2016 Annual Report
International exploration & production
2016
Annual Report
TABLE OF CONTENTS
Message to Shareholders
Fiscal 2016 Highlights
Management’s Discussion and Analysis
Consolidated Financial Statements
Notes to the Consolidated Financial Statements
Corporate Information
1
4
5
28
34
58
BENGAL ENERGY LTD.
MESSAGE TO SHAREHOLDERS
In Fiscal 2016, Bengal continued to focus on growing reserves, reducing costs, improving financial
flexibility. Operationally and financially, I am pleased with the progress Bengal made over the past year,
despite the challenging commodity price environment. We continued to further develop and grow our asset
base, while maintaining our focus on delivering long-term value for our shareholders.
Over the past year, Bengal, like its peers, faced a challenging and volatile oil price environment. As a
result, the Company only undertook low-risk operational activities that yielded economic returns, including
optimization of our base production and hydraulic stimulation of selected wells in the Cuisinier Field within
ATP 752 Barta Block (30.357% Bengal Working Interest). No development, appraisal or exploratory wells
were drilled during this time. In spite of this, Bengal grew its Proved plus Probable reserves during the fiscal
year by almost 9% to 6,204 Mbbls. While the net present value discounted at 10% (NPV10, before tax) of
Bengal’s 2P reserves declined to $103.9 million as a result of significantly lower forecast pricing for Brent
crude, we remain confident in the high quality of our asset base and our ability to continue to grow the size
and value of our reserves base.
Crude oil production for the year averaged 505 bopd, an 11% increase over 452 bopd in fiscal 2015. This
increase was a result of a combination of the 2014 Phase 2 being on-stream for the entire year as well as
frac success. Despite the anemic oil prices seen over the past year, Bengal’s netbacks continued to remain
strong due to the high quality of our crude, which is priced at a premium to Brent, and an astute hedging
program. During the year, Bengal realized operating netbacks of approximately CDN $21.53 per bbl, before
1
BENGAL ENERGY LTD.
hedging and corporate overhead. Including the contribution from Bengal’s hedge, field operating netbacks
increased to CDN $42.31 per bbl. Currently, Bengal has approximately 148,000 barrels of production
hedged with a floor price of US$80 per barrel through to June 2017.
The hydraulic stimulation campaign at Cuisinier exceeded Bengal’s technical and commercial expectations.
Four of the five wells demonstrated an aggregate incremental rate of over 200 gross bopd, or 61 bopd net
to Bengal, when placed back into production post-stimulation. This campaign has added to our production
base while providing an excellent foundation for future production additions as other low cost, low risk
stimulation opportunities are identified.
At ATP 934 Barrolka, Bengal has completed the reprocessing of 500+ line kilometers of 2D seismic over the
permit; interpretation of this data is currently underway. Once complete, the most favorable areas will be
high-graded for additional detailed geophysical work that may include the acquisition of 3D seismic in 2016.
The Company is encouraged by recent discoveries near the Barrolka permit, which suggest the presence of
a basin centered gas play in the region and will serve as the basis for internal technical analysis. Bengal is
operator with a 71% working interest in this permit and has held preliminary discussions with third parties
who may have an interest in farming in on this block.
In January, Bengal’s farm-in partner on ATP 732 Tookoonooka withdrew from the farm-in and re-assigned
their 50% equity back to Bengal. The farm-in partner drilled one well (Tangalooma-1) and completed the
acquisition of 300 km2 of 3D seismic (Nassarius 3D). In the oil price environment prevailing at that time, the
size and perceived risk of the prospects identified did not meet necessary thresholds for the farm-in partner
to continue with the work program. Bengal now retains a 100% working interest in this 2,648 km 2 permit on
the eastern flank of the Cooper Basin. There are no remaining commitments on this permit until the expiry
of the Tookoonooka Phase 1 work program in March of 2017, at which time a new work program for the
Phase 2 of the tenement tenure will be considered.
At the ATP 752 Wompi Block (38.08% Bengal Working Interest), the Nubba-1 well, which had encountered
multiple oil shows within the Jurassic as well as up to 6 metres of Permian Toolachee gas pay, is expected
to be evaluated within the next 12 months. Pressure testing and logging suggest that this Toolachee gas
well could be part of a significant gas column. This suggests the prospective gas pay could extend down dip
of the Nubba well where seismic indicates that the Toolachee section thickens. If test results are positive,
an application will be made for a Petroleum Production Lease, which should allow for commercialization.
The produced natural gas could be connected by pipeline to the nearest gas transmission line in the area,
which is approximately 5 kilometres from the Nubba-1 well. Wompi continues to offer Bengal moderate risk
exploration in a well-established, oil-producing fairway with multi-zone potential.
At Bengal’s onshore India block situated within the Cauvery Basin (CY-ONN-2005/1 – 30% WI), the
Company has continued over the past 2+ years to make all efforts and coordinate plans with its partners,
Gas Authority of India Ltd. (“GAIL”) and Gujarat State Petroleum Corporation, for the drilling of three
exploration wells. Bengal has considered the various factors influencing the status of the project including
that the Operator has been unable to acquire the land required for exploratory drilling and unable to obtain
statutory clearance from the local regulators in more than two years. New policy guidelines issued by the
Government of India allow companies to exit out of Production Sharing Contracts, due to such events
beyond the control of the joint venture companies, without paying any penalties for an unfinished work
2
Message to Shareholders
program. Because of these reasons, Bengal has decided, together with its partners, to exit out of this block
effective immediately.
Since inception, we have remained true to our underlying business strategy and have assembled an
attractive asset base that can generate value to our shareholders by adding consistent reserves growth
year-over-year. The value of this strategy has been clearly demonstrated over the past 7 years as we
continued to develop and enhance our high-quality Australian assets. Since 2009, Bengal has added
proved plus probable reserves at a compound annual growth rate (CAGR) of approximately 98%, and
grown the associated discounted before tax, net present value (NPV10) at a CAGR of 80%. While this is
exceptional, Bengal’s assets remain in their early stages of growth, and we look forward to continuing our
development at Cuisinier while undertaking exciting exploration activities, as Operator, to prove up new
natural gas opportunities that will service a growing Eastern Australian market.
Bengal continues to maintain a responsible approach to our operations and exercise prudent fiscal
management during these times of commodity price uncertainty. 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 continue to grow and expand the underlying value of our world-class assets.
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,
2016 and 2015.
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2016 Annual Report
FINANCIAL HIGHLIGHTS:
Continued Reserve Growth - The Company’s independently evaluated year-end reserve volumes
have increased by 9% and 1% to 6.2 million barrels (Mbbls) and 2.2 Mbbls for the Proved plus
Probable (“2P”) and Proved (“1P”) reserve categories respectively. These increases result from the
impacts of the Company’s successful five well fracture stimulation campaign completed during the
year. Based on 1P and 2P reserves additions, Bengal has replaced approximately 1.1 times and
3.7 times its annual production, respectively.
Revenue – Crude oil sales revenue was $2.3 million in the fourth quarter of fiscal 2016, which is
23% higher than the $1.8 million recorded in Q3 2016, due to increased quarter end commodity
prices and production during the quarter. Revenues were 33% lower than Q4 2015 due to a
corresponding decrease in realized commodity prices. Annual revenues for fiscal 2016 were $11.2
million compared to $15.7 million during fiscal 2015. The 29% decrease relates primarily to lower
commodity prices realized during fiscal 2016, which is partially offset by the Company’s hedging
program.
Hedging – At March 31, 2016, the Company has 148,000 barrels of oil (“bbls”) remaining in its
hedging program, which is comprised of a blend of puts and swaps with a floor price of US $80/bbl
that expire on June 30, 2107.
Funds Flow from Operations(1) – Funds flow from operations generated during Q4 2016 was $1.4
million compared to $1.3 million during the previous quarter and $0.9 million during Q4 2015. The
increase is due to the impacts of foreign exchange as well as realized gains generated by the
Company’s hedging program. Annual funds from operations were $4.0 million in fiscal 2016
compared to $4.6 million in fiscal 2015. The 12% decrease reflects the impact of lower realized
commodity prices during fiscal 2016.
Impairments – During the fourth quarter of 2016, the Company recognized $11.3 million of
impairment charges, primarily relating to its exploration permits. Impairments include a $7.4 million
charge for the entirety of the value of the Company’s on-shore India exploration permit; a $3.8
million charge associated with expected relinquishments on ATP 732 in Australia’s Cooper Basin;
and $0.7 million for the entire carrying value of the Toparoa producing asset.
Earnings - The Company recorded a net loss of $11.7 million during the fourth quarter of 2016,
compared to a loss of $1.3 million in the previous quarter and $0.5 million during Q4 2015. Annual
net loss was $10.4 million during fiscal 2016 compared to net losses of $3.2 million recorded in the
previous year. Both annual and quarterly losses were driven primarily by $11.3 million of
impairments booked this quarter.
Operational Highlights:
Production Volumes – Quarterly production during Q4 2016 decreased 7% compared to Q4 2015,
and increased by 7% compared to the preceding quarter. The 7% decrease in production is due
primarily to natural declines which were only partially offset by the impact of the five well fracture
stimulation program that was completed in December 2016. Production from these five wells came
back on stream and ramped up to full deliverability through the quarter. By the end of fiscal Q4
2016, gross production from the stimulated wells had increased by over 220 bopd. Annual
production increased by 12% compared to the prior year due to the impact of the 2014 phase 1 and
2 drilling programs which added four wells that were on stream for the entire fiscal year and two
wells that were on stream for more than half the year.
4
2016 Annual Report
Cuisinier Well Stimulation Program– Bengal and its joint venture parties completed a five well
hydraulic stimulation program during fiscal Q4 2016, which successfully increased production on
four of the five wells stimulated. Production on these four wells was restored in February of 2016
with incremental production of approximately 240 bbls, or 73 bbls net to Bengal. The Cuisinier 14
well encountered technical difficulties during the fracture stimulation program and therefore did not
benefit from increased productivity.
Production tie-ins – The Cuisinier 20 and Cuisinier 21 wells were brought on stream at the end of
June 2015 at restricted rates and were on production throughout most of Q1 fiscal 2016.
ATP 934 Barrolka Block –The Company completed a transaction to acquire an additional 21%
interest in the Barrolka permit for $0.1 million in April of 2015, and reached agreement with the
Queensland authorities regarding ongoing work commitments. Initial exploration work on this permit
has commenced with the reprocessing of approximately 500 kms of 2D seismic.
Onshore India – Effective June 1, 2016, Bengal and its Joint Venture has unanimously agreed and
provided notice to the applicable Government of India Authorities of its intention to exit the CY-
ONN-2005/1 exploration block. The joint venture was unable to acquire the land rights required for
exploration causing a force majeure condition for the duration of the first term of exploration, and is
therefore entitled to exit the permit without penalty for unfinished work program commitments. With
the exit from the permit, the Company has effectively ceased all operations in India.
Tookoonooka – During the fourth quarter of fiscal 2016, Bengal’s farm-in partner on ATP 732
announced its withdrawal from the farm-in and re-assigned their 50% equity back to Bengal. The
farm-in partner drilled one well (Tangalooma-1) and completed the acquisition of 300 km2 of 3D
seismic. There are no remaining commitments on this permit until after March of 2017, at which
time a Phase 2 work program will be considered.
MANAGEMENT’S DISCUSSION AND ANALYSIS – June 16, 2016
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, Barrolka and Tookoonooka, are
situated within an area of the Cooper Basin. Still in early stages, in terms of appraisal and development,
Bengal believes these assets offer attractive upside potential. Australia features a stable political, fiscal and
economic environment in which to operate, with a favorable royalty regime for oil and gas production.
OUTLOOK
AUSTRALIA
ATP 752 BARTA BLOCK CUISINIER
Current volatility in commodity prices continues to focus the Joint Venture on cost reductions, production
optimization as well as low cost and low risk development opportunities such as the recently completed five
well hydraulic stimulation program. The success of this operation has both validated upside available with
several existing wells identified as optimal stimulation candidates and further de-risked future development
drilling.
The Joint Venture is currently finalizing plans for its 2016 drilling and fracture stimulation program, which is
expected to benefit from significant cost reductions as service costs across Australia’s Cooper Basin have
declined in response to lower commodity prices. The success of the 2015 fracture stimulation program has
5
BENGAL ENERGY LTD.
provided the joint venture with the confidence to plan a follow-up program on several under-performing
wells during 2016.
Given the current crude pricing environment, the Company plans to defer the selection of wells for its next
drilling program until the results from the recent fracture stimulation program have been fully evaluated, the
field development plan has been completed, and the joint venture has finalized its cost structure review.
ATP 934 BARROLKA
Bengal has completed reprocessing of 500+ line kilometers of 2D seismic over the permit and interpretation
of this data is underway. Once complete the most favorable areas will be high-graded for additional detailed
geophysical work that may include the acquisition of 3D seismic in 2016. The Company is encouraged by
recent discoveries near the Barrolka permit, which suggest the presence of a basin centered gas play in the
region, which will serve as the basis for internal technical analysis. Bengal is operator with a 71% working
interest in this permit and has held preliminary discussions with third parties who may have an interest in
farming in on this block
ATP 732 TOOKOONOOKA BLOCK
The Tookoonooka Permit (ATP 732 – 100% WI effective January 28, 2016) is located in the emerging East
Flank oil fairway of the Cooper Basin. Beach Energy Ltd. (“Beach”) completed the acquisition of 300 sq. km
3D seismic in Tookoonooka in February 2014 and subsequently relinquished its interest in the permit;
Bengal was fully carried for the cost of this seismic program. While there are no outstanding commitments
on this permit, Bengal is now reviewing its 3D seismic results and evaluating its options towards further
exploration of this large permit.
ATP 752 WOMPI
The Nubba-1 well, which encountered multiple oil shows within the Jurassic, as well as up to 6 metres of
Permian Toolachee gas. Pressure testing, as well as logging, suggests that this Toolachee gas well could
be part of a gas column that may be up to 70 metres in height. This suggests the prospective gas pay
extends down dip of the Nubba well where seismic indicates the Toolachee section thickens. A Potential
Commercial Area (PCA) will be applied for which will allow for commercialization. The produced natural
gas would likely be pipeline connected to the nearest gas transmission line in the area, which is
approximately 5 kilometres from the Nubba-1 well. Wompi offers Bengal moderate risk exploration in a well-
established, oil-producing fairway with multi-zone potential.
6
2016 Annual Report
Three Months Ended
March 31
Twelve Months Ended
March 31
2016
2015 % Change
2016
2015
% Change
$
$
$
2,253
-
-
2,253
106
5
$ 1,833
1,474
$
$
$
$
$
2,506
1,496
1,439
0.02
(11,704)
(0.17)
$ (10,685)
(0.16)
$
332
469
-
-
469
$ 3,359
23
(4)
$ 3,378
$ 202
6
$ 717
$ 1,727
$ 2,166
$ 978
$ 939
0.01
$ (1,052)
(0.02)
$ (474)
(0.01)
$ 2,410
506
114
-
525
(33)
(100)
(100)
(33)
(48)
(17)
156
(15)
16
53
62
100
$ 11,187
-
-
$ 11,187
$ 728
7
$ 3,840
$ 6,480
$ 7,819
$ 5,398
$ 4,048
0.06
$ 15,395
246
28
$ 15,669
$ 1,057
7
(27)
(100)
(100)
(29)
(31)
-
$ 981
331
$ 6,247
4
$ 9,256 (16)
$ 6,921 (22)
$ 4,589 (12)
(14)
0.07
1,013
750
$ (10,380)
(0.15)
2,154
1,500
(86)
(7)
(100)
-
(11)
$ (12,270)
-
$ 3,347
505
-
-
505
$ (3,172)
(0.05)
227
200
$ (6,052)
(0.09)
103
-
$13,463 (75)
452
164
1
480
12
(100)
(100)
5
$
52.83
$ 71.53
(26)
$ 60.54
$ 89.43 (32)
OPERATING HIGHLIGHTS
$000s except per share,
volumes and netback amounts
Revenue
Oil
Natural gas
Natural gas liquids
Total
Royalties
% of revenue
Realized gain on financial
instruments
Operating & transportation
Operating netback(1)
Cash from operations:
Funds from operations:(2)
Per share ($) (basic & diluted)
Net income (loss)
Per share ($) (basic & diluted)
Adjusted net (loss) income (3)
Per share ($) (basic & diluted)
Capital expenditures
Volumes
Oil (boepd)
Natural gas (mcfpd)
Natural gas liquids (boepd)
Total (boepd @ 6:1)
Netback(1) ($/boe)
Revenue
Realized gain on financial
instrument
Royalties
Operating & transportation
Operating netback/boe
$
42.98
2.49
34.57
58.75
15.18
4.28
36.57
$ 45.86
183
(42)
(6)
20.78
3.94
35.07
28
$
42.31
5.09
6.03
35.65
308
(35)
(2)
$ 52.84 (20)
(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 three and twelve months ended
March 31, 2016 and 2015. The terms “current quarter”, Q4 2016 and “the quarter” are used throughout the
MD&A and in all cases refer to the period from January 1, 2016 through March 31, 2016. The terms “prior
year’s quarter”, Q4 2015 and “2015 quarter” are used throughout the MD&A for comparative purposes and
refer to the period from January 1, 2015 through March 31, 2015.
The fiscal year for the Company is the twelve-month period ended March 31, 2016. The terms “fiscal
2016,” “current year” and “the year” are used in the MD&A and in all cases refer to the period from April 1,
2015 through March 31, 2016. The terms “previous year,” “prior year” and “fiscal 2015” are used in the
MD&A for comparative purposes and refer to the period from April 1, 2014 through March 31, 2015. The
term YTD means year-to-date.
7
BENGAL ENERGY LTD.
For the purpose of calculating unit costs, natural gas volumes have been converted to barrels of oil
equivalent (“boe”) using a conversion ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel
(“bbl”) of oil. This conversion ratio of 6:1 is based on an energy equivalency conversion for the individual
products, primarily at the burner tip, and is not intended to represent a value equivalency at the wellhead.
Such disclosure of boe may be misleading, particularly if used in isolation.
The following abbreviations are used in this MD&A: boepd means barrels of oil equivalent per day; bpd
means barrels per day; mcfpd 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 (including realized gain on financial
instruments) 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.
The following table reconciles cash flow from operations to funds flow from operations, which is used in the
MD&A:
Three Months Ended
March 31
Twelve Months Ended
March 31
$000s
Cash flow from (used in) operating activities
Changes in non-cash working capital
2016
1,496
(57)
2015
978
(92)
% Change
53
(38)
2016
5,398
(1,350)
2015
6,921
(2,332)
% Change
(22)
(42)
Funds from (used in) operations
1,439
939
62
4,048
4,589
(12)
8
2016 Annual Report
Adjusted net earnings is a non-IFRS measure, which should not be considered an alternative to “Net
income (loss)” as presented in the consolidated statement of income (loss) and comprehensive income
(loss), and is presented in the Company’s financial reports to assist management and investors in analyzing
financial performance net of gains and losses outside of management’s immediate control. Adjusted net
earnings equal net income (loss) less unrealized losses/gains on foreign exchange and unrealized
losses/gains on financial instruments. Adjusted net earnings per share is calculated based on the weighted
average number of common shares outstanding consistent with the calculation of earnings (loss) per share.
The following table reconciles net income (loss) to adjusted net earnings (loss), which is used in the MD&A:
$000s
Net income (loss)
Unrealized loss (gain) on financial
Instruments
Unrealized foreign exchange loss (gain)
Adjusted net (loss) earnings
Three Months Ended
March 31
2016
(11,704)
2015
(1,052)
1,941
(922)
(10,685)
(440)
1,018
(474)
Twelve Months Ended
March 31
% Change
2016
2015 % Change
1,013
(10,380)
(541)
(191)
(1,861)
(29)
2,154
(12,270)
(3,172)
(4,962)
2,082
(6,052)
227
(63)
(101)
103
RESULTS OF OPERATONS - AUSTRALIA
Netbacks
Production
Oil Production (boepd)
($000s)
Oil sales
Realized gain on financial
instrument
Royalties
Operating expenses
Netback ($000s)
Oil sales ($/bbl)
Realized gain on financial
instrument
Royalties ($/bbl)
Operating expenses ($/bbl)
Netback ($/bbl)
Three Months Ended
Twelve Months Ended
2016
469
March 31
2015
506
% Change
(7)
2016
505
March 31
2015
% Change
452
2,253
3,359
(33)
11,187
15,395
1,833
106
1,469
2,511
717
201
1,683
2,192
156
(47)
(13)
15
3,840
728
6,463
7,836
891
1,026
6,014
9,246
52.83
73.08
(28)
60.54
93.40
42.98
2.49
34.45
58.87
15.75
4.42
36.98
48.15
173
(44)
(7)
22
20.78
3.94
34.98
42.40
5.41
6.22
36.49
56.10
12
(27)
331
(30)
7
(15)
(35)
284
(37)
(4)
(24)
Production, Commodity Pricing and Sales
Production
Quarterly production during Q4 2016 decreased 7% compared to Q4 2015, and increased by 7% compared
to the preceding quarter. The 7% decrease in production in due primarily to natural declines which were
only partially offset by the impact of the five well fracture stimulation program that was completed in
December 2016. Production from these five wells came back on stream and ramped up to full deliverability
through the quarter. By the end of fiscal Q4 2016, gross production from the stimulated wells had increased
by over 220 bopd.
9
BENGAL ENERGY LTD.
Annual production increased by 12% compared to the prior year due to the impact of the 2014 phase 1 and
2 drilling programs which added four wells that were on stream for the entire fiscal year and two wells that
were on stream for more than half the year.
Pricing
The price received for Bengal’s Australian oil sales is benchmarked 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 US $2.10 bbl over Brent for the twelve months ended March 31, 2016 (2015 – US
$3.44).
Realized crude oil prices in Q4 2016 decreased 24% increased by 16% compared to Q4 2015 and Q3 2016
respectively due to corresponding fluctuations in benchmark pricing. Annual average realized prices
decreased by 35% compared to the prior fiscal year. The declines in Brent crude prices through fiscal 2016
have been partially offset by foreign exchange gains as the value of Canadian and Australian dollars has
decreased relative to U.S. dollars.
The Company’s reported sales include approximately 15,000 bbls of crude for which prices were not yet
determined at March 31, 2016, therefore these barrels are valued at period end pricing.
The following table outlines average benchmark prices compared to Bengal’s realized prices:
Prices and Marketing
Three Months Ended
Twelve Months Ended
March 31
March 31
Average Benchmark Price
2016
2015
% Change
2016
2015
% Change
Bengal realized crude oil price
before realized gain on financial
instruments($CAD/bbl)
Realized gain on financial
Instruments ($CAD/bbl)
Dated Brent oil ($CAD/bbl)
Dated Brent oil ($US/bbl)
Number of CAD$ for 1 AUS$
Number of CAD$ for 1 US$
$ 52.83
$73.80
(28)
$ 60.54
$93.40
42.98
46.53
33.89
0.99
1.37
15.75
66.83
53.97
0.97
1.24
173
(30)
(37)
2
10
20.78
62.20
47.44
0.96
1.31
5.41
97.31
85.43
0.99
1.14
(35)
284
(36)
(44)
(3)
15
(1) Translated at March 31, 2016 at an average quarterly exchange rate of US $1.00 = CAD $1.3731 and 1.3112 for the three
and twelve months ended March 31, 2016 respectively.
Risk Management Activities
Bengal has entered into financial commodity contracts as part of its risk management program to manage
commodity price fluctuations related to its primary producing assets being the Cuisinier field in Australia’s
Cooper Basin.
With respect to financial contracts, which are derivative financial instruments, management has elected not
to use hedge accounting and consequently records the fair value of its crude oil financial contracts on the
statement of financial position at each reporting period with the change in fair value being classified as
unrealized gains and losses in the consolidated statement of income.
The Company has managed the price application to production volumes through the following contracts:
10
2016 Annual Report
Time Period
Type of Contract
Apr 1, 2016 – May 31, 2017
Apr 1, 2016 – May 31, 2017
Oil - Swap
Oil – Put option
Quantity
Contracted (bbls)
81,605
66,764
Price Floor
(US$/bbl)
80.00
80.00
Price Ceiling
(US$/bbl)
80.00
-
The fair value of the financial contracts outstanding as at March 31, 2016 is an estimated asset of $7.1
million. The fair value of these contracts is based on an approximation of the amounts that would have
been paid or received from counterparties to settle the contracts outstanding at the end of the period having
regard to forward prices and market values provided by independent sources. Due to the inherent volatility
in commodity prices, actual amounts realized may differ from these estimates.
For the twelve months ended March 31, 2016, the derivative commodity contracts resulted in realized gains
of $3.8 million and unrealized gains of $1.9 million.
Royalties
Royalties ($000s)
Royalty Expense
$/bbl
% of revenue
Three Months Ended
Twelve Months Ended
March 31
March 31
2016
2015
% Change
106
2.49
5
201
4.42
6
(47)
(44)
(17)
2016
728
3.94
7
2015
% Change
1,026
6.22
7
(29)
(37)
-
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 operating and allowable capital costs, resulting in an effective rate of less than 10%.
Royalties per barrel decreased 37% compared to Q4 2015 and decreased 8% compared to the previous
quarter. Annual royalties per barrel have decreased by 44% compared to the prior fiscal year. Royalties as
a percentage of crude oil sales have continued to decrease through the year along with commodity prices
as deductible costs have remained consistent.
Operating & Transportation Expenses
Operating & trans.
expenses ($000s)
Operating
Transportation
Operating - $/boe
Transp. - $/boe
Three Months Ended
Twelve Months Ended
2016
159
1,310
1,469
3.73
30.72
34.45
March 31
2015
% Change
303
1,380
1,683
6.66
30.32
36.98
(48)
(5)
(13)
(44)
1
(7)
2016
994
5,469
6,463
5.38
29.60
34.98
March 31
2015
% Change
1,050
4,964
6,014
6.37
30.12
36.49
(5)
10
7
(16)
(2)
(4)
Operating costs per barrel decreased by 44% compared to Q4 2015 and 29% compared to the prior
quarter. Total operating expenses for the Cuisinier field, which comprises a majority of the Company’s
operations are accrued based on the Operator’s annual budget. Actual operating costs incurred during the
year were below budget expectations due to a general reduction of costs across Australia’s Cooper Basin,
therefore a portion of the Company’s operating expense accrual was reversed during Q4 2016. Annual
operating costs per barrel have decreased by 16%, which reflects basin wide cost reductions.
11
BENGAL ENERGY LTD.
Transportation costs on a boe basis have increased 1% compared to Q4 2015 and 2% compared to the
prior quarter. Annual transportation costs have decreased by 2% compared the prior fiscal year. These
fluctuations relate primarily to foreign exchange fluctuations between the Australian and Canadian dollars.
General and Administrative (G&A) Expenses and Share-based Compensation (“SBC”)
G&A Expenses and SBC ($000s)
Three Months Ended
Twelve Months Ended
Net G&A
Capitalized G&A
Total G&A
Expensed share-based compensation
Capitalized share-based compensation
Total share-based compensation
March 31
2015
901
83
% Change
(23)
10
984
23
4
27
(21)
(26)
(100)
(37)
2016
690
91
781
17
-
17
March 31
2015 % Change
(22)
3,407
(10)
373
3,780
170
40
210
(21)
(46)
(75)
(52)
2016
2,663
335
2,998
91
10
101
Total G&A expenditures have decreased by 21% for the quarter and fiscal year ended March 31, 2016,
which reflects the Company’s ongoing effort to minimize discretionary spending without impacting
operations.
The Company uses the Black-Scholes pricing model to estimate the fair value of options on the date of
grant and amortizes the estimated expense over the vesting period with a corresponding charge to
contributed surplus. Options expire 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.
Depletion and Depreciation (DD&A)
DD&A Expenses
($000s)
PNG – Australia
PNG – Canada
Subtotal
Rig - Canada
Total
$/boe – PNG Australia
$/boe – PNG Canada
$/boe – Total PNG
Three Months Ended
Twelve Months Ended
2016
766
5
771
-
771
17.96
-
18.08
March 31
2015
% Change
1,161
150
1,311
-
1,311
25.51
87.72
27.76
(34)
(97)
(41)
-
(41)
(30)
-
(35)
2016
4,519
24
4,543
-
4,543
24.46
-
24.59
March 31
2015
% Change
4,623
413
4,531
330
5,162
28.05
53.86
29.46
(2)
(89)
(6)
(100)
(12)
(13)
-
(17)
Australian depletion per barrel decreased by 35% for Q4 2016 compared to Q4 2015 and decreased by
17% comparing fiscal year 2016 to fiscal year 2015. The decrease to depletion per barrel resulted from the
following two factors; the Company’s 2P reserve volumes increased by 9% compared to the prior year and
drilling costs have materially decreased in Australia, reducing the costs associated with future development
of the Company’s reserves.
12
2016 Annual Report
Impairment
Impairment
($000s)
Total
Three Months Ended
Twelve Months Ended
March 31
March 31
2016
11,253
2015
% Change
2016
2015
% Change
-
-
11,253
4,762
136
During the twelve months ended March 31, 2016, the Company recorded impairment charges of $7.4
million and $3.8 million relating to petroleum and natural gas exploration properties in India and Australia
respectively.
The CY-ONN-2005/1 exploration block in India has been under force majeure conditions since March 2014
due to land owner disputes that have restricted access to drilling locations. During this period, the
underlying term of this permit has expired allowing for parties to exit the permit without liability for damages
relating to unfulfilled work commitments. Bengal management has evaluated the potential prospectivity of
the block against the risks associated with future drilling and operational delays as well as potential
damages and notified the Operator of the Company’s intent to exit the block. This has triggered a $7.4
million impairment equivalent to the asset’s entire carrying value.
In the process of management’s internal analysis of prospectivity and planning for scheduled relinquishment
in 2017 for ATP 732, located in Australia’s Cooper Basin, Bengal identified several areas deemed to have
low potential for future exploration. All historical costs associated with exploration in these select areas
have been impaired subject to the Company’s plans to relinquish.
The Company’s Toparoa asset located in Australia’s Cooper basin has been fully impaired at March 31,
2016. Natural declines and wellbore obstructions have reduced productivity over time, and current costs
structures relative to current commodity prices have resulted in significant uncertainty regarding future cash
flows.
Finance Income/Expenses
Finance Expenses ($000s)
Three Months Ended
Twelve Months Ended
Interest income
Accretion expense on
decommissioning liabilities
Accretion expense on notes payable
Change in FV of VARs
Letter of credit charges
Interest and penalties on notes payable
and credit facility
Finance expenses
March 31
March 31
2015
% Change
2016
2015
% Change
5
(60)
9
18
(50)
(4)
-
7
(87)
(342)
(421)
2,150
-
(86)
(100)
2
(3)
(33)
-
3
14
(1,311)
(1,318)
(15)
(507)
58
(87)
(1,212)
(1,745)
120
(100)
(95)
(116)
8
(25)
2016
2
(90)
-
1
-
(348)
(435)
Interest on the credit facility is based on US dollar Libor + 3.2% margin.
13
BENGAL ENERGY LTD.
CAPITAL EXPENDITURES
Capital Expenditures ($000s)
Geological and geophysical
Drilling
Completions
Cuisinier working interest purchase
Total expenditures
Exploration & evaluation
expenditures
Development & production
expenditures
Total net expenditures
Three Months Ended
Twelve Months Ended
March 31
March 31
2016
2015
% Change
2016
2015
% Change
111
20
201
-
332
95
237
332
320
1,732
358
-
2,410
267
2,143
2,410
(65)
(99)
(44)
-
(86)
1,320
(14)
1,931
110
3,347
1,276
8,458
3,729
-
13,463
(64)
761
3,189
(89)
(86)
2,586
3,347
10,247
13,436
3
(100)
(48)
-
(75)
(76)
(75)
(75)
Development expenditures during the year related primarily to the Cuisinier fracture stimulation program.
NOTES PAYABLE & CREDIT FACILITY
On January 24, 2014, $1.75 million of convertible notes set to expire on January 25, 2014 were extended to
January 24, 2015. These notes were redeemed on January 21, 2015 for a redemption price of $2.0 million
including principle and accrued and unpaid interest. Approximately $0.8 million of the aggregate was paid in
cash, and certain holders of the remaining $0.9 million of aggregate principle received the redemption price
through the issuance of common shares of the Company at a price of $0.28 per common share in lieu of
cash.
In October 2014, Bengal closed its secured credit facility with Westpac Institutional Bank and placed an
initial draw on November 12, 2014 of US $14.0 million. The facility is secured by the Company’s producing
assets in the Cuisinier field in Australia’s Cooper Basin, has a three-year term and carries an interest rate of
US Libor plus 3.2% to 3.5% depending on certain reserve forecast parameters.
The credit facility is structured as a reserves-based revolving facility under a predetermined reduction
schedule, to be evaluated based on existing reserves at each calculation date. Calculation dates
commenced December 31, 2015 and occur every six months thereafter until June 30, 2017 with a reduction
of $6.25 million to the facility limit at each calculation date based on the Company’s existing reserve profile.
The facility limit at March 31, 2016, is US $18.75 millionThe current portion of the credit facility (US $7.75
million/CAD $10.5 million) reflects the June 30, 2016 reduction of US $1.5 million and the December 31,
2016 of US $6.25 million. Under the reduction schedule the facility limit would be reduced to nil by June 30,
2017.
The credit facility’s covenants include a debt service coverage ratio (cash available for debt payments
divided by mandatory debt repayments) as well as a loan life coverage ratio (net present value of future
cash available for debt service divided by the available facility). These covenants impact the Company’s
availability facility limit, and therefore the ability to secure its debt as a percentage of reserve forecasts and
are evaluated at each calculation date. The facility’s available borrowing base and corresponding reduction
schedule is determined at each calculation date subject to these covenant calculations, which are
calculated using inputs as prescribed by Westpac. A default event triggered by a breach of covenants may
result in a full redemption of all outstanding borrowings under the terms of the credit facility. There are no
financial covenants associated with this credit facility. The Company was in compliance with the stated
covenants at March 31, 2016.
14
2016 Annual Report
SHARE CAPITAL
At June 16, 2016, there were 68,177,796 common shares issued and outstanding, together with 4,357,500
outstanding options, 703,125 warrants and 546,875 value appreciation rights.
Trading History
Three Months Ended
Twelve Months Ended
High
Low
Close
Volume (000s)
Shares outstanding (000s)
Weighted average shares
outstanding (000s)
Basic
Diluted
March 31
March 31
2016
2015
% Change
2016
2015
% Change
$ 0.32
$ 0.10
$ 0.13
15,329
68,178
$ 0.32
$ 0.18
$ 0.19
2,759
68,178
68,178
68,178
67,364
67,364
-
$ 0.32
$ 0.76
(44)
(32)
456
$ 0.10
$ 0.13
15,329
$ 0.18
$ 0.19
11,161
-
1
1
68,178
68,178
68,178
68,178
65,349
65,349
(58)
(44)
(32)
(32)
-
4
4
LIQUIDITY AND CAPITAL RESOURCES
Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including work
commitments, as they are due. The Company’s existing cash and cash equivalents and operating cash
flows combined with the available credit described above 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).
At March 31, 2016 the Company had $0.4 million of working capital deficiency, including cash and short-
term deposits of $3.0 million and restricted cash of $0.1 million, compared to working capital of $5.2 million
at March 31, 2015. The decrease in working capital is due to the nominal reduction schedule associated
with the Company’s Westpac credit facility. The Company plans to limit its capital expenditures during the
next quarters to replenish its cash reserves in order to meet potential debt obligations.
The Company’s credit facility was reduced to US $18.75 million effective December 31, 2015. The credit
facility’s covenants include a debt service cover ratio (cash available for debt payments divided by
mandatory debt repayments) as well as a loan life cover ratio (net present value of future cash available for
debt service divided by the available facility). These covenants impact the Company’s ability to secure its
debt as a percentage of reserve forecasts and are evaluated at each calculation date (June 2016,
December 2016, June 2017) and under a default condition could result in early repayment. The facility’s
available borrowing base and corresponding reduction schedule is determined at each calculation date
subject to these covenant calculations, which are calculated using inputs as prescribed by the Lender
(Westpac Banking Corporation). There are no financial covenants associated with this credit facility. The
Company was in compliance with the stated covenants at March 31, 2016.
The majority of the Company’s oil sales are benchmarked on dated Brent prices which averaged US $47.44
/bbl for the twelve months ended March 31, 2016. The Company incurs most of its expenditures in
Australian dollars whereas the Company generates most of its revenues in US dollars. To mitigate the net
impact of low crude prices, the Company is acting with its joint venture partners to reduce discretionary
spending and focus capital towards lower risk projects with near-term cash flow upside. The Company has
also entered into derivative commodity contracts to reduce the impact of price volatility.
Bengal will continue to monitor trends in commodity prices to ensure its financial obligations are met, while
continuing to grow its asset base where appropriate. Under the current commodity price environment, the
Company has no plans to use its internal source of cash to fund exploration activities. These are expected
to be financed through farm-out or alternative financing sources.
15
BENGAL ENERGY LTD.
The table below indicates the payment schedule for the credit facility:
Credit facility (US$000s)
Fiscal year 2017
Fiscal year 2018
COMMITMENTS
7,750
6,250
14,000
The Queensland Government regulatory authority granted the Company the Authority To Prospect 934
("ATP 934") under a revised work program on March 1, 2015. The Company acquired an additional 21.43
% working interest and received ministerial approval for the acquisition on August 11, 2015. Currently, the
Company holds a 71.43% operating interest in this permit. Work program consists of 200 kilometers of 2D
seismic and up to three wells.
Country and Permit
Work Program
Onshore Australia –
ATP 934P
200 km2 of 2D seismic and up to three
wells
Obligation Period
Ending
Estimated Expenditure (net)
(millions CAD$)(1)
March 2021
$ 16.6
(2) Translated at March 31, 2016 at an exchange rate of AUS $1.00 = CAD $0.9943.
OTHER
At March 31, 2016, the contractual obligations for which the Company is responsible are as follows:
Contractual Obligations ($000s)
Office lease
Decommissioning obligations
Total contractual obligations
Total
265
1,422
1,687
$
$
Less than
1 Year
$
$
265
-
265
1-3
Years
4-5
Years
After
5 Years
$
$
-
239
239
$
$
-
$
-
119
119
1,064
$ 1,064
16
OFF BALANCE SHEET TRANSACTIONS
The Company does not have any off balance sheet transactions.
SELECTED ANNUAL INFORMATION
2016 Annual Report
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
Funds from operations (1)
Per share – basic and diluted
Balance drawn on credit facility
Notes payable – long term
Total assets
Working capital (deficiency)(2)
2016
505
-
60.54
11,187
(10,380)
(0.15)
5,398
4,048
0.06
17,865
-
58,903
(420)
2015
480
4.10
93.35
15,669
(3,172)
(0.05)
6,921
4,589
0.07
16,982
-
65,679
5,221
2014
468
3.74
123.13
19,822
150
0.00
7,591
8,183
0.13
-
6,085
62,425
3,104
(1) See “Non-IFRS Measurements” on page 7 of this MD&A.
(2) Calculated as current assets minus current liabilities.
SELECTED QUARTERLY INFORMATION
($000s, except per share amounts)
Mar. 31
2016
Dec.31
2015
Sep. 30
2015
Jun. 30
2015
Mar. 31
2015
Dec. 31
2014
Sep. 30
2014
Jun. 30
2014
Petroleum and natural gas sales
Cash from (used in) operations
Funds from (used in) operations(1)
2,253
1,496
1,439
1,838
935
105
3,392
2,318
1,282
3,704
3,378
649
1,222
978
939
3,944
1,144
1,318
4,458
2,232
1,459
3,889
2,219
926
Per share
Basic and diluted
0.02
0.00
0.02
0.02
0.01
0.02
0.02
0.01
Net income (loss)
Per share
Basic and diluted
Capital expenditures
Working capital (deficiency)
(11,704)
1,413
1,167
(1,256)
(1,052)
(1,293)
(98)
(729)
(0.17)
332
(420)
0.02
0.02
(0.02)
(0.02)
(0.02)
0.00
(0.01)
1,311
(1,487)
596
5,775
1,108
2,410
4,489
2,909
3,655
3,087
5,221
4,931
(1,705)
(88)
Total assets
58,903
72,353
66,583
62,926
65,679
66,229
60,385
60,216
Shares outstanding (000s)
68,178
68,178
68,178
68,178
68,178
64,692
64,692
64,692
Operations
Average daily production
Natural gas (mcfpd)
Oil and NGLs (bpd)
Combined (boepd)
-
-
-
469
469
-
439
439
-
592
592
-
520
520
114
506
525
181
548
578
169
429
457
194
329
361
Netback ($/boe)
58.75
72.03
36.97
46.23
45.86
36.79
65.05
73.15
(1) See “Non-IFRS Measurements” on page 7 of this MD&A.
17
BENGAL ENERGY LTD.
Production over the last eight quarters initially increased with the addition of the Phase One wells in fiscal
Q3 2015. Production then declined naturally, before the 2014 Phase Two wells in fiscal Q1 2016 brought
production to 592 bopd in fiscal Q2 2016. During the third fiscal quarter of 2016, production decreased to
439 bopd as a result of five wells being temporarily offline to undergo fracture stimulation operations.
These wells were brought back online post fracture stimulation during Q4 2016 increasing production.
Netbacks during the past eight quarters have been impacted primarily by fluctuations in benchmark crude
prices.
FINANCIAL INSTRUMENTS
Financial instruments comprise cash, restricted cash and short term deposits, accounts receivable and
accounts payable and accrued liabilities and debt. The fair values of these financial instruments
approximate their carrying amounts due to their short-term maturities, and floating interest rate associated
with the Company’s credit facility.
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. Refer to section “Risk Management Activities” for discussion of the Company’s 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, notes
payable and the credit facility are classified as other financial liabilities, which are measured at amortized
cost.
(ii) Derivative financial instruments
The Company enters into certain financial derivative contracts in order to manage the exposure to market
risks from fluctuations in commodity prices. These instruments are not used for trading or speculative
purposes. The Company does not designate its financial derivative contracts as effective accounting
hedges and therefore will not apply hedge accounting, even though the Company considers all commodity
contracts to be economic hedges. As a result, all derivative contracts are classified as FVTPL and are
recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or
loss when incurred. Subsequent to initial recognition, derivatives are measured at fair value, and changes
18
2016 Annual Report
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
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, 2016 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
19
BENGAL ENERGY LTD.
conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the
control system are met.
During the design and operating effectiveness assessment certain material weaknesses in internal controls
over financial reporting were identified, as follows:
Management is aware that there is a lack of segregation of duties due to the small number of
employees dealing with general and administrative and financial matters. However, management
believes that at this time the potential benefits of adding employees to clearly segregate duties do
not justify the costs;
Bengal does not have full-time in-house personnel to address all complex and non-routine financial
accounting issues and tax matters that may arise. It is not deemed as economically feasible at this
time to have such personnel. Bengal relies on external experts for review and advice on complex
financial accounting issues and for tax planning, tax provision and compilation of corporate tax
returns.
These material weaknesses in internal controls over financial reporting result in a reasonable possibility that
a material misstatement will not be prevented or detected on a timely basis. Management and the Board of
Directors work to mitigate the risk of material misstatement; however, Management and the Board do not
have reasonable assurance that this risk can be reduced to a remote likelihood of a material misstatement.
APPLICATION OF CRITICAL ACCOUNTING ESTIMATES
The 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.
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.
20
2016 Annual Report
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 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)
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.
21
BENGAL ENERGY LTD.
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
Newly adopted accounting standards
On January 1, 2016, the Company adopted the amendments made to IFRS 11 – Joint Arrangements, which
provided new guidance on the accounting for the acquisition of an interest in a joint operation that
constitutes a business. There was no impact to the Company as a result of adopting the amended
standard.
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.
Sale or contribution of assets between an investor and its associate or joint venture
In September 2014, the IASB issued amendments to address an inconsistency between the requirements
in IFRS 10 “Consolidated Financial Statements” and those in IAS 28 “Investments in Associates and Joint
Ventures” regarding the sale or contribution of assets between an investor and its associate or joint venture.
The amendment clarified that a full gain or loss is recognized when a transaction involves a business. A
partial gain or loss is recognized when a transaction involves assets that do not constitute a business.
Prospective application of this interpretation is effective for annual periods beginning on or after January 1,
2016, with earlier application permitted. The adoption of this amendment could impact the Company in the
event that it has transactions with associates or joint ventures.
Disclosure initiative
In December 2014, the IASB issued narrow-focus amendments to IAS 1 “Presentation of Financial
Statements” to clarify existing requirements relating to materiality, order of notes, subtotals, accounting
policies and disaggregation. Retrospective application of this standard is effective for fiscal years beginning
on or after January 1, 2016, with earlier application permitted. The adoption of this amended standard is
not expected to have a material impact on the Company’s disclosure.
Revenue from contracts with customers
In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers”. It replaces existing
revenue recognition guidance and provides a single, principles-based five-step model to be applied to all
contracts with customers. Retrospective application of this standard was to be effective for fiscal years
beginning on or after January 1, 2017, with earlier application permitted. On May 19, 2015, the IASB
published the expected exposure draft aimed at deferring the effective date of IFRS 15 “Revenue from
Contracts with Customers” to January 1, 2018. The Company is currently assessing the impact of this
standard.
Financial instruments: recognition and measurement
In July 2014, IFRS 9 “Financial Instruments” was issued as a complete standard, including the requirements
previously issued related to classification and measurement of financial assets and liabilities, and additional
22
2016 Annual Report
amendments to introduce a new expected loss impairment model for financial assets including credit
losses. Retrospective application of this standard with certain exemptions is effective for fiscal years
beginning on or after January 1, 2018, with earlier application permitted. The Company is currently
assessing the impact of this standard.
Leases
On January 13, 2016 the IASB issued IFRS 16 “Leases”. The new standard is effective for annual periods
beginning on or after January 1, 2019. Earlier application is permitted for entities that apply IFRS 15
“Revenue from Contracts with Customers” at or before the date of initial adoption of IFRS 16. IFRS 16 will
replace IAS 17 “Leases”. This standard introduces a single lessee accounting model and requires a lessee
to recognize assets and liabilities for all leases with a term of more than 12 months, unless the underlying
asset is of low value. A lessee is required to recognize a right-of-use asset representing its right to use the
underlying asset and a lease liability representing its obligation to make lease payments. The Company
intends to adopt IFRS 16 in its financial statements for the annual period beginning on January 1, 2019.
The extent of the impact of adoption of the standard has not yet been determined.
RISK FACTORS
Companies engaged in the oil and gas industry are exposed to a number of business risks which can be
described as operational, financial and political risks, many of which are outside of the Company’s control.
More specifically, these include risks of economically finding reserves and producing oil and gas in
commercial quantities, marketing the production, commodity prices, environmental and safety risks, and
risks associated with the foreign jurisdiction in which the Company operates. In order to mitigate these
risks, the Company has an experienced base of qualified technical and financial personnel in both Canada
and Australia. Further, the Company has focused its foreign operations and plans to target future foreign
operations in known and prospective hydrocarbon basins in jurisdictions that have previously established
long-term oil and gas ventures with foreign oil and gas companies.
An investment in the shares of the Company should be considered speculative due to the nature of the
Company's involvement in the exploration for and the acquisition, development and production of oil and
natural gas in foreign countries, and its current stage of development. An investor should consider carefully
the risk factors set out below and consider all other information contained herein and in the Company's
other public filings before making an investment decision. Additional risks and uncertainties not currently
known to the management of the Company may also have an adverse effect on Bengal’s business and the
information set out below does not purport to be an exhaustive summary of the risks affecting Bengal.
Exploration, Development and Production Risks
Oil and natural gas exploration involves a high degree of risk, for which even a combination of experience,
knowledge and careful evaluation may not be able to overcome. There is no assurance that expenditures
made on future exploration by Bengal will result in new discoveries of oil or natural gas in commercial
quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the
inherent uncertainties of drilling in unknown formations, the costs associated with encountering various
drilling conditions such as over-pressured zones, tools lost in the hole and changes in drilling plans and
locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.
The long-term commercial success of Bengal will depend on its ability to find, acquire, develop and
commercially produce oil and natural gas reserves. No assurance can be given that Bengal will be able to
locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations
are identified, Bengal may determine that current markets, terms of acquisition and participation or pricing
conditions make such acquisitions or participations uneconomic.
23
BENGAL ENERGY LTD.
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that
are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other
costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion
and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost
of operations, and various field operating conditions may adversely affect the production from successful
wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of
connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or
other geological and mechanical conditions. While diligent well supervision and effective maintenance
operations can contribute to maximizing production rates over time, production delays and declines from
normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and
cash flow levels to varying degrees.
In addition, oil and gas operations are subject to the risks of exploration, development and production of oil
and natural gas properties, including encountering unexpected formations or pressures, premature declines
of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence
of any of these risks could have a materially adverse effect on future results of operations, liquidity and
financial condition.
Bengal attempts to minimize exploration, development and production risks by utilizing a high-end technical
team with extensive experience and multidisciplinary skill sets to assure the highest probability of success
in its drilling efforts. Bengal’s collaboration of a team of seasoned veterans in the oil and gas business,
each with a unique expertise in the various upstream to downstream technical disciplines of prospect
generation to operations, provides the best assurance of competency, risk management and drilling
success. A full cycle economic model is utilized to evaluate all hydrocarbon prospects. Detailed geological
and geophysical techniques are regularly employed including 3D seismic, petrography, sedimentology,
petrophysical log analysis and regional geological evaluation.
Risks Associated with Foreign Operations
International operations are subject to political, economic and other uncertainties, including, among others,
risk of war, risk of terrorist activities, border disputes, expropriation, renegotiations or modification of
existing contracts, restrictions on repatriation of funds, import, export and transportation regulations and
tariffs, taxation policies, including royalty and tax increases and retroactive tax claims, exchange controls,
limits on allowable levels of production, currency fluctuations, labor disputes, sudden changes in laws,
government control over domestic oil and gas pricing and other uncertainties arising out of foreign
government sovereignty over the Company's international operations. With respect to taxation matters, the
governments and other regulatory agencies in the foreign jurisdictions in which Bengal operates and
intends to operate in the future may make sudden changes in laws relating to taxation or impose higher tax
rates, which may affect Bengal’s operations in a significant manner. These governments and agencies may
not allow certain deductions in calculating tax payable that Bengal believes should be deductible under
applicable laws or may have differing views as to values of transferred properties. This can result in
significantly higher tax payable than initially anticipated by Bengal. In many circumstances, readjustments to
tax payable imposed by these governments and agencies may occur years after the initial tax amounts
were paid by Bengal, which can result in the Company having to pay significant penalties and fines.
Furthermore, in the event of a dispute arising from international operations, the Company may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the
jurisdiction of courts in Canada.
24
2016 Annual Report
Prices, Markets and Marketing of Crude Oil and Natural Gas
Oil and natural gas are commodities that have prices determined based on world demand, supply and other
factors, all of which are beyond the control of Bengal. World prices for oil and natural gas have fluctuated
widely in recent years. Any material decline in prices could result in a reduction of net production revenue.
Certain wells or other projects may become uneconomic as a result of a decline in world oil prices and
natural gas prices, leading to a reduction in the volume of Bengal’s oil and gas reserves. Bengal might also
elect not to produce from certain wells at lower prices. All of these factors could result in a material
decrease in Bengal’s future net production revenue, causing a reduction in its oil and gas acquisition and
development activities. In addition to establishing markets for its oil and natural gas, Bengal must also
successfully market its oil and natural gas to prospective buyers. The marketability and price of oil and
natural gas which may be acquired or discovered by Bengal will be affected by numerous factors beyond its
control. The ability of Bengal to market its natural gas may depend upon its ability to acquire space on
pipelines which deliver natural gas to commercial markets. Bengal will also likely be affected by
deliverability uncertainties related to the proximity of its reserves to pipelines and processing facilities and
related to operational problems with such pipelines and facilities and extensive government regulation
relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and
many other aspects of the oil and natural gas business.
Substantial Capital Requirements and Liquidity
Bengal’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From
time to time, Bengal may require additional financing in order to carry out its oil and gas acquisition,
exploration and development activities. Failure to obtain such financing on a timely basis could cause
Bengal to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or
terminate its operations. If Bengal’s revenues from its reserves decrease as a result of lower oil and natural
gas prices or otherwise, it will affect Bengal’s ability to expend the necessary capital to replace its reserves
or to maintain its production. If Bengal’s funds from operations are not sufficient to satisfy its capital
expenditure requirements, there can be no assurance that additional debt or equity financing will be
available to meet these requirements or available on terms acceptable to Bengal.
Bengal monitors and updates its cash projection models on a regular basis which assists in the timing
decision of capital expenditures. Farm outs of projects may be arranged if capital constraints are an issue
or if the risk profile dictates that Bengal wishes to hold a lesser working interest position. Equity, if available
and if on favorable terms, may be utilized to help fund Bengal’s capital program.
Health, Safety and Environment
All phases of the oil and natural gas business present environmental risks and hazards and are subject to
environmental regulation pursuant to a variety of federal, provincial and local laws and regulations.
Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases
or emissions of various substances produced in association with oil and natural gas operations. The
legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to
the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant
expenditures and a breach of applicable environmental legislation may result in the imposition of fines and
penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement,
larger fines and liability and potentially increased capital expenditures and operating costs. The discharge
of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and
third parties and may require the Company to incur costs to remedy such discharge.
25
BENGAL ENERGY LTD.
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.
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;
●
●
●
26
●
●
●
●
Expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and
development;
The Company expects netbacks to remain above $35/bbl under current market conditions;
Treatment under governmental regulatory regimes and tax laws;
Capital expenditures programs and estimates of costs;
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;
2016 Annual Report
With respect to the forward looking statements contained in the MD&A, Bengal has made assumptions regarding: future
commodity prices; the impact of royalty regimes; the timing and the amount of capital expenditures; production of new
and existing wells and the timing of new wells coming on stream; future operating expenses including processing and
gathering fees; the performance characteristics of oil and natural gas properties; the size of oil and natural gas
reserves; the ability to raise capital; the continued availability of undeveloped land and skilled personnel; the ability to
obtain equipment in a timely manner to carry out exploration and development activities; the ability to obtain financing
on acceptable terms; the ability to add production and reserves through exploration and development activities; and the
continued stability of political, regulatory; tax and fiscal regimes in which the Company has operations.
The actual results could differ materially from those anticipated in these forward-looking statements as a result of the
risk factors set forth below and elsewhere in this Management’s Discussion and Analysis:
●
●
●
●
●
●
●
●
●
●
Volatility in market prices for oil and natural gas;
Liabilities inherent in oil and natural gas operations;
Uncertainties associated with estimating oil and natural gas reserves;
Competition
for, among other
things: capital, acquisitions of
reserves, undeveloped
lands and
skilled personnel;
Incorrect assessment of the value of acquisitions;
Unable to meet commitments due to inability to raise funds or complete farm-outs;
Geological, technical, drilling and processing problems;
Changes in income tax laws or changes to royalty and environmental regulations relating to the oil and
gas industry;
The risk that Bengal may not be successful in raising funds by an equity issue; and
Counter-party credit risk, stock market volatility and market valuation of Bengal’s stock.
Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the
implied assessment, based on certain estimates and assumptions, which the resources and reserves described can be
profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The
forward-looking statements contained in this MD&A and the documents incorporated by reference herein are expressly
qualified by this cautionary statement. The forward-looking statements contained in this document speak only as of the
date of this document and Bengal does not assume any obligation to publicly update or revise them to reflect new
events or circumstances, except as may be required pursuant to applicable securities laws. Additional information on
these and other factors that could affect Bengal’s operations and financial results are included in reports on file with
Canadian securities authorities and may be accessed through the SEDAR website (www.sedar.com) and at Bengal’s
website (www.bengalenergy.ca).
These statements speak only as of the date of this MD&A or as of the date specified in the documents incorporated by
reference into this Management’s Discussion and Analysis, as the case may be.
27
BENGAL ENERGY LTD.
MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL REPORTING
The accompanying consolidated financial statements are the responsibility of management. The
consolidated financial statements have been prepared by management in accordance with International
Financial Reporting Standards outlined in the notes to the consolidated financial statements. The
consolidated financial statements include certain estimates that reflect 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, 2016. During this evaluation, management
identified material 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 Professional Accountants, has been engaged, as approved
by a vote of the shareholders at the Company’s most recent annual general meeting, to examine the
consolidated financial statements in accordance with Canadian generally accepted auditing standards and
provide an independent professional opinion.
The audit committee of the Board of Directors with all of its members being independent directors, have
reviewed the consolidated financial statements including notes thereto with management and KPMG LLP.
The consolidated financial statements have been approved by the Board of Directors on the
recommendation of the Audit Committee.
(signed) “Chayan Chakrabarty”
Chayan Chakrabarty
President & Chief Executive Officer
(signed) “Jerrad Blanchard”
Jerrad Blanchard
Chief Financial Officer
28
2016 Annual Report
INDEPENDENT AUDITORS’ REPORT
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, 2016 and March 31, 2015, the
consolidated statements of loss and comprehensive loss, changes in equity and cash flows for the years
then ended, and notes, comprising a summary of significant accounting policies and other explanatory
information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial
statements in accordance with International Financial Reporting Standards, and for such internal control as
management determines is necessary to enable the preparation of consolidated financial statements that
are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those
standards require that we comply with ethical requirements and plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are free from material
misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on our judgment, including the
assessment of the risks of material misstatement of the consolidated financial statements, whether due to
fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s
preparation and fair presentation of the consolidated financial statements in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on
the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of
accounting policies used and the reasonableness of accounting estimates made by management, as well
as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a
basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated
financial position of Bengal Energy Ltd. as at March 31, 2016 and March 31, 2015, and its consolidated
financial performance and its consolidated cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered Professional Accountants
June 16, 2016
Calgary, Canada
29
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Thousands of Canadian dollars)
As at March 31,
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Prepaid expenses and deposits
Fair value of financial instruments
Non-current assets:
Exploration and evaluation assets
Petroleum and natural gas properties
Fair value of financial instruments
Total assets
LIABILITIES AND SHAREHOLDERS’
EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Current portion of credit facility
Non-current liabilities:
Decommissioning liability
Credit facility
Other long-term liabilities
Shareholders’ equity:
Share capital
Contributed surplus
Warrants
Accumulated other comprehensive
income (loss)
Deficit
Total liabilities and shareholders’ equity
Commitments and contingencies (note 16)
Subsequent event (note 17)
Notes
2016
2015
3
13
4
5
13
8
9
8
7
10
7
$ 3,010
140
3,187
155
5,806
12,298
19,626
24,875
1,294
45,795
$ 58,093
$ 1,749
140
3,109
348
2,164
7,510
28,245
27,122
2,802
58,169
$ 65,679
$ 2,669
10,049
12,718
$ 2,289
-
2,289
1,422
7,816
-
9,238
94,151
7,442
167
1,454
16,982
3
18,439
94,151
7,341
167
1,335
(66,958)
36,137
$ 58,093
(130)
(56,578)
44,951
$ 65,679
See accompanying notes to the consolidated financial statements.
On behalf of the Board:
(signed) “Chayan Chakrabarty”
Chayan Chakrabarty
President & Chief Executive Officer
(signed) “James B. Howe”
James B. Howe
Director
30
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE
INCOME (LOSS)
(Thousands of Canadian dollars, except per share amounts)
For the years ended March 31,
2016
2015
2016 Annual Report
Income
Petroleum and natural gas revenue
Royalties
Realized gain on financial instruments
Unrealized gain on financial instruments
Operating expenses
General and administrative
Operating and transportation
Depletion and depreciation
Pre-licensing & impairment
Share-based compensation
Operating (loss) income
Other expenses
Other
Finance expenses
Foreign exchange
Net loss
Exchange differences on translation of foreign operations
Total comprehensive loss for the year
Loss per share
- Basic & diluted
Weighted average number of shares outstanding (000s)
- Basic & diluted
See accompanying notes to the consolidated financial statements.
Notes
$11,187
(728)
10,459
3,840
1,861
16,160
2,663
6,480
4,543
11,223
91
25,000
(8,840)
(2)
(1,318)
(220)
(1,540)
(10,380)
1,465
(8,915)
5
4,5
12
10
10
$15,669
(1,057)
14,612
891
4,962
20,465
3,407
6,247
5,162
4,762
170
19,748
717
(334)
(1,745)
(1,810)
(3,889)
(3,172)
(1,666)
(4,838)
(0.15)
(0.05)
68,178
65,349
31
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Thousands of Canadian dollars)
Issuance of common shares
3,510,714
1,000
Balance at
April 1, 2014
Net loss for the year
Comprehensive loss for the
year
Share-based compensation –
expensed
Share-based compensation –
capitalized
Balance at
March 31, 2015
Balance at
April 1, 2015
Net loss for the year
Comprehensive income for
the year
Share-based compensation –
expensed
Share-based compensation –
capitalized
Balance at
March 31, 2016
Shares
outstanding
Share
capital Warrants
Contributed
surplus
Accumulated
other
comprehensive
income
Total
shareholders’
equity
Deficit
64,667,082
$ 93,151
$ 167
$ 7,141
$ 1,536
$ (53,406)
$ 48,589
-
-
-
-
-
-
-
-
-
(10)
(1,666)
-
-
-
-
-
170
-
40
-
(3,172)
(3,172)
-
-
-
-
(1,666)
990
170
40
-
-
-
68,177,796
$94,151
$ 167
$ 7,341
$ (130)
$ (56,578)
$ 44,951
68,177,796
$94,151
$167
$7,341
$ (130) $(56,578)
$44,951
-
-
-
-
-
-
-
-
-
-
-
-
-
-
91
10
-
(10,380)
(10,380)
1,465
-
-
-
-
-
1,465
91
10
68,177,796
$94,151
$167
$7,442
$1,335
$(66,958)
$36,137
See accompanying notes to the consolidated financial statements.
32
CONSOLIDATED STATEMENTS OF CASH FLOWS
2016 Annual Report
(Thousands of Canadian dollars)
For the years ended March 31,
Operating activities
Net loss for the year
Non-cash items:
Depletion and depreciation
Pre-licensing & impairment
Accretion on decommissioning liability
Accretion on notes payable and credit facility
/change in fair value of VARs
Settlement of decommissioning liability
Share-based compensation
Unrealized gain on financial instruments
Unrealized foreign exchange (gain) loss
Change in non-cash working capital
Net cash from operating activities
Investing activities
Exploration and evaluation expenditures
Petroleum and natural gas properties
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 credit facility, net of
issuance costs
Repayment of notes
Changes in non-cash working capital
Net cash (used in) 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
2016
2015
Notes
$ (10,380)
$ (3,172)
4,543
11,223
33
5,162
4,762
15
428
-
91
(1,861)
(29)
4,048
1,350
5,398
551
(19)
170
(4,962)
2,082
4,589
2,332
6,921
(761)
(2,586)
(579)
(3,926)
(3,189)
(10,274)
(2,642)
(16,105)
-
-
-
(282)
(282)
71
1,261
1,749
3,010
14
14,520
(8,774)
(673)
5,087
(138)
(4,235)
5,984
$ 1,749
15
4
5
15
10
8
7
15
See accompanying notes to the consolidated financial statements.
33
BENGAL ENERGY LTD.
Notes to Consolidated Financial Statements (the “financial statements”)
Years ended March 31, 2016 and 2015
(Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)
1.
REPORTING ENTITY
Bengal Energy Ltd (the “Company” or “Bengal”) is incorporated under the laws of the Province of
Alberta and is involved in the exploration for and development 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, 2016 and 2015 and for the years ended March 31, 2016 and 2015 are
comprised of the Company and its wholly owned subsidiaries Bengal Energy International Inc., which
are incorporated in Canada and Bengal Energy Australia (Pty) Ltd., Avery Resources (Northern
Ireland) Ltd. and Northstar Energy Pty Ltd. which are incorporated in 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 financial statements were approved and authorized for issuance by the Board of Directors on
June 16, 2016.
b) Basis of measurement
These financial statements have been prepared on a historical cost basis, except for commodity
contracts as discussed in Note 20.
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 Indian subsidiary is US
dollars; and the functional currency of the Australian subsidiary is Australian dollars.
3.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash on hand and in banks and investments with an original
maturity date of 90 days or less. Cash and cash equivalents at the end of the reporting period as shown
in the statement financial position are comprised of:
As at
($000s)
Cash and bank balances
Short-term deposits
March 31, 2016
March 31, 2015
$
$
3,003
7
3,010
$
$
1,743
6
1,749
34
4.
EXPLORATION AND EVALUATION ASSETS (E&E ASSETS)
($000s)
Balance at March 31, 2014
Additions
Capitalized share-based compensation
E&E impairment loss
Exchange adjustments
Balance at March 31, 2015
Additions
Acquisition
Capitalized share-based compensation
E&E impairment loss
Exchange adjustments
Balance at March 31, 2016
2016 Annual Report
$
26,821
3,189
10
(1,592)
(183)
$ 28,245
651
110
4
(10,475)
1,091
19,626
Exploration and evaluation assets consist of the Company’s exploration projects in Australia which are
pending the determination of proved or probable reserves. Costs primarily consist of acquisition costs,
geological & geophysical work, seismic and drilling and completion costs until the drilling of wells is
complete and the results have been evaluated.
On April 1, 2015, the Company acquired an incremental 21.4% interest in ATP 934 for an acquisition
price of $0.1 million resulting in a current 71.4% working interest. ATP 934 is an exploration permit,
without any operating revenues or expenditures.
In India, the Company has provided notice to its partners and applicable Government authorities of its
intention to withdraw from all ongoing operations and does not expect to recover any exploration costs.
Based on this, the Company recorded an impairment charge of $7.4 million equal to its E&E assets in
India.
In the process of management’s internal analysis of prospectively and planning for scheduled
relinquishment in 2017 for ATP 732, Bengal identified several areas deemed to have low potential for
future exploration. All historical costs associated with exploration in these select areas have been
impaired for an expecnse of $3.2 million subject to the Company’s plans to relinquish.
A summary of E&E assets is shown in the table below:
($000s)
ATP 732P – Tookoonooka
ATP 752P
CY-ONN-2005/1 – onshore
Other(1)
March 31, 2015 ($000)
$
India
Australia
$ 18,825
1,044
Exploration and Evaluation Assets
Total
$ 18,825
1,044
6,771
1,605
$ 28,245
Exploration and Evaluation Assets
Total
$ 16,163
1,243
-
2,220
$ 19,626
Other includes ATP 934P, capitalized G&A and share-based compensation and foreign exchange effects on assets
denominated in foreign currencies.
Australia
$ 16,163
1,243
1,605
$ 21,474
2,220
$ 19,626
-
6,771
$ 6,771
-
India
$
$
-
-
ATP 732P – Tookoonooka
ATP 752P
CY-ONN-2005/1 – onshore
Other(1)
March 31, 2016 ($000)
(1)
35
BENGAL ENERGY LTD.
5.
PETROLEUM AND NATURAL GAS PROPERTIES
($000s)
Cost:
Balance at April 1, 2014
Additions
Non-cash additions
Capitalized share-based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2015
Additions
Capitalized share-based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2016
($000s)
Accumulated depletion, depreciation and
impairment losses:
Balance at April 1, 2014
Depletion and depreciation charge
Exchange adjustments
Balance at March 31, 2015
Depletion and depreciation charge
Impairment
Exchange adjustments
Balance at March 31, 2016
Net carrying value
At March 31, 2015
At March 31, 2016
Petroleum and
Natural Gas
Properties
Corporate
Assets
28,404
10,274
53
30
1,118
(1,178)
38,701
2,586
6
(95)
622
41,820
318
-
-
-
-
24
342
-
-
-
2
344
Petroleum and
Natural Gas
Properties
Corporate
Assets
6,819
4,800
59
11,678
4,519
748
75
17,020
27,023
24,800
234
32
(23)
243
24
-
2
269
99
75
Total
28,722
10,274
53
30
1,118
(1,154)
39,043
2,586
6
(95)
624
42,164
Total
7,053
4,832
36
11,921
4,543
748
77
17,289
27,122
24,875
The calculation of depletion for the year ended March 31, 2016 included $83.6 million for estimated
future development costs associated with proved and probable reserves in Australia (March 31, 2015 -
$123.8 million).
As a result of the significant decline in forecast crude oil prices, the Company tested its CGUs for
impairment. The recoverable amount of a CGU was determined based on the higher of value in use
and fair value less costs to sell. The recoverable amount for the year ended March 31, 2016 was
determined using value in use, based on discounted before tax cash flows of proved plus probable
crude oil reserves estimated by the Company’s qualified reserves evaluators using forecasted prices
and costs.
The reserves relating to the Toporoa CGU were determined to be uneconomic in the current commodity
price environment. As a result, the carrying value of $0.7 million relating to the Toporoa CGU was
impaired at March 31, 2016. No impairment was determined to exist relating to the Cuisinier CGU.
36
6.
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:
2016 Annual Report
Years Ended March 31,
($000s)
(Loss) income before taxes
Statutory tax rate
Expected income tax expense (recovery)
Foreign exchange
Stock-based compensation
Effect of change in tax rate & other
Other
Changes in unrecognized tax asset
Income tax recovery
2016
(10,380)
26.5%
(2,751)
(258)
24
768
(50)
2,267
-
$
2015
(3,172)
25%
(793)
(614)
51
(394)
194
1,556
$ -
The Government of Alberta increased the corporate income tax rate from 10 percent to 12 percent,
resulting in a blended Alberta provincial corporate tax rate of 11 percent for the year ended December
31, 2015. This was substantively enacted in June 2015.
The temporary deductible differences included in the Company’s unrecognized deferred income tax
assets are as follows:
As of March 31,
($000s)
Non-capital losses
Net capital losses
P&NG properties
Share issue costs
Decommissioning obligations
2016
30,976
5,742
14,386
764
101
51,969
$
$
2015
27,373
5,890
8,288
742
99
42,392
$
$
The components of the Company’s and its subsidiaries deferred income tax liabilities are as follows:
As of March 31,
($000s)
Property, plant & equipment
Fair value of financial instruments
Foreign exchange
Decommissioning obligations
Non-capital losses
2016
13,286
2,130
(673)
(390)
(14,353)
-
$
2015
14,515
1,490
(416)
(400)
(15,189)
-
$
At March 31, 2016, the Company had approximately $23.9 million and $49.8 million of non-capital
losses in Canada and Australia respectively (2015- $29.5 million and $50.6 million), available to reduce
future taxable income. The Canadian non-capital losses expire at various dates from March 31, 2016 to
2035. The Australian non-capital losses have no term to expiry. The Company’s ongoing drilling
activities continue to generate deferred assets related to Petroleum Resource Rent Tax (“PRRT”) in its
Australia subsidiary, which has not been recognized.
The Company has temporary differences associated with its investments in its foreign subsidiaries,
branches, and interests in joint ventures. At March 31, 2016, the Company has no deferred tax
liabilities in respect of these temporary differences.
37
BENGAL ENERGY LTD.
7.
NOTES PAYABLE
Non-Convertible Notes – Issued
July 5, 2013 ($000s)
Gross proceeds
Total cash fees
Accretion on debt/change in fair
value of VARs
Deferred tax impact
Repayment
Balance at March 31, 2015
Change in fair value of VARs
Balance at March 31, 2016
Total
8,000
(257)
7,743
482
(55)
(8,000)
170
(3)
167
Debt
Component
Other long-term
liability
Warrants
7,593
(256)
7,337
663
-
(8,000)
-
-
-
178
6
184
(181)
-
-
3
(3)
-
229
(7)
222
-
-
-
167
-
167
In October 5, 2014, the Company repaid $0.5 million of outstanding principal of notes issued July 5,
2013. In November 2014, the Company redeemed the remaining principal of $7.5 million for an early
redemption price equal to $1.03 per $1.00 (booked as interest expense) of outstanding principal amount
plus all accrued and unpaid interest thereon. Interest expense recorded during the year on the July 5,
2013 notes totaled $0.7 million, including the early redemption fee.
In conjunction with the $8.0 million notes issued July 5, 2013, 546,845 VARs and 703,125 warrants
remain outstanding. Each whole warrant entitles the holder thereof, until July 5, 2016, 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, until July 5, 2016, 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. The warrants and initial VAR valuation are valued based on the following key assumptions:
a term of 3 years, volatility of 73% and a price of $0.75/share.
On January 21, 2015 the Company redeemed its January 25, 2013 notes payable for a redemption
price of $2.0 million including principal and accrued and unpaid interest. Approximately $0.8 million of
the aggregate was paid in cash, and certain holders of the remaining $0.9 million of aggregate principal
received the redemption price through the issuance of common shares of the Company at a price of
$0.28 per common share in lieu of cash. Interest expense recorded during fiscal 2015 on the January
25, 2013 notes totaled $0.1 million.
8.
CREDIT FACILITY
Facility Agreement – Issued November 12, 2014 ($000s)
Gross proceeds
Total cash fees
Unrealized foreign exchange loss
Accretion
Balance at March 31, 2015
Unrealized foreign exchange loss
Accretion
Balance at March 31, 2016
Current portion of credit facility at March 31,
Current portion of credit facility
Non-current portion of credit facility
38
15,364
(844)
14,520
2,307
16,827
155
16,982
452
431
17,865
2015
-
16,982
2016
10,049
7,816
2016 Annual Report
In October 2014, Bengal closed its secured credit facility with Westpac Institutional Bank and placed an
initial draw on November 12, 2014 of US $14.0 million. The facility is secured by the Company’s
producing assets in the Cuisinier field in Australia’s Cooper Basin, has a three-year term and carries an
interest rate of US Libor plus 3.2% to 3.5% depending on certain reserve forecast parameters.
The credit facility is structured as a reserves-based revolving facility under a predetermined reduction
schedule, to be evaluated based on existing reserves at each calculation date. Calculation dates
commenced December 31, 2015 and occur every six months thereafter until June 30, 2017 with a
reduction of $6.25 million to the facility limit at each calculation date based on the Company’s existing
reserve profile. The facility limit at March 31, 2016, is US $18.75 million. The current portion of the
credit facility (US $7.75 million/CAD $10.5 million) reflects the June 30, 2016 reduction of US $1.5
million and the December 31, 2016 of US $6.25 million. Under the reduction schedule the facility limit
would be reduced to nil by June 30, 2017.
The credit facility’s covenants include a debt service coverage ratio (cash available for debt payments
divided by mandatory debt repayments) as well as a loan life coverage ratio (net present value of future
cash available for debt service divided by the available facility). These covenants impact the
Company’s availabile facility limit, and therefore the ability to secure its debt as a percentage of reserve
forecasts and are evaluated at each calculation date. These covenants are calculated using inputs as
prescribed by Westpac, and a default event triggered by a breach of covenants may result in a full
redemption of all outstanding borrowings under the terms of the credit facility. There are no financial
covenants associated with this credit facility. The Company was in compliance with the stated
covenants at March 31, 2016.
9.
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:
March 31,
($000s)
Decommissioning liability, beginning of year
Revision
Decommissioning expenditures
Additions
Accretion
Exchange adjustments
Decommissioning liability, end of year
2016
1,454
(95)
-
-
33
30
1,422
2015
358
901
(19)
217
15
(18)
1,454
The Company’s decommissioning liability results 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, 2016 is approximately $1.9
million (March 31, 2015 – $2.0 million) which will be incurred between 2019 and 2044. An inflation
factor of 1.5% – 1.7% and a risk-free discount rate ranging between 1.36% and 2.49% have been
applied to the decommissioning liability at March 31, 2016.
10.
SHARE CAPITAL
(a) Authorized:
Unlimited number of common shares with no par value.
Unlimited number of preferred shares, of which none have been issued.
39
BENGAL ENERGY LTD.
(b) Issued:
The following provides a continuity of share capital:
($000s)
Balance at March 31, 2014
Issued on conversion of debt
Issued on exercise of stock options for cash
Issued from contributed surplus on exercise of
stock options
Balance at March 31, 2015
Issued on conversion of debt
Issued on exercise of stock options for cash
Issued from contributed surplus on exercise of
stock options
Balance at March 31, 2016
(c) Share-based compensation – stock options:
Number of Shares
64,667,082
3,485,714
25,000
-
68,177,796
-
-
-
68,177,796
Amount
93,151
976
14
10
94,151
-
-
-
94,151
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. Effective with the
option grant of July 30, 2015, performance criteria were introduced, which allow for the vesting of
stock options contingent on meeting pre-established targets based on internal and external metrics.
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 on 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:
Options
Weighted Average Exercise
Price
Outstanding at March 31, 2014
Granted
Forfeited
Expired
Exercised
Outstanding at March 31, 2015
Granted
Forfeited
Expired
Exercised
Outstanding at March 31, 2016
Exercisable at March 31, 2016
3,873,333
-
(116,667)
(216,666)
(25,000)
3,515,000
1,072,500
-
(230,000)
-
4,357,500
3,285,000
40
$
0.89
-
0.62
0.99
0.58
$
0.89
0.18
-
0.86
-
0.72
$ 0.89
$
2016 Annual Report
Option Price (1)
$0.00 - $0.46
$0.47 - $0.65
$0.66 - $1.25
$1.26 - $1.32
Total
Options Outstanding
Options Exercisable
Number
Outstanding
Exercise
Price (2)
Remaining
Life (3)
Number
Exercisable
Exercise
Price (2)
1,072,500
1,730,000
985,000
570,000
4,357,500
$0.18
$0.59
$1.17
$1.32
$0.72
4.33
2.09
0.83
0.25
2.12
-
1,730,000
985,000
570,000
3,285,000
$0.18
$0.59
$1.17
$1.32
$0.89
(1) Range of option exercise prices
(2)
(3)
Weighted average exercise price of options
Weighted average remaining contractual life of options in years
The fair value of options granted on July 30, 2015, were estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average assumptions and resulting
values:
For the Year Ended March 31,
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
2016
1.5%
5 yr
78%
-
$0.18
$0.18
2015
-
-
-
-
-
-
(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, 2016 was $122 (2015 -
$nil). No options were granted during the year ended March 31, 2015.
(d) Per share amounts:
Loss per share is calculated based on net loss and the weighted-average number of common
shares outstanding.
For the Year Ended
($000s)
Loss for the year
Weighted average number of common shares (basic)
Weighted average number of common shares (diluted)
Basic and diluted loss per share
2016
2015
(10,380)
68,178
68,178
(0.15)
(3,172)
65,349
65,349
(0.05)
For the twelve months ended March 31, 2016, there were 4,357,000 (March 31, 2015 – 3,515,000)
options respectively considered anti-dilutive.
In addition, there were 703,125 warrants and 546,875 value appreciation rights considered anti-
dilutive.
11.
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:
41
BENGAL ENERGY LTD.
Year ended March 31,
($000s)
Salaries & employee benefits
Share-based compensation(1)
General & administrative expenses
2016
2015
$ 974
79
$ 1,053
$ 1,011
156
$ 1,167
(1) Represents the amortization of share-based payment expense associated with the company’s share-based compensation
plans granted to key management personnel.
12.
FINANCE INCOME/EXPENSES
Year ended March 31,
($000s)
Interest income
Accretion on decommissioning obligations
Performance Security Guarantee fee
Letter of credit charges
Interest on notes payable and credit facility
Accretion on notes payable and change in fair value of VARs
Finance income (expenses)
13.
FINANCIAL RISK MANAGEMENT
2016
2015
$ 9
(33)
-
14
(1,311)
3
$ (1,318)
$ 18
(15)
(55)
(32)
(1,212)
(449)
$ (1,745)
The Company has exposure to credit, liquidity and market risk from its use of financial instruments. This
note presents information about the Company’s exposure to these risks, the Company’s objectives and
policies and processes for measuring and managing risk.
The Board of Directors has overall responsibility for identifying the principal risks of the Company and
ensuring the policies and procedures are in place to appropriately manage these risks. Bengal’s
management identifies, analyzes and monitors risks and considers the implication of the market
condition in relation to the Company’s activities.
(a) Credit risk:
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial
instrument fails to meet its contractual obligations, and arises principally from Bengal’s cash calls
paid to joint venture partners and receivables from petroleum and natural gas marketers. As at
March 31, 2016, Bengal’s receivables consisted of $2.6 million (March 31, 2015 - $2.6 million) from
joint venture partners and $0.6 million (March 31, 2015 - $0.5 million) of other trade receivables of
which $1.9 million has been subsequently collected.
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.
The Company had no accounts considered past due at March 31, 2016, (March 31, 2015 - $nil
million). Past due is considered greater than 90 days outstanding.
The carrying amount of accounts receivable and cash and cash equivalents and fair value of
financial instruments represents the maximum credit exposure. Bengal establishes an allowance
for doubtful accounts as determined by management based on their assessment of collection.
42
2016 Annual Report
Bengal does not have an allowance for doubtful accounts as at March 31, 2016 and did not provide
for any doubtful accounts, nor was it required to write-off any receivables during the twelve months
ended March 31, 2015. Exposure to the carrying value of its financial instruments relates to the
Company’s commodity-based derivatives held by WestPac Banking Corporation, which carries a
Standard & Poor’s credit rating of AA-. Management considers the credit risk of these instruments
to be adequately mitigated by the credit stating of their holder, therefore no allowance has been
established.
Cash and cash equivalents, when held, consist of cash bank balances and guaranteed investment
certificates redeemable at any time. Bengal manages the credit exposure related to guaranteed
investments by selecting counterparties based on credit ratings and monitors all investments to
ensure a stable return, avoiding complex investment vehicles with higher risk such as asset-backed
commercial paper.
(b) Liquidity risk:
Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including
work commitments, as they are due. Bengal prepares an annual budget and updates forecasts for
operating, financing and investing activities on an ongoing basis to ensure it will have sufficient
liquidity to meet its liabilities when due.
Bengal’s financial liabilities consist of accounts payable and accrued liabilities, and credit facility
and amounted to $20.6 million at March 31, 2016, (March 31, 2015- $19.3 million).
At March 31, 2016 the Company had $0.5 million of working capital deficiency, including cash and
short-term deposits of $3.0 million and restricted cash of $0.1 million, compared to working capital
of $5.2 million at March 31, 2015.
In the previous fiscal year, Bengal had finalized a US $25.0 million secured credit facility drawing
US $14.0 million in November 2014. Proceeds from this facility are restricted for use within the
Cuisinier production licence. Refer to Note 8 for discussion on repayment terms and covenants
related to the credit facility.
The majority of the Company’s oil sales are benchmarked on dated Brent prices which averaged
US $47.44/bbl for the twelve months ended March 31, 2016. The Company incurs most of its
expenditures in Australian dollars whereas the Company generates most of its revenues in US
dollars. To mitigate the net impact of low crude prices, the Company is acting with its joint venture
partners to reduce discretionary spending and focus capital towards lower risk projects with near-
term cash flow upside. The Company has also entered into derivative commodity contracts to
reduce the impact of price volatility.
Bengal will continue to monitor trends in commodity prices to ensure its financial obligations are
met, while continuing to grow its asset base where appropriate. Under the current commodity price
environment, the Company has no plans to use its internal source of cash to fund exploration
activities. These are expected to be financed through farm-out or alternative financing sources.
The table below indicates the payment schedule for the credit facility:
Credit facility (US $000s)
Fiscal year 2017
Fiscal year 2018
(c)
Market risk:
7,750
6,250
14,000
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,
43
BENGAL ENERGY LTD.
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, US dollars for Australian oil sales and incurs expenditures in Australian, Canadian and US
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, 2016
($000s)
Cash and short-term deposits
Restricted cash
Accounts receivable
Accounts payable and accrued liabilities
Credit facility
Fair value of financial instruments
Commodity Price Risk
CAD
AUD
USD
280
140
18
(258)
-
-
180
73
-
3,169
(2,391)
-
-
851
2,657
-
-
(20)
(17,865)
7,100
(8,128)
Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of a
change in commodity prices. Commodity prices for petroleum and natural gas are impacted by not
only the relationship between the Canadian and United States dollar, as outlined above, but also
world economic events that dictate the levels of supply and demand. Australian oil prices are
based on the Dated Brent reference price, which trades at a premium to WTI.
At March 31, 2016, the following derivative contracts were outstanding and recorded at estimated
fair value:
Time Period
Type of Contract
April 1, 2016 – May 31, 2017
Oil - Swap
April 1, 2016 – May 31, 2017
($000s)
Current fair value of financial instruments
Non-current fair value of financial instruments
Total
Oil – Put option
Quantity
Contracted
(bbls)
81,605
66,764
Oil - swap
3,188
706
3,894
Price Floor
(US$/bbl)
Price Ceiling
(US$/bbl)
80.00
80.00
Oil – put
80.00
-
Total
5,806
588 1,294
3,206 7,100
2,618
A US$1.00 increase in the future crude oil price per barrel would result in an approximate $148,000
decrease in the fair value of financial instruments at March 31, 2016 while a $US1.00 decrease
would result in an increase of approximately US$148,000 in the fair value of the instruments.
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, 2016 as the funds are not invested in interest-bearing instruments. The Company’s
44
credit facility carries a floating interest rate based on quoted US dollar Libor rates. The Company
had no interest rate derivatives at March 31, 2016.
For the year ended March 31, 2016, a 1% increase in US Libor would increase interest expense by
$184,000.
2016 Annual Report
14.
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 has drawn US $14 million from its US $18.75 million available credit facility and typically
structures its debt position to ensure forecasted cash flows exceed debt covenant ratios. The Company
is within these parameters at March 31, 2016. There have been no changes in how the Company
manages capital as compared to the prior year other than the covenants described in Note 8. There
are no external restrictions on the Company’s capital.
15.
CHANGES IN NON-CASH WORKING 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
2016
$
(78)
193
380
(6)
$ 489
$ 1,350
(282)
(579)
$ 489
$
$
$
$
2015
712
142
(1,885)
48
(983)
2,332
(673)
(2,642)
(983)
The following represents the cash interest paid and received in each period.
Year ended March 31,
($000s)
Cash interest paid
Cash interest received
2016
2015
$ 870 1
$ 9
$ 1,195
$ 13
45
BENGAL ENERGY LTD.
16.
COMMITMENTS AND CONTINGENCIES
Pursuant to current production sharing contracts (“PSC”), the Company is required to perform minimum
exploration activities that include various types of surveys, acquisition and processing of seismic data
and drilling of exploration wells. Additional commitments are reflected where the Company has agreed
with joint operating 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.
The Queensland Government regulatory authority granted the Company Authority to Prospect 934
("ATP 934") under a revised work program on March 1, 2015. The Company acquired an additional
21.43 % working interest and received ministerial approval for the acquisition on August 11, 2015.
Currently the Company holds a 71.43% operating interest in this permit. Work program consists of 200
kilometers of 3D seismic and up to three wells.
Country and Permit
Work Program
Obligation Period
Ending
Estimated Expenditure
(net) (millions CAD$)(1)
Onshore Australia –
ATP 934P
200 km2 of 3D seismic and up to
three wells
March 2021
$ 16.6
(1) Translated at March 31, 2016 at an exchange rate of AUS $1.00 = CAD $0.9943.
At March 31, 2016 the Company had the following lease commitment for office space in Canada.
($000s)
April 2016 to March 2017
Office lease
Total
265
Less than
1 Year
265
1-3
Years
-
4-5
Years
-
After
5 Years
-
Effective April 1, 2012 the Company entered into a head lease in Calgary, Canada for a term of five
years.
SUBSEQUENT EVENT
17.
Effective June 1, 2016, Bengal and its Joint Venture has unanimously agreed and provided notice to the
applicable Government of India Authorities of its intention to exit the CY-ONN-2005/1 exploration block.
The joint venture was unable to acquire the land rights required for exploration causing a force majeure
condition for the duration of the first term of exploration, and is therefore entitled to exit the permit
without penalty for unfinished work program commitments. With the exit from the permit, the Company
has effectively ceased all operations in India.
18.
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, 2016 amount to $1.3 million (March 31, 2015 - $1.4
million).
19.
SEGMENTED INFORMATION
As at March 31, 2016, the Company has three reportable operating segments being the Australian,
Canadian and Indian oil and gas operations.
Revenue reported below represents revenue generated from external customers. There were no inter-
segment sales in any of the reported periods.
The accounting policies of the reportable segments are the same as the group’s accounting policies.
Segment profit represents the profit earned by each segment without allocation of central administration
46
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.
2016 Annual Report
For the year ended March 31, 2016 ($000s)
Australia
Canada
India
Revenue
Interest revenue
Interest expense
Depletion and depreciation
Net (earnings) loss
Exploration and evaluation expenditures
Petroleum and natural gas property
expenditures
Impairment losses (recovery)
March 31, 2016 ($000s)
Petroleum and natural gas properties
Cost
Accumulated impairment losses
Accumulated depletion, depreciation
and accretion
Net book value
Exploration and evaluation assets
Accumulated impairment losses
Net book value
For the year ended March 31, 2015 ($000s)
11,187
8
1,311
4,519
(1,342)
741
2,586
3,848
37,527
(796)
(11,931)
24,800
28,831
(9,205)
19,626
-
1
-
24
(1,305)
-
-
-
4,638
(310)
(4,253)
75
-
-
-
-
(7,733)
20
-
7,375
-
-
-
-
-
-
-
8,188
(8,188)
-
Total
11,187
9
1,311
4,543
(10,380)
761
2,586
11,223
42,165
(1,106)
(16,184)
24,875
37,019
(17,393)
19,626
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, 2015 ($000s)
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
Australia
15,395
17
332
4,623
4,354
3,084
Canada
274
1
880
413
(6,964)
-
India
-
-
-
-
(562)
105
10,274
-
1,592
-
-
3,170
34,407
(796)
4,637
(437)
(6,586)
27,025
32,653
(11,179)
21,474
-
(4,103)
97
-
-
-
5,130
-
(403)
-
-
-
-
-
-
-
7,963
(1,192)
6,771
-
-
Total
15,669
18
1,212
5,036
(3,172)
3,189
10,274
-
4,762
39,044
(1,233)
(10,689)
27,122
40,616
(12,371)
28,245
5,130
(403)
-
- -
(4,727)
-
-
(4,727)
-
20.
SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently to all periods presented in these
financial statements, and have been applied consistently by the Company and its subsidiaries.
47
BENGAL ENERGY LTD.
(a) Basis of consolidation:
The 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.,
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 financial statements from the
date that control commences until the date that control ceases.
The Company recognizes in the financial statements its proportionate share of the assets, liabilities,
revenues and expenses of its joint operations.
All intra-group transactions, balances, income and expenses are eliminated in full on consolidation.
(b) Cash and cash equivalents
Cash and cash equivalents include cash and all investments with a maturity of three months or less.
(c) Provisions
A provision is recognized if, as a result of a past event, the Company has a present legal or
constructive obligation that can be estimated reliably, and it is probable that an outflow of economic
benefits will be required to settle the obligation. Provisions are determined by discounting the
expected future cash flows at a pre-tax “risk-free” rate that reflects current market assessments of
the time value of money and the risks specific to the liability. The unwinding of the discount is
recognized as a finance expense. Provisions are not recognized for future operating losses.
Decommissioning and restoration liabilities:
The Company’s activities give rise to dismantling, decommissioning and site disturbance
remediation activities. Provision is made for the estimated cost of site restoration and capitalized in
the relevant asset category.
Decommissioning obligations are measured at the present value of management’s best estimate of
the expenditures required to settle the present obligation at the period end date. Subsequent to the
initial measurement, the obligation is adjusted at the end of each period to reflect the passage of
time and changes in the estimated future cash flows underlying the obligation. The increase in the
provision due to the passage of time is recognized as finance costs whereas increases/decreases
due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon
settlement of the asset retirement obligations are charged against the provision to the extent the
provision was established.
(d) Oil and natural gas exploration and evaluation expenditures
Exploration and evaluation 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 have not yet been demonstrated. These
costs generally include unproved property acquisition costs, geological and geophysical costs,
sampling and appraisals, drilling and completion costs and capitalized decommissioning costs.
48
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.
2016 Annual Report
(e) Petroleum and natural gas properties
Carrying value
Costs incurred subsequent to the determination of technical feasibility and commercial viability are
recognized as petroleum and natural gas properties in the specific asset to which they relate.
Petroleum and natural gas properties are stated at cost less accumulated depreciation and
depletion and accumulated impairment losses. The initial cost of a petroleum and natural gas
property is comprised of its purchase price or construction cost, any costs directly attributable to
bringing the asset into operation, the initial estimate of the decommissioning obligation, and for
qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate
amount paid and the fair value of any other consideration given up to acquire the asset.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability and
the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas
interests only when they increase the future economic benefits embodied in the specific asset to
which they relate. All other expenditures are recognized in profit or loss as incurred. Such
capitalized oil and natural gas interests generally represent costs incurred in developing proved
and/or probable reserves and bringing in or enhancing production from such reserves, and are
accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold
component is derecognized. The costs of the day-to-day servicing of property, plant and equipment
are recognized in profit or loss as incurred.
Depletion and depreciation
The net book value of producing assets are depleted on a field-by-field basis using the unit of
production method with reference to the ratio of production in the year to the related proved and
probable reserves, taking into account estimated future development costs necessary to bring those
reserves into production. For purposes of these calculations, production and reserves of natural
gas are converted to barrels on an energy equivalent basis.
Other assets are depreciated on a declining basis at rates ranging from 20% to 30% per annum.
Gains and losses on disposal of an item of property, plant and equipment, including oil and natural
gas interests, are determined by comparing the proceeds from disposal with the carrying amount of
property, plant and equipment and are recognized as separate line items in profit or loss.
(f) Impairment
E&E 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
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.
49
BENGAL ENERGY LTD.
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
cash generating units (“CGU”s) for the purpose of impairment testing, which is the lowest level at
which there are identifiable cash inflows that are largely independent of the cash flows of other
groups of assets. If any such indication of impairment exists, the Company makes an estimate of its
recoverable amount. A CGU’s recoverable amount is the higher of its fair value less 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 in
use 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.
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
50
is recognized in profit or loss.
(g) Financial instruments
2016 Annual Report
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,
notes payable and the credit facility are classified as other financial liabilities, which are measured
at amortized cost.
(ii) Derivative financial instruments
The Company enters into certain financial derivative contracts in order to manage the exposure to
market risks from fluctuations in commodity prices. These instruments are not used for trading or
speculative purposes. The Company does not designate its financial derivative contracts as
effective accounting hedges and therefore will not apply hedge accounting, even though the
Company considers all commodity contracts to be economic hedges. As a result, all derivative
contracts are classified as FVTPL and are recorded on the statement of financial position at fair
value. Transaction costs are recognized in profit or loss when incurred. Subsequent to initial
recognition, derivatives are measured at fair value, and changes therein will be recognized
immediately in profit or loss.
The Company may enter into physical delivery sales contracts for the purposes of receipt or delivery
of non-financial items in accordance with its expected purchase, sale or usage requirements as
executory contracts. As such, these contracts are not considered to be derivative financial
instruments and will not be recorded at fair value on the statement of financial position. Settlements
on these physical delivery contracts will be recognized in petroleum and natural gas revenue in the
period of settlement.
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.
51
BENGAL ENERGY LTD.
Share capital
Common shares are classified as equity. Incremental costs directly attributable to the issue of
common shares and stock options are recognized as a deduction from equity, net of any tax effects.
(h) Foreign currency translation:
The financial statements are presented in Canadian dollars, which is the Company’s functional and
presentation currency. For the accounts of foreign operations, assets and liabilities are translated at
period end exchange rates, while revenues and expenses are translated using average rates over
the period. Translation gains and losses relating to the foreign operations are included in
accumulated other comprehensive income, a component of equity. Foreign currency transactions
are translated into the legal entity’s functional currency at the exchange rate in effect at the
transaction; and any gains or losses are recorded in profit or loss.
(i) Share-based compensation:
The Company accounts for share-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. Share-based compensation expense is recorded
and reflected as share-based compensation expense over the vesting period with a corresponding
amount reflected in contributed surplus. At exercise, the associated amounts previously recorded
as contributed surplus are reclassified to common share capital.
(j) Revenue recognition:
Revenue from the sale of natural gas, natural gas liquids and crude oil is recognized when the
significant risks and rewards of ownership are transferred, which is when title passes to the
customer in accordance with the terms of the sales contract. This generally occurs when the
product is physically transferred into a pipe, truck or other delivery mechanism.
(k) Per share amounts:
Basic per share amounts are computed by dividing net income (loss) by the weighted average
number of common shares outstanding for the period. Diluted per share amounts are calculated
giving effect to the potential dilution that would occur if stock options or other dilutive instruments
were exercised into common shares. The treasury stock method assumes that any proceeds upon
the exercise of dilutive instruments, including remaining unamortized compensation costs, would be
used to purchase common shares at the average market price of the common shares during
the period.
(l)
Income taxes:
Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit
or loss except to the extent that it relates to items recognized directly in equity, in which case it is
recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted
or substantively enacted at the reporting date, and any adjustments to tax payable in respect of
previous years.
Deferred tax is recognized providing for temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for taxation purposes.
Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is
not a business combination. In addition, deferred tax is not recognized for taxable temporary
52
2016 Annual Report
differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates
that are expected to be applied to temporary differences when they reverse, based on the laws that
have been enacted or substantively enacted by the reporting date. Deferred tax assets and
liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes
levied by the same tax authority on the same taxable entity, or on different tax entities, but they
intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will
be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be
available against which the temporary difference can be utilized. Deferred tax assets are reviewed
at each reporting date and are reduced to the extent that it is no longer probable that the related tax
benefit will be realized.
(m) Finance income and expenses:
Finance income consists of interest earned on term deposits. Finance expenses include fees on
Performance Security Guarantees issued by Export Development Canada, bank fees on Bank
Guarantees issued to the Government of India, letter of credit charges, interest on notes payable
and the credit facility, accretion on notes payable and change in fair value of Value Appreciation
Rights (“VARS”), and accretion of the discount on decommissioning obligations.
(n) Determination of fair value:
A number of the Company’s accounting policies and disclosures required the determination of fair
value, both for financial and non-financial assets and liabilities. Fair values have been determined
for measurement and/or disclosure purposes based on the following methods. When applicable,
further information about the assumptions made in determining fair values is disclosed in the notes
specific to that asset or liability.
Fair Value Hierarchy
Financial instruments that are measured subsequent to initial recognition at fair value are grouped
into three categories based on the degree to which fair value is observable:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the
reporting date. Active markets are those in which transactions occur in sufficient frequency and
volume to provide pricing information on an ongoing basis;
Level 2 - Valuations are based on inputs other than quoted prices included in Level 1 that are
observable for the asset or liability, either directly or indirectly; including forward prices for
commodities, time value and volatility factors which can be substantially observed or corroborated
in the marketplace;
Level 3 - Inputs that are not based on observable data for the asset or liability.
Financial instruments comprise cash, cash equivalents, restricted cash, accounts receivable,
accounts payable and accrued liabilities, credit facility and derivatives.
The Company's policy is to recognize transfers in and out of the fair value hierarchy as of the date
of the event or change in circumstances that caused the transfer. There were no such transfers
during the period.
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BENGAL ENERGY LTD.
Fair values have been determined for measurement and disclosure purposes as follows:
i. Cash and cash equivalents, restricted cash, accounts receivable, accounts payable
and accrued liabilities
The fair values of these financial instruments approximate their carrying amounts due to their
short-term maturity.
ii. Credit facility
The fair value of the Company’s credit facility approximates its carrying value as it bears
interest at floating rates and the applicable margin is indicative of the Company’s current
credit risk.
iii. Derivatives
The Company’s commodity contracts (swaps and put options) are measured at level 2 of the
fair value hierarchy. The fair value of the swap component is determined by discounting the
difference between the contracted prices and published forward price curves as at the period
end date, using the remaining contracted oil volumes and a risk-free interest rate. The fair
value of puts are based on option models that use publish information with respect to
volatility, prices and interest rates.
(o) Newly adopted accounting standards
On January 1, 2016, the Company adopted the amendments made to IFRS 11 – Joint
Arrangements, which provided new guidance on the accounting for the acquisition of an interest in
a join operation that constitutes a business. There was no impact to the Company as a result of
adopting the amended standard.
(p) 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.
Accounting for acquisitions of interests in joint operations
In May 2014, the IASB issued amendments to IFRS 11 “Joint Arrangements” to clarify that the
acquirer of an interest in a joint operation in which the activity constitutes a business is required to
apply all of the principles of business combinations accounting in IFRS 3 “Business Combinations”.
Prospective application of this interpretation is effective for annual periods beginning on or after
January 1, 2016, with earlier application permitted. The adoption of this amendment could impact
the Company in the event that it increases or decreases its ownership share in an existing joint
operation or invests in a new joint operation.
Sale or contribution of assets between an investor and its associate or joint venture
In September 2014, the IASB issued amendments to address an inconsistency between the
requirements in IFRS 10 “Consolidated Financial Statements” and those in IAS 28 “Investments in
Associates and Joint Ventures” regarding the sale or contribution of assets between an investor and
its associate or joint venture. The amendment clarified that a full gain or loss is recognized when a
transaction involves a business. A partial gain or loss is recognized when a transaction involves
assets that do not constitute a business. Prospective application of this interpretation is effective for
annual periods beginning on or after January 1, 2016, with earlier application permitted. The
adoption of this amendment could impact the Company in the event that it has transactions with
associates or joint ventures.
Disclosure initiative
In December 2014, the IASB issued narrow-focus amendments to IAS 1 “Presentation of Financial
Statements” to clarify existing requirements relating to materiality, order of notes, subtotals,
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2016 Annual Report
accounting policies and disaggregation. Retrospective application of this standard is effective for
fiscal years beginning on or after January 1, 2016, with earlier application permitted. The adoption
of this amended standard is not expected to have a material impact on the Company’s disclosure.
Revenue from contracts with customers
In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers”. It replaces
existing revenue recognition guidance and provides a single, principles-based five-step model to be
applied to all contracts with customers. Retrospective application of this standard was to be
effective for fiscal years beginning on or after January 1, 2017, with earlier application permitted.
On May 19, 2015, the IASB published the expected exposure draft aimed at deferring the effective
date of IFRS 15 “Revenue from Contracts with Customers” to January 1, 2018. The Company is
currently assessing the impact of this standard.
Financial instruments: recognition and measurement
In July 2014, IFRS 9 “Financial Instruments” was issued as a complete standard, including the
requirements previously issued related to classification and measurement of financial assets and
liabilities, and additional amendments to introduce a new expected loss impairment model for
financial assets including credit losses. Retrospective application of this standard with certain
exemptions is effective for fiscal years beginning on or after January 1, 2018, with earlier application
permitted. The Company is currently assessing the impact of this standard.
Leases
On January 13, 2016 the IASB issued IFRS 16 “Leases”. The new standard is effective for annual
periods beginning on or after January 1, 2019. Earlier application is permitted for entities that apply
IFRS 15 “Revenue from Contracts with Customers” at or before the date of initial adoption of IFRS
16. IFRS 16 will replace IAS 17 “Leases”. This standard introduces a single lessee accounting
model and requires a lessee to recognize assets and liabilities for all leases with a term of more
than 12 months, unless the underlying asset is of low value. A lessee is required to recognize a
right-of-use asset representing its right to use the underlying asset and a lease liability representing
its obligation to make lease payments. The Company intends to adopt IFRS 16 in its financial
statements for the annual period beginning on January 1, 2019. The extent of the impact of
adoption of the standard has not yet been determined.
21.
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
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BENGAL ENERGY LTD.
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 required management to make certain judgments as to future events and
circumstances as to whether economic quantities of reserves have been found.
iii) Recognition of deferred income tax assets
The recognition of deferred income tax assets requires judgments regarding the likelihood and
applicability of future income tax deductions. 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 ability to apply income tax deductions.
Key sources of uncertainty
The following are the key assumptions concerning the sources of estimation uncertainty at the end of
the reporting period that have a significant risk of causing adjustments to the carrying amounts of
assets and liabilities.
ii)
Decommissioning provisions
The Company estimates future remediation costs of production facilities, wells and pipelines at different
stages of development and construction of assets or facilities. In most instances, removal of assets
occurs many years into the future. This requires judgment regarding abandonment date, future
environmental and regulatory legislation, the extent of reclamation activities, the engineering
methodology for estimating cost, future removal technologies in determining the removal cost and
liability-specific discount rates to determine the present value of these cash flows.
ii)
Impairment of petroleum and natural gas assets
For the purposes of determining whether impairment of petroleum and natural gas assets occurred, and
the extent of any impairment or its reversal, the key assumptions the Company uses in estimating future
cash flows are future petroleum and natural gas prices, expected production volumes and anticipated
recoverable quantities of proved and probable reserves. These assumptions are subject to change as
new information becomes available. Changes in economic conditions can also affect the rate used to
discount future cash flow estimates. Changes in the aforementioned assumptions could affect the
carrying amount of assets, and impairment charges and reversal will affect profit or loss.
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. 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.
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
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2016 Annual Report
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.
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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
WestPac • Sydney, Australia
ICICI Bank Ltd. • Calgary, Canada and Mumbai, India
REGISTRAR AND TRANSFER AGENT
Computershare • Toronto, Canada
INVESTOR RELATIONS
5 Quarters Investor Relations, Inc. • Calgary, Canada
DIRECTORS
Chayan Chakrabarty
Peter D. Gaffney
James B. Howe
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)
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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