International Exploration & Production
Annual Report
Twelve Months Ended
March 31, 2017
BENGAL ENERGY LTD.
TABLE OF CONTENTS
Message to Shareholders ........................................................................... 3
Fiscal 2017 Highlights ................................................................................. 5
Management’s Discussion and Analysis .................................................. 6
Consolidated Financial Statements ......................................................... 28
Notes to the Consolidated Financial Statements .................................... 35
Corporate Information .............................................................................. 58
2
BENGAL ENERGY LTD.
BENGAL ENERGY LTD.
MESSAGE TO SHAREHOLDERS
During fiscal 2017, Bengal continued to focus on a balance of low-risk development and near field
exploration drilling in the face of volatile oil prices. Our prudent 2017 capital program was underpinned by
our attractive hedge position, which allowed the company to execute meaningful advancement on several
core assets. Bengal’s operational activities were specifically focused in the Cuisinier field within ATP 752
Barta Block (30% working interest), and all wells achieved geological success. I am pleased with the
progress Bengal made over the past year to further develop and grow our reserves and future production
base, while we also remain especially bullish on our high-impact natural gas exploration assets which could
deliver significant long-term optionality for shareholders.
The Cuisinier drilling campaign consisted of five wells, including three low-risk development locations in the
central/south part of Petroleum Lease (“PL”) 303, one appraisal well (Cuisinier-22) and a near field
exploration well (Shefu-1). All five wells drilled were successful in locating oil-bearing sands, but were not
connected and producing during the fiscal year. Four of these wells were completed and commenced
production in May of 2017, while the fifth well (Cuisinier-23) is a future fracture stimulation candidate
following the evaluation of nearby well performance. Our exploration well, Shefu-1, was situated on the
western flank of PL 303 and encountered 7 meters of net pay; the discovery was also structurally lower than
previous rounds of appraisal drilling at Cuisinier and further confirmed our view of incremental reserves and
production potential in the area.
Production for 2017 averaged 379 bopd, a decrease of 25% over fiscal 2016 due to natural production
declines, but the successful drilling of the appraisal and exploration locations increased reserves through
the expansion of pool boundaries. Bengal grew its Proved plus Probable (“2P”) reserves during the fiscal
year by 14% to 7,056 Mbbls and proved reserves increased by 25% to 2,761 Mbbls. The net present value
(NPV10, before tax) of Bengal’s 2P reserves increased to $118 million, or $1.15 per share and the
Company’s net asset value, which deducts net debt is $108.5 million or 1.06 per share. W e remain
confident in our ability to further grow the size and value of our reserves base through future drilling
programs.
In late December 2016, the Company successfully completed a $4.1 million rights offering, of which
approximately 39% was subscribed for by insiders of Bengal, which will be used to fund the development
program on the Barta Sub-Block of ATP 752. This program includes the completion and tie-in of the wells
drilled in calendar 2016 (Cuisinier-22, Cuisinier-24, Cuisinier-25 and Shefu-1) and the acquisition of Barta
West 3D seismic to allow further definition of the Shefu-1 oil discovery. Planning for the 3D seismic program
has been finalized, with activities expected to commence shortly, and will cover an estimated 250 square
kilometers. Bengal views the Barta West area as a continuing natural extension from the de-risked Cuisinier
pool area and our technical team has mapped numerous prospects on existing 2D seismic.
During the year, Bengal completed the reprocessing of 500+ line kilometers of 2D seismic over the ATP 934
Barrolka permit and the most favourable areas have been high-graded for additional detailed geophysical
work. We are encouraged by recent natural gas discoveries surrounding the Barrolka permit, which suggest
the presence of a basin centered gas play in the region, as well as significant conventional potential for
natural gas in the Permian Toolachee and Patchawarra sandstone reservoirs. Neighboring gas fields
offsetting ATP 934 are producing approximately 18 mmcf/d with 400 bbls/d of condensate. Infrastructure is
developed with numerous gas pipelines crossing the Bengal permit.
Bengal holds a 71% working interest and operatorship in the ATP 934 permit and has commenced
discussions with third parties who may have an interest in farming in on this block. The permit is now in
Year 2, having met the Year 1 permit commitment with the reprocessing of the existing 2D data, and
planning for the Year 2 commitment program (260 square kilometer 3D seismic acquisition program) has
begun with favourable contractor bids already secured. Bengal's view of the potential for significant gas
discoveries on the ATP 934 permit is supported by both 2D and 3D seismic data and our team has
identified and mapped a total of five individual ‘conventional’ drilling prospects to date.
3
BENGAL ENERGY LTD.
The near-term outlook for crude oil and natural gas prices in the Australian market has become somewhat
two pronged due to unique domestic dynamics. While Brent and WTI oil prices remain volatile and under
pressure, natural gas prices have reached record highs in eastern Australia due to the significant increase
in demand associated with several newly commissioned LNG export projects. We are encouraged on the
outlook for natural gas demand continuing to grow over the medium term and we are also bullish on the
multiple marketing opportunities to optimize ATP 934 natural gas pricing and returns.
Bengal has also recently executed a new Crude Oil Sale and Purchase Agreement (“COSPA”) with the
South Australia Cooper Basin Joint Venture, which will provide improved pricing over previous levels based
on a direct pass-through mechanism. Exploration is also incentivized in the new agreement, with
incremental volumes attracting further improved pricing. We are also revising our agreement with the
Aquitaine B Joint Venture parties for crude oil produced at the Cuisinier Field, which is expected to reduce
transportation tariffs. The impact of both the transportation tariff reductions and the new COSPA pricing are
expected to be realized in improved netbacks commencing in fiscal Q2 2018 and will partially offset the
impact of the company’s US$80/bbl hedges that expire in June 2017.
Bengal will continue to maintain a prudent approach to our fiscal 2018 capital program in light of the oil price
uncertainty, while also focusing on risk management strategies and protecting cash flow. We remain bullish
on our core Australian market which is a very strong platform for future growth given the unique
combination of fiscal stability, attractive gas market fundamentals, established infrastructure and high-
impact exploration potential. I want to thank our strong and supportive Board of Directors, our diligent and
talented technical team, as well as each of our shareholders for your support as we continue to
methodically develop 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,
2017 and 2016.
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2017 Annual Report
FISCAL 2017 HIGHLIGHTS
Financial Highlights:
Continued Reserve Growth - The Company’s independently evaluated year-end corporate reserve
volumes have increased by 25% and 14% to 2,761 thousand barrels (Mbbls) and 7,056 Mbbls for
the Proved (“1P”) and Proved plus Probable (“2P”) reserve categories respectively. These increases
result from the impacts of the Company’s ongoing capital programs. Based on 1P and 2P reserves
additions, Bengal has replaced approximately 5 times and 7 times its annual corporate production,
respectively.
Revenue – Crude oil sales revenue was $2.2 million in the fourth quarter of fiscal 2017, which is 4%
lower than the $2.3 million recorded in Q3 2017 and 3% lower than crude oil sales during fiscal Q4
2016. The decreases are driven by natural production declines, partially offset by increases in
benchmark crude oil prices. Annual crude oil sales for fiscal 2017 were $9.3 million compared to
$11.2 million during fiscal 2016. The 17% decline is due primarily to natural production declines.
Hedging – At March 31, 2017, the Company had 29,000 barrels of oil (“bbls”) remaining in its US
$80 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, 2017.
Funds Flow from Operations – Funds flow from operations generated during Q4 2017 was $1.6
million compared to $1.4 million during the previous quarter and during fiscal Q4 2016. The increase
is due to reductions in operating expenses and royalty credits realized during the quarter. Annual
funds from operations were $6.2 million in fiscal 2017 compared to $4.0 million in fiscal 2016. The
57% increase was the result of a 23% increase in realized gain on financial instruments and royalty
credits described above.
Earnings - The Company recorded net income of $1.9 million for the fourth quarter of fiscal 2017,
compared to a $2.3 million net loss in the preceding quarter and a net loss $11.7 million during Q4
fiscal 2016. Annual net losses were $2.8 million during fiscal 2017 compared to losses of $10.4
million recorded in the previous year. Excluding the impact of unrealized foreign exchange and
unrealized hedging gains and losses, adjusted net earnings were $1.2 million for the fourth quarter of
fiscal 2017 compared to an adjusted net loss of $0.8 million during the previous quarter and an
adjusted net loss of $10.7 million recorded in fiscal Q4 2016. Annual adjusted net income was $3.6
million compared to an adjusted net loss of $12.3 million recorded during the previous year.
Rights Offering – On December 29, 2016, the Company completed a rights offering raising $4.0
million net of $0.1 million of share issue costs.
OPERATIONAL HIGHLIGHTS:
Production Volumes – Production (net to Bengal) in the fourth quarter of fiscal 2017 averaged 344
barrels of oil per day (“bopd”), a 3% and 27% decrease compared to the preceding quarter and fiscal
Q4 2016, respectively. These decreases were due to natural production declines. Four of the five
wells drilled during fiscal 2017 were connected in May of 2017 with initial combined production rates
of approximately 245 bopd (gross). These initial rates are less than pre connection expectations and
continued optimization and well cleanup work is ongoing. With recent positive results from fracture
stimulation programs, the Joint Venture will review the 2016 wells for stimulation in addition to
planning frac programs to occur immediately after completion in future drilling campaigns. In
Bengal’s opinion, operational delays experienced between completion and tie-in during the 2017
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2017 Annual Report
campaign may have been a contributor to longer well clean up timing and on initial reservoir
performance. Bengal will continue to closely monitor production rates of the newly connected wells.
Cuisinier 2016 drilling program – All five wells drilled during the year were successful in locating
oil-bearing sands and four of these wells were completed and commenced production in May 2017.
The fifth well, Cuisinier-23 was suspended as a future fracture stimulation candidate following the
evaluation of nearby well performance. This drilling program included one appraisal well (“Cuisinier-
22”) and one exploration well (“Shefu-1”). Successful drilling of the appraisal and exploration
locations have materially increased the Company’s reserve volumes by expanding the pool
boundaries.
Credit Facility Update - On August 26, 2016, the Company extended its credit facility with Westpac
Banking Corporation by 18 months with a borrowing base of US $15 million. The borrowing base, if
not further extended, will follow a reduction schedule of US $5 million in December 2017, US $5
million in June 2018, and US $5 million in December 2018. All associated terms and covenants are
consistent with the existing facility.
Onshore India – Effective June 1, 2016, Bengal and its partners 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. Subsequent to the year-end, this
application was accepted by the Director General of Hydrocarbons and is awaiting final approval
from the Ministry of Petroleum and Natural Gas. With the exit from the permit, the Company has
effectively ceased all operations in India.
MANAGEMENT’S DISCUSSION AND ANALYSIS – JUNE 15, 2017
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
During the second half of calendar 2017, the Joint Venture will commence a fracture stimulation program on
the Cuisinier North 1, Cuisinier 2 and Cuisinier 19 wells. Production testing at these new and stimulated
wells will assist the Joint Venture in planning for its next drilling campaign. The Cuisinier 23 well has
encountered hydrocarbon bearing sands based on logging results, however estimated deliverability is
uncertain, therefore future completion and potential stimulation of this well will be evaluated along with
production rates from the recently tied-in wells.
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 and
there is sufficient production history on the newly connected wells (Cuisinier 22, Cuisinier 24, Cuisinier 25
and Shefu 1)
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2017 Annual Report
The Barta Joint Venture have commenced preliminary discussions on the implementation of a pilot pressure
maintenance scheme following receipt of a preliminary Field Development Plan from the operator.
The Joint Venture is also in the preliminary stages of planning for a 3D seismic program in the Barta West
area, immediately west of Cuisinier PL303. The 3D will cover an area of approximately 250 km2 with timing
to be finalized in the coming months pending resolution of surface access and Native Title Cultural Heritage
surveys. Initial estimates are that the seismic acquisition portion of the survey will be done during Q3 2017
with processing and interpretation to follow.
ATP 934 Barrolka
Bengal has completed reprocessing of 500+ line kilometers of 2D seismic over the permit and interpretation
of this data is now complete. Seismic amplitude inversion studies are underway and the most favorable
areas of the permit have been high-graded for additional detailed geophysical work that may include the
acquisition of 3D seismic in 2017. The Company is encouraged by recent natural gas discoveries near the
Barrolka permit, which suggest the presence of a basin centered gas play in the region, as well as significant
conventional potential for natural gas occurrence in the Permian Toolachee and Patchawarra sandstone
reservoirs. 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 km 2 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. The Company made application for the
required regulatory relinquishment of 1/3 of the block and filed a revised Later Work Program (LWP)
application covering the period March 2017 through March 2019. Among other things, this LWP will allow
Bengal to study the Permian gas potential along the northern flank of the permit as well as the largely
unexplored oil potential in the southern part of the permit closer to the producing Jackson/Jackson South
Field which has produced greater than 49.4 million barrels of oil to date. Regulatory approval of the LWP
application was received May 30, 2017.
ATP 752 Wompi
The Nubba-1 well 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 (38% Bengal interest) offers Bengal moderate risk exploration in a well-
established, oil-producing fairway with multi-zone potential and the Joint Venture is currently evaluating the
appropriate timing to continue the development of this discovery, which is not expected to occur during the
first half of calendar 2017.
7
2017 Annual Report
AC/RL 10 (formerly AC/P 24), Ashmore Cartier Area, Timor Sea, Offshore Australia
Bengal holds a 10% working interest in the Ashmore Cartier Retention License 10 ("AC/RL 10") located in
the Ashmore Cartier area offshore Australia comprised of approximately 168 square kilometers (41,514
acres). Bengal is partnered with PTTEP Australia Timor Sea Pty Ltd. (90% working interest) and operator.
This permit was granted as a five year Petroleum Retention Lease, AC/RL 10 on March 22, 2013 expiring
March 21, 2018. Subject to fulfilling acceptable later work programs, AC/RL10 may be continued for two
further five year terms. The operator continues to reprocess existing 3D seismic data and evaluate
commercialization options.
OPERATING HIGHLIGHTS
$000s except per share,
volumes and netback amounts
Oil sales revenue
Realized gain on financial
instruments
Royalties
% of revenue
Operating & transportation
Operating netback(1)
Cash from operations:
Funds from operations:
Per share ($) (basic & diluted)
Net income (loss)
Per share ($) (basic & diluted)
Adjusted net (loss) income (2)
Per share ($) (basic & diluted)
Capital expenditures
Oil Volumes (bopd)
Netback(1) ($/boe)
Revenue
Realized gain on financial
instruments
Royalties
Operating & transportation
Three Months Ended
March 31
Twelve Months Ended
March 31
2017
2016 % Change
2017
2016
% Change
$2,179
$
2,253
(3)
$ 9,294
$ 11,187
(17)
$971
$ 1,833
$(347)
(16)
$ 987
$
$
106
5
1,474
(47)
(427)
(420)
(33)
$2,510
$
2,506
-
1,496
1,439
0.02
(57)
14
-
$643
$
$
$1,639
0.02
$1,931 $
0.02
$1,181
0.01
(11,704)
(0.17)
$ (10,685)
(0.16)
(117)
(112)
(111)
(106)
$681
$
332
105
344
469
(27)
$4,712
$(213)
(2)
$4,864
$9,355
$4,515
$6,196
0.08
$ 3,840
23
$ 728
7
$ 6,480
(129)
(129)
(25)
$ 7,819
20
$ 5,398 (16)
$ 4,048
0.06
53
33
$(2,768) $ (10,380)
(0.04)
$3,605
0.05
$5,618
379
(73)
(0.15) (73)
$ (12,270)
(0.18)
(129)
(128)
$ 3,347
68
505
(25)
$70.40 $
52.83
33
$67.17
$ 60.54
11
31.37
(11.21)
31.89
42.98
2.49
34.57
(27)
(550)
(8)
34.06 20.78
3.94
(1.54)
35.07
35.16
64
(139)
-
Netback/boe
$81.09 $
58.75
38
$67.61
$ 42.31
60
(1) Operating netback is a non-IFRS measure. Netback per boe is calculated by dividing the revenue (including gain on financial
instruments) less royalties, operating and transportation costs by the total production of the Company measured in boe.
(2) Adjusted net (loss) is a non-IFRS measure. The comparable IFRS measure net loss. 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, 2017 and 2016. The terms “current quarter”, Q4 2017 and “the quarter” are used throughout the
MD&A and in all cases refer to the period from January 1, 2017 through March 31, 2017. The terms “prior
year’s quarter”, Q4 2016 and “2016 quarter” are used throughout the MD&A for comparative purposes and
refer to the period from January 1, 2016 through March 31, 2016.
The fiscal year for the Company is the twelve-month period ended March 31, 2017. The terms “fiscal 2017,”
“current year” and “the year” are used in the MD&A and in all cases refer to the period from April 1, 2016
8
2017 Annual Report
through March 31, 2017. The terms “previous year,” “prior year” and “fiscal 2016” are used in the MD&A for
comparative purposes and refer to the period from April 1, 2015 through March 31, 2016. The term YTD
means year-to-date.
For the purpose of calculating unit costs, natural gas volumes have been converted to barrels of oil
equivalent (“boe”) using a conversion ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel
(“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. Netbacks and
adjusted net earnings do not have any standardized meaning under IFRS and are referred to as non-IFRS
measures. 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
operational performance. 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:
Three Months Ended
March 31
Twelve Months Ended
March 31
$000s
Net income (loss)
Unrealized loss (gain) on financial
Instruments
Unrealized foreign exchange loss (gain)
2017
1,931
241
(991)
2016
% Change
2017
2016 % Change
(11,704)
(117)
(2,768)
(10,380)
(73)
1,941
(88)
6,308
(1,861)
(922)
8
65
(29)
(439)
(324)
(129)
Adjusted net (loss) earnings
1,181
(10,685)
(111)
3,605
(12,270)
RESULTS OF OPERATIONS - AUSTRALIA
Netbacks
Production
Three Months Ended
March 31
2016
2017
% Change
Twelve Months Ended
March 31
2016
2017
% Change
Oil Production (boepd)
344
469
(27)
379
505
(25)
($000s)
Oil sales
Realized gain on financial
instrument
Royalties
Operating and transportation
971
(347)
1,833
106
(47)
4,712
(427)
(213)
expenses
987
1,469
(33)
4,864
2,179
2,253
(3)
9,294
11,187
(17)
3,840
728
6,463
23
(129)
(25)
9
Netback ($000s)
2,510
2,511
Oil sales ($/bbl)
Realized gain on financial
instrument
Royalties ($/bbl)
Operating and transportation
expenses ($/bbl)
Netback ($/bbl)
70.40
52.83
31.37
(11.21)
31.89
81.09
42.98
2.49
34.45
58.87
Production, Commodity Pricing and Sales
Production
2017 Annual Report
-
33
9,355
7,836
67.17
60.54
(27)
34.06
(550)
(1.54)
(7)
38
35.16
67.61
20.78
3.94
34.98
42.40
19
11
64
(139)
1
59
Quarterly production during fiscal Q4 2017 decreased 27% compared to fiscal Q4 2016 and 3% compared to
the preceding quarter. These decreases in production are due primarily to natural declines as production
from the Cuisinier 2016 drilling program did not come on stream until May of 2017.
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 $1.68 bbl over Brent for the twelve months ended March 31, 2017 (2016 – US
$2.10).
Realized crude oil prices in Q4 2017 increased by 33% compared to Q4 2016 and decreased by 1%
compared to Q3 2017 due to corresponding fluctuations in benchmark pricing and a decrease to the Tapis
premium realized in fiscal Q4 2017. Annual average realized prices increased by 11% compared to the prior
fiscal year. The declines in Brent crude prices through fiscal 2017 have been partially offset by foreign
exchange gains as the value of Canadian and Australian dollars has decreased relative to the U.S. dollar.
The Company’s reported sales include approximately 30,000 bbls of crude for which prices were not yet
determined at March 31, 2017 and therefore valued at year-end pricing.
The following table outlines average benchmark prices compared to Bengal’s realized prices:
Prices and Marketing
Three Months Ended
March 31
Twelve Months Ended
March 31
Average Benchmark Price
2017
2016
% Change
2017
2016
% Change
Bengal realized crude oil price
before realized gain on financial
instruments($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$
Risk Management Activities
70.40
$ 52.83
33
$67.17
$ 60.54
31.37
71.18
53.78
1.00
1.32
42.98
46.53
33.89
0.99
1.37
(27)
53
59
1
(4)
34.06
63.88
48.66
0.99
1.31
20.78
62.20
47.44
0.96
1.31
11
64
3
3
3
-
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
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2017 Annual Report
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:
Time Period
Type of Contract
Quantity
Contracted (bbls)
Price Floor
(US$/bbl)
Price Ceiling
(US$/bbl)
April 1, 2017 – May 31, 2017
Oil - Swap
April 1, 2017 – May 31, 2017
Oil – Put option
15,814
12,937
80.00
80.00
80.00
-
Time Period
Type of Contract
Quantity
Contracted (bbls)
Price Floor
(US$/bbl)
Price Ceiling
(US$/bbl)
July 1, 2017 – December 31, 2018
Oil - Swap
July 1, 2017 – December 31, 2018
Oil – Put option
67,373
67,373
47.00
47.00
47.00
-
The fair value of the financial contracts outstanding as at March 31, 2017 is an estimated asset of $0.7
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 three months ended March 31, 2017, the Company’s derivative commodity contracts resulted in a
realized gain of $1.0 million (2016 - $1.8 million) and an unrealized loss of $0.2 million (2016 - $1.9 million).
Realized gains were impacted by increased benchmark crude oil prices during fiscal Q4 2017 compared to
Q4 2016.
For the twelve months ended March 31, 2017, the derivative commodity contracts resulted in a realized gain
of $4.7 million (2016 - $3.8 million) and an unrealized loss of $6.3 million (2016 – gain of $1.8 million).
Realized gains were impacted by increased benchmark crude oil prices during fiscal 2017 compared to fiscal
2016. A total of 120,000 barrels were hedged during fiscal 2017 compared to 88,000 in fiscal 2016 resulting
in a net 23% increase in annual realized gain on financial instruments.
Royalties
Royalties ($000s)
Royalty Expense
$/bbl
% of revenue
Three Months Ended
Twelve Months Ended
March 31
March 31
2017
2016
% Change
(347)
(11.21)
(16)
106
2.49
5
(427)
(550)
(420)
2017
(213)
(1.54)
(2)
2016
% Change
728
3.94
7
(129)
(139)
(129)
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%.
During the year, the Barta Joint Venture operator revised its allowable capital calculation submitted to the
relevant authorities. Due to uncertainties regarding the acceptance of the Operator’s revised royalty
calculation, the Company had accrued royalty expenses based on the previously accepted methodology.
The period for royalty assessment has expired without adjustment, thus Bengal is satisfied that the royalty
calculation as submitted by the Joint Venture operator is acceptable. The Company reversed its Royalty
accrual during fiscal Q4 2017. Due to this credit, Royalties per barrel are in a credit position for both the
quarter and year ended March 31, 2017.
11
2017 Annual Report
OPERATING & TRANSPORTATION EXPENSES
Operating & trans.
expenses ($000s)
Operating
Transportation
Operating - $/boe
Transp. - $/boe
Three Months Ended
Twelve Months Ended
March 31
2017
2016
% Change
53
934
987
1.71
30.18
31.89
159
1,310
1,469
3.73
30.72
34.45
(67)
(29)
(33)
(54)
(2)
(7)
2017
563
4,301
4,864
4.07
31.09
35.16
March 31
2016
% Change
994
5,469
6,463
5.38
29.60
(43)
(21)
(25)
(24)
5
34.98
1
Operating costs per barrel decreased by 67% compared to Q4 2016 and 76% 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 costs across Australia’s Cooper Basin, therefore a portion of
the Company’s operating expense accrual was reversed during Q4 2017. Annual operating costs per barrel
have decreased by 43%, which reflects basin wide cost reductions as well as the Operator’s focus on cost
control.
Transportation costs on a boe basis decreased 2% compared to Q4 2016 and 7% compared to the prior
quarter. Annual transportation costs have increased by 5% 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
2016
690
91
% Change
4
(9)
781
17
-
17
3
(76)
-
(71)
2017
721
83
804
4
1
5
March 31
2016 % Change
3
2,663
1
335
2,998
3
91
10
101
(68)
(30)
(64)
2017
2,740
338
3,078
29
7
36
Total G&A expenditures increased by 3% compared to fiscal Q4 2016 and by 10% compared to the prior
quarter while annual G&A expenditures have increased by 3%. These minor increases reflect increased
travel costs associated with the Company’s business development initiatives.
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. Options granted in July of 2015 vest
conditionally based on certain performance criteria on their first, second and third anniversaries.
12
2017 Annual Report
DEPLETION AND DEPRECIATION (DD&A)
DD&A Expenses
($000s)
PNG – Australia
Corporate
Total
Three Months Ended
Twelve Months Ended
2017
443
4
447
March 31
2016
% Change
766
5
771
(42)
(20)
(42)
2017
2,291
18
2,309
March 31
2016
4,519
24
4,543
$/boe – PNG Australia
14.31
17.96
(20)
16.56
24.46
% Change
(49)
(25)
(49)
(32)
Australian depletion per barrel decreased by 20% for Q4 2017 compared to Q4 2016 and decreased by 32%
comparing fiscal year 2017 to fiscal year 2016. The decrease to depletion per barrel resulted from the
following two factors; the Company’s 2P reserve volumes increased by 14% 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.
IMPAIRMENT
Impairment
($000s)
Total
Three Months Ended
Twelve Months Ended
March 31
March 31
2017
-
2016
% Change
2017
2016
% Change
11,223
(100)
-
11,223
(100)
The 2016 impairment charges related to petroleum and natural gas exploration properties in India and
Toparoa, Australia. During the twelve months ended March 31, 2017, the Company recorded no impairment
charges.
FINANCE INCOME/EXPENSES
Finance Expenses ($000s)
Three Months Ended
Twelve Months Ended
Interest income
Accretion expense on
decommissioning liabilities
Change in FV of VARs
Letter of credit charges
Interest on credit facility
Total
2017
8
(10)
-
-
(178)
(180)
March 31
2016
% Change
2
300
(9)
1
-
(348)
(354)
11
(100)
-
(49)
(49)
2017
12
(37)
-
(55)
(947)
(1,027)
March 31
2016 % Change
9
(33)
3
14
(1,311)
(1,318)
33
12
(100)
(493)
(28)
(22)
Interest on the credit facility is based on US dollar Libor + 3.2% margin.
13
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
2017 Annual Report
Three Months Ended
Twelve Months Ended
March 31
2016
% Change
2017
March 31
2016
1,320
(14)
1,931
110
3,347
% Change
(33)
(21343)
(9)
(100)
68
107
(365)
151
-
105
883
2,974
1,761
-
5,618
2017
230
(53)
504
-
681
97
584
681
111
20
201
-
332
95
237
332
2
407
761
146
105
5,211
5.618
2,586
3,347
(47)
102
68
Development expenditures during the year related primarily to the Cuisinier 2016 drilling, completion and tie-
in program.
CREDIT FACILITY
In October 2014, Bengal closed its US $25.0 million secured credit facility with WestPac Banking Corporation
(“WestPac”) and placed an initial draw on November 12, 2014 of US $14.0 million. On August 26, 2016
following a US $1.5 million repayment, the Company extended the credit facility by 18 months to December
2018 with a borrowing base of US $15 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%.
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. In the event that the facility is
not further extended, the reduction schedule would commence on December 31, 2017 and occur every six
months thereafter until December 31, 2018 with a nominal reduction of US $5 million to the facility limit at
each calculation date based on the Company’s existing reserve profile. The facility limit at March 31, 2017 is
US $15 million, of which US $12.5 million is currently drawn. The repayment schedule is US $2.5 million in
fiscal 2018 and US $10.0 million in fiscal 2019, respectively.
The credit facility’s reserves based 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 available 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. The Company was in
compliance with the stated covenants at March 31, 2017.
14
2017 Annual Report
SHARE CAPITAL
At June 15, 2017, there were 102,266,694 common shares issued and outstanding, together with 2,702,500
outstanding options.
Trading History
Three Months Ended
Twelve Months Ended
High
Low
Close
Volume (000s)
Shares outstanding (000s)
Weighted average shares
outstanding (000s)
Basic
Diluted
2017
$0.23
$0.13
$0.14
3,546
102,267
102,267
102,267
March 31
March 31
2016
% Change
2017
2016
% Change
$ 0.15
$ 0.11
$ 0.13
1,682
68,178
68,178
68,178
53
18
8
111
50
50
50
$0.24
$0.11
$0.14
12,725
$ 0.32
$ 0.10
$ 0.13
15,329
102,267
68,178
76,770
76,770
68,178
68,178
(25)
10
8
(17)
50
13
13
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. 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.
The Company completed a rights offering which closed on December 29, 2016. Total proceeds were $4.1
million. Related share issuance costs were $142,000.
Bengal’s financial liabilities consist of accounts payable and accrued liabilities, fair value of financial
instruments, and credit facility and amounted to $18.1 million at March 31, 2017, (March 31, 2016- $20.6
million).
At March 31, 2017 the Company had $3.8 million of working capital, including cash and short-term deposits
of $3.9 million and restricted cash of $0.1 million, compared to a working capital deficiency of $0.4 million at
March 31, 2016.
The Company has a limit of US $15 million on its Westpac Credit facility, of which US $12.5 million is
currently drawn. Proceeds from this facility are restricted for use within the Cuisinier production licence.
Refer to Notes Payable and Credit Facility on page 11 for covenants related to the credit facility.
The majority of the Company’s oil sales are benchmarked on dated Brent prices which averaged US
$48.66/bbl for the twelve months ended March 31, 2017. 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
The table below indicates the payment schedule for the credit facility:
Credit facility (US$000s)
Fiscal year 2018
Fiscal year 2019
COMMITMENTS
2017 Annual Report
2,500
10,000
12,500
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 square kilometers
of 3D seismic and up to three wells, which would require a capital spend of $2.1 million in 2017 and a further
$2.1 million in 2018 net to Bengal.
Country and Permit
Work Program
Obligation Period
Ending
Estimated Expenditure (net)
(millions CAD$)(1)
Onshore Australia –
ATP 934P
Onshore Australia –
ATP 752
200 km2 of 3D seismic and up to three
wells
March 2021
Barta West 3D seismic program
November 2017
(1) Translated at March 31, 2017 at an exchange rate of AUS $1.00 = CAD $1.0187
$16.3
$1.5
OTHER
At March 31, 2017, the contractual obligations for which the Company is responsible are as follows:
Contractual Obligations ($000s)
Office lease
Decommissioning obligations
Total contractual obligations
Total
944
1,516
2,460
$
$
Less than
1 Year
$
$
52
-
52
$
$
1-3
Years
311
237
548
4-5
Years
After
5 Years
$
$
311
117
428
$
270
1,162
$ 1,432
OFF BALANCE SHEET TRANSACTIONS
The Company does not have any off balance sheet transactions other than its office lease, which is classified
as an operating lease.
16
2017 Annual Report
2017
379
-
67.17
9,294
(2,768)
(0.04)
4,515
6,196
0.08
16,500
57,706
3,815
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
SELECTED ANNUAL INFORMATION
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
Total assets
Working capital (deficiency)(2)
(1) See “Non-IFRS Measurements” on page 6 of this MD&A.
(2) Calculated as current assets minus current liabilities.
SELECTED QUARTERLY INFORMATION
($000s, except per share amounts)
Fiscal quarter
Mar. 31
2017
Mar. 31
2016
Q4 2017 Q3 2017 Q2 2017 Q1 2017 Q4 2016
Dec. 31
2016
Sep. 30
2016
Jun. 30
2016
Dec.31
2015
Q3 2016
Sep. 30
2015
Q2 2016
Jun. 30
2015
Q1 2016
Petroleum and natural gas sales
Cash from (used in) operations
Funds from (used in) operations(1)
2,179
643
1,639
2,325
934
1,412
2,301
1,982
1,797
2,489
956
1,348
2,253
1,496
1,439
1,838
935
105
3,392
2,318
1,282
3,704
649
1,222
Per share
Basic and diluted
0.02
0.02
0.03
0.02
0.02
0.00
0.02
0.02
Net income (loss)
Per share
1,931
(2,288)
325
(2,736)
(11,704)
1,413
1,167
(1,256)
Basic and diluted
0.02
(0.03)
0.00
(0.04)
(0.17)
0.02
0.02
(0.02)
Capital expenditures
Working capital (deficiency)
681
3,816
1,234
3,291
3,320
383
4,421
(9,171)
332
(420)
1,311
(1,487)
596
5,775
1,108
3,087
Total assets
57,706
56,020
55,552
54,108
58,903
72,353
66,583
62,926
Shares outstanding (000s)
102,267
102,267
68,178
68,178
68,178
68,178
68,178
68,178
Operations
Oil Volumes (bopd)
Netback ($/boe)
344
355
386
431
469
81.09
69.01
67.30
56.09
58.75
439
27.54
592
520
36.97
46.23
(1) See “Non-IFRS Measurements” on page 6 of this MD&A.
Production over the last eight quarters initially climbed with the addition of 2014 Phase One wells during
fiscal Q3 2015. Production declined naturally for the subsequent quarters, offset partially during fiscal Q1
2016 as 2014 Phase Two wells were brought on stream near the end of the quarter. Production increased to
592 bopd during fiscal Q2 2016 before decreasing to 439 bopd during the quarter as a result of five wells
which were temporarily offline during the quarter. These wells were brought back online post fracture
stimulation during Q4 2016 increasing production. Due to delays in tieing in Cuisinier wells drilled in 2016,
production has continued to decline since fiscal Q4 2016.
17
2017 Annual Report
Crude oil sales and associated cash and funds from operations has been driven primarily by production rates
and underlying commodity price fluctuations.
Capital expenditures have been driven by drilling programs at the Company’s Cuisinier field, which peaked
during fiscal Q2 2017 due to a five well drilling campaign commencing during the quarter. Total assets have
increased through drilling activities at Cuisinier and were significantly reduced during fiscal Q4 2016 and
fiscal Q1 2017 due to impairments of associated with the Tookoonooka exploration permit in Australia and
CY-ONN-2005/1 exploration block in India respectively. Working capital reached a deficit of $9.1 at Q1 2017
prior to the extension of the Company’s Westpac credit facility in August 2017. During fiscal Q3 2017 $3.4
million of the credit facility became current, but this decrease to working capital was offset by the Company’s
issuance of $4 million in common shares.
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, 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
18
2017 Annual Report
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
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, 2017 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.
19
2017 Annual Report
While Bengal’s Chief Executive Officer and Chief Financial Officer believe the Company’s internal controls
and procedures provide a reasonable level of assurance that they are reliable, an internal control system
cannot prevent all errors and fraud. It is management’s belief that any control system, no matter how well
conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the
control system are met.
During the design and operating effectiveness assessment certain material weaknesses in internal controls
over financial reporting were identified, as follows:
Management is aware that there is a lack of segregation of duties due to the small number of
employees dealing with general and administrative and financial matters. However, management
believes that at this time the potential benefits of adding employees to clearly segregate duties do
not justify the costs;
Bengal does not have full-time in-house personnel to address all complex and non-routine financial
accounting issues and tax matters that may arise. It is not deemed as economically feasible at this
time to have such personnel. Bengal relies on external experts for review and advice on complex
financial accounting issues and for tax planning, tax provision and compilation of corporate tax
returns.
These material weaknesses in internal controls over financial reporting result in a reasonable possibility that
a material misstatement will not be prevented or detected on a timely basis. Management and the Board of
Directors work to mitigate the risk of material misstatement; however, Management and the Board do not
have reasonable assurance that this risk can be reduced to a remote likelihood of a material misstatement.
APPLICATION OF CRITICAL ACCOUNTING ESTIMATES
The 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.
The following are the critical judgments, apart from those involving estimations (see below), that
management has made in the process of applying the Company’s accounting policies and that have the
most significant effect on the amounts recognized in these financial statements.
i.
Identification of Cash-generating units
Bengal’s assets are aggregated into cash-generating units, for the purpose of calculating impairment, based
on their ability to generate largely independent cash flows. By their nature, these estimates and assumptions
are subject to measurement uncertainty and may impact the carrying value of the Company's assets in future
periods.
ii.
Impairment indicators
Judgments are required to assess when impairment indicators exist and impairment testing is required. The
application of the Company’s accounting policy for exploration and evaluation, petroleum and natural gas
properties and PP&E assets required management to make certain judgments as to future events and
circumstances as to whether economic quantities of reserves have been found.
iii.
Recognition of deferred income tax assets
20
2017 Annual Report
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 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.
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.
iv.
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.
21
2017 Annual Report
NEW ACCOUNTING STANDARDS AND PRONOUNCEMENTS
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.
Revenue from contracts with customers
In April 2016, the IASB issued its final amendments to IFRS 15 Revenue from Contracts with Customers,
which replaces IAS 18 Revenue, IAS 11 Construction Contracts and related interpretations. The new
standard contains a single model that applies to contracts with customers and two approaches to recognizing
revenue; at appoint in time or over time. The model features a contract-based five-step analysis of
transactions to determine whether, how much and when revenue is to be recognized. New estimates and
judgmental thresholds have been introduced, which may affect the amount and timing of the revenue
recognized. The new standard applies to contracts with customers and does not apply to insurance
contracts, financial instruments or lease contracts. The new standard is to be adopted either retrospectively
or using a modified retrospective approach for annual periods beginning on or after January 1, 2018, with
early adoption permitted. The extent of the impact of adoption of the standard has not yet been determined.
Financial instruments: recognition and measurement
In July 2014, the IASB issued the complete IFRS 9 Financial Instruments to replace IAS 9 Financial
Instruments: Recognition and Measurement. IFRS 9 includes a principle-based approach for the
classification and measurement of financial assets, a single ‘expected credit loss’ impairment model and a
new hedge accounting standard which aligns hedge accounting more closely with risk management. The
new standard is to be adopted retrospectively with some exemptions for annual periods on or after January
1, 2018, with early adoption permitted. Bengal intends to adopt IFRS 9 on a retrospective basis on April 1,
2018. The extent of the adoption of IFRS 9 on the classification and measurement of the Company’s
financial assets and financial liabilities and related disclosures has not yet been determined. Bengal does
not currently apply hedge accounting to its financial instrument contracts and does not currently intend to
apply hedge accounting to any of its financial instrument contracts upon adoption of IFRS 9.
Leases
In January 2016, the IASB issued IFRS 16 Leases. This standard introduces a single recognition and
measurement model for leases, which would require the recognition of assets and liabilities for most leases
with a term of more than 12 months. 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 initial adoption date of January 1, 2018. The new standard is to be adopted either
retrospectively or using a modified retrospective approach. The Company intends to adopt IFRS 16 in its
financial statements for the annual period beginning on April 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
22
2017 Annual Report
operations in known and prospective hydrocarbon basins in jurisdictions that have previously established
long-term oil and gas ventures with foreign oil and gas companies.
An investment in the shares of the Company should be considered speculative due to the nature of the
Company's involvement in the exploration for and the acquisition, development and production of oil and
natural gas in foreign countries, and its current stage of development. An investor should consider carefully
the risk factors set out below and consider all other information contained herein and in the Company's other
public filings before making an investment decision. Additional risks and uncertainties not currently known to
the management of the Company may also have an adverse effect on Bengal’s business and the information
set out below does not purport to be an exhaustive summary of the risks affecting Bengal.
Exploration, Development and Production Risks
Oil and natural gas exploration involves a high degree of risk, for which even a combination of experience,
knowledge and careful evaluation may not be able to overcome. There is no assurance that expenditures
made on future exploration by Bengal will result in new discoveries of oil or natural gas in commercial
quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent
uncertainties of drilling in unknown formations, the costs associated with encountering various drilling
conditions such as over-pressured zones, tools lost in the hole and changes in drilling plans and locations as
a result of prior exploratory wells or additional seismic data and interpretations thereof.
The long-term commercial success of Bengal will depend on its ability to find, acquire, develop and
commercially produce oil and natural gas reserves. No assurance can be given that Bengal will be able to
locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations
are identified, Bengal may determine that current markets, terms of acquisition and participation or pricing
conditions make such acquisitions or participations uneconomic.
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce sufficient net revenues to return a profit after drilling, operating and other
costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and
operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of
operations, and various field operating conditions may adversely affect the production from successful wells.
These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected
wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other
geological and mechanical conditions. While diligent well supervision and effective maintenance operations
can contribute to maximizing production rates over time, production delays and declines from normal field
operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow
levels to varying degrees.
In addition, oil and gas operations are subject to the risks of exploration, development and production of oil
and natural gas properties, including encountering unexpected formations or pressures, premature declines
of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence of
any of these risks could have a materially adverse effect on future results of operations, liquidity and financial
condition.
Bengal attempts to minimize exploration, development and production risks by utilizing a high-end technical
team with extensive experience and multidisciplinary skill sets to assure the highest probability of success in
its drilling efforts. Bengal’s collaboration of a team of seasoned veterans in the oil and gas business, each
with a unique expertise in the various upstream to downstream technical disciplines of prospect generation to
operations, provides the best assurance of competency, risk management and drilling success. A full cycle
economic model is utilized to evaluate all hydrocarbon prospects. Detailed geological and geophysical
techniques are regularly employed including 3D seismic, petrography, sedimentology, petrophysical log
analysis and regional geological evaluation.
23
2017 Annual Report
Risks Associated with Foreign Operations
International operations are subject to political, economic and other uncertainties, including, among others,
risk of war, risk of terrorist activities, border disputes, expropriation, renegotiations or modification of existing
contracts, restrictions on repatriation of funds, import, export and transportation regulations and tariffs,
taxation policies, including royalty and tax increases and retroactive tax claims, exchange controls, limits on
allowable levels of production, currency fluctuations, labor disputes, sudden changes in laws, government
control over domestic oil and gas pricing and other uncertainties arising out of foreign government
sovereignty over the Company's international operations. With respect to taxation matters, the governments
and other regulatory agencies in the foreign jurisdictions in which Bengal operates and intends to operate in
the future may make sudden changes in laws relating to taxation or impose higher tax rates, which may
affect Bengal’s operations in a significant manner. These governments and agencies may not allow certain
deductions in calculating tax payable that Bengal believes should be deductible under applicable laws or
may have differing views as to values of transferred properties. This can result in significantly higher tax
payable than initially anticipated by Bengal. In many circumstances, readjustments to tax payable imposed
by these governments and agencies may occur years after the initial tax amounts were paid by Bengal,
which can result in the Company having to pay significant penalties and fines. Furthermore, in the event of a
dispute arising from international operations, the Company may be subject to the exclusive jurisdiction of
foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of courts in Canada.
Prices, Markets and Marketing of Crude Oil and Natural Gas
Oil and natural gas are commodities that have prices determined based on world demand, supply and other
factors, all of which are beyond the control of Bengal. World prices for oil and natural gas have fluctuated
widely in recent years. Any material decline in prices could result in a reduction of net production revenue.
Certain wells or other projects may become uneconomic as a result of a decline in world oil prices and
natural gas prices, leading to a reduction in the volume of Bengal’s oil and gas reserves. Bengal might also
elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease
in Bengal’s future net production revenue, causing a reduction in its oil and gas acquisition and development
activities. In addition to establishing markets for its oil and natural gas, Bengal must also successfully market
its oil and natural gas to prospective buyers. The marketability and price of oil and natural gas which may be
acquired or discovered by Bengal will be affected by numerous factors beyond its control. The ability of
Bengal to market its natural gas may depend upon its ability to acquire space on pipelines which deliver
natural gas to commercial markets. Bengal will also likely be affected by deliverability uncertainties related to
the proximity of its reserves to pipelines and processing facilities and related to operational problems with
such pipelines and facilities and extensive government regulation relating to price, taxes, royalties, land
tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural
gas business.
Substantial Capital Requirements and Liquidity
Bengal’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From time
to time, Bengal may require additional financing in order to carry out its oil and gas acquisition, exploration
and development activities. Failure to obtain such financing on a timely basis could cause Bengal to forfeit its
interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If
Bengal’s revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it
will affect Bengal’s ability to expend the necessary capital to replace its reserves or to maintain its
production. If Bengal’s funds from operations are not sufficient to satisfy its capital 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.
24
2017 Annual Report
Bengal monitors and updates its cash projection models on a regular basis which assists in the timing
decision of capital expenditures. Farm outs of projects may be arranged if capital constraints are an issue or
if the risk profile dictates that Bengal wishes to hold a lesser working interest position. Equity, if available and
if on favorable terms, may be utilized to help fund Bengal’s capital program.
Health, Safety and Environment
All phases of the oil and natural gas business present environmental risks and hazards and are subject to
environmental regulation pursuant to a variety of federal, provincial and local laws and regulations.
Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or
emissions of various substances produced in association with oil and natural gas operations. The legislation
also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the
satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant
expenditures and a breach of applicable environmental legislation may result in the imposition of fines and
penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement,
larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of
oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and
third parties and may require the Company to incur costs to remedy such discharge.
Insurance
Bengal’s involvement in the exploration for and development of oil and gas properties may result in the
Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other
hazards. Although Bengal has insurance in accordance with industry standards to address such risks, such
insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In
addition, such risks may not, in all circumstances be insurable or, in certain circumstances, Bengal may elect
not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance
or other reasons. The payment of such uninsured liabilities would reduce the funds available to Bengal. The
occurrence of a significant event that Bengal is not fully insured against, or the insolvency of the insurer of
such event, could have a material adverse effect on Bengal’s financial position, results of operations or
prospects.
Competition
Bengal actively competes for reserve acquisitions, exploration leases, licenses and concessions and skilled
industry personnel with a substantial number of other oil and gas companies, many of which have
significantly greater financial and personnel resources than Bengal. Bengal's competitors include major
integrated oil and natural gas companies and numerous other independent oil and natural gas companies
and individual producers and operators.
Bengal’s ability to successfully bid on and acquire additional property rights, to discover reserves, to
participate in drilling opportunities and to identify and enter into commercial arrangements with customers will
be dependent upon developing and maintaining close working relationships with its future industry partners
and joint operators and its ability to select and evaluate suitable properties and to consummate transactions
in a highly competitive environment.
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., 2000, 715 5th Avenue
SW., Calgary, Alberta T2P 2X6, by email to info@bengalenergy.ca or by accessing Bengal’s website at
www.bengalenergy.ca.
25
2017 Annual Report
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;
The expected timing of the completion and tie-ins of the successful 5 well at Barta Block Cuisinier
Timing of the finalization of the credit facility extension
Projections of market prices and costs;
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;
and
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.
26
2017 Annual Report
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
2017 Annual Report
MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL REPORTING
financial statements are
The accompanying consolidated
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, 2017. During this evaluation, management
identified material weaknesses due to the limited number of finance and accounting personnel at the
Company dealing with complex and non-routine accounting transactions that may arise and due to a lack of
segregation of duties and as a result the controls are not considered effective. All internal control systems,
no matter how well designed, have inherent limitations. Therefore, these systems provide reasonable but
not absolute assurance that financial information is accurate and complete.
KPMG LLP, an independent firm of Chartered Professional Accountants, has been engaged, as approved by
a vote of the shareholders at the Company’s most recent annual general meeting, to examine the
consolidated financial statements in accordance with Canadian generally accepted auditing standards and
provide an independent professional opinion.
The audit committee of the Board of Directors with all of its members being independent directors, have
reviewed the consolidated financial statements including notes thereto with management and KPMG LLP.
The consolidated
the
recommendation of the Audit Committee.
financial statements have been approved by
the Board of Directors on
(signed) “Chayan Chakrabarty”
Chayan Chakrabarty
President & Chief Executive Officer
(signed) “Jerrad Blanchard”
Jerrad Blanchard
Chief Financial Officer
28
2017 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, 2017 and March 31, 2016, 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.
29
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, 2017 and March 31, 2016, and its consolidated
financial performance and its consolidated cash flows for the years then ended in accordance with
International Financial Reporting Standards.
2017 Annual Report
Chartered Professional Accountants
June 15, 2017
Calgary, Canada
30
2017 Annual Report
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
Notes
3
12
4
5
12
2017
2016
$ 3,903
140
3,575
193
820
8,631
20,529
28,546
-
49,075
$ 3,010
140
3,187
155
5,806
12,298
19,626
24,875
1,294
45,795
Total assets
$ 57,706
$ 58,093
LIABILITIES AND SHAREHOLDERS’
EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Current portion of credit facility
7
8
7
12
9
Non-current liabilities:
Decommissioning liability
Credit facility
Fair value of financial instruments
Shareholders’ equity:
Share capital
Contributed surplus
Warrants
Accumulated other comprehensive
income
Deficit
Total liabilities and shareholders’ equity
Commitments and contingencies (note 15)
Subsequent event (note 16)
$ 1,484
3,332
4,816
1,516
13,168
102
14,786
98,100
7,645
-
2,085
(69,726)
38,104
$ 57,706
See accompanying notes to the consolidated financial statements.
On behalf of the Board:
Director
Chayan Chakrabarty
Director
James B. Howe
$ 2,669
10,049
12,718
1,422
7,816
-
9,238
94,151
7,442
167
1,335
(66,958)
36,137
$ 58,093
31
2017 Annual Report
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
(Thousands of Canadian dollars, except per share amounts)
For the years ended March 31,
2017
2016
Income
Petroleum and natural gas revenue
Royalties
Realized gain on financial instruments
Unrealized (loss) gain on financial instruments
Operating expenses
General and administrative
Operating and transportation
Depletion and depreciation
Pre-licensing & impairment
Share-based compensation
Operating loss
Other expenses
Other
Finance expenses
Foreign exchange
Net loss
Notes
5
4,5
11
$9,294
213
9,507
$11,187
(728)
10,459
4,712
(6,308)
7,911
2,740
4,864
2,309
-
29
9,942
(2,031)
3,840
1,861
16,160
2,663
6,480
4,543
11,223
91
25,000
(8,840)
378
(1,027)
(88)
(737)
(2)
(1,318)
(220)
(1,540)
(2,768)
(10,380)
Exchange differences on translation of foreign operations
750
1,465
Total comprehensive loss for the year
$(2,018)
$(8,915)
Loss per share
- Basic & diluted
Weighted average number of shares outstanding (000s)
- Basic & diluted
See accompanying notes to the consolidated financial statements.
9
9
$(0.04)
$(0.15)
76,770
68,178
32
2017 Annual Report
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Thousands of Canadian dollars)
Shares
outstanding
Share
capital Warrants
Contributed
surplus
Accumulated
other
comprehensive
income
Total
shareholders’
equity
Deficit
68,177,796
$94,151
$167
$7,341
$ (130) $(56,578)
$44,951
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(10,380)
(10,380)
-
1,465
91
10
-
-
-
-
-
1,465
91
10
68,177,796
$94,151
$167
$7,442
$1,335
$(66,958)
$36,137
68,177,796
$94,151
$167
$7,442
$1,335
$(66,958)
$36,137
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
Balance at
April 1, 2016
Net loss for the year
Comprehensive income for
the year
-
-
-
-
Rights offering
34,088,898
4,091
Share issue costs
Expiry of warrants
Share-based compensation –
expensed
Share-based compensation –
capitalized
Balance at
March 31, 2017
(142)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
750
-
-
(167)
167
-
-
-
29
7
-
-
-
(2,768)
(2,768)
-
-
-
-
750
4,091
(142)
-
-
29
-
7
102,266,694
$98,100
$ -
$7,645
$2,085
$(69,726)
$38,104
See accompanying notes to the consolidated financial statements.
33
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Canadian dollars)
2017 Annual Report
For the years ended March 31,
2017
2016
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
Share-based compensation
Loss (profit) on disposition of petroleum and natural
gas properties
Unrealized loss (gain) on financial instruments
Unrealized foreign exchange (gain) loss
Funds from operations
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
Repayment of credit facility
Facility extension fees
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
Notes
$ (2,768)
$ (10,380)
2,309
-
37
278
29
4,543
11,223
33
428
91
(62)
6,308
65
6,196
(1,681)
4,515
-
(1,861)
(29)
4,048
1,350
5,398
(407)
(5,211)
(178)
(5,796)
(761)
(2,586)
(579)
(3,926)
3,949
(1,984)
(150)
285
2,100
-
-
-
(282)
(282)
74
893
3,010
$ 3,903
71
1,261
1,749
$ 3,010
14
4
5
14
9
7
7
14
See accompanying notes to the consolidated financial statements.
34
BENGAL ENERGY LTD.
Notes to Consolidated Financial Statements (the “financial statements”)
Years ended March 31, 2017 and 2016
(Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)
2017 Annual Report
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, 2017 and 2016 and for the years ended March 31, 2017 and 2016 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 2000, 715 5th Ave SW, Calgary,
Alberta, Canada, T2P 2X6.
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 15, 2017.
b) Basis of measurement
These financial statements have been prepared on a historical cost basis, except for commodity
contracts as discussed in Note 19.
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, 2017
March 31, 2016
1,655
2,248
3,903
3,003
7
3,010
35
4.
EXPLORATION AND EVALUATION ASSETS (E&E ASSETS)
($000s)
Balance at March 31, 2015
Additions
Acquisition
Capitalized share-based compensation
E&E impairment loss
Exchange adjustments
Balance at March 31, 2016
Additions
Capitalized share-based compensation
Exchange adjustments
Balance at March 31, 2017
2017 Annual Report
28,245
651
110
4
(10,475)
1,091
19,626
407
3
493
20,529
Exploration and evaluation assets consist of the Company’s exploration projects in Australia which are
pending the determination of proved or probable reserves. Costs primarily consist of acquisition costs,
geological & geophysical work, seismic and drilling and completion costs until the drilling of wells is
complete and the results have been evaluated.
In the process of management’s internal analysis of prospectivity and planning for scheduled
relinquishment in 2017 for ATP 732 Tookoonooka, Bengal identified several areas deemed to have low
potential for future exploration at March 31, 2016. All historical costs associated with exploration in
these select areas were impaired during fiscal 2016. No further impairments were incurred during fiscal
2017.
A summary of E&E assets is shown in the table below:
($000s)
ATP 732 - Tookoonooka
ATP 752 - Barta
ATP 934 - Barrolka
Other(1)
March 31, 2016 ($000)
ATP 732 - Tookoonooka
ATP 752 - Barta
ATP 934 - Barrolka
Other(1)
March 31, 2017 ($000)
Australia
16,163
1,243
781
1,439
19,626
Australia
16,573
1,273
1,114
1,569
20,529
(1)
Other includes capitalized G&A, share-based compensation and foreign exchange effects on assets denominated in
foreign currencies.
36
5.
PETROLEUM AND NATURAL GAS PROPERTIES
2017 Annual Report
$000s
Cost:
Balance at April 1, 2015
Additions
Capitalized share-based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2016
Additions
Capitalized share-based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2017
$000s
Accumulated depletion, depreciation and
impairment losses:
Balance at April 1, 2015
Depletion and depreciation charge
Impairment
Exchange adjustments
Balance at March 31, 2016
Depletion and depreciation charge
Exchange adjustments
Balance at March 31, 2017
Net carrying value
At March 31, 2016
At March 31, 2017
Petroleum and
Natural Gas
Properties
Corporate
Assets
38,701
2,586
6
(95)
622
41,820
5,211
4
80
760
47,875
342
-
-
-
2
344
-
-
-
-
344
Petroleum and
Natural Gas
Properties
Corporate
Assets
11,678
4,519
748
75
17,020
2,291
75
19,386
24,800
28,489
243
24
-
2
269
18
-
287
75
57
Total
39,043
2,586
6
(95)
624
42,164
5,211
4
80
760
48,219
Total
11,921
4,543
748
77
17,289
2,309
75
19,673
24,875
28,546
The calculation of depletion for the year ended March 31, 2017 included $73.4 million for estimated
future development costs associated with proved and probable reserves in Australia (March 31, 2016 -
$83.6 million).
At March 31, 2016, the reserves relating to the Toparoa CGU were determined to be uneconomic. As a
result, the carrying value of $0.7 million relating to the Toparoa CGU was impaired at March 31,
2016. Toparoa CGU was disposed of in September 2016. No impairment triggers requiring an
impairment test to be performed were determined to exist relating to the Cuisinier CGU at March 31,
2017.
37
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:
2017 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
2017
(2,768)
27%
(747)
(269)
8
(45)
-
1,053
-
2016
(10,380)
26.5%
(2,751)
(258)
24
768
(50)
2,267
-
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
2017
32,915
5,740
13,150
557
102
52,464
2016
30,976
5,742
14,386
764
101
51,969
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
2017
14,651
216
(942)
(418)
(13,507)
-
2016
13,286
2,130
(673)
(390)
(14,353)
-
At March 31, 2017, the Company had approximately $29.3 million and $48.7 million of non-capital losses
in Canada and Australia respectively (2016- $23.9 million and $49.8 million), available to reduce future
taxable income. The Canadian non-capital losses expire at various dates from March 31, 2026 to 2037.
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, 2017, the Company has no deferred tax liabilities
in respect of these temporary differences.
38
7.
CREDIT FACILITY
Facility Agreement – Issued November 12, 2014 ($000s)
Gross proceeds
Total cash fees
Unrealized foreign exchange loss
Accretion
Balance at March 31, 2016
Repayment
Facility extension fees
Unrealized foreign exchange loss
Accretion
Balance at March 31, 2017
Current portion of credit facility
Non-current portion of credit facility
2017 Annual Report
15,364
(844)
14,520
2,747
17,267
598
17,865
(1,984)
(150)
491
278
16,500
March 31,
2017
March 31,
2016
3,332
13,168
10,049
7,816
In October 2014, Bengal closed its US $25.0 million secured credit facility with WestPac Banking
Corporation (“WestPac”) and placed an initial draw on November 12, 2014 of US $14.0 million. On
August 26, 2016 following a US $1.5 million repayment, the Company extended the credit facility by 18
months to December 2018 with a borrowing base of US $15 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%.
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. The next calculation date
will occur on June 30, 2017. In the event that the facility is not further extended, the reduction schedule
would commence on December 31, 2017 and occur every six months thereafter until December 31,
2018 with a nominal reduction of US $5 million to the facility limit at each calculation date based on the
Company’s existing reserve profile. The facility limit at March 31, 2017 is US $15 million, of which US
$12.5 million is currently drawn. Refer to Note 12(b) for a repayment schedule.
The credit facility’s reserves based 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 available 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. The Company was in
compliance with the stated covenants at March 31, 2017.
39
8.
DECOMMISSIONING AND RESTORATION LIABILITY
2017 Annual Report
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
Change in estimate net of disposals
Additions
Accretion
Exchange adjustments
Decommissioning liability, end of year
2017
1,422
(259)
278
37
38
1,516
2016
1,454
(95)
-
33
30
1,422
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, 2017 is approximately $2.3
million (March 31, 2016 – $1.9 million) which will be incurred between 2020 and 2044. An inflation factor
of 1.5% – 1.6% and a risk-free discount rate ranging between 1.63% and 2.49% have been applied to
the decommissioning liability at March 31, 2017.
9.
SHARE CAPITAL
(a) Authorized:
Unlimited number of common shares with no par value.
Unlimited number of preferred shares, of which none have been issued.
(b) Issued:
The following provides a continuity of share capital:
($000s)
Balance at March 31, 2015 and 2016
Issued on exercise of rights offering
Share issue costs
Balance at March 31, 2017
Number of Shares
68,177,796
34,088,898
-
102,266,694
Amount
94,151
4,091
(142)
98,100
The Company completed a rights offering (the "Rights Offering") which closed on December 29,
2016. Under the terms of the Rights Offering, each registered holder of common shares, at the
close of business on December 2, 2016, received one Right for each common share held. Two
Rights, plus the sum of $0.12 (the "Subscription Price"), entitled the holder thereof to acquire one
common share. The Rights Offering resulted in 34,088,898 common shares being issued
(16,056,853 common shares were issued to officers and directors) for total proceeds of $4.1
million. Share issuance costs of $142,000 were incurred related to the Rights Offering and have
been recognized in the carrying value of share capital on the consolidated statement of financial
position.
40
2017 Annual Report
(c) Share-based compensation – stock options:
The Company has a share option plan for directors, officers, employees and consultants of the
Company whereby share options representing up to 10% of the issued and outstanding common
shares can be granted by the Board of Directors. Share options are granted for a term of three to
five years and vest one-third immediately and one-third on each of the next two anniversary dates.
The exercise price of each option equals the market price of the Company’s common shares on the
date of the grant. Effective with the option grant on December 21, 2012, vesting occurs one third
after the first year and one third on each of the two subsequent anniversaries. 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, 2015
Granted
Forfeited
Expired
Exercised
Outstanding at March 31, 2016
Granted
Forfeited
Expired
Exercised
Outstanding at March 31, 2017
Exercisable at March 31, 2017
3,515,000
1,072,500
-
(230,000)
-
4,357,500
-
-
(1,655,000)
-
2,702,500
1,808,756
$
$
0.89
0.18
-
0.86
-
0.72
-
-
1.19
-
$ 0.43
$ 0.55
Options Outstanding
Options Exercisable
Option Price (1)
$0.18 - $0.46
$0.47 - $0.65
Total
Number
Outstanding
Exercise
Price (2)
Remaining
Life (3)
Number
Exercisable
Exercise
Price (2)
1,072,500
1,630,000
2,702,500
$0.18
$0.59
$0.43
3.33
1.09
1.98
178,756
1,630,000
1,808,756
$0.18
$0.59
$0.55
(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:
41
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
2017 Annual Report
2016
1.5%
5 yr
78%
-
$0.18
$0.18
(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. No options
were granted during the year ended March 31, 2017.
(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
2017
2016
$ (2,768)
$ (10,380)
Weighted average number of common shares (basic)
Weighted average number of common shares (diluted)
Basic and diluted loss per share
76,770
76,770
$(0.04)
68,178
68,178
$(0.15)
For the twelve months ended March 31, 2017, there were 2,702,500 (March 31, 2016 – 4,357,000)
options respectively considered anti-dilutive.
10.
COMPENSATION OF KEY MANAGEMENT PERSONNEL
The Company considers its directors and executives to be key management personnel. The key
management personnel compensation is comprised of the following:
Year ended March 31,
($000s)
Salaries & employee benefits
Share-based compensation(1)
General & administrative expenses
2017
986
33
1,019
2016
974
79
1,053
(1) Represents the amortization of share-based payment expense associated with the company’s share-based compensation
plans granted to key management personnel.
42
11.
FINANCE INCOME/EXPENSES
Year ended March 31,
($000s)
Interest income
Accretion on decommissioning obligations
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)
12.
FINANCIAL RISK MANAGEMENT
2017 Annual Report
2017
2016
12
(37)
(55)
(947)
-
(1,027)
9
(33)
14
(1,311)
3
(1,318)
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, 2017, Bengal’s receivables consisted of $3.1 million (March 31, 2016 - $2.6 million) from
joint venture partners and $0.4 million (March 31, 2016 - $0.6 million) of other trade receivables of
which $2.8 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, 2017, (March 31, 2016 - $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. Bengal
does not have an allowance for doubtful accounts as at March 31, 2017 and did not provide for any
doubtful accounts, nor was it required to write-off any receivables during the twelve months ended
March 31, 2017. Exposure to the carrying value of its financial instruments relates to the Company’s
commodity-based derivatives held by WestPac, 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
43
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.
2017 Annual Report
(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, fair value of financial
instruments, and credit facility and amounted to $18.1 million at March 31, 2017, (March 31, 2016-
$20.6 million).
At March 31, 2017 the Company had $3.8 million of working capital, including cash and short-term
deposits of $3.9 million and restricted cash of $0.1 million, compared to a working capital deficiency
of $0.4 million at March 31, 2016.
The Company has a limit of US $15 million on its WestPac credit facility, of which US $12.5 million is
currently drawn. The remaining US $2.5 million is available to be drawn. Proceeds from this facility
are restricted for use within the Cuisinier production licence. Refer to Note 7 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
$48.66/bbl for the twelve months ended March 31, 2017. 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 2018
Fiscal year 2019
(c)
Market risk:
2,500
10,000
12,500
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate
because of changes in market prices. Market risk comprises three types of risk: currency risk,
interest rate risk and other price risk. The Company is exposed to market risks resulting from
fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of
operations. A variety of derivative instruments may be used to reduce exposure to these risks.
Foreign Currency Risk
Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate as
a result of changes in foreign exchange rates. Bengal receives Canadian dollars for sales in Canada,
US dollars for Australian oil sales and incurs expenditures in Australian, Canadian and US
44
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:
2017 Annual Report
As at March 31, 2017
($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
Total
112
140
19
(278)
-
-
(7)
2,458
-
3,556
(1,201)
-
-
4,813
1,333
-
-
(5)
(16,500)
718
(14,454)
3,903
140
3,575
(1,484)
(16,500)
718
(9,648)
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, 2017, the following derivative contracts were outstanding and recorded at estimated
fair value:
Time Period
Type of Contract
April 1, 2017 – May 31, 2017
April 1, 2017 – May 31, 2017
($000s)
Current fair value of financial instruments
Non-current fair value of financial instruments
Total
Oil - Swap
Oil – Put option
Time Period
Type of Contract
July 1, 2017 – December 31, 2018
July 1, 2017 – December 31, 2018
($000s)
Current fair value of financial instruments
Non-current fair value of financial instruments
Total
Oil - Swap
Oil – Put option
Quantity
Contracted
(bbls)
15,814
12,937
Oil - swap
561
-
561
Quantity
Contracted
(bbls)
67,373
67,373
Oil - swap
(295)
(291)
(586)
Price Floor
(US$/bbl)
Price Ceiling
(US$/bbl)
80.00
80.00
Oil – put
459
-
459
80.00
-
Total
1,020
-
1,020
Price Floor
(US$/bbl)
Price Ceiling
(US$/bbl)
47.00
47.00
Oil – put
95
189
284
47.00
-
Total
(200)
(102)
(302)
A US $1.00 increase in the future crude oil price per barrel would result in an approximate US
$163,000 decrease in the fair value of financial instruments at March 31, 2017 while a $ US1.00
decrease would result in an increase of approximately US $163,000 in the fair value of the
instruments.
45
2017 Annual Report
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, 2017 as the funds are not invested in interest-bearing instruments. The Company’s credit
facility carries a floating interest rate based on quoted US dollar Libor rates. The Company had no
interest rate derivatives at March 31, 2017.
For the year ended March 31, 2017, a 1% increase in US Libor would increase interest expense by
$164,000.
13.
CAPITAL MANAGEMENT
The Company’s policy is to maintain a strong capital base for the objectives of maintaining financial
flexibility which will allow it to execute on its capital investment program, provide creditor and market
confidence and to sustain future development of the business.
The Company manages its capital structure and makes adjustments by continually monitoring its
business conditions, including: changes in economic conditions, the risk profile of its drilling inventory,
the efficiencies of past investments, the efficiencies of forecasted investments and the timing of such
investments, the forecasted cash balances, the forecasted commodity prices and resulting cash flow.
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 $12.5 million from its US $15.0 million available credit facility and typically
structures its debt position below 2.0 times projected 12-month net operating cash flows. The Company
is within these parameters at March 31, 2017.
14.
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
2017
(388)
(38)
(1,185)
37
(1,574)
(1,681)
285
(178)
(1,574)
2016
(78)
193
380
(6)
489
1,350
(282)
(579)
489
The following represents the cash interest paid and received in each period.
Year ended March 31,
($000s)
Cash interest paid
Cash interest received
2017
2016
705
12
870
9
46
15.
COMMITMENTS AND CONTINGENCIES
2017 Annual Report
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, which would require a discretionary capital spend of $2.1 million in
2017 and a further discretionary $2.1 million in 2018 net to Bengal.
Country and Permit
Work Program
Obligation Period
Ending
Estimated Expenditure
(net) (millions CAD$)(1)
Onshore Australia –
ATP 934P
200 km2 of 3D seismic and up to
three wells
March 2021
$16.3
Onshore Australia –
ATP 752
Barta West 3D seismic program
November 2017
$1.5
(1) Translated at March 31, 2017 at an exchange rate of AUS $1.00 = CAD $1.0187.
At March 31, 2017 the Company had the following lease commitment for office space in Canada.
($000s)
April 2017 to November 2023
Office lease
16.
SUBSEQUENT EVENT
Total
944
Less than
1 Year
52
1-3
Years
311
4-5
Years
311
After
5 Years
270
Effective June 1, 2016, Bengal and its joint venture partner 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. Subsequent to March 31, 2017, this
exit without penalty has been approved by the Director General of Hydrocarbons and is awaiting final
approval from the Indian Ministry of Petroleum and Natural Gas. With the exit from the permit, the
Company will effectively cease all operations in India.
17.
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, 2017 amount to $1.3 million (March 31, 2016 - $1.3 million).
18.
SEGMENTED INFORMATION
As at March 31, 2017, the Company has three reportable operating segments being the Australian and
Indian oil and gas operations, and corporate.
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2017 Annual Report
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
costs and directors’ salaries, finance costs and income tax expense. This is the measure reported to the
chief operating decision maker for the purposes of resource allocation and assessment of segment
performance.
For the year ended March 31, 2017 ($000s)
Australia Corporate
India
Total
Revenue
Interest revenue
Interest expense
Depletion and depreciation
Net earnings (loss)
Exploration and evaluation expenditures
Petroleum and natural gas property
expenditures
March 31, 2017
Petroleum and natural gas properties
Cost
Accumulated impairment losses
Accumulated depletion and
depreciation
Net book value
Exploration and evaluation assets
Accumulated impairment losses
Net book value
9,294
11
947
2,291
(1,425)
407
5,211
43,582
(796)
(14,297)
28,489
29,850
(9,321)
20,529
-
1
-
18
(1,153)
-
-
4,637
(310)
(4,270)
57
-
-
-
-
(190)
-
9,294
12
947
2,309
(2,768)
407
-
-
-
-
-
5,211
48,219
(1,106)
(18,567)
28,546
-
-
-
8,415
(8,415)
-
38,265
(17,736)
20,529
For the year ended March 31, 2016 ($000s)
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 and
depreciation
Net book value
Exploration and evaluation assets
Accumulated impairment losses
Net book value
Australia
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
Canada
-
1
-
24
(1,305)
-
-
-
4,638
(310)
(4,253)
75
-
-
-
India
-
-
-
-
(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
48
19.
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.
2017 Annual Report
(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.
49
2017 Annual Report
Generally, costs directly associated with the exploration and evaluation of crude oil and natural gas
reserves are initially capitalized. Exploration and evaluation costs are those expenditures for an
area where technical feasibility and commercial viability have not yet been demonstrated. These
costs generally include unproved property acquisition costs, geological and geophysical costs,
sampling and appraisals, drilling and completion costs and capitalized decommissioning costs.
Costs are held in exploration and evaluation until the technical feasibility and commercial viability of
the project is established. Amounts are generally reclassified to petroleum and natural gas
properties once probable reserves have been assigned to the field. If probable reserves have not
been established through the completion of exploration and evaluation activities and there are no
future plans for activity in that field, then the exploration and evaluation expenditures are determined
to be impaired and the amounts are charged to profit or loss.
(e) Petroleum and natural gas properties
Carrying value
Costs incurred subsequent to the determination of technical feasibility and commercial viability are
recognized as petroleum and natural gas properties in the specific asset to which they relate.
Petroleum and natural gas properties are stated at cost less accumulated depreciation and depletion
and accumulated impairment losses. The initial cost of a petroleum and natural gas property is
comprised of its purchase price or construction cost, any costs directly attributable to bringing the
asset into operation, the initial estimate of the decommissioning obligation, and for qualifying assets,
borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair
value of any other consideration given up to acquire the asset.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability and
the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas
interests only when they increase the future economic benefits embodied in the specific asset to
which they relate. All other expenditures are recognized in profit or loss as incurred. Such
capitalized oil and natural gas interests generally represent costs incurred in developing proved
and/or probable reserves and bringing in or enhancing production from such reserves, and are
accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold
component is derecognized. The costs of the day-to-day servicing of property, plant and equipment
are recognized in profit or loss as incurred.
Depletion and depreciation
The net book value of producing assets are depleted on a field-by-field basis using the unit of
production method with reference to the ratio of production in the year to the related proved and
probable reserves, taking into account estimated future development costs necessary to bring those
reserves into production. For purposes of these calculations, production and reserves of natural gas
are converted to barrels on an energy equivalent basis.
Other assets are depreciated on a declining basis at rates ranging from 20% to 30% 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
50
2017 Annual Report
amount exceeds the recoverable amount and when they are reclassified to Development and
Production (“D&P”) assets. For the purpose of impairment testing, E&E assets are grouped by
concession or field with other E&E assets belonging to the same concession or field. The
impairment loss will be calculated as the excess of the carrying value over recoverable amount of the
E&E impairment grouping and any resulting impairment loss is recognized in profit or loss.
Recoverable amount is determined as the higher of the value in use or fair value less costs to sell.
At the end of each reporting period, the Company reviews the petroleum and natural gas properties
for circumstances that indicate that the assets may be impaired. Assets are grouped together into
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 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
51
characteristics.
All impairment losses are recognized in profit or loss.
An impairment loss is reversed if the reversal can be related objectively to an event occurring after
the impairment loss was recognized. For financial assets measured at amortized cost, the reversal
is recognized in profit or loss.
(g) Financial instruments
2017 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,
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.
52
2017 Annual Report
Fair value
The fair value of financial instruments that are actively traded in organized financial markets is
determined by reference to quoted market bid prices at the valuation date. For financial instruments
that have no active market, fair value is determined using valuation techniques including the use of
recent arm’s length market transactions, reference to the current market value of equivalent financial
instruments and discounted cash flow analysis.
Share capital
Common shares are classified as equity. Incremental costs directly attributable to the issue of
common shares and stock options are recognized as a deduction from equity, net of any tax effects.
(h) Foreign currency translation:
The financial statements are presented in Canadian dollars, which is the Canadian parent entity’s
functional and presentation currency; the functional currency of the Indian subsidiary is US dollars
and the functional currency of the Australian subsidiary is Australian dollars. For the accounts of
foreign operations, assets and liabilities are translated at period end exchange rates, while revenues
and expenses are translated using average rates over the period. Translation gains and losses
relating to the foreign operations are included in accumulated other comprehensive income, a
component of equity. Foreign currency transactions are translated into the legal entity’s functional
currency at the exchange rate in effect at the transaction; and any gains or losses are recorded in
profit or loss.
(i) Share-based compensation:
The Company accounts for share-based compensation granted to directors, officers, employees and
consultants using the Black-Scholes option-pricing model to determine the fair value of the 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
53
2017 Annual Report
or loss except to the extent that it relates to items recognized directly in equity, in which case it is
recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted
or substantively enacted at the reporting date, and any adjustments to tax payable in respect of
previous years.
Deferred tax is recognized providing for temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for taxation purposes.
Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is
not a business combination. In addition, deferred tax is not recognized for taxable temporary
differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates
that are expected to be applied to temporary differences when they reverse, based on the laws that
have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities
are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the
same tax authority on the same taxable entity, or on different tax entities, but they intend to settle
current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized
simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be
available against which the temporary difference can be utilized. Deferred tax assets are reviewed at
each reporting date and are reduced to the extent that it is no longer probable that the related tax
benefit will be realized.
(m) Finance income and expenses:
Finance income consists of interest earned on term deposits. Finance expenses include 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, 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.
54
2017 Annual Report
The Company's policy is to recognize transfers in and out of the fair value hierarchy as of the date of
the event or change in circumstances that caused the transfer. There were no such transfers during
the period.
Fair values have been determined for measurement and disclosure purposes as follows:
i. 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) 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.
Revenue from contracts with customers
In April 2016, the IASB issued its final amendments to IFRS 15 Revenue from Contracts with
Customers, which replaces IAS 18 Revenue, IAS 11 Construction Contracts, and related
interpretations. The new standard contains a single model that applies to contracts with customers
and two approaches to recognizing revenue; at appoint in time or over time. The model features a
contract-based five-step analysis of transactions to determine whether, how much and when revenue
is to be recognized. New estimates and judgmental thresholds have been introduced, which may
affect the amount and timing of the revenue recognized. The new standard applies to contracts with
customers and does not apply to insurance contracts, financial instruments or lease contracts. The
new standard is to be adopted either retrospectively or using a modified retrospective approach for
annual periods beginning on or after January 1, 2018, with early adoption permitted. The extent of
the impact of adoption of the standard has not yet been determined.
Financial instruments: recognition and measurement
In July 2014, the IASB issued the complete IFRS 9 Financial Instruments to replace IAS 9 Financial
Instruments: Recognition and Measurement. IFRS 9 includes a principle-based approach for the
classification and measurement of financial assets, a single ‘expected credit loss’ impairment model
and a new hedge accounting standard which aligns hedge accounting more closely with risk
management. The new standard is to be adopted retrospectively with some exemptions for annual
periods on or after January 1, 2018, with early adoption permitted. Bengal intends to adopt IFRS 9
on a retrospective basis on April 1, 2018. The extent of the adoption of IFRS 9 on the classification
and measurement of the Company’s financial assets and financial liabilities and related disclosures
has not yet been determined. Bengal does not currently apply hedge accounting to its financial
instrument contracts and does not currently intend to apply hedge accounting to any of its financial
instrument contracts upon adoption of IFRS 9.
55
2017 Annual Report
Leases
In January 2016, the IASB issued IFRS 16 Leases. This standard introduces a single recognition
and measurement model for leases, which would require the recognition of assets and liabilities for
most leases with a term of more than 12 months. 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 initial adoption date of January 1, 2018.
The new standard is to be adopted either retrospectively or using a modified retrospective approach.
The Company intends to adopt IFRS 16 in its financial statements for the annual period beginning on
April 1, 2019. The extent of the impact of adoption of the standard has not yet been determined.
20.
MANAGEMENT JUDGMENTS AND ESTIMATES
The timely preparation of the financial statements requires management to make judgments, estimates
and assumptions that affect the application of accounting policies and reported amounts of assets and
liabilities and income and expenses. Accordingly, actual results may differ from these estimates.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting
estimates are recognized in the period in which the estimates are revised and in any future periods
affected. Significant estimates and judgments made by management in the preparation of these
financial statements are out-lined below.
Critical judgments in applying accounting policies
The following are the critical judgments, apart from those involving estimations (see below), that
management has made in the process of applying the Company’s accounting policies and that have the
most significant effect on the amounts recognized in these financial statements.
i)
Identification of Cash-generating units
Bengal’s assets are aggregated into cash-generating units, for the purpose of calculating impairment,
based on their ability to generate largely independent cash flows. By their nature, these estimates and
assumptions are subject to measurement uncertainty and may impact the carrying value of the
Company's assets in future periods.
ii)
Impairment indicators
Judgments are required to assess when impairment indicators exist and impairment testing is required.
The application of the Company’s accounting policy for exploration and evaluation, petroleum and
natural gas properties 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.
56
i) Decommissioning provisions
2017 Annual Report
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
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.
the extent of reclamation activities,
legislation,
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) 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.
iv) 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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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
2017 Annual Report
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