International Exploration & Production
2018 Annual Report
Twelve Months Ended
March 31, 2018
BENGAL ENERGY LTD.
TABLE OF CONTENTS
Message to Shareholders ........................................................................... 3
Fiscal 2018 Highlights ................................................................................. 6
Management’s Discussion and Analysis .................................................. 7
Consolidated Financial Statements ......................................................... 27
Notes to the Consolidated Financial Statements .................................... 33
Corporate Information .............................................................................. 56
2 BENGAL ENERGY LTD.
MESSAGE TO SHAREHOLDERS
During fiscal 2018, Bengal Energy Ltd. (“Bengal” or the “Company”) has been active across numerous
fronts. This included focused geological and geophysical efforts to accelerate the drilling of an exciting
westward extension to the productive Cuisinier field, a thorough geophysical re-work of seismic data on
ATP 934 resulting in what we believe to be a paradigm shift in exploration risk reduction, and negotiating
an amendment to Bengal’s credit facility. In addition, the Company was active in identifying and analyzing
production acquisition opportunities within our core areas in onshore Australia. All these activities have
positioned the Company well, setting the stage for future years’ exploration and development drilling
programs in a time of improved commodity pricing.
At Cuisinier, the Company was successful in negotiating lower transportation costs for its oil sales, and
continued premium pricing was achieved through the new Crude Oil Sale and Purchase Agreement entered
into at the end of fiscal Q1 2018.
Bengal will continue to maintain a prudent approach to fiscal 2019 activities, but look forward to the results
of the high-impact Chookola well which was identified on the Barta West 3D seismic program in the Barta
block on ATP 752. This exploration well, targeting three separate geological horizons, is scheduled to be
drilled in August of 2018. We are also working diligently with our joint venture partners to advance a
waterflood pilot at Cuisinier, hydraulically stimulate select producing wells, as well as identify 9 to 10
development drilling locations for 2019 and 2020.
Production for fiscal year ended March 31, 2018 averaged 360 bopd, a decrease of only 5% over fiscal
2017 which speaks to the efficiency of the operator in effectively managing the reservoir during a time of
no in-field drilling. This modest decrease is due to natural production declines. Bengal saw a decline of 9%
in its Proved Plus Probable (“2P”) reserves during the fiscal year ended March 31, 2018 to 6,416 Mbbls
from the previous year and Proved reserves decreased by 6% to 2,583 Mbbls. On the other hand, the net
present value (NPV10, before tax) of Bengal’s 2P reserves increased to $141 million, or $1.38 per share.
The Company’s 2P net asset value before tax, which deducts net debt from the net present value (NPV10,
before tax), is $128.8 million or $1.26 per share. The 2P after tax, net asset value is $94.2 million and $0.92
per share. These increases in value are primarily a result of higher forecast crude oil prices. We remain
confident in our ability to further grow the size and value of our reserves base through future drilling
programs.
On ATP 934, a portion of the 2D data set has been processed and interpreted using an AVO/Inversion
workflow which has led to a breakthrough in the Company’s ability to more accurately predict presence of
reservoir sandstones within coal rich sedimentary sequences which is not possible using conventional
amplitude interpretation. Bengal believes this process will help de-risk drilling locations in future programs
and is encouraged by recent natural gas discoveries surrounding the permit, which suggest the presence
of a broader stratigraphically trapped gas resource in the region. ATP 934 is surrounded by producing gas
fields, and infrastructure is developed with numerous gas pipelines crossing the Bengal permit providing
market access.
We were successful in our goal of consolidating ownership in ATP 934 and acquired the 28.57% held by
the remaining party with an effective date of August 1, 2017. With 100% interest, Bengal has commenced
discussions with third parties who may have an interest in farming in on this block.
The near-term outlook for crude oil and natural gas prices in the Australian market has strengthened
considerably with the rise in current and forecast Brent crude oil pricing in US$ and a continued shortage
of readily available natural gas is creating upward pressure on spot pricing in east coast markets. 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 by 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 also successfully negotiated an amendment to its secured credit facility (the “Credit Facility”) with
the Australian-based Westpac Institutional Bank, which includes a deferment of principal payments on the
3 BENGAL ENERGY LTD.
Credit Facility. The Credit Facility continues to have an expiry date of December 31, 2019 and provides a
borrowing base of US$ 12.5 million, of which the full amount is currently drawn.
Considerable attention has been paid to maintaining balance sheet strength and optionality and to this end
we thank our new CFO, Mr. Matthew Moorman, for his contributions and fiscal prudency in the face of
commodity price volatility.
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 oil and 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,
2018 and 2017.
4 International exploration & production
Management’s Discussion & Analysis
Three and Twelve Months Ended
March 31, 2018 and 2017
5 FISCAL 2018 HIGHLIGHTS
Financial Highlights:
Summary of Reserves and Values
Reserve valuation increased year-over-year with total proved (1P) reserves at March 31, 2018 up by
37% to $62.9 million from March 31, 2017. Proved plus probable (2P) reserves increased in value by
19.5% to $141 million from 2017. Reserve values increased due to higher assumed oil prices
combined with expected lower capital costs while reserve volumes declined due to lower expected
capital spending.
Revenue
Crude oil sales for the fourth quarter of fiscal 2018 were $2.8 million, a 28% increase over the same
quarter in the fiscal year 2017. Annual crude oil sales for fiscal 2018 were $10.7 million, a 15%
increase over annual 2017. Both increases were due to a 31% improvement in US Brent pricing year-
over-year.
Hedging
For the period April 2018 through December 2018, the Company has 65,261 barrels hedged using
both puts and swaps at US$ 47/bbl. In addition the Company has hedged 15,906 barrels for the
period January 2019 to March 2019 using both puts and swaps at US$ 55.70/bbl. This hedging
program is required under the Company’s Credit Facility.
Funds Flow from Operations
Funds flow from operations generated $0.5 million in fiscal Q4 2018 compared to $1.6 million in fiscal
Q4 2017. The funds flow from operations for the full year 2018 was $3.7 million compared to $6.2
million for full year 2017. The primary reason for the reduced funds flow performance in both the 2018
fiscal Q4 and annual results was the drop in realized hedging value year-over-year. The fiscal year
2017 enjoyed $80/bbl hedges compared to $47/bbl hedges in the fiscal year 2018.
Earnings
The Company recorded a net loss for the fiscal Q4 2018 of $12.5 million compared to a net income
of $1.9 million for the fiscal Q4 2017. For the full year 2018, the Company recorded a net loss of
$12.3 million compared to a full year 2017 net loss of $2.8 million. In fiscal Q4 2018, the Company
has taken a non-cash $12.2 million impairment primarily as related to ATP 732. After adjusting for
unrealized gains and losses on financial instruments and foreign exchange, and the non-cash
impairment of non-current assets, the adjusted earnings are $(143) and $1, 459 for the three and
twelve months ended March 31, 2018, respectively.
Operational Highlights:
Production Volumes
Production (net to Bengal) in fiscal Q4 2018 averaged 334 barrels per day for a total production of
30,050 barrels compared to 344 average barrels per day in fiscal Q4 2017 or a total of 30,951 barrels,
representing a reduction of 3%. For the full year 2018, production averaged 360 barrels per day
compared to 379 barrels per day in 2017 for a reduction of 5%. Full year 2018 production was 131,455
barrels compared to 138,360 barrels in 2017. Normal production declines and reduced capital
spending are the reason for the reduction in production for both the 2018 Q4 and full year.
Credit Facility Update
During fiscal 2018, the Company’s credit facility with Westpac Banking Corporation was amended on
September 25, 2017 and March 5, 2018 resulting in the elimination of the June 2018 principle
repayment.
6 MANAGEMENT’S DISCUSSION AND ANALYSIS – June 8, 2018
Bengal’s producing assets are located in Australia’s Cooper Basin, a region featuring many large oil and gas
pools. The Company’s core Australian assets: Barrolka, Cuisinier and Tookoonooka are situated within the
southwest Queensland 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 favourable royalty regime for oil and gas production.
OUTLOOK
AUSTRALIA
ATP 752 Barta Block Cuisinier
During the fourth quarter of fiscal 2018 the Company finalized the four wells at Cuisinier to be fracture
stimulated. The frac programs are expected to be conducted early in the third calendar quarter with results
known shortly thereafter. Prior frac programs showed positive results and increased well productivity.
The Barta West 3D seismic program processing has been completed and is in final stages of interpretation.
The first exploration well location has been chosen (named Chookola #1) which is expected to spud mid third
calendar quarter of 2018. It will take approximately 14 days to drill to evaluate all zones to the base of the
Triassic with primary targets of the Murta, Birkhead and Doonmulla formations. All of these zones have been
proven productive in the Cuisinier West area. Recent increases in crude oil pricing is steadily increasing
corporate field oil netbacks which are now forecasted to exceed AUS $60 per barrel inclusive of the
Company’s hedging program and after any and all JV operational audit credits are accounted for.
The Barta joint venture has commenced planning for the implementation of a pressure maintenance/water
injection pilot, which is designed to increase reservoir pressure and recovery factor for the offsetting Cuisinier
wells. If results are encouraging, the implementation of a broader field wide program will be considered.
Bengal’s engineering evaluation suggests that Cuisinier is a favourable candidate for waterflood installation.
ATP 934 Barrolka
During the fourth quarter of fiscal 2018, Bengal completed consolidating the ownership of ATP 934 and now
owns and controls a 100% working interest. 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 have highlighted several favourable areas of the permit allowing for additional work that may include
the acquisition of 3D seismic in 2018. The Company is encouraged by the number of recent natural gas
discoveries surrounding the Barrolka permit. This high success rate could indicate the presence of a broader
stratigraphic trap and the presence of a more regional gas resource in the area. Bengal’s strategy is to
evaluate the potential of a broader resource while targeting more conventional prospects in the Permian
Toolachee and Patchawarra sandstone reservoirs. Bengal is in 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. A regulatory condition of an ATP granted under the Queensland Issuing
Authority is the mandatory relinquishment of 8.33% of the original grant area per year. For ease of
administration, the 8.33% per year is cumulative for four year periods therefore 33.33% is relinquished every
fourth year. Post ATP issuance, on April 1, 2011 new legislation was put in place extending the first four year
term by an additional two years thus requiring the first 33.3% relinquishment by March 31, 2017. The second
7 four year term now ends March 31, 2019 at which time a further 33.3% of the original grant area is due to be
relinquished. During fiscal 2017, the Company completed the required regulatory relinquishment of 1/3 of the
block and filed a revised Later Work Program (LWP) application covering the period from March 2017 through
March 2019 at which time a further 1/3 of the block will be relinquished. The aim with this relinquishment was
to preserve all high-graded prospect areas thus far defined on acquired 2D and 3D seismic. Given this
relinquishment program and the fact that, upon review the Company has no intention of developing or
renewing such leases that are to be relinquished in March 2019, the carrying value of ATP 732 was written
down to $5.38 million. The final LWP on the remaining 33.3% of the block will allow Bengal to further study
the Permian gas potential along the northern flank of the permit identifying areas most favorable from a
reservoir development and trap perspective. In addition, the southern part of the permit will be examined from
an oil charge and migration perspective. While this southern area is close to the producing Jackson/Jackson
South Field, which has produced greater than 49.4 million barrels of oil to date, the oil migration pathways
and trapping configurations need further review. Upon completion of this work, the Company will engage with
prospective third parties who may have an interest in farming in on this block.
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 implies that the prospective gas pay extends down
dip of the Nubba well where seismic indicates the Toolachee section thickens. A Potential Commercial Area
(the Yilgarn PCA), which will allow for commercialization, was granted on March 31, 2017. 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 could occur
during calendar 2019. The Yilgarn PCA was granted for an additional period of 15 years from March 31, 2017
and the associated work program is divided into three five-year terms. Work anticipated during these terms
includes further geological, geophysical and engineering studies as well as extended production testing of
the Nubba well and determination of commercial viability of the Nubba gas accumulation. The Company is
reviewing the timing of this activity with the Joint Venture Operator.
AC/RL 10 (formerly AC/P 24), Ashmore Cartier Area, Timor Sea, Offshore Australia
Bengal holds a 10% working interest in the offshore Ashmore Cartier Retention License 10 ("AC/RL 10")
located in the Ashmore Cartier area west of Australia comprised of approximately 168 km2 (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 which
expired on March 21, 2018. A LWP application was successfully lodged and the permit has now been
continued for a further five years. The operator continues to reprocess existing 3D seismic data and evaluate
commercialization options.
Business Development
The Company continues to examine potential transactions targeting complementary asset bases to increase
reserves, production and cash flows per share.
8 OPERATING SUMMARY
$000s except per share,
volumes and netback amounts
Oil sales revenue
Realized (loss) gain on financial
instruments
Royalties
% of revenue
Operating & transportation
Operating netback(1)
Cash from operations
Funds from operations:
Per share ($) (basic & diluted)(2)
Net income (loss)
Per share ($) (basic & diluted)
Adjusted net income (loss)(3)
Per share ($) (basic & diluted)
Capital expenditures
Oil Production (bopd)
Netback(1) ($/boe)
Revenue
Realized (loss) gain on
financial instruments
Royalties
Operating & transportation
Netback/boe
Three Months Ended
Twelve Months Ended
March 31
March 31
2017
% Change
2017
% Change
2018
$2,783
$(288)
$136
5
$1,077
$1,282
$858
$525
0.01
$(12,526)
(0.12)
(143)
0.00
939
334
$2,179
$971
$(347)
(16)
$987
$2,510
$643
$1,639
0.02
$1,931
0.02
$1,181
0.01
$681
344
$ 92.61
$ 70.40
(9.58)
4.53
35.84
42.66
31.37
(11.21)
31.89
$ 81.09
28
(130)
(139)
(131)
9
(49)
33
(68)
(50)
(749)
(700)
(112)
(100)
38
(3)
32
(131)
(140)
12
(47)
2018
$10,710
$568
$642
6
$3,718
$6,918
$3,627
$3,737
0.04
$(12,271)
(0.12)
$1,459
0.01
$3,511
360
$ 9,294
$ 4,712
$
(213)
(2)
$ 4,864
$ 9,355
$ 4,515
$ 6,196
0.08
$ (2,768)
(0.04)
$ 3,605
0.05
$ 5,618
379
$81.47
$ 67.17
4.32
4.88
28.28
$52.63
34.06
(1.54)
35.16
$ 67.61
15
(88)
(401)
(400)
(24)
(26)
(20)
(40)
(50)
343
200
(60)
(80)
(38)
(5)
21
(87)
(417)
(20)
(22)
(1) Operating netback is a non-IFRS measure and includes realized losses on financial instruments. Netback per boe is calculated
by dividing revenue (including realized loss on financial instruments) less royalties, operating and transportation costs by the
total production of the Company measured in boe.
(2) Funds from operations per share is a non-IFRS measure calculated by dividing funds from operations by weighted average
basic and diluted shares outstanding for the periods disclosed.
(3) Adjusted net income (loss) and adjusted net income (loss) per share are non-IFRS measures. The comparable IFRS measure
is net income (loss). A reconciliation of the two measures can be found in the table on page 6 of the Company's management's
discussion and analysis for the Q4 and fiscal year ended March 31, 2018.
Basis of Presentation
This MD&A is for the three and twelve months ended March 31, 2018 and 2017 and should be read in
conjunction with Bengal’s consolidated financial statements and related notes for the years ended March 31,
2018 and 2017. The terms “current quarter” and “the quarter” are used throughout the MD&A and in all cases
refer to the period from January 1, 2018 through March 31, 2018. The terms “prior year’s quarter” and “2018
quarter” are used throughout the MD&A for comparative purposes and refer to the period from Jan 1, 2017
through March 31, 2017. The terms “prior quarter”, “preceding quarter” and “previous quarter” refer to the
three months ended December 31, 2017.
The fiscal year for the Company is the twelve-month period ended March 31, 2018. The terms “fiscal 2018,”
“current year” and “the year” are used in the MD&A and in all cases refer to the period from April 1, 2017
through March 31, 2018. The terms “previous year,” “prior year” and “fiscal 2017” are used in the MD&A for
comparative purposes and refer to the period from April 1, 2016 through March 31, 2017. The term YTD
means year-to-date.
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.
9 Non-IFRS Measurements
Within the MD&A, references are made to terms commonly used in the oil and gas industry. Netbacks, funds
from operations per share, adjusted net earnings and adjusted net earnings per share do not have any
standardized meaning under IFRS and are referred to as non-IFRS measures. Netbacks equal total revenue
(including realized losses/gains on financial instruments) less royalties and operating and transportation
expenses calculated on a boe basis. Management utilizes these measures to operational performance.
Funds from operations per share is a non-IFRS measure calculated by dividing funds from operations by
weighted average basic and diluted shares outstanding for the periods disclosed. 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 plus
non-cash impairment of non-current assets. 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)
Non-cash impairment of non-current
assets
Adjusted net earnings (loss)
2018
(12,526)
(39)
255
12,167
(143)
2017 % Change
(749)
1,931
2018
(12,271)
2017
(2,768)
241
(991)
-
1,181
(116)
(126)
-
(112)
1,661
(98)
12,167
1,459
6,308
65
-
3,605
%
Change
343
(74)
(251
-
(60)
The adjusted net loss of $0.143 million and adjusted net earnings of $1.459 million for the three months ended
and fiscal year ended 2018 represented net income (loss) adjusted for unrealized loss (gain) on financial
instruments and foreign exchange as well as the non-cash impairment of non-current assets taken in Q4
fiscal 2018.
RESULTS OF OPERATIONS
Production, Commodity Pricing and Sales
Production
Three Months Ended
Twelve Months Ended
Oil Production (bpd)
Oil Production (bbls)
2018
334
30,050
March 31
2017 % Change
344
30,951
(3)
(3)
March 31
2017 % Change
2018
360
379
131,455
138,360
(5)
(5)
Crude oil production declined marginally in Q4 fiscal 2018 vs Q4 fiscal 2017. Total production during the
quarter was 30,050 bbls (334 bbl/d) vs 30,951 bbls (344 bbl/d) in Q4 fiscal 2017. For the twelve months fiscal
2018, total production was 131,455 bbls (360 bbl/d) vs 138,360 (379 bbl/d) for the twelve months fiscal 2017.
Pricing
The price received for Bengal’s Australian oil sales is benchmarked on US Brent for the month in which the
Bill of Lading occurs, plus a realized premium. This premium is from marketing contracts negotiated on behalf
of the Joint Venture by the current operator that took effect on July 1, 2017.
10 Realized crude oil prices increased 32% and increased 21% compared to the prior quarter and Q4 fiscal 2017
respectively. The increases are due to the strengthening US Brent commodity price on a year-over-year
basis.
The following table outlines average benchmark prices compared to Bengal’s realized prices:
Prices and Marketing
Three Months Ended
March 31
Twelve Months Ended
March 31
Average Benchmark Price
2018
2017 % Change
2018
2017 % Change
Bengal realized crude oil price
before realized gain (loss) on
financial instruments($CAD/bbl)
Realized gain (loss) on financial
Instruments ($CAD/bbl)
Brent oil ($CAD/bbl)
Brent oil ($US/bbl)
Number of CAD$ for 1 AUS$
Number of CAD$ for 1 US$
$92.61
$ 70.40
32
$81.47
$ 67.17
(9.58)
86.61
66.81
0.99
1.26
31.37
71.18
53.78
1.00
1.32
(131)
18
24
(1)
(5)
4.32
74.23
57.57
0.99
1.28
34.06
63.88
48.66
0.99
1.31
21
(87)
16
18
-
(2)
Netbacks
Netbacks
($000s)
Oil sales
Realized gain (loss) on
financial instruments
Royalties
Operating and transportation
expenses
Netback ($000s)
Oil sales ($/bbl)
Realized gain (loss) on
financial instruments ($/bbl)
Royalties ($/bbl)
Operating and transportation
expenses ($/bbl)
Netback ($/bbl)
Three Months Ended
Twelve Months Ended
March 31
March 31
2018
2017 % Change
2018
2017 % Change
2,783
2,179
28
10,710
9,294
15
(288)
136
971
(347)
1,077
1,282
987
2,510
(130)
(139)
9
(49)
568
642
3,718
6,918
4,712
(213)
4,864
9,355
92.61
70.40
32
81.47
67.17
(9.58)
4.53
31.37
(11.21)
35.84
42.66
31.89
81.09
(131)
(140)
12
(47)
4.32
4.88
28.28
52.63
34.06
(1.54)
35.15
67.62
(88)
(401)
(24)
(26)
21
(87)
(417)
(20)
(22)
During the fourth quarter of fiscal year (FY) 2018, the Company realized a significant increase in its oil sales
per barrel compared to Q4 FY 2017. The primary factor was the strong underling US Brent price for Q4 FY
2018. The average US Brent price for the quarter was US$ 66.81/bbl vs US$ 53.78/bbl in Q4 FY 2017. When
the average premium to Brent is factored in, CAD$ 6 per barrel is added to the average base revenue price
of CAD$ 86.61/bbl to arrive at CAD$ 92.61. Similarly, the twelve month FY 2018 is stronger than the twelve
month FY 2017 due to the improvement in US Brent pricing. Full year 2018 saw US Brent average US$
57.57/bbl compared to US$ 48.66/bbl for FY 2017. This in turn reflects a CAD$ 81.47/bbl average FY 2018
price compared to average CAD$ 67.17/bbl for FY 2017. In terms of netbacks, the Company realized a
reduction in netback per barrel both in Q4 fiscal 2018 and full year 2018 due to realized losses on financial
instruments. Throughout fiscal 2017, the Company realized large gains on financial instruments due to its
US$ 80/bbl hedges when the average US Brent price was US$ 49.88/bbl compared to the US$ 47 hedges in
fiscal 2018 when the average US Brent price was US$ 57.85/bbl. Operating costs per barrel are higher in the
three months ended 2018 than previous quarters and previous year as no audit recoveries were realized in
the quarter but expected in Q1 fiscal 2019.
11 Risk Management Activities
Bengal has entered into financial commodity contracts as part of its risk management program to manage
commodity price fluctuations related to its primary producing assets being the Cuisinier field in Australia’s
Cooper Basin. It is a requirement under Bengal’s Credit Facility to hedge 50% of its annual production.
With respect to financial contracts, which are derivative financial instruments, management has elected not
to use hedge accounting and consequently records the fair value of its crude oil financial contracts on the
statement of financial position at each reporting period with the change in fair value being classified as
unrealized gains and losses in the consolidated statement of income (loss).
The Company has the following derivative contracts:
Time Period
Type of Contract
April 1, 2018 – December 31, 2018
Oil - Swap
April 1, 2018 – December 31, 2018
Oil – Put option
Time Period
Type of Contract
Jan. 1, 2019 – March 31, 2019
Oil - Swap
Jan. 1, 2019 – March 31, 2019
Oil – Put option
Quantity
Contracted
(bbls)
34,572
30,689
Quantity
Contracted
(bbls)
7,953
7,953
Price Floor
(US$/bbl)
Price Ceiling
(US$/bbl)
47.00
47.00
47.00
-
Price Floor
(US$/bbl)
Price Ceiling
(US$/bbl)
55.40
55.40
55.40
-
The fair value of the financial contracts outstanding as at March 31, 2018 is an estimated liability of $1.0
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, 2018, the derivative commodity contracts resulted in a realized loss
of $0.3 million (Q4 fiscal 2017 - $1.0 million gain) and an unrealized loss of $0.4 million (Q4 fiscal 2017 - $0.2
million loss).
The realized and unrealized losses incurred in the current quarter were the result of the below-market hedges
currently in place and the increase in Brent forward strip pricing. The realized gain in Q4 fiscal 2017 was the
result of the US$ 80 per barrel oil swaps that have now expired.
Royalties
Royalties ($000s)
Royalty expense
$/bbl
% of revenue
Three Months Ended
Twelve Months Ended
March 31
March 31
2018
2017 % Change
2018
2017 % Change
136
4.53
5
(347)
(11.21)
(16)
(139)
(140)
(131)
642
4.88
6
(213)
(1.54)
(2)
(401)
(417)
(400)
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 allowable capital,
transportation and operating costs, resulting in an effective rate of approximately 6% of gross revenue.
Royalties have increased compared to Q4 fiscal 2017 due to a one time significant credit received for
reduction of allowable capital deductions during Q4 fiscal 2017 and due to lower recent drilling activity. For
the fiscal year 2018, Royalty expenses have been impacted in the same manner as the Q4 fiscal year 2018.
Overall, deductible allowances are down compared to fiscal year 2017 and Royalties as a percentage of
revenue are more in line with the 6% expectation.
12 Operating & Transportation Expenses
Operating & trans.
expenses ($000s)
Operating
Transportation
Operating - $/boe
Transp. - $/boe
Three Months Ended
2018
151
926
1,077
5.02
30.82
35.84
March 31
2017
% Change
53
934
987
1.71
30.18
31.89
185
(1)
9
194
2
12
Twelve Months Ended
March 31
2018
(239)
3,957
3,718
(1.82)
30.10
28.28
2017 % Change
563
4,301
4,864
4.07
31.08
35.15
(142)
(8)
(24)
(145)
(3)
(20)
Operating costs increased in Q4 of fiscal 2018 due to extra well work-overs and pump changes compared to
Q4 of fiscal 2017. The lower operating costs for twelve months fiscal 2018 are due to the recovery of $1.1
million from an ongoing joint venture audit. These recoveries also explain the 142% decrease in YTD fiscal
2018 operating cost per barrel as compared to fiscal 2017.
Transportation costs on a per boe basis have increased 2% compared to Q4 fiscal 2017 but have decreased
in FY 2018 by 3% compared to FY 2017 as the Company is realizing some cost reductions in transportation
tariffs due to the previously disclosed new transportation tariff reductions that are now taking effect.
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
March 31
2018
614
69
683
28
5
33
2017 % Change
(15)
(17)
(15)
721
83
804
4
1
5
600
400
560
2018
2,398
295
2,693
95
15
110
2017 % Change
(12)
2,740
(13)
338
(13)
3,078
29
7
36
228
114
206
The 15% decrease in net G&A expenditures compared to Q4 2017 is a result of the Company focusing on
limiting discretionary spending. Similarly on a full year fiscal 2018 basis, G&A costs were 12% less than in
fiscal year 2017 due to cost management.
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 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 2015 and June 2017 vest conditionally
based on certain performance criteria on their first, second and third anniversaries. The increase in share-
based compensation expense reflects the issuance of the June 2017 option grant.
Impairment
The Company has taken a total impairment charge of $12.167 million. The majority of the impairment charge
is against the Company’s ATP 732 asset. Due to certain leases expiring over the next two years with the
13 (12)
(22)
(12)
(7)
Company having no intention of developing or renewing these leases, the carrying value of ATP 732 was
written down to $5.38 million.
Depletion and Depreciation (DD&A)
DD&A Expenses
($000s)
PNG – Australia
Corporate
Total
Three Months Ended
March 31
Twelve Months Ended
March 31
2018
2017 % Change
573
3
576
443
4
447
29
(25)
29
2018
2,026
14
2,040
2,291
18
2,309
2017 % Change
$/boe – PNG Australia
19.17
14.31
34
15.41 16.56
The increase in depletion per barrel from Q4 fiscal 2017 is due to a 9% decline in reserves for the comparative
quarter. The decrease in depletion per barrel for the twelve months ended March 31, 2018 is due to a 26%
decline in the expected future costs associated with developing the proved and probable reserves and that
the decline in reserves only impacts Q4 2018.
Finance Income/Expenses
Finance Income/Expenses
($000s)
Three Months Ended
March 31
Interest income
Accretion expense on
decommissioning liabilities
Letter of credit charges
Interest on credit facility
Total
2018
1
(9)
-
(236)
(244)
2017 % Change
(88)
8
(10)
-
(178)
(180)
(10)
-
33
36
Interest on the credit facility is based on US dollar Libor + 3.2% margin.
Twelve Months Ended
March 31
2017
12
% Change
8
(37)
(55)
(947)
(1,027)
-
(100)
1
(5)
2018
13
(37)
-
(954)
(978)
CAPITAL EXPENDITURES
Capital Expenditures ($000s)
Three Months Ended
Twelve Months Ended
Geological and geophysical
Drilling
Completions
Acquisition
Total expenditures
Exploration & evaluation
expenditures
Development & production
expenditures
Total net expenditures
2018
1,586
-
(1,156)
509
939
1,996
(1,057)
939
March 31
2017
% Change
2018
March 31
2017
% Change
230
(53)
504
-
681
97
584
681
590
(100)
(329)
-
38
2,139
(52)
915
509
3,511
883
2,974
1,761
-
5,618
142
(102)
(48)
-
(38)
1,958
2,277
407
1,996
(281)
38
1,234
3,511
5,211
5,618
(76)
(38)
The addition of $509 thousand of acquisition costs, in Q4 fiscal year 2018, is a result of acquiring the final
30% interest in ATP 934 bringing the Company’s ownership to 100%. Capital expenditures are down overall
in fiscal year 2018 due to a reduction in the drilling program compared to FY 2017. The credit balances for
drilling completions of $1.2 million and development & production expenditures of $1.1 in the three months
ended March 31, 2018 are both due to the reclassification of $1.4 million of costs from plant and natural gas
properties back to exploration and evaluation assets related to the Chookola well program.
14 CREDIT FACILITY
In October 2014, Bengal closed its US $25.0 million secured credit facility with Westpac Institutional Bank
(“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. On September 25, 2017, the Company extended the credit
facility to December 2019 with a borrowing base of US $12.5 million. The facility is secured by the Company’s
producing assets in the Cuisinier field in Australia’s Cooper Basin, has a five and one-half year term and
carries an interest rate of US Libor plus 3.2%. Based on the extension, the Company is committed to
extending its hedge contracts through December 2019 prior to June 30, 2018.
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 reduction schedule
commences on June 30, 2018 and occurs every six months thereafter until December 31, 2019 with a nominal
reduction of US $2.5 million to the facility limit at each calculation date (through June 30, 2019) based on the
Company’s existing reserve profile and a nominal reduction of US $5 million at December 31, 2019. The
facility limit at March 31, 2018 is US $12.5 million, of which US $12.5 million is currently drawn.
The credit facility’s reserve 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, 2018.
On March 5, 2018, Westpac agreed to amend the terms of the 2nd Extension Agreement dated September
25, 2017. Previously, the terms required Bengal to make principal payments on its facility of US $2.5 million
US on June 30, 2018 and US $2.5 million US on December 31, 2018. The new amendment will defer the full
amount of the June 30, 2018 payment into the second half of 2019 and the December 2018 principal payment
has been reduced to US $1.5 million US. The balance of the December 2018 payment will also be deferred
until the second half of 2019. In return Bengal has agreed to amend the debt service coverage ratio covenant
definition, provide for a cash sharing arrangement which requires the Company to deposit 50% of free cash
flow against the outstanding loan amount and agree to a reserve base review by April 30, 2019.
SHARE CAPITAL
At June 8, 2018 there were 102,266,694 common shares issued and outstanding, together with 4,852,500
outstanding options.
Trading History
High
Low
Close
Volume (000s)
Shares outstanding (000s)
Weighted average shares
outstanding (000s)
Basic
Diluted
Three Months Ended
March 31
2018
2017 % Change
$0.13
$0.09
$0.10
2,800
102,267
$ 0.23
$ 0.13
$ 0.14
3,546
102,267
102,267
102,267
102,267
102,267
(43)
(31)
(29)
(21)
-
-
-
Twelve Months Ended
2018
$0.17
$0.08
$0.10
15,454
March 31
2017
$ 0.24
$ 0.11
$ 0.14
12,725
% Change
(29)
(27)
(29)
21
102,267
102,267
-
102,267
102,267
76,770
76,770
33
33
15 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.
Bengal’s financial liabilities consist of accounts payable and accrued liabilities, credit facility and fair value of
financial instruments and amounted to $19.3 million at March 31, 2018 (March 31, 2017 - $18.1 million).
At March 31, 2018, the Company had working capital of $3.4 million, including cash and cash equivalents of
$3.9 million and restricted cash of $0.1 million, compared to working capital of $3.8 million at March 31, 2017.
The Company has no available undrawn debt capacity under its Westpac credit facility.
The majority of the Company’s oil sales are benchmarked on Brent prices which averaged US $57.57/bbl for
the twelve months ended March 31, 2018. 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 (as required by Westpac) 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 2019
Fiscal year 2020
COMMITMENTS
1,500
11,000
12,500
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. In fiscal Q4 2018, the
Company consolidated its ownership of ATP 934 and now holds a 100% operating interest in this permit. The
purchase consideration was AUS $311,221 cash and potential future cash payments of up to AUS
$1,000,000, which is made up of a AUS $200 thousand on certification by an independent competent person
appointed by the Buyer of not less than 25 billion cubic feet of Proved Reserves and AUS $800 thousand due
upon the delivery of First Gas to market.. Work program consists of 200 kilometers of 3D seismic and up to
three wells.
AFE commitments are reflected where the Company has agreed with partners to proceed with activities (e.g.
onshore Australia ATP 752 Cuisinier). The costs of these activities are based on minimum work budgets
included in bid documents and agreements among joint venture parties, and have not been provided for in
the financial statements. Actual costs may vary from budget.
Country and Permit
Work Program
Onshore Australia –
ATP 934P
200 km2 of 2D seismic and up to
three wells
Obligation Period
Ending
Estimated Expenditure
(net) (millions CAD$)(1)
March 2021
$13.4
(1) Translated at March 31, 2018 at an exchange rate of AUS $1.00 = CAD $0.9898.
16 OTHER
At March 31, 2018, the contractual obligations for which the Company is responsible are as follows:
Contractual Obligations ($000s)
Office lease
Decommissioning obligations
Total contractual obligations
Total
893
1,556
2,449
$
$
Less than
1 Year
$
$
155
-
155
1-3
Years
311
60
371
4-5
Years
315
175
490
$
$
After
5 Years
$ 112
1,321
$ 1,433
$
$
OFF BALANCE SHEET TRANSACTIONS
The Company does not have any off balance sheet transactions.
SELECTED QUARTERLY INFORMATION
($000s, except per share amounts)
Fiscal quarter
Q4 2018
Q3 2018
Q2 2018 Q1 2018 Q4 2017 Q3 2017 Q2 2017 Q1 2017
Mar. 31
2018
Dec. 31
2017
Sep. 30
2017
Jun. 30
2017
Mar. 31
2017
Dec. 31
2016
Sep. 30
2016
Jun. 30
2016
Petroleum and natural gas sales
Cash from operations
Funds from operations
Per share
Basic and diluted (1)
Net income (loss)
Per share
Basic and diluted
Capital expenditures
Working capital (deficiency)
2,783
858
525
0.01
(12,526)
(0.12)
939
3,385
3,211
431
1,268
0.01
206
0.00
342
(637)
2,410
648
110
2,306
1,690
1,834
2,179
643
1,639
2,325
934
1,412
2,301
1,982
1,797
2,489
956
1,348
0.00
0.02
0.02
0.02
0.03
0.02
(500)
549
1,931
(2,288)
325
(2,736)
0.02
(0.03)
0.00
(0.04)
0.00
1,527
0.01
703
2,107
(2,477)
3,815
681
1,234
3,291
3,320
4,421
383
(9,171)
Total assets
45,714
56,932
56,032
57,104
57,706
56,020
55,552
54,108
Shares outstanding (000s)
102,667
102,267
102,267
102,267
102,267
102,267
68,178
68,178
Operations
Oil Volumes (bpd)
Netback ($/boe)
334
42.66
354
383
369
344
355
386
431
63.13
28.97
49.80
81.09
69.01
67.30
56.09
(1) See “Non-IFRS Measurements” on page 6 of this MD&A.
Production over the last eight quarters peaked during Q1 fiscal 2017 as incremental production from the fiscal
2016 fracture stimulation program came on stream. Production increased in the Q1 and Q2 fiscal 2018
quarters as the wells from the Cuisinier fiscal 2017 drilling campaign were put on stream. Variances in net
income have been impacted by unrealized gains/losses on foreign exchanges and derivative contracts as
well as material impairments recorded in Q4 fiscal 2016 and Q4 fiscal 2018.
Fluctuations in netbacks have been primarily driven by volatile benchmark crude prices and associated
hedging gains and losses as royalties and operating and transportation costs have remained consistent (with
the exception of the joint venture audit proceeds). Joint venture audit proceeds received during Q1 and Q3
fiscal 2018 contributed to increased funds from operations and cash flows in that period.
17 DISCLOSURE CONTROLS & PROCEDURES AND
REPORTING (ICFR)
INTERNAL CONTROL OVER FINANCIAL
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, 2018 due to the material weaknesses noted below.
No changes in internal controls over financial reporting were identified during the period that have materially
affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.
While Bengal’s Chief Executive Officer and Chief Financial Officer believe the Company’s internal controls
and procedures provide a reasonable level of assurance that they are reliable, an internal control system
cannot prevent all errors and fraud. It is management’s belief that any control system, no matter how well
conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control
system are met.
During the design and operating effectiveness assessment, certain material weaknesses in internal controls
over financial reporting were identified, as follows:
Management is aware that there is a lack of segregation of duties due to the small number of
employees dealing with general and administrative and financial matters. However, management
believes that at this time the potential benefits of adding employees to clearly segregate duties do
not justify the costs; and
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.
18 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
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
19 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.
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 Company will adopt the standard for its fiscal year commencing April 1, 2018, using the
retrospective approach. Based on the Company’s review of contracts with customers, at this time, the
Company does not anticipate that the adoption of IFRS 15 will have a material impact on net income (loss)
and financial position. However, the Company is still in the process of reviewing all of its contracts and fully
assessing the financial statement impact. The Company does anticipate expanding disclosures in the notes
to its consolidated financial statements as described by IFRS 15.
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
20 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
Company determined that there will not by any material changes to the measurement and carrying values of
the Company’s financial instruments as a result of the adoption of IFRS 9. The Company 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
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.
21 Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.
Completion of a well does not assure a profit on the investment or recovery of drilling, completion and
operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of
operations, and various field operating conditions may adversely affect the production from successful wells.
These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells
resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological
and mechanical conditions. While diligent well supervision and effective maintenance operations can
contribute to maximizing production rates over time, production delays and declines from normal field
operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow
levels to varying degrees.
In addition, oil and gas operations are subject to the risks of exploration, development and production of oil
and natural gas properties, including encountering unexpected formations or pressures, premature declines
of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence
of any of these risks could have a materially adverse effect on future results of operations, liquidity and
financial condition.
Bengal attempts to minimize exploration, development and production risks by utilizing a high-end technical
team with extensive experience and multidisciplinary skill sets to assure the highest probability of success in
its drilling efforts. Bengal’s collaboration of a team of seasoned veterans in the oil and gas business, each
with a unique expertise in the various upstream to downstream technical disciplines of prospect generation
to operations, provides the best assurance of competency, risk management and drilling success. A full cycle
economic model is utilized to evaluate all hydrocarbon prospects. Detailed geological and geophysical
techniques are regularly employed including 3D seismic, petrography, sedimentology, petrophysical log
analysis and regional geological evaluation.
Risks Associated with Foreign Operations
International operations are subject to political, economic and other uncertainties, including, among others,
risk of war, risk of terrorist activities, border disputes, expropriation, renegotiations or modification of existing
contracts, restrictions on repatriation of funds, import, export and transportation regulations and tariffs,
taxation policies, including royalty and tax increases and retroactive tax claims, exchange controls, limits on
allowable levels of production, currency fluctuations, labor disputes, sudden changes in laws, government
control over domestic oil and gas pricing and other uncertainties arising out of foreign government sovereignty
over the Company's international operations. With respect to taxation matters, the governments and other
regulatory agencies in the foreign jurisdictions in which Bengal operates and intends to operate in the future
may make sudden changes in laws relating to taxation or impose higher tax rates, which may affect Bengal’s
operations in a significant manner. These governments and agencies may not allow certain deductions in
calculating tax payable that Bengal believes should be deductible under applicable laws or may have differing
views as to values of transferred properties. This can result in significantly higher tax payable than initially
anticipated by Bengal. In many circumstances, readjustments to tax payable imposed by these governments
and agencies may occur years after the initial tax amounts were paid by Bengal, which can result in the
Company having to pay significant penalties and fines. Furthermore, in the event of a dispute arising from
international operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may
not be successful in subjecting foreign persons to the jurisdiction of courts in Canada.
Prices, Markets and Marketing of Crude Oil and Natural Gas
Oil and natural gas are commodities that have prices determined based on world demand, supply and other
factors, all of which are beyond the control of Bengal. World prices for oil and natural gas have fluctuated
widely in recent years. Any material decline in prices could result in a reduction of net production revenue.
Certain wells or other projects may become uneconomic as a result of a decline in world oil prices and natural
22 gas prices, leading to a reduction in the volume of Bengal’s oil and gas reserves. Bengal might also elect not
to produce from certain wells at lower prices. All of these factors could result in a material decrease in Bengal’s
future net production revenue, causing a reduction in its oil and gas acquisition and development activities.
In addition to establishing markets for its oil and natural gas, Bengal must also successfully market its oil and
natural gas to prospective buyers. The marketability and price of oil and natural gas which may be acquired
or discovered by Bengal will be affected by numerous factors beyond its control. The ability of Bengal to
market its natural gas may depend upon its ability to acquire space on pipelines which deliver natural gas to
commercial markets. Bengal will also likely be affected by deliverability uncertainties related to the proximity
of its reserves to pipelines and processing facilities and related to operational problems with such pipelines
and facilities and extensive government regulation relating to price, taxes, royalties, land tenure, allowable
production, the export of oil and natural gas and many other aspects of the oil and natural gas business.
Substantial Capital Requirements and Liquidity
Bengal’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From time
to time, Bengal may require additional financing in order to carry out its oil and gas acquisition, exploration
and development activities. Failure to obtain such financing on a timely basis could cause Bengal to forfeit its
interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If
Bengal’s revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it
will affect Bengal’s ability to expend the necessary capital to replace its reserves or to maintain its production.
If Bengal’s funds from operations are not sufficient to satisfy its capital expenditure requirements, there can
be no assurance that additional debt or equity financing will be available to meet these requirements or
available on terms acceptable to Bengal.
Bengal monitors and updates its cash projection models on a regular basis which assists in the timing decision
of capital expenditures. Farm outs of projects may be arranged if capital constraints are an issue or if the risk
profile dictates that Bengal wishes to hold a lesser working interest position. Equity, if available and if on
favorable terms, may be utilized to help fund Bengal’s capital program.
Health, Safety and Environment
All phases of the oil and natural gas business present environmental risks and hazards and are subject to
environmental regulation pursuant to a variety of federal, provincial and local laws and regulations.
Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or
emissions of various substances produced in association with oil and natural gas operations. The legislation
also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction
of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and
a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of
which may be material.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement,
larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of
oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third
parties and may require the Company to incur costs to remedy such discharge.
Insurance
Bengal’s involvement in the exploration for and development of oil and gas properties may result in the
Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other
hazards. Although Bengal has insurance in accordance with industry standards to address such risks, such
insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In
addition, such risks may not, in all circumstances be insurable or, in certain circumstances, Bengal may elect
not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance
or other reasons. The payment of such uninsured liabilities would reduce the funds available to Bengal. The
23 occurrence of a significant event that Bengal is not fully insured against, or the insolvency of the insurer of
such event, could have a material adverse effect on Bengal’s financial position, results of operations or
prospects.
Competition
Bengal actively competes for reserve acquisitions, exploration leases, licenses and concessions and skilled
industry personnel with a substantial number of other oil and gas companies, many of which have significantly
greater financial and personnel resources than Bengal. Bengal's competitors include major integrated oil and
natural gas companies and numerous other independent oil and natural gas companies and individual
producers and operators.
Bengal’s ability to successfully bid on and acquire additional property rights, to discover reserves, to
participate in drilling opportunities and to identify and enter into commercial arrangements with customers will
be dependent upon developing and maintaining close working relationships with its future industry partners
and joint operators and its ability to select and evaluate suitable properties and to consummate transactions
in a highly competitive environment.
ADDITIONAL INFORMATION
Additional information relating to Bengal is filed on SEDAR and can be viewed at www.sedar.com. Information
can also be obtained by contacting the Company at Bengal Energy Ltd., Suite 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.
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 frac program on Barta Block Cuisinier;
The expected timing of the spudding of Chookola well on Barta Block Cuisinier and timing to complete evaluation
of all associated the target zones;
The presence of a gas resource play on ATP 934 Barrolka permit;
The timing of the development of the Nubba-1 well discovery on the Yilgarn PCA, ATP 752, Wompi Block;
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 $60/bbl under current market conditions;
Treatment under governmental regulatory regimes and tax laws;
Capital expenditures programs and estimates of costs; and
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.
24 With respect to the forward looking statements contained in the MD&A, Bengal has made assumptions regarding: future
commodity prices; the impact of royalty regimes; the timing and the amount of capital expenditures; production of new
and existing wells and the timing of new wells coming on stream; future operating expenses including processing and
gathering fees; the performance characteristics of oil and natural gas properties; the size of oil and natural gas reserves;
the ability to raise capital; the continued availability of undeveloped land and skilled personnel; the ability to obtain
equipment in a timely manner to carry out exploration and development activities; the ability to obtain financing on
acceptable terms; the ability to add production and reserves through exploration and development activities; and the
continued stability of political, regulatory; tax and fiscal regimes in which the Company has operations.
The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk
factors set forth below and elsewhere in this Management’s Discussion and Analysis:
●
●
●
●
●
●
●
●
●
●
Volatility in market prices for oil and natural gas;
Liabilities inherent in oil and natural gas operations;
Uncertainties associated with estimating oil and natural gas reserves;
Competition
for, among other
things: capital, acquisitions of
reserves, undeveloped
lands and
skilled personnel;
Incorrect assessment of the value of acquisitions;
Unable to meet commitments due to inability to raise funds or complete farm-outs;
Geological, technical, drilling and processing problems;
Changes in income tax laws or changes to royalty and environmental regulations relating to the oil and
gas industry;
The risk that Bengal may not be successful in raising funds by an equity issue; and
Counter-party credit risk, stock market volatility and market valuation of Bengal’s stock.
Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions, which the resources and reserves described, can be profitably
produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking
statements contained in this MD&A and the documents incorporated by reference herein are expressly qualified by this
cautionary statement. The forward-looking statements contained in this document speak only as of the date of this
document and Bengal does not assume any obligation to publicly update or revise them to reflect new events or
circumstances, except as may be required pursuant to applicable securities laws. Additional information on these and
other factors that could affect Bengal’s operations and financial results are included in reports on file with Canadian
securities authorities and may be accessed through the SEDAR website (www.sedar.com) and at Bengal’s website
(www.bengalenergy.ca).
These statements speak only as of the date of this MD&A or as of the date specified in the documents incorporated by
reference into this Management’s Discussion and Analysis, as the case may be.
25 Consolidated Financial Statements
Years Ended
March 31, 2018 and 2017
26 Bengal Energy Ltd.
Consolidated Financial Statements
MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL REPORTING
The accompanying consolidated financial statements are the responsibility of management. The consolidated
financial statements have been prepared by management in accordance with International Financial
Reporting Standards outlined in the notes to the consolidated financial statements. The consolidated financial
statements include certain estimates that reflect 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, 2018. 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 financial statements have been approved by the Board of Directors on the recommendation
of the Audit Committee.
(signed) “Chayan Chakrabarty”
Chayan Chakrabarty
President & Chief Executive Officer
(signed) “Matthew Moorman”
Matthew Moorman
Chief Financial Officer
27
Bengal Energy Ltd.
Consolidated Financial Statements
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, 2018 and March 31, 2017, the consolidated
statements of loss and comprehensive loss, changes in equity and cash flows for the years then ended, and
notes, comprising a summary of significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial
statements in accordance with International Financial Reporting Standards, and for such internal control as
management determines is necessary to enable the preparation of consolidated financial statements that are
free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those
standards require that we comply with ethical requirements and plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are free from material
misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on our judgment, including the
assessment of the risks of material misstatement of the consolidated financial statements, whether due to
fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s
preparation and fair presentation of the consolidated financial statements in order to design audit procedures
that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of
accounting policies used and the reasonableness of accounting estimates made by management, as well as
evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a
basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated
financial position of Bengal Energy Ltd. as at March 31, 2018 and March 31, 2017, and its consolidated
financial performance and its consolidated cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered Professional Accountants
June 8, 2018
Calgary, Canada
28 Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Thousands of Canadian dollars)
Notes
3
12
4
5
7
12
8
7
12
9
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
Total assets
LIABILITIES AND SHAREHOLDERS’
EQUITY
Current liabilities:
Accounts payable and accrued
liabilities
Current portion of credit facility
Fair value of financial instruments
Non-current liabilities:
Decommissioning liability
Credit facility
Fair value of financial instruments
Shareholders’ equity:
Share capital
Contributed surplus
Accumulated other comprehensive
income
Deficit
Total liabilities and shareholders’ equity
Commitments (note 15)
$
2018
3,904
140
4,307
154
-
8,505
10,102
27,107
37,209
$ 45,714
$
2,232
1,934
954
5,120
1,556
14,146
-
15,702
98,100
7,755
1,034
(81,997)
24,892
$ 45,714
See accompanying notes to the consolidated financial statements.
On behalf of the Board:
Director
Chayan Chakrabarty
Director
James B. Howe
$
$
$
2017
3,903
140
3,575
193
820
8,631
20,529
28,546
49,075
57,706
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
$
29 Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
(Thousands of Canadian dollars, except per share amounts)
For the years ended March 31,
2018
2017
Notes
Income
Petroleum and natural gas revenue
Royalties recovery (expense)
Realized gain on financial instruments
Unrealized loss on financial instruments
Operating expenses
General and administrative
Operating and transportation
Depletion and depreciation
Impairment
Share-based compensation
Operating loss
Other income (expenses)
Other
Finance expenses
Foreign exchange gain (loss)
Net loss
Exchange differences on translation of foreign operations
Total comprehensive loss for the year
Loss per share
- Basic & diluted
Weighted average number of shares outstanding
(000s)
- Basic & diluted
See accompanying notes to the consolidated financial statements.
$10,710
(642)
10,068
568
(1,661)
8,975
2,398
3,718
2,040
12,167
95
20,418
$9,294
213
9,507
4,712
(6,308)
7,911
2,740
4,864
2,309
-
29
9,942
(11,443)
(2,031)
124
(978)
26
(828)
378
(1,027)
(88)
(737)
(12,271)
(2,768)
(1,051)
$(13,322)
750
$(2,018)
$(0.12)
$(0.04)
102,267
76,770
5
4
11
9
9
30 Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Thousands of Canadian dollars)
Shares
outstanding
Share
capital
Warrants
Contributed
surplus
Accumulated
other
comprehensive
income
Total
shareholders’
equity
Deficit
Balance at
April 1, 2016
68,177,796 $ 94,151
$
167
$
7,442
$
1,335
$ (66,958) $
36,137
Net loss for the year
Comprehensive income for the
year
-
-
-
-
Rights offering
Share issue costs
Expiry of warrants
Share-based compensation –
expensed
Share-based compensation –
capitalized
Balance at
March 31, 2017
Balance at
April 1, 2017
Net loss for the year
Comprehensive loss for the
year
Share-based compensation –
expensed
Share-based compensation –
capitalized
Balance at
March 31, 2018
34,088,898
4,091
-
-
-
-
(142)
-
-
-
102,266,694
$ 98,100
102,266,694 $ 98,100
$
$
-
-
-
-
-
-
-
-
102,266,694
$ 98,100
$
-
-
-
-
-
-
-
-
-
See accompanying notes to the consolidated financial statements.
-
-
-
-
-
-
-
-
(167)
167
29
7
-
(2,768)
(2,768)
750
-
-
-
-
-
-
-
-
-
-
-
750
4,091
(142)
-
29
7
$
7,645
$
2,085
$ (69,726) $
38,104
$ 7,645
$2,085
$ (69,726) $
38,104
-
-
95
15
-
(12,271)
(12,271)
(1,051)
-
-
-
-
-
(1,051)
95
15
$ 7,755
$ 1,034
$ (81,997)
$
24,892
31 Bengal Energy Ltd.
Consolidated Financial Statements
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Canadian dollars)
For the years ended March 31,
Operating activities
Net loss for the year
Non-cash items:
Depletion and depreciation
Impairment
Accretion on decommissioning liability
Accretion on credit facility
Share-based compensation
Loss (profit) on disposition of petroleum and natural
gas properties
Unrealized loss 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 in cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
2018
2017
Notes
$ (12,271)
$
(2,768)
2,040
12,167
37
230
95
(124)
1,661
(98)
3,737
(110)
3,627
(2,277)
(1,234)
208
(3,303)
-
-
(95)
(109)
(204)
(119)
1
3,903
3,904
$
$
2,309
-
37
278
29
62
6,308
65
6,196
(1,681)
4,515
(407)
(5,211)
(178)
(5,796)
(3,949)
(1,984)
(150)
285
2,100
74
893
3,010
3,903
14
4
5
14
9
7
7
14
See accompanying notes to the consolidated financial statements.
32 BENGAL ENERGY LTD.
Notes to Consolidated Financial Statements (the “financial statements”)
Year ended March 31, 2018 and 2017
(Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts)
1.
REPORTING ENTITY
Bengal Energy Ltd. (the “Company” or “Bengal”) is incorporated under the laws of the Province of Alberta
and is involved in the exploration for and development and production of oil and gas reserves in Australia,
India and Canada. The consolidated financial statements (the “financial statements”) of the Company as
at March 31, 2018 and 2017 and for the years then ended are comprised of the Company and its wholly-
owned subsidiaries including Bengal Energy International Inc. and Bengal Energy Australia (Pty) Ltd.,
which are incorporated in Canada and Australia respectively. The Company conducts many of its
activities jointly with others; these financial statements reflect only the Company’s proportionate interest
in such activities.
Bengal’s principal place of business and registered office is located at 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 8, 2018.
b) Basis of measurement
These financial statements have been prepared on a historical cost basis, except for commodity
contracts as discussed in Note 12.
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, 2018
March 31, 2017
3,897
7
3,904
1,655
2,248
3,903
33 4.
EXPLORATION AND EVALUATION ASSETS (E&E ASSETS)
($000s)
Balance at April 1, 2016
Additions
Capitalized share-based compensation
Exchange adjustments
Balance at March 31, 2017
Additions
Acquisition
Capitalized share-based compensation
Impairment
Exchange adjustments
Balance March 31, 2018
19,626
407
3
493
20,529
1,768
509
7
(12,167)
(544)
10,102
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.
A summary of E&E assets is shown in the table below:
($000s)
ATP 732P – Tookoonooka
ATP 752P – Barta Cuisinier
ATP 934P – Barrolka
Other(1)
March 31, 2017
($000s)
ATP 732P – Tookoonooka
ATP 752P – Barta Cuisinier
ATP 934P – Barrolka
Other(1)
March 31, 2018
Australia
16,573
1,273
1,114
1,569
20,529
Australia
5,380
2,725
1,852
145
10,102
(1)
Other includes capitalized G&A, share-based compensation and foreign exchange effects on these
assets denominated in foreign currencies.
In fiscal Q4 2018, the Company consolidated its ownership of ATP 934 and now owns and controls
operatorship of a 100% working interest. The purchase consideration was AUS$ 311,221 cash and
potential future cash payments of up to AUS$ 1,000,000, subject to certain conditions and commercial
benchmarks being achieved (see Note 15).
The Company recorded an impairment charge of $12.17 million against the Company’s ATP 732 asset
due to certain leases expiring over the next two years that the Company has no intention of developing
or renewing. These impairment charges were taken into the Consolidated Statement of Loss in fiscal Q4,
2018.
34 5.
PETROLEUM AND NATURAL GAS PROPERTIES
$000s
Cost:
Balance at April 1, 2016
Additions
Capitalized share-based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2017
Additions
Disposals
Capitalized share-based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2018
$000s
Accumulated depletion, depreciation and
impairment losses:
Balance at April 1, 2016
Depletion and depreciation charge
Exchange adjustments
Balance at March 31, 2017
Depletion and depreciation charge
Disposals
Exchange adjustments
Balance at March 31, 2018
Net carrying value
At March 31, 2017
At March 31, 2018
Petroleum and
Natural Gas
Properties
Corporate
Assets
41,820
5,211
4
80
760
47,875
1,234
(4,316)
8
167
(732)
44,236
344
-
-
-
-
344
-
-
-
-
-
344
Petroleum and
Natural Gas
Properties
Corporate
Assets
17,020
2,291
75
19,386
2,026
(4,316)
76
17,172
28,489
27,064
269
18
-
287
14
-
-
-
301
57
43
Total
42,164
5,211
4
80
760
48,219
1,234
(4,316)
8
167
(732)
44,580
Total
17,289
2,309
75
19,673
2,040
(4,316)
76
17,473
28,546
27,107
The calculation of depletion for the quarter ended March 31, 2018 included $58.1 million for estimated
future development costs associated with proved and probable reserves in Australia (March 31, 2017 -
$73.4 million).
During the second quarter of fiscal 2018, the Company disposed of petroleum and natural gas properties
that had no net carrying value for nominal proceeds. The properties had an associated decommissioning
liability of $124,000.
35 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:
Years Ended March 31,
($000s)
Loss before taxes
Statutory tax rate
Expected income tax recovery
Foreign exchange
Stock-based compensation
Effect of change in tax rate & other
Other
Changes in unrecognized tax asset
Income tax recovery
2018
(12,271)
27%
(3,313)
(403)
26
(308)
-
3,998
-
2017
(2,768)
27%
(747)
(269)
8
(45)
-
1,053
-
The deductible temporary 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
2018
46,135
6,034
12,983
263
-
65,415
2017
32,915
5,740
13,150
557
102
52,464
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
2018
4,446
(286)
(430)
(467)
(3,263)
-
2017
14,651
216
(942)
(418)
(13,507)
-
At March 31, 2018, the Company had approximately $30.3 million and $26.8 million of non-capital losses
in Canada and Australia respectively (2017- $29.3 million and $48.7 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, 2018, the Company has no deferred tax liabilities
in respect of these temporary differences.
36 7.
CREDIT FACILITY
Facility Agreement – Issued November 12, 2014 ($000s)
Gross proceeds
Total cash fees
Repayment
Unrealized foreign exchange loss
Accretion
Balance at March 31, 2017
Facility extension fees
Unrealized foreign exchange gain
Accretion
Balance at March 31, 2018
Current portion of credit facility
Non-current portion of credit facility
15,364
(994)
(1,984)
12,386
3,238
876
16,500
(95)
(555)
230
16,080
March 31,
2017
3,332
13,168
March 31,
2018
1,934
14,146
In October 2014, Bengal closed its US $25.0 million secured credit facility with Westpac Institutional Bank
(“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. On September 25, 2017, the Company
extended the credit facility to December 2019 with a borrowing base of US $12.5 million. On March 5,
2018 the Credit Agreement was further amended to delay the majority of principle payments into 2019.
The facility is secured by the Company’s producing assets in the Cuisinier field in Australia’s Cooper
Basin, has a five and one-half year term and carries an interest rate of US Libor plus 3.2%.
The credit facility is structured as a reserves-based revolving facility under a predetermined reduction
schedule, to be evaluated based on existing reserves at each calculation date. Under the Amendment
dated March 5, 2018 the Company is required to make a US$ 1.5 million principle payment on December
31, 2018 and a further US$ 5 million on June 30, 2019 and US$ 6 million on December 30, 2019. In
return, the Company has agreed to amend the debt service coverage ratio covenant definition, provide
for a cash sharing arrangement which requires the Company to deposit 50% of free cash flow against the
outstanding loan amount and agree to a reserve base review by April 30, 2019.
The credit facility’s reserve-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, 2018.
37 8.
DECOMMISSIONING AND RESTORATION LIABILITY
The total decommissioning and restoration obligations were estimated by management based on the
estimated costs to reclaim and abandon the wells, well sites and certain facilities based on the Company’s
contractual requirements.
Changes to decommissioning and restoration obligations were as follows:
March 31,
($000s)
Decommissioning liabilities, beginning of year
Change in estimate net of disposals
Additions
Accretion
Exchange adjustments
Decommissioning liabilities, end of year
2018
1,516
43
-
37
(40)
1,556
2017
1,422
(259)
278
37
38
1,516
The Company’s decommissioning liabilities result from ownership interests in petroleum and natural gas
properties. The Company estimates the total inflation-adjusted undiscounted amount of cash flows
required to settle its decommissioning and restoration costs at March 31, 2018 is approximately $2.2
million (March 31, 2017 – $2.3 million) which will be incurred between 2020 and 2046. An inflation factor
of 1.9% and a risk-free discount rate of 2.6% have been applied to the decommissioning liability at March
31, 2018.
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, 2016
Issued on exercise of rights offering
Share issue costs
Balance at March 31, 2017 and 2018
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.
(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.
38 The Company 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:
Outstanding at March 31, 2016
Granted
Forfeited
Expired
Exercised
Outstanding at March 31, 2017
Granted
Forfeited
Expired
Exercised
Outstanding at March 31, 2018
Exercisable at March 31, 2018
Options
Weighted Average
Exercise Price
4,357,000
-
-
(1,655,000)
-
2,702,500
3,355,000
(543,853)
(911,147)
-
4,602,500
986,096
$
$
$
$
0.72
-
-
1.19
-
0.43
0.10
0.11
0.55
-
0.20
0.52
Options Outstanding
Options Exercisable
Option Price (1)
$0.10 - $0.46
$0.47 - $0.65
Total
Number
Outstanding
3,852,500
750,000
4,602,500
Exercise
Price (2)
$0.12
$0.63
$0.20
Remaining
Life (3)
3.78
0.32
3.21
Number
Exercisable
236,096
750,000
986,096
Exercise
Price (2)
$0.18
$0.63
$0.52
(1) Range of option exercise prices
(2) Weighted average exercise price of options
(3) Weighted average remaining contractual life of options in years
The fair value of options granted during Q2 and Q3 fiscal 2018 were estimated on the date of grant
using the Black-Scholes option-pricing model with the following weighted average assumptions and
resulting values:
Granted
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
3,330,000
25,000
1.13%
5 yrs.
91%
20%
$0.07
$0.10
1.78%
5 yrs.
92%
20%
$0.09
$0.125
(1) Expected volatility is estimated by considering historic average share price volatility.
The fair value of 3,330,000 and 25,000 stock options granted during Q2 and Q3 fiscal 2018 were
approximately $187,000 and $2,000 respectively. No options were granted during the year ended
39 March 31, 2017.
(d) Per share amounts:
Income (loss) per share is calculated based on net income (loss) and the weighted-average number
of common shares outstanding.
For the Year Ended
($000s)
Loss for the year
(000s shares)
Weighted average number of common shares (basic)
Weighted average number of common shares (diluted)
Basic and diluted loss per share
2018
2017
$ (12,271)
$ (2,768)
102,267
102,267
$(0.12)
76,770
76,770
$(0.04)
For the year ended March 31, 2018, there were 4,602,500 (March 31, 2017- 2,702,500) options
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
2018
977
97
1,074
2017
986
33
1,019
(1) Represents the amortization of share-based payment expense associated with the company’s share-based
compensation plans granted to key management personnel.
11.
FINANCE INCOME/EXPENSES
Year ended March 31,
($000s)
Interest income
Accretion on decommissioning obligations
Letter of credit charges
Interest on credit facility
Finance expenses
12.
FINANCIAL RISK MANAGEMENT
2018
2017
13
(37)
-
(954)
(978)
12
(37)
(55)
(947)
(1,027)
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
40 paid to joint venture partners and receivables from petroleum and natural gas marketers. As at March
31, 2018, Bengal’s receivables consisted of $4.3 million (March 31, 2017 - $3.1 million) from joint
venture partners (of which $1.3 million has been subsequently collected) and $nil million (March 31,
2017 - $0.4 million) of other trade receivables.
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, 2018 (March 31, 2017- $nil). 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, 2018 and did not provide for any doubtful
accounts, nor was it required to write-off any receivables during the year ended March 31, 2018
(March 31, 2017 – nil). Exposure to the carrying value of its financial instruments relates to the
Company’s commodity-based derivatives held by Westpac Banking Corporation, which carries a
Standard & Poor’s credit rating of AA-. Management considers the credit risk of these instruments to
be adequately mitigated by the credit stating of their holder; therefore, no allowance has been
established.
Cash and cash equivalents, when held, consist of cash bank balances and guaranteed investment
certificates redeemable at any time. Bengal manages the credit exposure related to guaranteed
investments by selecting counterparties based on credit ratings and monitors all investments to
ensure a stable return, avoiding complex investment vehicles with higher risk such as asset-backed
commercial paper.
(b) Liquidity risk:
Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including
work commitments, as they are due. Bengal prepares an annual budget and updates forecasts for
operating, financing and investing activities on an ongoing basis to ensure it will have sufficient
liquidity to meet its liabilities when due.
Bengal’s financial liabilities consist of accounts payable and accrued liabilities, fair value of financial
instruments, and credit facility and amounted to $19.3 million at March 31, 2018 (March 31, 2017 -
$18.1 million).
At March 31, 2018, the Company had working capital of $3.4 million, including cash and short-term
deposits of $3.9 million and restricted cash of $0.1 million, compared to working capital of $3.8 million
at March 31, 2017. The Company has no available undrawn debt capacity under its Westpac credit
facility.
The majority of the Company’s oil sales are benchmarked on US Brent prices. 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.
41 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 plans to use its internal source of cash to fund exploration activities.
The table below indicates the current payment schedule for the credit facility:
Credit facility (US$000s)
Fiscal year 2019
Fiscal year 2020
(c) Market risk:
1,500
11,000
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 of future cash flows will fluctuate as
a result of changes in foreign exchange rates. Bengal receives U.S. dollars for Australian oil sales
and incurs expenditures in Australian, Canadian and U.S. currencies. Having sales and expenditures
denominated in three currencies spreads the impact of individual currency fluctuations.
The Company may enter into derivative foreign currency contracts in order to manage foreign
currency exchange rate risk, but has not done so to date.
The table below shows the Company’s exposure to foreign currencies for its financial instruments:
As at March 31, 2018
(CDN$000s)
Cash and cash equivalents
Restricted cash
Accounts receivable
Accounts payable and accrued
liabilities
Credit facility
Fair value of financial instruments
CAD
AUD
USD
Total
439
140
15
(327)
-
-
267
82
-
4,292
(1,905)
-
-
2,469
3,383
-
-
-
(16,080)
(954)
(13,651)
3,904
140
4,307
(2,232)
(16,080)
(954)
(10,915)
Commodity Price Risk
Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of a
change in commodity prices. Commodity prices for petroleum and natural gas are impacted by not
only the relationship between the Canadian and United States dollar, as outlined above, but also
world economic events that dictate the levels of supply and demand. Australian oil prices are based
on the US Brent reference price, which currently trades at a premium to WTI.
At March 31, 2018, the following derivative contracts were outstanding and recorded at estimated fair
value:
42 Time Period
Type of Contract
April 1, 2018 – December 31, 2018
April 1, 2018 – December 31, 2018
($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
January 1, 2019 – March 31, 2019
January 1, 2019 – March 31, 2019
($000s)
Current fair value of financial instruments
Non-current fair value of financial instruments
Total
Oil - Swap
Oil – Put option
Quantity
Contracted
(bbls)
34,572
30,689
Oil - swap
(894)
-
(894)
Quantity
Contracted
(bbls)
7,953
7,953
Oil - swap
(97)
-
(97)
Price Floor
(US$/bbl)
Price Ceiling
(US$/bbl)
47.00
47.00
Oil – put
9
-
9
47.00
-
Total
(885)
-
(885)
Price Floor
(US$/bbl)
Price Ceiling
(US$/bbl)
55.40
55.40
Oil – put
28
-
28
55.40
-
Total
(69)
-
(69)
A US $1.00 increase in the future crude oil price per barrel would result in an approximate US $81,000
decrease in the fair value of financial instruments at March 31, 2018 while a US$ 1.00 decrease would
result in an increase of approximately US $81,000 in the fair value of the instruments.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest
rates. The Company is not exposed to interest rate risk on its cash and cash equivalents at March
31, 2018 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, 2018.
For the year ended March 31, 2018, a 1% increase in US Libor would increase interest expense by
$121,000.
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.
43 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
2018
(732)
39
748
(66)
(11)
(110)
(109)
208
(11)
The following represents the cash interest paid and received in each period.
Year ended March 31 ($000s)
Cash interest paid
Cash interest received
15.
COMMITMENTS
2018
777
13
2017
(388)
38
(1,185)
37
(1,574)
(1,681)
285
(178)
(1,574)
2017
705
12
Pursuant to current production sharing contracts (“PSC”), the Company is required to perform minimum
exploration activities that include various types of surveys, acquisition and processing of seismic data
and drilling of exploration wells. Additional commitments are reflected where the Company has agreed
with joint operating partners to proceed with activities. The costs of these activities are based on minimum
work budgets included in bid documents and have not been provided for in the financial statements.
Actual costs will vary from budget.
The Queensland Government regulatory authority granted the Company Authority to Prospect 934 ("ATP
934") under a revised work program on March 1, 2015. The Company acquired an additional 21.43%
working interest and received ministerial approval for the acquisition on August 11, 2015. In Q4 2018,
the Company consolidated its ownership of ATP 934 and now holds a 100% operating interest in this
permit. The purchase consideration was AUS$ 311,221 cash and potential future cash payments of up
to AUS$ 1,000,000, which is made up of a AUS$ 200 thousand on certification by an independent
competent person appointed by Bengal Energy Australia (Pty) Ltd. of not less than 25 billion cubic feet of
Proved Reserves and AUS$ 800 thousand due upon the delivery of the first shipments of gas to market.
Work program consists of 200 kilometers of 3D seismic and up to three wells.
Country and Permit
Work Program
Obligation Period
Ending
Estimated Expenditure
(net) (millions CAD$)(1)
Onshore Australia –
ATP 934P
200 km2 of 3D seismic and up to
three wells
March 2021
$13.4
(1) Translated at March 31, 2018 at an exchange rate of AUS $1.00 = CAD $0.9898.
44 At March 31, 2018 the Company had the following lease commitment for office space in Canada.
($000s)
April 2018 to November 2023
Office lease
16.
SEGMENTED INFORMATION
Total
893
Less than
1 Year
155
1-3
Years
311
4-5
Years
315
After
5 Years
112
As at March 31, 2018, the Company has three reportable operating segments being the Australian and
Indian oil and gas operations, and corporate.
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 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.
45 For the year ended March 31, 2018 ($000s)
Revenue
Interest revenue
Interest expense
Depletion and depreciation
Net earnings (loss)
Exploration and evaluation expenditures
Petroleum and natural gas property
expenditure.
Impairment
March 31, 2018 ($000s)
Petroleum and natural gas properties
Cost
Accumulated impairment loss
Accumulated depletion and depreciation
Net book value
Exploration and evaluation assets
Accumulated impairment losses
Net book value
For the ended March 31, 2017 ($000s)
Revenue
Interest income
Interest expense
Depletion and depreciation
Net earnings (loss)
Exploration and evaluation expenditures
Petroleum and natural gas property
expenditures
March 31, 2017 ($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
10,710
12
954
1,869
(11,205)
2,277
1,234
12,324
44,236
(797)
(16,375)
27,064
31,410
(21,308)
10,102
Australia
9,294
11
947
2,291
(1,425)
407
5,211
43,582
(796)
(14,297)
28,489
29,850
(9,321)
20,529
Corporate
-
1
-
14
(1,056)
-
India
-
-
-
-
(10)
-
-
-
344
-
(301)
43
-
-
-
-
-
-
Total
10,710
13
954
1,883
(12,271)
2,277
1,234
12,324
44,580
(797)
(16,676)
27,107
-
-
-
8,140
(8,140)
-
39,550
(29,448)
10,102
Corporate
-
1
-
18
(1,153)
-
-
4,637
(310)
(4,270)
57
India
-
-
-
-
(190)
-
-
-
-
-
-
Total
9,294
12
947
2,309
(2,768)
407
5,211
48,219
(1,106)
(18,567)
28,546
-
-
-
8,415
(8,484)
-
38,265
(17,736)
20,529
17.
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.
(a) Basis of consolidation:
The financial statements incorporate the financial statements of the Company and its wholly-owned
subsidiaries Bengal Energy Australia (Pty) Ltd. and Bengal Energy International Inc.
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.
46 All intra-group transactions, balances, income and expenses are eliminated in full on consolidation.
(b) Cash and cash equivalents
Cash and cash equivalents include cash and all investments with a maturity of three months or less.
(c) Provisions
A provision is recognized if, as a result of a past event, the Company has a present legal or
constructive obligation that can be estimated reliably, and it is probable that an outflow of economic
benefits will be required to settle the obligation. Provisions are determined by discounting the
expected future cash flows at a pre-tax “risk-free” rate that reflects current market assessments of
the time value of money and the risks specific to the liability. The unwinding of the discount is
recognized as a finance expense. Provisions are not recognized for future operating losses.
Decommissioning and restoration liabilities:
The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation
activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant
asset category.
Decommissioning obligations are measured at the present value of management’s best estimate of
the expenditures required to settle the present obligation at the period end date. Subsequent to the
initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time
and changes in the estimated future cash flows underlying the obligation. The increase in the
provision due to the passage of time is recognized as finance costs whereas increases/decreases
due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon
settlement of the asset retirement obligations are charged against the provision to the extent the
provision was established.
(d) Oil and natural gas exploration and evaluation expenditures
Exploration and evaluation costs (“E&E” assets)
All costs incurred prior to obtaining the legal right to explore an area are expensed when incurred.
Generally, costs directly associated with the exploration and evaluation of crude oil and natural gas
reserves are initially capitalized. Exploration and evaluation costs are those expenditures for an area
where technical feasibility and commercial viability have not yet been demonstrated. These costs
generally include unproved property acquisition costs, geological and geophysical costs, sampling
and appraisals, drilling and completion costs and capitalized decommissioning costs.
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
47 asset into operation, the initial estimate of the decommissioning obligation, and for qualifying assets,
borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair
value of any other consideration given up to acquire the asset.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability and
the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas
interests only when they increase the future economic benefits embodied in the specific asset to which
they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil
and natural gas interests generally represent costs incurred in developing proved and/or probable
reserves and bringing in or enhancing production from such reserves, and are accumulated on a field
or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized.
The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss
as incurred.
Depletion and depreciation
The net book value of producing assets are depleted on a field-by-field basis using the unit of
production method with reference to the ratio of production in the year to the related proved and
probable reserves, taking into account estimated future development costs necessary to bring those
reserves into production. For purposes of these calculations, production and reserves of natural gas
are converted to barrels on an energy equivalent basis.
Other assets are depreciated on a declining basis at rates ranging from 20% to 30% per annum.
Gains and losses on disposal of an item of property, plant and equipment, including oil and natural
gas interests, are determined by comparing the proceeds from disposal with the carrying amount of
property, plant and equipment and are recognized as separate line items in profit or loss.
(f)
Impairment
E&E and petroleum and natural gas properties
E&E assets are assessed for impairment when facts and circumstances suggest that the carrying
amount exceeds the recoverable amount and when they are reclassified to Development and
Production (“D&P”) assets. For the purpose of impairment testing, E&E assets are grouped by
concession or production field with other E&E assets belonging to the same concession or production
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
48 and gas assets is generally determined as the net present value of the estimated future cash flows
expected to arise from the continued use of the CGU, including any expansion prospects, and its
eventual disposal, using assumptions that an independent market participant may take into account.
These cash flows are discounted by an appropriate discount rate which would be applied by such a
market participant to arrive at a net present value of the CGU. Where the carrying amount of a CGU
exceeds its recoverable amount, the CGU is considered impaired and is written down. Consideration
is given to acquisition metrics or recent transactions completed on similar assets to those contained
with the relevant CGU.
When the recoverable amount is less than the carrying amount, the asset or CGU is impaired. For
impairment losses identified based on a CGU, the loss is allocated on a pro rata basis to the assets
within the CGU(s). The impairment loss is recognized as an expense in profit or loss.
At the end of each subsequent reporting period these impairments are assessed for indicators of
reversal. Where an impairment loss subsequently reverses, the carrying amount of the asset or CGU
is increased to the revised estimate of its recoverable amount, but so that the increased carrying
amount does not exceed the carrying amount that would have been determined had no impairment
loss have been recognized for the asset or CGU in prior years. A reversal of an impairment loss is
recognized immediately in profit or loss.
Financial assets
A financial asset is assessed at each reporting date to determine whether there is any objective
evidence that it is impaired. A financial asset is considered to be impaired if objective evidence
indicates that one or more events have had a negative effect on the estimated future cash flows of
that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the
difference between its carrying amount and the present value of the estimated future cash flows
discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The remaining
financial assets are assessed collectively in groups that share similar credit risk characteristics.
All impairment losses are recognized in profit or loss.
An impairment loss is reversed if the reversal can be related objectively to an event occurring after
the impairment loss was recognized. For financial assets measured at amortized cost, the reversal
is recognized in profit or loss.
(g) Financial instruments
Financial assets and liabilities are classified as either financial assets or liabilities at fair value through
profit and loss (“FVTPL”), loans and receivables, held-to-maturity investments, available-for -sale
financial assets, or other liabilities, as appropriate. Financial assets and liabilities are recognized
initially at fair value.
Subsequent measurement of financial instruments is based on their initial classification. FVTPL
financial assets and liabilities are measured at fair value and changes in fair value are recognized in
profit or loss. Available-for-sale financial instruments are measured at fair value with changes in fair
value recorded in other comprehensive loss until the instrument is derecognized or impaired. The
remaining categories of financial instruments are recognized at amortized cost using the effective
interest rate method.
The transaction costs that are directly attributable to the acquisition or issue of a financial asset or
financial liability classified as FVTPL are expensed immediately. For a financial asset or financial
liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the
49 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.
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 options at
grant date. An estimated forfeiture rate is incorporated into the fair value calculated and adjusted to
50 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 common shares during
the period.
the average market price of
(l)
Income taxes:
Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit
or loss except to the extent that it relates to items recognized directly in equity, in which case it is
recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted
or substantively enacted at the reporting date, and any adjustments to tax payable in respect of
previous years.
Deferred tax is recognized providing for temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for taxation purposes.
Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is
not a business combination. In addition, deferred tax is not recognized for taxable temporary
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.
51 (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 and cash equivalents, restricted cash, accounts receivable,
accounts payable and accrued liabilities, credit facility and derivatives.
The Company's policy is to recognize transfers in and out of the fair value hierarchy as of the date of
the event or change in circumstances that caused the transfer. There were no such transfers during
the period.
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
52 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 Company
will adopt the standard for its fiscal year commencing April 1, 2018, using the retrospective approach.
Based on the Company’s review of contracts with customers, at this time, the Company does not
anticipate that the adoption of IFRS 15 will have a material impact on net income (loss) and financial
position. However, the Company is still in the process of reviewing all of its contracts and fully
assessing the financial statement impact. The Company does anticipate expanding disclosures in the
notes to its consolidated financial statements as described by IFRS 15.
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 Company determined that there will not by any material
changes to the measurement and carrying values of the Company’s financial instruments as a result
of the adoption of IFRS 9. The Company 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.
18.
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.
53 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.
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.
54 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.
55 CORPORATE INFORMATION
AUDITORS
KPMG LLP • Calgary, Canada
LEGAL COUNSEL
Burnet, Duckworth & Palmer LLP • Calgary, Canada
Piper Alderman • Sydney, Australia
BANKERS
Royal Bank of Canada • Calgary, Canada
WestPac • Sydney, Australia
REGISTRAR AND TRANSFER AGENT
Computershare • Toronto, 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
Chayan Chakrabarty
Matthew Moorman
AUDIT COMMITTEE
James B. Howe (Chairman)
Robert D. Steele
W.B. (Bill) Wheeler
RESERVES COMMITTEE
Peter D. Gaffney (Chairman)
Dr. Brian J. Moss
Ian J. Towers
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
Matthew Moorman, Chief Financial Officer
Gordon R. MacMahon, Vice President, Exploration
Bruce Allford, Secretary
STOCK EXCHANGE LISTING – TSX: BNG
56