)
−
$
$
At March 31, 2014, the Company had approximately $23.7 million and $46.5 million of non-capital
losses in Canada and Australia respectively (2012 - $18.5 million and $43.0 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, 2014, the Company has no deferred tax liabilities
in respect of these temporary differences.
10. CONVERTIBLE AND NON-CONVERTIBLE NOTES
January 25, 2013
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.
July 18, 2013
On July 18, 2013, $1.5 million of the Convertible Notes were converted into 2,678,572 common shares
of the Company at a conversion price of $0.56 per share. On July 22, 2013 the remaining $250,000 of
outstanding Convertible Notes were repaid. On April 18, 2013 the Non-convertible Note Holders
agreed to extend the term of the Note from July 24, 2013 to January 24, 2014 at which time the Non-
convertible Notes were extended further to January 24, 2015. As consideration for the extension the
Company has agreed to increase the interest rate payable on the Notes to 10% effective July 25, 2013.
The fair value of the debt approximates the carrying value, therefore no adjustment was recognized on
either extension.
49
BENGAL ENERGY LTD.
Convertible Note
Gross proceeds
Accretion on debt
Conversion of debt
Repayment of debt
Transfer to contributed surplus
Balance at March 31, 2014
Non-Convertible Note
Balance at March 31, 2013
Accretion on debt
Balance at March 31, 2014
Total
$000s
1,745
30
(1,500)
(250)
(25)
-
Liability
component
$ 000s
1,720
30
(1,500)
(250)
-
-
Equity
Component
$000s
25
-
-
-
(25)
-
Total
$000s
1,720
30
$1,750
On July 5, 2013 the Company closed a non-brokered private placement of 8,000 units at a price of
$1,000 per unit for aggregate gross proceeds of $8.0 million. The proceeds from the private placement
were used to fund the Company's purchase of an additional 5.357% interest in its Cuisinier property,
located in the Cooper-Eromanga Basin in Queensland, Australia. The acquisition had an effective date
of March 15, 2013 and closed on December 18, 2013.
Each unit consists of $1,000 principal amount of 10% unsecured non-convertible redeemable notes and
either: (i) 156.25 common share purchase warrants, in the case of subscriptions by non-insiders, or (ii)
156.25 value appreciation rights ("VARs"), in the case of subscriptions by insiders. The notes bear
interest at a rate of 10% per annum, payable quarterly, and have a term of 36 months. Following the
first anniversary of the closing date of the private placement, the Company shall be required to make
quarterly repayments of the outstanding principal of Notes in an amount equal to 6.25% of the principal
amount of notes outstanding on the last day of each applicable quarter. Each whole warrant entitles the
holder thereof, for a period of 36 months following the closing date, to acquire one common share in the
capital of the Company at a purchase price equal to $0.75 per share. Each whole VAR entitles the
holder thereof, for a period of 36 months following the closing date, to exercise the VAR and thereby
receive a cash payment equal to the difference between the market price of one common share on the
exercise date and $0.75. Certain insiders of the Company purchased 3,500 Units and received
546,875 VARs, and 4,500 Units were purchased by non-insiders who received 703,125 warrants.
The warrants are valued based on the following key assumptions: a term of 3 years, volatility of 73%
and a price of $0.75/share, which is equivalent to the preliminary VAR valuation.
50
Notes to Consolidated Financial Statements
Non-Convertible Note – Issued
July 5, 2013
Gross proceeds
Total cash fees
Accretion on debt/Change in fair
value of VARs
Deferred tax impact
Balance at March 31, 2014
Total
$000s
$ 8,000
(257)
7,743
33
(55)
$ 7,721
Debt
Component
$000s
$ 7,593
(256)
7,337
156
Other long term
liability
$000s
$ 178
6
184
(123)
Warrants
$000s
$ 229
(7)
222
-
-
$ 7,493
-
$ 61
(55)
$ 167
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
Accretion
Exchange adjustments
Decommissioning liabilities, end of year
March 31, 2014 March 31, 2013
228
(55)
140
7
$
$ 320
(82)
120
8
(8)
$ 358
$
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, 2014 is approximately
$567,000 (March 31, 2013 – $421,000) which will be incurred between 2015 and 2038. An inflation
factor ranging between 1.0% and 2.5% and a risk free discount rate ranging between 1.5% and 4.1%
have been applied to the decommissioning liability at March 31, 2014.
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 March 31, 2012 and 2013
Shares issued for cash
Issued on conversion of convertible
debentures
Issued on exercise of stock options for cash
Issued on cashless exercise of stock options
Share issue costs
At March 31, 2014
Number of Shares
52,110,177
9,500,666
$
Amount
86,246
5,700
2,678,572
351,667
26,000
-
64,667,082
1,500
127
-
(422)
93,151
On April 16, 2013 the Company issues a total of 9,5000,666 Common Shares at a price of $0.60
per Common Share for aggregate gross proceeds of $5.7 million. The Company paid the Agents a
cash commission of $0.3 million. A total of 2,400,300 shares of the Offering were purchase by
insiders of the Company.
51
BENGAL ENERGY LTD.
On July 18, 2013 1$1.5 million of convertible debentures were converted into 2,678,572 Common
Shares at a price of $0.56 per common share.
(c) 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.
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 March 31, 2012
Granted
Expired
Forfeited
Outstanding at March 31, 2013
Granted
Forfeited
Expired
Exercised
Outstanding at March 31, 2014
Exercisable at March 31, 2014
Options
3,611,665
1,150,000
(416,667)
(148,333)
4,196,665
1,195,000
(270,001)
(846,664)
(401,667)
3,873,333
2,520,005
$
Weighted Average
Exercise Price
1.14
0.58
1.30
1.11
0.98
0.62
0.71
1.23
0.36
0.89
1.04
$
$
Options Outstanding
Options Exercisable
Option Price (1)
$0.47 - $0.65
$0.66 - $1.25
$1.26 - $1.32
Total
Number
Outstanding
2,063,333
1,230,000
580,000
3,873,333
Exercise
Price (2)
$0.60
$1.17
$1.32
0.91
Remaining
Life (3)
4.07
2.92
2.25
Number
Exercisable
710,005
1,230,000
580,000
3.43
2,520,005
Exercise
Price (2)
$0.60
$1.17
$1.32
1.04
(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:
52
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
Notes to Consolidated Financial Statements
March 31,
2014
March 31,
2013
2.0%
5 yr
73%
7.1%
$0.37
$0.62
2.0%
5 yr
86%
6.5%
$0.40
$0.58
(1)
Expected volatility is estimated by considering historic average share price volatility.
The fair value of stock options granted during the year ended March 31, 2014 was $417,000 (2013
- $454,000).
(d) Per share amounts:
Income (loss) per share is calculated based on net income (loss) and the weighted-average number
of common shares outstanding.
For the Year Ended ($000s)
Income (loss) for the year
Weighted average number of common shares (basic)
Weighted average number of common shares (diluted)
Basic and diluted income (loss) per share
March 31,
2014
150
63,134
63,209
0.00
March 31,
2013
(1,799)
52,110
52,110
(0.03)
At March 31, 2014, there were 2,683,000 (March 31, 2013 – 4,196,665) options considered anti-
dilutive. In addition, there were 703,125 warrants and 546,875 value appreciation rights 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
2014
$ 930
208
$ 1,138
$
$
2013
822
496
1,318
(1) Represents the amortization of share based payment expense associated with the Company’s share based compensation plans
granted to key management personnel.
Salaries and benefits for the year ended March 31, 2014 include a non-recurring retirement payment to
former employees of $0.2 million (2013 - $nil).
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 and change in
fair value of VARs
Finance expenses
2014
$ 8
72
756
93
$ 929
$
$
2013
7
43
38
45
133
(1) Fees paid to Export Development Canada and ICICI Bank for security guarantees for onshore and offshore India work programs.
53
BENGAL ENERGY LTD.
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 notes payable. The fair values of these financial
instruments approximate their carrying amounts due to their short-term maturities, with the
exception of notes payable. The fair value of notes payable is estimated as the present value of
future cash flows, discounted at the market rate of interest at the reporting date. At March 31, 2014
and March 31, 2013 the fair value of these balances approximated their carrying value due to their
short term to maturity
(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, 2014, Bengal’s receivables consisted of $3.5 million (March 31, 2013 - $3.4 million) from
joint venture partners and $0.3 million (March 31, 2013 - $0.2 million) of other trade receivables of
which $3.4 million has been subsequently collected.
Production from the Canadian operations is marketed by the operator. Bengal established a
payment schedule with the operator of the property and considers the entire amount to be
receivable.
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 31, 2014, the Company had $0.1 million that were considered past due (past due is
considered greater than 90 days outstanding). Bengal believes these receivables will 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, 2014 and did not provide for any doubtful accounts nor was it
required to write-off any receivables during the year ended March 31, 2014.
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.
54
Notes to Consolidated Financial Statements
(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 $13.4 million at March 31, 2014 (March 31,
2013 - $8.1 million). Bengal had $6.0 million in cash (March 31, 2013 - $2.6 million), $0.1 million in
restricted cash (March 31, 2013 - $0.1 million) and a working capital surplus of $3.1 million at March
31, 2014 (March 31, 2013 – deficit of $1.6 million). All accounts payable and accrued liabilities are
due within one year.
The table below indicates the payment schedule for o/s notes payable:
Note issued/extended
Fiscal year 2015
Fiscal year 2016
Fiscal year 2017
(d) Market risk:
July 5, 2013
1,408
1,500
5,092
$ 8,000
January 24, 2014
1,750
-
-
$ 1,750
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, 2014 ($000s)
Cash and short-term deposits
Restricted cash
Accounts receivable
Accounts payable and accrued liabilities
Notes payable and other long term
liability
Commodity Price Risk
CAD
AUD
U.S.D
$ 299
140
105
(625)
$ 1,235
-
3,700
(3,046)
$ 4,443
-
-
298
(9,304)
$ (9,385)
-
$ 1,889
-
$ 4,741
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
55
BENGAL ENERGY LTD.
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, 2014.
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, 2014 as the funds are not invested in an interest bearing instrument. The Company is
also exposed to interest rate risk on its Notes Payable. A 1% increase in the Prime rate would
increase interest expense on the Notes by $97,500. The Company had no interest rate derivatives
at March 31, 2014.
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 W ORKING CAPITAL
Year ended March 31 ($000s)
Accounts receivable
Prepaid expenses and deposits
Accounts payable and accrued liabilities
Impact of foreign exchange
Total
Relating to:
Operating
Financing
Investing
Total
$
$
$
$
2014
(271)
(380)
(449)
(305)
(1,405)
(592)
(808)
(5)
(1,405)
$
$
$
$
The following represents the cash interest received in each period.
Year ended March 31 ($000s)
Cash interest received
2014
74
$
$
18. COMMITMENTS AND CONTINGENCIES
Commitments:
2013
(3,034)
17
2,139
221
(657)
(1,802)
38
1,107
(657)
2013
274
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
56
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.
Notes to Consolidated Financial Statements
Country and
Permit
Work Program
Obligation
Period Ending
Estimated
Expenditure (net)
(millions CAD$)(1)
Two well exploration program
September 30, 2014
$1.6
Cuisinier (ATP 752 –
Bart permit)
Onshore India – CY-
ONN-2005/1
Three wells
February 25, 2015
(2)
Offshore India – CY-
OSN-2009/1
310km 2D seismic & 81km
3D seismic
2
August 15, 2014
(3)
$3.8
$5.5
(1) Translated at March 31, 2014 at an exchange rate of US $1.0000 = CAD $1.10, and AUS $1.00 = CAD $1.025
(2) If the Company did not participate in the drilling of three wells, costs of $5.2million would be impaired and the
Company’s interest in the permit would decline.
(3) The Company expects to relinquish this permit on or before its expiry date, resulting in an impairment of 100%
of the asset’s carrying value and a provision for expected penalties.
At March 31, 2014 the Company had the following lease commitment for office space in Canada.
($000s)
April 2014 to March 2017
Office lease
Total
$ 775
Less than
1 Year
258
1-3
Years
517
4-5
Years
-
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.
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
$ 11.9
19. SUPPLEMENTAL DISCLOSURE
Bengal’s consolidated statement of income (loss) and comprehensive income (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, 2014 amount to $1.4 million (2013 - $1.0 million).
20. RELATED PARTY TRAN SACTIONS
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
57
BENGAL ENERGY LTD.
of the Company subscribed for approximately 85% of the principal amount of the notes issued pursuant
to the Private Placement.
21. SUBSEQUENT EVENT
On May 27, 2014 Bengal announced it had entered into an indicative term sheet for a US $20.0 million
secured credit facility (the “Facility”) with a leading Australian commercial bank (the “Lender”). The
Facility contemplates a borrowing base of up to US $20 million, over a three year term at attractive fixed
income market rates tied to USD LIBOR to fund its ongoing Australian development. The Facility
remains subject to the completion of due diligence by the Lender and the entering into of a final Offer to
Finance with Bengal and will remain open for a fixed period to allow Bengal to review other competitive
lending proposals that may be received.
22. SEGMENTED INFORMATION
As at March 31, 2014, 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
Notes to Consolidated Financial Statements
For the year ended March 31, 2014 ($000)
Revenue
Interest revenue
Interest expense
Depletion and depreciation
Net (earnings) loss
Exploration and evaluation expenditures
Petroleum and natural gas property
expenditures
Property, plant & equipment expenditures
Impairment losses (recovery)
March 31, 2014 ($000)
Petroleum and natural gas properties
Cost
Impairment loss
Accumulated depletion, depreciation
and accretion
Net book value
Exploration and evaluation assets
Accumulated impairment losses
Net book value
Property, plant & equipment
Accumulated depletion, depreciation and
accretion
Impairment
Net book value
For the year ended March 31, 2013 ($000)
Australia
19,480
73
-
4,435
6,802
767
14,313
-
-
24,105
-
(3,034)
21,072
30,619
(9,621)
20,998
Canada
342
1
777
96
(4,976)
-
-
371
(1,928)
4,617
-
(4,019)
598
India
-
-
-
-
(1,676)
1,196
-
-
(1,173)
-
-
-
-
-
-
-
6,993
(1,170)
5,823
-
-
-
-
5,127
(70)
(1,557)
3,500
-
-
-
-
Total
19,822
74
777
4,531
150
1,963
14,313
371
3,101
28,722
-
(7,053)
21,669
37,612
(10,791)
26,821
5,127
(70)
(1,557)
3,500
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)
Petroleum and natural gas properties
Cost
Impairment loss
Accumulated depletion, depreciation
and accretion
Net book value
Australia
$ 5,669
82
-
1,255
1,266
13,167
$
Canada
216
87
38
193
(2,251)
-
$
India
-
(2)
-
-
(814)
2,850
Total
$ 5,885
167
38
1,448
(1,799)
16,017
$ 7,876
-
$
80
$
(23)
$ 4,511
-
$
$
-
-
-
$ 7,853
$ 4,511
80
$ 13,065
-
$ 1,172
(311)
$
(1,828)
11,237
$
$
(468)
393
$
-
-
-
-
$ 14,237
(311)
(2,296)
$ 11,630
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
$
−
$
4,756
$
−
$
4,756
Accumulated depletion, depreciation and
accretion
Net book value
−
$ −
(73)
4,683
−
$ −
(73)
4,683
$
$
59
BENGAL ENERGY LTD.
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
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)
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
Jerrad Blanchard, Chief Financial Officer
Gordon R. MacMahon, Vice President, Exploration
Bruce Allford, Secretary
STOCK EXCHANGE LISTING – TSX:BNG
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