Consolidated Financial Statements
international exploration & production
2015 Annual Report
TABLE OF CONTENTS
1
3
6
32
36
64
Message to Shareholders
Fiscal 2015 Highlights
Management’s Discussion and Analysis
Consolidated Financial Statements
Notes to the Consolidated Financial Statements
Corporate Information
BENGAL ENERGY LTD.
MESSAGE TO SHAREHOLDERS
Bengal’s 2015 fiscal year was the most active period in our history, with results from our two-phased
Cuisinier drilling campaign contributing to a 51% increase in our proved plus probable (“2P”) reserve base
over fiscal year end 2014. New reserve additions from our successful drilling and development program
effectively replaced more than 12 times our 2015 annual production volumes. Despite a significant
downturn in global crude oil prices facing the industry, on the strength of Bengal’s asset base we were able
to solidify our financial flexibility by finalizing a US$25 million secured credit facility with Westpac
Institutional Bank of Australia. Operationally and financially, I am very pleased with the progress Bengal
has made in 2015 to further develop and grow our asset base, while positioning the Company to deliver
long-term value.
As a direct result of our fiscal 2015 activities in the Cuisinier oil pool on the Barta block in Australia’s Cooper
Basin, the net present value discounted at 10% (NPV10) of Bengal’s 2P reserves increased 17% over the
prior year, and was assessed at $118 million by our independent reserve evaluators. This is a clear
demonstration of the inherent value in Bengal’s asset base, and the magnitude of its potential, particularly in
light of the dramatic decrease in world oil prices year over year. Our team’s technical capabilities,
BENGAL ENERGY LTD.
consistent execution of strategy and unwavering value-focus have led to the successful growth and
delineation of the Cuisinier pool and its related asset value for Bengal.
While crude oil prices have shown moderate improvement from their dramatic lows in early calendar 2015,
the global outlook for commodity prices remains challenged. However, Bengal is very well-positioned
relative to many of our North American energy sector peers. As a result of our high quality asset base,
which produces ultra-light oil and commands a premium price to the Brent benchmark, coupled with
Australia’s favourable and predictable royalty regime, our Australian netbacks averaged CDN$89.43/bbl for
the 2015 fiscal year. To further underpin our future revenues and in concert with our new US$25 million
secured credit facility, Bengal entered into a combination of fixed future swap and put positions on
approximately 269,000 barrels effective December 2014 through June 2017, with an attractive floor price of
US $80 per barrel. This robust and advantageous hedging position serves to further support Bengal’s
revenue and funds flow during periods of commodity price volatility.
Bengal’s 2015 capital program was primarily directed to the development and appraisal of the Cuisinier oil
pool where Bengal and our joint venture parties successful drilled and completed four development wells
from late March 2014 through early May 2014. The Phase Two drilling campaign also included one
successful exploration well at Wompi, three appraisal wells and two development wells, Cuisiner-20 and
Cuisnier-21 on the ATP 752 Barta Block within the Cuisinier field. Cuisiner-20 and Cuisnier-21 are currently
being tied-in by the operator. Through the first three months of fiscal 2016, our production has been
relatively stable relative to the previous calendar quarter, averaging approximately 525 boepd.
In addition to contributing new production volumes, the new Cuisinier-21 development well is significant
because it successfully expanded the lowest known oil level in the Cuisinier structure by establishing a 42-
plus meter oil column. This expansion further increases the areal extent of the Cuisinier pool and provides
new opportunities for future drilling and development. The success of our 2015 drilling program has
enhanced our understanding of the geological features in the area and resulted in record year-end reserve
assignments for Bengal by our independent reserve evaluators.
Bengal remains catalyst-rich as we move into fiscal 2016 with a combination of continued development and
exploration activities. At Wompi, Bengal holds a 38% working interest and with our JV parties, are
preparing for the completion and testing of our newest gas discovery. In early calendar 2016, the JV will
complete and test the commerciality of the Nubba-1 exploration well. While the Phase Two exploration well
encountered multiple oil shows, we are even more excited by its potential as a future natural gas producer,
showing up to 6 metres of gas pay. The discovery has the potential to provide another significant target-rich
play for future development.
Bengal and our Joint Venture Partner, Beach Energy Ltd (“Beach”), are planning to drill a second well at our
Tookoonooka asset, the cost for which Bengal will be fully carried. Beach has completed the acquisition;
processing and preliminary interpretation of a 300 square kilometre 3D seismic survey and the Joint
Venture will identify potential drilling locations in advance of drilling in calendar mid-2016. This area could
provide an important driver for Bengal, offering new near-term production volumes and revenue, as well as
extensive future drilling locations to support growth over the longer term.
In our onshore India block at CY-ONN-2005/1, Bengal holds a 30% working interest in 946 square
kilometres (233,000 acres), and we continue to coordinate with our partners, Gas Authority of India Ltd.
(“GAIL”) and Gujarat State Petroleum Corporation to advance plans for the drilling of three exciting
exploration wells. GAIL, the operator, is working with various local stakeholders and government bodies to
obtain the necessary approvals to proceed, with current expectations for drilling the first well at the earliest,
in late calendar 2015.
2
Bengal Energy Ltd.
2015 Annual Report
Following up on Bengal’s largest ever capital program, and in response to the currently uncertain
commodity price environment, our primary focus for fiscal 2016 will be to ensure prudent capital investment
supported by a thorough analysis of development, appraisal and exploration opportunities, with continued
cost reduction efforts.
In response to a weakened commodity price environment, we anticipate a number of production acquisition
and other strategic opportunities to arise over the coming quarters. Bengal will continue to examine and
evaluate potential opportunities and transactions with the objective of adding to production, reserves and
funds flow, all of which support enhanced shareholder value. We will continue development and appraisal
drilling at our core properties in Cuisinier, expected to drive near-term and operating income while paving
the way for future expanded development.
Bengal has taken steps to weather the current commodity price downturn by improving our financial
flexibility, establishing an attractive hedge position, and maintaining a responsible approach to our
operations. I want to thank our strong and supportive Board, our hard-working and skilled technical team,
as well as each of our shareholders for your support as we grow and further unlock the value of Bengal
Energy.
Sincerely,
Chayan Chakrabarty
President & CEO
Note: this Message to Shareholders contains forward-looking statements and is subject to the forward-
looking statement disclaimer in the Management’s Discussion & Analysis for the Years Ended March 31,
2015 and 2014.
BENGAL ENERGY LTD.
FISCAL 2015 HGHLIGHTS
Financial Highlights:
Reserves Growth Continues – The independent third party year-end reserves evaluation to March
31, 2015 shows a 31% and 51% year-over-year corporate Proved (“1P”) and Proved plus Probable
(“2P”) reserves increase, respectively. 1P reserves are now 2.2 million barrels and 2P reserves are
now 5.7 million barrels of high quality, high netback 52 degree gravity light oil. These increases
were primarily driven by the successful drilling program conducted throughout the year on the
Cuisinier asset. Based on 1P and 2P reserves additions, Bengal has replaced approximately 4.0
times and 12.0 times its annual production, respectively.
Hedging in place through June 2017 – Effective December 2014, the Company entered into a
combination of fixed for future swaps and put positions for approximately 269,000 barrels in total
through to June 2017 with a floor price of US $80 per barrel. Since December 2014, the hedging
program has resulted in a realized gain of $0.9 million and carries an unrealized fair value of $5.0
million.
Revenue – Bengal generated revenue of approximately $3.4 million in the fourth quarter of fiscal
2015 compared with $3.9 million in the third quarter of fiscal 2015. The difference is primarily due to
a decrease in benchmark commodity prices and is partially offset by the Company’s hedging
positions. Revenue was 36% lower than the $5.3 million generated during the fourth quarter of
fiscal 2014. For the full fiscal year ended 2015, Bengal generated revenue of approximately $15.4
million, which is a 21% decrease over fiscal 2014. The decrease was again driven by lower realized
pricing for crude oil.
Funds Flow from Operations(1) – Bengal generated funds flow from operations of $0.9 million in
Q4 2015, being the quarter ended March 31, 2015, compared to $2.2 million during Q4 2014 and
$1.3 million generated in Q3 2015, due to lower netbacks associated with declining benchmark
crude prices. The full fiscal year ended 2015 funds flow from operations was $4.6 million, versus
$8.2 million generated during the fiscal year ended March 31, 2014.
Earnings – Bengal reported a net loss of $3.2 million during the fiscal year ended 2015, compared
to a net income of $0.2 million in the prior year due to the impact decreased crude oil prices on
funds from operations as well as the $3.2 million impairment of its wholly owned drilling rig and $1.8
million of foreign exchange losses. When the impact of unrealized foreign exchange losses and
unrealized hedging gains are eliminated, Bengal’s 2015 annual adjusted net loss(1) was $6.1 million
compared to annual adjusted net earnings of $0.02 million in the fiscal year ended March 31, 2014.
Additional Financial Flexibility – On October 24, 2014, Bengal finalized its US $25.0 million
secured credit facility with Westpac Institutional Bank of Australia. An initial draw of US $14.0
million was used to repay the Company’s existing $8.0 million aggregate principal amount of notes
and to fund a portion of the Cuisinier Phase Two development drilling program.
2015 Operational Highlights:
Production Volumes – Production in the fourth quarter of 2015 averaged 525 barrels of oil
equivalent per day (“boepd”), a 4% increase from the fourth quarter of 2014, and a 9% decrease
from the previous quarter due to natural declines. Full year 2015 production increased 3% to 480
boepd compared to 468 boepd produced in 2014 as a result of incremental production from the
Cuisinier Phase One drilling program. Incremental production from the 2014 Cuisinier drilling
1 See non-IFRS measurements section on page 6 to this MD&A
4
Bengal Energy Ltd.
2015 Annual Report
program has been partially offset by the unexpected increase in water cut at the Cuisinier-6 well,
which underwent a work over program in April 2015 in an attempt to restore production.
Production has been relatively stable through the first quarter of fiscal 2016, averaging 525 boepd,
with two new producing wells coming online in June 2015.
Cuisinier Drilling Campaign – From late March 2014 to early May 2014, Bengal and its joint
venture parties (“JV”) carried out the first of its calendar 2014 two-phase drilling campaign at
Cuisinier. The four Phase One development wells targeted the oil-bearing Cretaceous Murta
Formation and were drilled with 100% success.
The Phase Two drilling campaign included three appraisal wells and two development wells at the
ATP 752 Barta Block Cuisinier oil field. The JV is in the process of tying-in the two development
wells, Cuisiner-20, and Cuisnier-21.
Cuisinier-21 – This development well tested the northwest flank of the Cuisinier structure and
came in structurally as predicted; testing 100% clean oil on perf at an estimated rate of 380 boepd.
This well has now established an oil column of at least 42 meters and further increasing the areal
extent of the Cuisinier pool.
Cuisinier-6 – During the month of April 2015, the operator completed production logging on this
well and set a bridge plug to isolate the producing Murta formation from the deeper Namur
formation aquifer. The performance of this well will be monitored closely in the coming months to
determine if isolation was complete.
Cuisinier-17 and -19 – As previously announced, the Cuisinier-17 and Cuisinier-19 have been
suspended pending finalization of an appropriate stimulation program. The operator is in the
process of developing a fracture stimulation program for a number of wells at Cuisinier that, based
on results, could potentially include the Cuisinier-17 and Cuisinier-19 wells in the future.
ATP 934 Barrolka Permit – On March 1, 2015, this gas prone 361,268 acre block was awarded to
the Bengal operated JV by the Minister of the Department of Natural Resources and Mines of the
Queensland Government. In addition, effective April 1, 2015, Bengal increased its ownership in the
permit to 80% through the acquisition of the interest held by one of its joint venture parties. The
remaining joint venture partner, effective June 19, 2015 exercised its option to purchase 8.6% of
this interest; therefore Bengal’s current working interest is 71.4%. As operator, Bengal is currently in
discussions with the Queensland Government and hopes to finalize a work program and budget for
this gas focused permit in the near future.
Wompi Exploration – Bengal and its JV parties completed drilling operations of the Nubba-1
exploration well. The well encountered multiple oil shows within the Jurassic, as well as up to 6
meters of Permian Toolachee Formation gas pay. Completion and testing of this gas discovery will
confirm rates and commerciality early in calendar 2016. Bengal has 38% in the Wompi block and
the Nubba well.
ATP 732 Tookoonooka Permit – Beach Energy Ltd. farmed in to this Permit in 2011 and have now
completed the acquisition, processing and preliminary interpretation of the 300 square kilometre
Nassarius 3D seismic survey. Additional pre-stack depth migration (“PSDM”) was required to better
image some of the leads that have been defined. The processing of the PSDM data has now been
completed and the final interpretation is due to commence imminently. The next phase of drilling will
be finalized upon completion of interpretation.
BENGAL ENERGY LTD.
Onshore India Drilling Plan – At Bengal’s onshore India block situated within the Cauvery Basin
(CY-ONN-2005/1 – 30% WI), the Company continues to coordinate with its partners, Gas Authority
of India Ltd. (“GAIL”) and Gujarat State Petroleum Corporation, for the drilling of three exploration
wells. GAIL, the operator, continues to negotiate with various stakeholders and government bodies
that provide the necessary approvals to proceed. The drilling of the first of three exploration wells is
expected to commence no earlier than in late calendar 2015.
MANAGEMENT’S DISCUSSION AND ANALYSIS – JUNE 18, 2015
Bengal’s producing assets are predominantly situated in Australia’s Cooper Basin, a region featuring large
hydrocarbon pools. The Company’s core Australian assets – Cuisinier and Tookoonooka – are situated
within an area of the Basin in its infancy in terms of appraisal and development, and Bengal believes these
assets offer attractive upside potential. Australia features a stable political, fiscal and economic environment
in which to operate, with a favourable royalty regime for oil and gas production.
With oil pricing benchmarked to Brent, Bengal’s realized operating netbacks from Australia have averaged
over C $56.10/bbl for the twelve months ending March 31, 2015. This competitive cost environment coupled
with a growing production base contributed to the Company’s positive funds flow from operations through
fiscal 2015.
OUTLOOK
AUSTRALIA
ATP 752 Barta Block Cuisinier
The Barta Joint Venture (“JV”) completed Phase Two of the Cuisinier drilling campaign and tied in two of
four development locations in June 2015. The two remaining suspended wells as well as several other
marginal producers in the field are currently being evaluated as candidates for a 2015 fracture stimulation
program. Given the current commodity price climate, the primary focus for the Cuisinier production license
will be low cost high yield development projects, such as fracture stimulation as well as overall field
evaluation. This field evaluation will result in a development plan focused on the continued expansion of
pool boundaries as well as increasing field production by targeting lower risk high productivity locations.
ATP 732 Tookoonooka Block
In Bengal’s Tookoonooka permit (ATP 732 - WI 50%), which is located in the emerging East Flank oil
fairway of the Cooper Basin, the Company is partnered with Beach Energy Ltd. (“Beach”). Following the
ongoing seismic interpretation, the joint venture is expected to identify drilling locations in advance of drilling
mid-2016.
ATP 752 Wompi
The Nubba-1 well, which encountered multiple oil shows within the Jurassic, as well as up to 6 metres of
Permian Toolachee gas pay is expected to be evaluated late 2015 or early 2016. Pressure testing as well
logging suggests that this Toolachee gas well could be part of a gas column which may be up to 70 metres
in height. This suggests the prospective gas pay extends down dip of the Nubba well where seismic
indicates the Toolachee section thickens. With positive test results a Petroleum Production Lease will be
applied for which will allow long term production to begin. The produced natural gas would likely be pipeline
connected to the nearest gas transmission line in the area which is approximately 5 kilometres from the
Nubba-1 well. Wompi offers Bengal moderate risk exploration in a well-established, oil-producing fairway
with multi-zone potential.
6
Bengal Energy Ltd.
SUMMARY
2015 Annual Report
Following up on the Company’s largest ever capital program, and in response to the currently uncertain
commodity price environment, the primary focus of fiscal 2016 will be prudent capital investment and
thorough analysis of development, appraisal and exploration opportunities.
The current depressed commodity price environment has caused some competitors to refocus their strategy
and operations. As a result, the company expects a number of production acquisition and other strategic
opportunities to arise over the next several quarters. Bengal continues to examine and evaluate potential
opportunities through various industry and financial entities with the objective of adding to Bengal’s
production and enhancing shareholder value. It is not possible to assess the likelihood of success in any
such endeavor at this time.
OPERATING HIGHLIGHTS
$000s except per share, volumes
and netback amounts
Three Months Ended
March 31
2015
2014
%
Change
Twelve Months Ended
March 31
2015
2014
%
Change
Revenue
Oil
Natural gas
Natural gas liquids
Total
Royalties
Realized gain on financial instruments
% of revenue
Operating & transportation
Operating netback(1)
Funds from (used in) operations:(2)
Per share ($) (basic & diluted)
Net income (loss):
Per share ($) (basic & diluted)
Adjusted net (loss) earnings:
Per share ($) (basic & diluted)
Capital expenditures
Volumes
Oil (bpd)
Natural gas (mcfd)
Natural gas liquids (boepd)
Total (boepd @ 6:1)
Netback(1) ($CDN/boe)
Revenue
Realized gain on financial
instrument
Royalties
Operating & transportation
Operating netback
$ 3,359
$ 5,174
(35)
$ 15,395
$ 19,480
23
(4)
87
11
$ 3,378
$ 5,272
202
717
6.0
1,727
407
-
7.7
1,496
$ 2,166
$ 3,369
939
0.01
(1,052)
(0.02)
(474)
(0.01)
$ 2,410 $
2,218
0.03
(1,804)
(0.03)
(1,936)
(0.03)
2,048
506
114
-
525
472
180
2
504
(74)
(136)
(36)
(50)
N/A
(22)
15
(36)
(58)
(67)
(42)
(33)
(76)
33
18
7
(37)
(100)
4
246
28
274
68
$ 15,669
$ 19,822
1,057
981
6.7
6,247
1,334
-
6.7
5,290
$ 9,256
$ 13,198
4,589
0.07
(3,172)
(0.05)
(6,052)
(0.09)
13,463
452
164
1
480
$
$
8,183
0.13
150
-
23
-
16,647
433
201
2
468
$ 71.53 $ 116.24
(39)
$ 89.43
$ 115.94
15.18
4.28
36.57
-
8.97
32.99
$ 45.86 $ 74.28
-
(52)
11
(38)
5.09
6.03
35.65
-
7.80
30.94
$ 52.84
$ 77.20
(21)
(10)
(59)
(21)
(21)
N/A
-
18
(37)
(43)
(46)
N/A
-
N/A
N/A
(19)
4
(18)
(50)
3
(23)
-
(23)
15
(32)
(1) Operating netback is a non-IFRS measure. Netback per boe is calculated by dividing the revenue and costs in total for the
Company by the total production of the Company measured in boe.
(2) Funds from operations is a non-IFRS measure. The comparable IFRS measure is cash from operations. A reconciliation of
the two measures can be found in the table on page 6.
(3) Adjusted net earnings is a non-IFRS measure. The comparable IFRS measure is net income. A reconciliation of the two
measures can be found in the table on page 7.
BENGAL ENERGY LTD.
Basis of Presentation
This MD&A and accompanying financial statements and notes are for the twelve months ended March 31,
2015 and 2014. The terms “current quarter” and “the quarter” are used throughout the MD&A and in all
cases refer to the period from January 1, 2015 through March 31, 2015. The terms “prior year’s quarter”
and “2014 quarter” are used throughout the MD&A for comparative purposes and refer to the period from
January 1, 2014 through March 31, 2014.
The fiscal year for the Company is the twelve-month period ended March 31, 2015. The terms “fiscal 2015,”
“current year” and “the year” are used in the MD&A and in all cases refer to the period from April 1, 2014
through March 31, 2015. The terms “previous year,” “prior year” and “fiscal 2014” are used in the MD&A for
comparative purposes and refer to the period from April 1, 2013 through March 31, 2014. The term YTD
means year-to-date.
For the purpose of calculating unit costs, natural gas volumes have been converted to barrels of oil
equivalent (“boe”) using a conversion ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel
(“bbl”) of oil. This conversion ratio of 6:1 is based on an energy equivalency conversion for the individual
products, primarily at the burner tip, and is not intended to represent a value equivalency at the wellhead.
Such disclosure of boe may be misleading, particularly if used in isolation.
The following abbreviations are used in this MD&A: boepd means barrels of oil equivalent per day; bpd
means barrels per day; mcfd means thousand cubic feet of natural gas per day; $/boe means Canadian
dollars per boe; and NGL means natural gas liquids.
Non-IFRS Measurements
Bengal uses measurements primarily based on IFRS as issued by the IASB and also certain secondary
non-IFRS measurements commonly used in the oil and gas industry. The non-IFRS measurements
included in this Management’s Discussion and Analysis are funds from operations, funds from operations
per share, adjusted net earnings, adjusted net earnings per share and operating netbacks which do not
have any standardized meaning under IFRS and are referred to as non-IFRS measures.
Operating netbacks assists management and investors to evaluate the specific operating performance of
the Company by product and is equal to total revenue less royalties and operating and transportation
expenses calculated on a boe basis. Management utilizes these measures to analyze operating
performance. Funds from operations is not intended to represent operating profit for the period nor should it
be viewed as an alternative to operating profit, net income, cash from operations or other measures of
financial performance calculated in accordance with IFRS. Total boe is calculated by multiplying the daily
production by the number of days in the period.
Funds from operations is a non-IFRS measure, which should not be considered an alternative to “Net cash
from operating activities” and is comprised of cash from operating activities as presented in the
consolidated statement of cash flows adding changes in non-cash working capital and the settlement of
decommissioning liabilities. Funds from operations, commonly referred to as cash flow by research
analysts, is used to value and compare oil and gas companies and is frequently included in published
research when providing investment recommendations and is presented in the Company’s’ financial reports
to assist management and investors in analyzing the Company’s operating performance. Funds from
operations per share is calculated based on the weighted average number of common shares outstanding
consistent with the calculation of net income (loss) per share.
8
Bengal Energy Ltd.
2015 Annual Report
The following table reconciles cash flow from operations to funds flow from operations, which is used in the
MD&A:
Three Months Ended
March 31
Twelve Months Ended
March 31
$000s
Cash flow from (used in) operating
activities
Changes in non-cash working capital
Funds from (used in) operations
2015
1,031
(92)
939
2014 % Change
2,106
112
2,218
(51)
(182)
(58)
2015
6,921
(2,332)
4,589
2014 % Change
7,591
592
8,183
(9)
(494)
(43)
Adjusted net earnings is a non-IFRS measure, which should not be considered an alternative to “Net (loss)
income” as presented in the consolidated statement of (loss) / income and comprehensive (loss)/ income 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 (loss) income less unrealized losses/gains on foreign exchange and unrealized losses/gains on
financial instruments. Adjusted net earnings per share is calculated based on the weighted average number
of common shares outstanding consistent with the calculation of net income (loss) per share.
The following table reconciles net (loss) income to adjusted net (loss) earnings, which is used in the MD&A:
$000s
Net (loss) income
Unrealized gain on financial instruments
Unrealized foreign exchange loss
Adjusted net earnings
Three Months Ended
Twelve Months Ended
2015
2014
(1,052)
(1,804)
(440)
1,018
(474)
-
(132)
(1,936)
March 31
%
Change
(42)
N/A
871
76
2015
2014
(3,172)
(4,962)
2,082
(6,052)
150
-
(127)
23
March 31
%
Change
(2,215)
N/A
507
N/A
RESULTS OF OPERATONS - AUSTRALLIA
Production, Commodity Pricing and Sales
The following table outlines Bengal’s production volumes for the periods indicated:
Oil Production (bopd)
($000s)
Oil Sales
Realized gain on financial
instrument
Royalties
Operating expenses
Operating netback ($000s)
Oil Sales ($/bbl)
Realized gain on financial
Instrument
Royalties ($/bbl)
Operating expenses ($/bbl)
Operating netback ($/bbl)
Three Months Ended
Twelve Months Ended
2015
506
March 31
2014 % Change
472
7
2015
452
March 31
2014 % Change
433
4
3,359
5,174
(35)
15,395
19,480
717
201
1,683
2,192
-
396
1,422
3,356
73.08
121.68
15.75
4.42
36.98
48.15
-
9.31
33.44
78.93
-
(49)
18
(35)
(39)
-
(53)
11
(59)
891
1,026
6,014
9,246
-
1,305
5,049
13,126
93.40
123.31
5.41
6.22
36.49
56.10
-
8.26
31.96
83.09
(21)
-
(21)
19
(30)
(24)
-
(25)
14
(32)
BENGAL ENERGY LTD.
Production
Production gains for both the year and quarter ended March 31, 2015 are the result of four successful
development wells drilled as part of the 2014 phase 1 drilling campaign which were brought online during
August and September 2014 adding an incremental 325 bopd of production net to Bengal during Q4 2015.
These production additions were partially offset by natural declines as well as continued production
disruptions at the Cuisinier 6 well, which has been producing close to 100% water since May 2014. The
operator completed a work over operation in May 2015 by setting a bridge plug to isolate a potential water
source below the Murta formation and the well’s potential productivity is being evaluated over the next few
months.
Pricing
The price received for Bengal’s Australian oil sales is based on Dated Brent quotes as published by Platts
Crude Oil Marketwire for the month in which the Bill of Lading occurs plus a Platts Tapis premium. Brent
typically has traded at a premium to West Texas Intermediate (WTI) and the Platts Tapis premium received
has averaged USD $3.44/bbl over Brent for the twelve months ended March 31, 2015 (2014 – USD $6.34).
Realized crude oil prices decreased by 24% for the year and 39% for the quarter ended March 31, 2015
relative to the prior year and quarter due to a respective 20% and 50% decrease in Benchmarked Brent
crude prices. The Company’s oil sales are based on a premium to Brent benchmark pricing denominated in
US dollars, therefore the depreciation in the value of the Canadian dollar relative to the US dollar has
partially offset the effect of decreased Brent pricing during Q4 2015.
The following table outlines average benchmark prices compared to Bengal’s realized prices:
Prices and Marketing
Three Months Ended
March 31
Twelve Months Ended
March 31
Average Benchmark Price
2015
2014 % Change
2015
2014 % Change
Bengal realized crude oil price
before realized gain on
financial instruments
($CAD/bbl)
Realized gain on financial
instrument ($CAD/bbl)
Bengal realized crude oil price
including realized gain on
financial instruments
($CAD/bbl)
$ 73.80
121.68
(39)
$ 93.40 $
123.31
15.75
-
N/A
5.41
-
89.55
121.68
Dated Brent oil ($CAD/bbl)
66.83
118.81
Dated Brent oil ($US/bbl)
53.97
108.14
Number of CAD$ for 1 AUS$
0.97
Number of CAD$ for 1 US$
1.24
0.99
1.10
Risk Management Activities
(26)
(44)
(50)
(2)
13
98.81
123.31
97.31
112.92
85.43
107.54
0.99
1.14
0.98
1.05
Bengal has entered into financial commodity contracts as part of its risk management program to manage
commodity price fluctuations related to its primary producing assets being the Cuisinier field in Australia’s
Cooper Basin.
With respect to financial contracts, which are derivative financial instruments, management has elected not
to use hedge accounting and consequently records the fair value of its crude oil financial contracts on the
10
(24)
N/A
(20)
(14)
(21)
1
9
Bengal Energy Ltd.
2015 Annual Report
statement of financial position at each reporting period with the change in fair value being classified as
unrealized gains and losses in the consolidated statement of income.
The company has managed the price application to production volumes through the following contracts:
Time Period
Type of Contract
Quantity
Apr 1, 2015 – May 31, 2017
Apr 1, 2015 – May 31, 2017
Oil - Swap
Oil – Put option
Contracted (bbls)
130,252
106,569
Price Floor
(US$/bbl)
80.00
80.00
Price Ceiling
(US$/bbl)
80.00
-
The fair value of the financial contracts outstanding as at March 31, 2015 is an estimated asset of $5.0
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 and twelve months ended March 31, 2015, the derivative commodity contracts resulted in
realized gains of $0.7 million (2014 – $nil) and $0.9 million (2014 - $nil) and unrealized gains of $0.5 million
(2014 - $nil) and $5.0 million (2014 - $nil).
Royalties
Royalties ($000s)
Royalty Expense
$/bbl
% of revenue
Three Months Ended
Twelve Months Ended
March 31
March 31
2015
2014 % Change
201
4.42
6
396
8.26
8
(49)
(53)
(25)
2015
1,026
6.22
7
2014
% Change
1,305
8.73
7
(21)
(29)
-
In Australia, oil royalties are based on a government-established rate of 10% plus a Native Title royalty
which is typically 1%. The royalty rate is applied to gross revenues after deducting an allowance for
transportation and operating costs resulting in an effective rate of less than 10%.
Royalties have decreased as a percentage of revenue for Q4 2015 compared to Q4 2014 primarily due to
an increase in allowable transportation expenditures claimed by the operator. For the year ended March
31, 2015 compared to the prior year, royalties have remained consistent as a percentage of revenue.
Operating & Transportation Expenses
Operating & trans.
expenses ($000s)
Operating
Transportation
Operating - $/bbl
Transp. - $/bbl
Three Months Ended
Twelve Months Ended
2015
303
1,380
1,683
6.66
30.32
36.98
March 31
2014 % Change
287
1,135
1,422
6.75
26.69
33.44
6
22
18
(1)
14
11
2015
1,050
4,964
6,014
6.37
30.12
36.49
March 31
2014 % Change
965
4,084
5,049
6.11
25.85
31.96
9
22
19
4
17
14
BENGAL ENERGY LTD.
The increase in operating and transportation costs for the current year and quarter were due primarily to
increased production volumes as operating costs per barrel have remained consistent when compared to
the prior year and quarter ended March 31, 2014.
Transportation costs on a boe basis have increased from prior quarter and year ended March 31, 2015 due
to commissioning of the Cuisinier to Cook pipeline and subsequent connection of this line to the Cook
facility and the Cook to Merrimelia pipeline. This pipeline was used to transport more than 98% of produced
volumes for both the quarter and year ended March 31, 2015. These pipeline costs are marginally higher
than trucking costs; however connecting Cuisinier oil from wellhead to tanker has increased deliverability.
RESULTS OF OPERATONS - CANADA
Canadian Operating Results
Three Months Ended
Twelve Months Ended
Natural Gas Sales ($000s)
Production(mcf/d)
Realized commodity prices ($/mcf)
NGL Sales ($000s)
Production(bbl/d)
Realized commodity prices ($/bbl)
Royalties ($000s)
($/boe)
Operating expenses ($000s)
($/boe)
Operating Netback ($000s)
($/boe)
2015
23
114
2.23
-
-
N/A
1
0.58
44
25.73
(26)
(15.20)
March 31
March 31
2014 % Change
2015
2014 % Change
87
180
5.38
11
2
79.14
11
2.21
71
18.56
16
5.56
(74)
(37)
(59)
N/A
N/A
N/A
(91)
(74)
(38)
39
(263)
(373)
246
164
4.10
28
1
70.89
31
2.98
233
22.42
10
0.96
274
201
3.74
68
2
87.29
29
3.82
241
26.13
72
5.48
(10)
(18)
10
(59)
(50)
(19)
7
34
(3)
21
(86)
(83)
Canadian operations are comprised entirely of the Company’s non-operated Oak natural gas field in British
Columbia. This asset is considered non-core and therefore no significant expenditures were allocated to
the Oak field in fiscal 2015, however decrease benchmark natural gas prices resulted in decreased
profitability for the asset.
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
$/boe
Expensed share-based compensation
Capitalized share-based compensation
Total share-based compensation
March 31
March 31
2015
901
83
984
20.84
23
4
27
2014 % Change
(25)
1,197
(36)
130
1,327
31.21
90
28
118
(26)
(33)
(74)
(86)
(77)
2015
3,407
373
3,780
22.93
170
40
210
2014 % Change
(11)
(11)
3,822
421
4,243
24.82
498
152
650
(11)
(8)
(66)
(74)
(68)
The 11% decrease in total cash G&A expenditures for the year reflects management’s ongoing efforts to
reduce discretionary spending and the elimination of certain one-time severance expenditures. These
targeted efforts to reduce G&A costs are fully reflected in the current quarter’s total cash G&A which has
decreased by 26% compared to Q4 2014.
Bengal accounts for its share-based compensation plan using the fair value method. Under this method,
each grant results in three instalments. The fair value of the first instalment is charged to profit or loss
immediately. The remaining two instalments are charged to profit or loss over their respective vesting period
12
Bengal Energy Ltd.
2015 Annual Report
of one and two years respectively. For options that vest one-third each year after the first year anniversary,
the fair value of the options are charged to profit and loss over the three year vesting period. Stock options
granted under the plan can be exercised on a cashless basis, whereby the employee receives a lesser
amount of shares in lieu of paying the exercise price based on the deemed market price of the shares on
the exercise date, and withholding taxes if the employee so elects.
Depletion and Depreciation (DD&A)
DD&A Expenses
($000s)
Three Months Ended
March 31
Twelve Months Ended
March 31
PNG – Australia
PNG – Canada
Subtotal
Rig - Canada
Total
$/boe – PNG Australia
$/boe – PNG Canada
$/boe – Total PNG
2015
1,161
150
1,311
-
1,311
25.51
87.72
27.76
2014 % Change
2015
2014 % Change
1,253
21
1,274
-
1,274
29.47
7.42
28.09
(7)
614
3
-
3
(13)
1,082
(1)
4,623
413
5,036
330
5,162
28.05
53.86
29.46
4,434
97
4,531
-
4,531
28.07
7.47
26.50
4
115
9
-
15
-
594
11
Depletion per boe in Australia has remained consistent with the prior year and quarter ended March 31,
2015 as significant increases to proved plus probable reserve volumes were complemented by a
corresponding increase to expected future development costs.
The drilling rig is fully impaired; therefore there is no depreciation charge.
Impairment
Impairment
($000s)
Total
Three Months Ended
March 31
Twelve Months Ended
March 31
2015
-
2014 % Change
2,111
N/A
2015
4,762
2014 % Change
3,101
54
As at December 31, 2014, the Company recognized the significant decrease in market crude prices and the
excess of drilling rigs in the local and international market as an indicator of impairment for its drilling rig.
The Company evaluated current drilling activity and rig sale activity both locally in Australia and
internationally to determine that under current market conditions its drilling rig should be fully impaired at
December 31, 2014.
During June 2014, the Koki-1 exploration well was drilled to a vertical depth of 2,573 meters and did not
encounter the targeted Murta DC70 reservoir. Its secondary target indicated minor, non-commercial oil
shows and it was agreed to suspend and abandon this well. Based on these results, the Company has
recorded an impairment charge of $0.8 million equal to its share of drilling costs associated with this well.
During December 2014, Bengal drilled the Wicho East exploration well primarily targeting the deeper
Jurassic Hutton horizon. This well failed to intersect a commercial hydrocarbon accumulation and was
plugged and abandoned during the quarter. Based on these results, the Company has recorded an
impairment charge of $0.8 million equal to its share of drilling costs associated with this well.
BENGAL ENERGY LTD.
Finance Income/Expenses
Finance Expenses ($000s)
Interest income
Accretion expense on
decommissioning liabilities
Accretion expense on notes payable
Change in fair value of VARs
Fee on bank guarantee
Letter of credit charges
Interest and prepayment penalties
on notes payable & credit facility
Finance expenses
Three Months Ended
March 31
2014 % Change
-
5
2015
18
2015
5
Twelve Months Ended
March 31
% Change
2014
74
(76)
(4)
-
7
(55)
(32)
(342)
(421)
(19)
(51)
64
(72)
-
(219)
(292)
(79)
(100)
(89)
(41)
N/A
(15)
(507)
58
(55)
(32)
56
44
(1,212)
(1,745)
(8)
(216)
123
(72)
-
(756)
(855)
88
135
(53)
(41)
N/A
60
104
The Performance Security Guarantee fee is paid to Export Development Canada and ICICI Bank of India
for security guarantee for onshore India work programs, to be cancelled on completion or relinquishment.
The increased fee is a result of the budgeted 2015 work program.
Interest expenses are comprised of $0.7 million of interest and prepayment penalties on notes payable,
$0.3 million of interest on the Company’s credit facility, and $0.2 million related to non-cash accretion of
debt instruments. The Company paid a 3% penalty on the remaining $7.5 million outstanding in addition to
interest otherwise accrued on its July 2014 $8.0 million notes payable.
CAPITAL EXPENDITURES
Capital Expenditures ($000s)
Three Months Ended
Twelve Months Ended
Geological and geophysical
Drilling
Rig
Completions
Cuisinier working interest purchase
Total oil & gas expenditures
Office
Total expenditures
Exploration & evaluation
expenditures
Development & production
expenditures
Property, plant & equipment
Total net expenditures
March 31
March 31
2014 % Change
2015
2014 % Change
708
389
371
376
204
2,048
-
2,048
(55)
345
(100)
(5)
(100)
18
-
18
1,276
8,458
-
3,729
-
13,463
-
13,463
3,137
2,601
371
3,574
6,964
16,647
-
16,647
(59)
225
(100)
4
(100)
(19)
-
(19)
2015
320
1,732
-
358
-
2,410
-
2,410
267
672
(60)
3,189
1,963
63
2,143
-
2,410
1,005
371
2,048
113
(100)
18
10,247
-
13,463
14,313
371
16,647
(28)
(100)
(19)
During the year, the Company drilled, completed and tied in all wells from its 2014 phase 1 drilling program,
as well as completed drilling and most completion work associated with the 2014 phase 2 drilling program.
These successful well costs, as well as the drilling costs associated with two unsuccessful exploration wells
(Koki, Wicho East) and one successful exploration well (Nubba-1) accounts for all drilling and completion
costs incurred during the quarter and year ended March 31, 2015.
Geological and geophysical costs relate primarily to the ongoing review and interpretation of seismic studies
on the ATP 752 exploration permit supporting exploration drilling in Barta and Wompi.
14
Bengal Energy Ltd.
2015 Annual Report
NOTES PAYABLE & CREDIT FACILITY
On January 24, 2014, $1.75 million of convertible notes set to expire on January 25, 2014 were extended to
January 24, 2015. These notes were redeemed on January 21, 2015 for a redemption price of $2.0 million
including principal and accrued and unpaid interest. Approximately $0.8 million of the aggregate was paid in
cash, and certain holders of the remaining $0.9 million of aggregate principal received the redemption price
through the issuance of common shares of the Company at a price of $0.28 per common share in lieu of
cash.
In October 5, 2014, the Company repaid $500,000 of outstanding principal of its $8.0 million notes issued
July 5, 2013. In November 2014, the Company redeemed the remaining principal of $7,500,000 for an early
redemption price equal to $1.03 per $1.00 (booked as interest expense) of outstanding principal amount
plus all accrued and unpaid interest thereon.
In October 2014, Bengal closed its US $25 million secured credit facility with Westpac Institutional Bank and
placed an initial draw on November 12, 2014 of US $14.0 million. The facility is secured by the Company’s
producing assets in the Cuisinier field in Australia’s Cooper Basin, has a three-year term and carries an
interest rate of US Libor plus 3.2% to 3.5% depending on certain reserve forecast parameters. Current
interest rate is 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. Calculation dates
commence December 31, 2015 and occur every six months thereafter until June 30, 2017 with a nominal
reduction of $6.25 million to the facility limit at each calculation date based on the Company’s existing
reserve profile. The facility limit at March 31, 2015 is US $25 million.
The credit facility’s covenants extend only to the Company’s ability to secure its debt as a percentage of
reserve forecasts to be evaluated at each calculation date. There are no financial covenants associated
with this credit facility.
SHARE CAPITAL
Bengal has an unlimited number of common shares authorized for issuance. At June 13, 2015, there were
68,177,796 common shares issued and outstanding, 3,495,000 employee stock options outstanding,
703,125 warrants outstanding and 546,875 VARs outstanding.
Trading History
Three Months Ended
Twelve Months Ended
March 31
March 31
2015
2014 % Change
2015
2014 % Change
High
Low
Close
Volume (000s)
Shares outstanding (000s)
Weighted average shares
outstanding (000s)
Basic
Diluted
$ 0.32
$ 0.18
$ 0.19
2,759
$
$
$
0.62
0.40
0.48
6,621
(48)
(55)
(60)
(58)
$ 0.76
$ 0.18
$ 0.19
11,611
0.79
$ 0.40
$ 0.48
10,323
68,178
64,667
5
68,178
64,667
67,364
67,364
64,446
64,446
5
5
65,349
65,349
63,134
63,209
(4)
(55)
(60)
12
5
4
3
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2015 the Company had $5.2 million of working capital, including cash and short-term deposits
of $1.7 million and restricted cash of $0.1 million, compared to working capital of $3.1 million, including cash
and short term deposits of $6.0 million and restricted cash of $0.1 million at March 31, 2014.
BENGAL ENERGY LTD.
In October 2014, Bengal closed its US $25 million secured credit facility with Westpac Institutional Bank and
placed an initial draw on November 12, 2014 of US $14.0 million. The facility is secured by and available
for the Company’s producing assets in the Cuisinier field in Australia’s Cooper Basin, has a three-year term
and carries an interest rate of US Libor plus 3.2% to 3.5% depending on certain reserve forecast
parameters. In the year ended March 31, 2015, $0.3 million has been charged to financing expenses
related to interest on the credit facility.
The credit facility is structured as a reserves based revolving facility under a predetermined reduction
schedule, to be evaluated based on existing reserves at each calculation date. Calculation dates
commence December 31, 2015 and occur every six months thereafter until June 30, 2017 with a nominal
reduction of $6.25 million to the facility limit at each calculation date based on the Company’s existing
reserve profile.
The credit facility’s covenants extend only to the Company’s ability to secure its debt as a percentage of
reserve forecasts to be evaluated at each calculation date.
Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including work
commitments, as they are due. The Company’s existing cash and cash equivalents and operating cash
flows supplemented by funds undrawn funds on its US $25 million credit facility available for use in the
Cuisinier field are expected to be sufficient to meet all of its working capital requirements for at least the
next twelve months and its commitments under its capital program (see Commitments below).
The Company expects cash generation to increase throughout the coming year as production from
Cuisinier ramps up, although predicting future events, some of which are beyond the Company’s control,
carries uncertainty.
COMMITMENTS
Pursuant to current production sharing contracts (“PSC”), the Company is required to perform minimum
exploration activities in its Indian permits that include various types of surveys, acquisition and processing
of seismic data and drilling of exploration wells. Additional commitments are reflected where the Company
has agreed with joint venture partners to proceed with activities (e.g. onshore Australia ATP 752 Cuisinier).
The costs of these activities are based on minimum work budgets included in bid documents and
agreements among joint venture parties, and have not been provided for in the financial statements. Actual
costs will vary from budget.
Country and Permit
Work Program
Obligation Period
Ending
Estimated Expenditure
(net) (millions CAD$)(1)
Onshore India – CY-ONN-
2005/1
3 wells
Currently under Force
Majeure(2)
$ 5.3
(1) Translated at March 31, 2015 at an exchange rate of US $1.0000 = CAD $1.2642
(2)
If the Company did not participate in the drilling of 3 wells, costs of $5.2 million would be impaired and the Company’s
interest in the permit would decline.
GUARANTEES – INDIA PERMITS
($000s) CAD
CY-OSN-2005/1 – Onshore India
CY-OSN-2009/1 – Offshore India
Total Guarantees
Year Ended
March 31, 2015
914
-
914
Year ended
March 31, 2014
1,570
166
$ 1,736
These performance guarantees are based on a percentage of the capital commitments shown in the table
above and are not reflected in the statement of financial position as they are secured by Export
16
Bengal Energy Ltd.
2015 Annual Report
Development Canada. These guarantees are cancelled when the Company completes the work program
commitment required for the applicable exploration period.
OTHER
At March 31, 2015, the contractual obligations for which the Company is responsible are as follows:
Contractual Obligations ($000s)
Office lease
Decommissioning obligations
Total
595
1,454
Less than
1 Year
263
-
$
1-3
Years
332
56
4-5
Years
-
116
After
5 Years
$ −
1,282
$
$
$
Total contractual obligations
$
2,049
$
263
$
388
$
116
$ 1,282
CONTINGENCIES
Effective March 1, 2015 ATP 934 has been granted for a period of 12 years comprised of 3, 4 year terms. In
the first four year work program Bengal is committed to capital spending of approximately $22.6 million
dollars (net $11.3 million) dedicated to acquisition of new 2D and 3D seismic as well as drilling of up to 8
new wells. Bengal has made application to the Queensland Government for a smaller work program to
reflect geographical conditions that may preclude surface access to parts of ATP 934.
Country and Permit
Work Program
Obligation Period
Ending
Estimated Expenditure
(net) (millions CAD$)
Onshore Australia –
ATP 934P
Awaiting Ministerial approval before
granting of ATP
4 years after grant of ATP
$ 11.3
RELATED PARTY TRANSACTIONS
On July 5, 2013, the Company issued $8.0 million of 10% non-convertible notes with warrants or value
appreciation rights. Members of the Board of Directors of the Company subscribed for approximately 44%
of the principal amount of the notes issued pursuant to the private placement. In October 2014, the
Company repaid $500,000 of outstanding principal of notes issued July 5, 2013 (“Notes”). In November
2014, the Company redeemed the remaining Notes for a redemption price equal to $1.03 per $1.00 of
outstanding principal amount plus all accrued and unpaid interest thereon.
On January 24, 2014 the Company extended its $1.75 million notes payable to January 23, 2015. Members
of the Board of Directors of the Company held 100% of this facility.
On January 21, 2015, the Company repaid the $1.75 million notes payable, together with accrued interest.
Two directors were issued 3,485,714 shares of the Company valued at $0.28 per share in lieu of a cash
settlement of $976,000.
SUBSEQUENT EVENTS
Effective April 1, 2015 Bengal acquired an additional 30% working interest in ATP 934 from one of its Joint
Venture partners for a total acquisition price of $0.1 million. This acquisition is subject to ministerial
approval. The remaining joint venture partner, effective June 19, 2015 exercised its option to purchase
8.6% of this interest; therefore Bengal’s current working interest is 71.4%.
BENGAL ENERGY LTD.
OFF BALANCE SHEET TRANSACTIONS
The Company does not have any off balance sheet transactions.
SELECTED ANNUAL FINANCIAL INFORMATION
($000s except per share data and prices)
Year Ended March 31
Total production volumes (boepd)
Natural gas prices ($/mcf)
Oil and liquids prices ($/boe)
Total production revenue
Net income (loss)
Per share – basic and diluted
Cash from operations
Funds from operations (1)
Per share – basic and diluted
Balance drawn on credit facility
Notes payable – long term
Total assets
Working capital (deficiency)(2)
2015
480
4.10
93.35
15,669
(3,172)
(0.05)
6,921
4,589
0.07
16,982
-
65,679
5,221
2014
468
3.74
123.13
19,822
150
0.00
7,591
8,183
0.13
-
6,085
62,425
3,104
2013
170
2.61
112.01
5,885
(1,799)
(0.03)
(703)
1,099
0.02
-
-
49.143
(1,647)
(1) See “Non-IFRS Measurements” on page 6 of this MD&A.
(2) Calculated as current assets minus current liabilities.
SELECTED QUARTERLY INFORMATION
(000s, except per share amounts)
Mar 31
2015
Dec. 31
2014
Sep. 30
2014
Jun. 30
2014
Mar 31
2014
Dec. 31
2013
Sep. 30
2013
Jun. 30
2013
Petroleum and
natural gas sales
$ 3,378
$3,944
$4,458
$3,889
$ 5,272
$ 5,516
$ 5,312
$ 3,722
Cash from
(used in)
operations
Funds from (used in)
operations(1)
Per share
Basic and diluted
Net (loss) income
Per share
Basic and diluted
Capital expenditures
Working capital
(deficiency)
Total assets
Shares outstanding
Basic and diluted
Operations
Average daily
production
Natural gas (mcfd)
Oil and NGLs
(bbls/d)
Combined (boepd)
1,031
1,144
2,232
2,219
2,106
2,170
2,066
1,249
939
1,318
1,459
926
2,218
2,862
2,063
1,732
0.01
$(1,052)
0.02
$(1,293)
0.02
$(98)
0.01
$(729)
0.03
$(1,804)
0.04
$ 573
0.03
$ 545
0.03
$ 836
(0.02)
2,410
5,221
65,679
(0.02)
$4,489
4,931
66,229
0.00
$2,909
$(0.01)
$3,655
(0.03)
$ 2,048
0.01
$ 6,462
0.01
$ 2,702
0.01
5,435
(1,705)
60,385
(88)
60,216
3,104
62,425
3,590
61,353
7,737
62,361
(279)
54,556
68,178
64,692
64,692
64,692
64,446
64,315
64,315
61,611
114
506
525
181
548
578
169
429
457
194
329
361
180
474
504
184
465
496
200
485
518
240
316
356
Netback ($/boe)
45.86
$36.79
$65.05
$73.15
$ 74.28
$ 83.13
$ 72.51
$ 79.82
18
Bengal Energy Ltd.
2015 Annual Report
(1) See “Non-IFRS Measurements” on page 7 of this MD&A. The bottom line of this table pops out showing a hefty decline in
netback from the December quarter perhaps we should explain this in the text.
Oil volumes increased through the first three quarters of fiscal 2015 as wells from the Cuisinier 2014 phase
1 development program came on stream. By the fourth quarter of 2015, natural declines decreased
production volumes compared to the prior quarter.
Netbacks and associated operating results decreased in the third and fourth quarter of fiscal 2015 due to a
significant decrease in benchmark crude oil prices.
FINANCIAL INSTRUMENTS
Financial instruments comprise cash, restricted cash and short term deposits, accounts receivable and
accounts payable and accrued liabilities and debt. The fair values of these financial instruments
approximate their carrying amounts due to their short-term maturities.
The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange
rates and interest rates in the normal course of operations. A variety of derivative instruments may be used
by the Company to reduce its exposure to fluctuations in commodity prices, foreign exchange rates and
interest rates. The Company does not use derivative instruments at this time.
Financial assets and liabilities are classified as either financial assets or liabilities at fair value through profit
and loss (“FVTPL”), loans and receivables, held to maturity investments, available for sale financial assets,
or other liabilities, as appropriate. Financial assets and liabilities are recognized initially at fair value.
Subsequent measurement of financial instruments is based on their initial classification. FVTPL financial
assets and liabilities are measured at fair value and changes in fair value are recognized in profit or loss.
Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in
other comprehensive loss until the instrument is derecognized or impaired. The remaining categories of
financial instruments are recognized at amortized cost using the effective interest rate method.
The transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial
liability classified as FVTPL are expensed immediately. For a financial asset or financial liability carried at
amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added
to or deducted from the fair value on initial recognition and amortized through profit or loss income over the
term of the financial instrument.
(i) Non-derivative financial instruments
Cash and cash equivalents, restricted cash as well as accounts receivable are classified as loans and
receivables, which are measured at amortized cost. Accounts payable and accrued liabilities, notes payable
and the credit facility are classified as other financial liabilities, which are measured at amortized cost.
(ii) Derivative financial instruments
The Company enters into certain financial derivative contracts in order to manage the exposure to market
risks from fluctuations in commodity prices. These instruments are not used for trading or speculative
purposes. The Company does not designate its financial derivative contracts as effective accounting
hedges and therefore will not apply hedge accounting, even though the Company considers all commodity
contracts to be economic hedges. As a result, all derivative contracts are classified as FVTPL and are
recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or
loss when incurred. Subsequent to initial recognition, derivatives are measured at fair value, and changes
therein will be recognized immediately in profit or loss.
The Company may enter into physical delivery sales contracts for the purposes of receipt or delivery of
nonfinancial items in accordance with its expected purchase, sale or usage requirements as executory
BENGAL ENERGY LTD.
contracts. As such, these contracts are not considered to be derivative financial instruments and will not be
recorded at fair value on the statement of financial position. Settlements on these physical delivery
contracts will be recognized in petroleum and natural gas revenue in the period of settlement.
Fair value
The fair value of financial instruments that are actively traded in organized financial markets is determined
by reference to quoted market bid prices at the valuation date. For financial instruments that have no active
market, fair value is determined using valuation techniques including the use of recent arm’s length market
transactions, reference to the current market value of equivalent financial instruments and discounted cash
flow analysis.
Share capital
Common shares are classified as equity. Incremental costs directly attributable to the issue of common
shares and stock options are recognized as a deduction from equity, net of any tax effects
DISCLOSURE CONTROLS & PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL
REPORTING (ICFR)
Disclosure Controls and Procedures
Disclosure controls and procedures are designed to provide reasonable assurance that information required
to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it
under securities legislation is recorded, processed, summarized and reported within the time periods
specified in the securities legislation and includes controls and procedures designed to ensure that
information required to be disclosed by the Company in its annual filings, interim filings or other reports filed
or submitted under securities legislation is accumulated and communicated to the Company’s management,
including its certifying officers, as appropriate to allow timely decisions regarding required disclosure.
The Chief Executive Officer and Chief Financial Officer oversee this evaluation process and have
concluded that the design and operation of these disclosure controls and procedures are not effective due
to the material weaknesses identified in internal controls over financial reporting as noted below. The Chief
Executive Officer and Chief Financial Officer have individually signed certifications to this effect.
Internal Controls over Financial Reporting
The Chief Executive Officer and Chief Financial Officer of Bengal are responsible for designing and
ensuring the operating effectiveness of internal controls over financial reporting (“ICFR”) or causing them to
be designed and operating effectively under their supervision in order to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with IFRS. Bengal’s certifying officers have assessed the design and operating
effectiveness of internal controls over financial reporting and concluded that the Company’s ICFR were not
effective at March 31, 2015 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.
20
Bengal Energy Ltd.
2015 Annual Report
During the design and operating effectiveness assessment certain material weaknesses in internal controls
over financial reporting were identified, as follows:
Management is aware that there is a lack of segregation of duties due to the small number of
employees dealing with general and administrative and financial matters. However, management
believes that at this time the potential benefits of adding employees to clearly segregate duties do
not justify the costs;
Bengal does not have full-time in-house personnel to address all complex and non-routine financial
accounting issues and tax matters that may arise. It is not deemed as economically feasible at this
time to have such personnel. Bengal relies on external experts for review and advice on complex
financial accounting issues and for tax planning, tax provision and compilation of corporate tax
returns.
These material weaknesses in internal controls over financial reporting result in a reasonable possibility that
a material misstatement will not be prevented or detected on a timely basis. Management and the Board of
Directors work to mitigate the risk of material misstatement; however, Management and the Board do not
have reasonable assurance that this risk can be reduced to a remote likelihood of a material misstatement.
APPLICATION OF CRITICAL ACCOUNTING ESTIMATES
The timely preparation of the financial statements requires management to make judgments, estimates and
assumptions that affect the application of accounting policies and reported amounts of assets and liabilities
and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and
underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are
recognized in the period in which the estimates are revised and in any future periods affected. Significant
estimates and judgments made by management in the preparation of these financial statements are out-
lined below.
Critical judgments in applying accounting policies
The timely preparation of the financial statements requires management to make judgments, estimates and
assumptions that affect the application of accounting policies and reported amounts of assets and liabilities
and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and
underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are
recognized in the period in which the estimates are revised and in any future periods affected. Significant
estimates and judgments made by management in the preparation of these financial statements are out-
lined below.
Critical judgments in applying accounting policies
The following are the critical judgments, apart from those involving estimations (see below), that
management has made in the process of applying the Company’s accounting policies and that have the
most significant effect on the amounts recognized in these financial statements.
i.
Identification of Cash-generating Units
Bengal’s assets are aggregated into cash-generating units, for the purpose of calculating impairment, based
on their ability to generate largely independent cash flows. By their nature, these estimates and
assumptions are subject to measurement uncertainty and may impact the carrying value of the Company's
assets in future periods.
BENGAL ENERGY LTD.
ii.
Impairment Indicators
Judgments are required to assess when impairment indicators exist and impairment testing is required. The
application of the Company’s accounting policy for exploration and evaluation, petroleum and natural gas
properties and PP&E assets required management to make certain judgments as to future events and
circumstances as to whether economic quantities of reserves have been found.
Key Sources of uncertainty
The following are the key assumptions concerning the sources of estimation uncertainty at the end of the
reporting period that have a significant risk of causing adjustments to the carrying amounts of the assets
and liabilities.
i)
Decommissioning provisions
The Company estimates future remediation costs of production facilities, wells and pipelines at different
stages of development and construction of assets or facilities. In most instances, removal of assets occurs
many years into the future. This requires judgment regarding abandonment date, future environmental and
regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost,
future removal technologies in determining the removal cost and liability-specific discount rates to determine
the present value of these cash flows.
ii)
Impairment of petroleum and natural gas assets
For the purposes of determining whether impairment of petroleum and natural gas assets occurred, and the
extent of any impairment or its reversal, the key assumptions the Company uses in estimating future cash
flows are future petroleum and natural gas prices, expected production volumes and anticipated
recoverable quantities of proved and probable reserves. These assumptions are subject to change as new
information becomes available. Changes in economic conditions can also affect the rate used to discount
future cash flow estimates. Changes in the aforementioned assumptions could affect the carrying amount of
assets, and impairment charges and reversal will affect profit or loss.
iii)
Income taxes
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect
amounts recognized in profit or loss both in the period of change, which would include any impact on
cumulative provisions, and in future periods. Deferred tax assets (if any) are recognized only to the extent it
is considered probable that those assets will be recoverable. This involves an assessment of when those
deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable
profits available to offset the tax assets when they do reverse. This requires assumptions regarding future
profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability
change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets
as well as the amounts recognized in profit or loss in the period which the change occurs.
iv)
Reserves
The estimate of petroleum and natural gas reserves is integral to the calculation of the amount of depletion
charged to the statement of operations and is also a key determinant in assessing whether the carrying
value of any of the Company’s development and production assets has been impaired. Changes in reported
reserves can impact asset carrying values due to changes in expected future cash flows.
The Company’s reserves are evaluated and reported on by independent reserve engineers at least annually
in accordance with Canadian Securities Administrators’ National Instrument 51-101. Reserve estimation is
based on a variety of factors including engineering data, geological and geophysical data, projected future
rates of production, commodity pricing and timing of future expenditures, all of which are subject to
significant judgment and interpretation.
22
Bengal Energy Ltd.
2015 Annual Report
v)
Share-based payments
The Company measures the cost of its share-based payments to directors, officers, employees and certain
consultants by reference to the fair value of the equity instruments at the date at which they are granted.
The assumptions used in determining fair value include: expected lives of options, risk-free rates of return,
share price volatility and the estimated forfeiture rate. Changes to assumptions may have a material impact
on the amounts presented.
NEW ACCOUNTING STANDARDS AND PRONOUNCEMENTS
The following new accounting policies were adopted as at April 1, 2014, both of which were applied
retrospectively:
The IASB issued International Financial Reporting Interpretations Committee Interpretation ("IFRIC") 21,
“Levies” which was adopted by the Company on April 1, 2014. The IFRIC clarifies that an entity should
recognize a liability for a levy when the activity that triggers payment occurs. The adoption of this
interpretation had no impact on the Company's consolidated financial statements.
IAS 32, “Financial Instruments: Presentation”, which clarifies the requirements for offsetting financial assets
and liabilities. The amendments clarify when an entity has a legally enforceable right to offset and certain
other requirements that are necessary to present a net financial asset or liability. There was no impact on
the Company’s consolidated financial statements on adoption of this standard.
New standards and interpretations not yet adopted:
Standards that are issued but not yet effective and that the Company reasonably expects to be applicable
at a future date are listed below.
Accounting for acquisitions of interests in joint operations
In May 2014, the IASB issued amendments to IFRS 11 “Joint Arrangements” to clarify that the acquirer of
an interest in a joint operation in which the activity constitutes a business is required to apply all of the
principles of business combinations accounting in IFRS 3 “Business Combinations”. Prospective application
of this interpretation is effective for annual periods beginning on or after January 1, 2016, with earlier
application permitted. The adoption of this amendment could impact the Company in the event that it
increases or decreases its ownership share in an existing joint operation or invests in a new joint operation.
Sale or contribution of assets between an investor and its associate or joint venture
In September 2014, the IASB issued amendments to address an inconsistency between the requirements
in IFRS 10 “Consolidated Financial Statements” and those in IAS 28 “Investments in Associates and Joint
Ventures” regarding the sale or contribution of assets between an investor and its associate or joint venture.
The amendment clarified that a full gain or loss is recognized when a transaction involves a business. A
partial gain or loss is recognized when a transaction involves assets that do not constitute a business.
Prospective application of this interpretation is effective for annual periods beginning on or after January 1,
2016, with earlier application permitted. The adoption of this amendment could impact the Company in the
event that it has transactions with associates or joint ventures.
Disclosure initiative
In December 2014, the IASB issued narrow-focus amendments to IAS 1 “Presentation of Financial
Statements” to clarify existing requirements relating to materiality, order of notes, subtotals, accounting
policies and disaggregation. Retrospective application of this standard is effective for fiscal years beginning
on or after January 1, 2016, with earlier application permitted. The adoption of this amended standard is not
BENGAL ENERGY LTD.
expected to have a material impact on the Company’s disclosure.
Revenue from contracts with customers
In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers”. It replaces existing
revenue recognition guidance and provides a single, principles-based five-step model to be applied to all
contracts with customers. Retrospective application of this standard was to be effective for fiscal years
beginning on or after January 1, 2017, with earlier application permitted. On May 19, 2015, the IASB
published the expected exposure draft aimed at deferring the effective date of IFRS 15 “Revenue from
Contracts with Customers” to January 1, 2018. The Company is currently assessing the impact of this
standard.
Financial instruments: recognition and measurement
In July 2014, IFRS 9 “Financial Instruments” was issued as a complete standard, including the requirements
previously issued related to classification and measurement of financial assets and liabilities, and additional
amendments to introduce a new expected loss impairment model for financial assets including credit
losses. Retrospective application of this standard with certain exemptions is effective for fiscal years
beginning on or after January 1, 2018, with earlier application permitted. The Company is currently
assessing the impact of this standard.
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
24
Bengal Energy Ltd.
2015 Annual Report
locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations
are identified, Bengal may determine that current markets, terms of acquisition and participation or pricing
conditions make such acquisitions or participations uneconomic.
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that
are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other
costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and
operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of
operations, and various field operating conditions may adversely affect the production from successful
wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of
connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or
other geological and mechanical conditions. While diligent well supervision and effective maintenance
operations can contribute to maximizing production rates over time, production delays and declines from
normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and
cash flow levels to varying degrees.
In addition, oil and gas operations are subject to the risks of exploration, development and production of oil
and natural gas properties, including encountering unexpected formations or pressures, premature declines
of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence
of any of these risks could have a materially adverse effect on future results of operations, liquidity and
financial condition.
Bengal attempts to minimize exploration, development and production risks by utilizing a high-end technical
team with extensive experience and multidisciplinary skill sets to assure the highest probability of success
in its drilling efforts. Bengal’s collaboration of a team of seasoned veterans in the oil and gas business, each
with a unique expertise in the various upstream to downstream technical disciplines of prospect generation
to operations, provides the best assurance of competency, risk management and drilling success. A full
cycle economic model is utilized to evaluate all hydrocarbon prospects. Detailed geological and geophysical
techniques are regularly employed including 3D seismic, petrography, sedimentology, petrophysical log
analysis and regional geological evaluation.
Risks Associated with Foreign Operations
International operations are subject to political, economic and other uncertainties, including, among others,
risk of war, risk of terrorist activities, border disputes, expropriation, renegotiations or modification of
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.
BENGAL ENERGY LTD.
Prices, Markets and Marketing of Crude Oil and Natural Gas
Oil and natural gas are commodities that have prices determined based on world demand, supply and other
factors, all of which are beyond the control of Bengal. World prices for oil and natural gas have fluctuated
widely in recent years. Any material decline in prices could result in a reduction of net production revenue.
Certain wells or other projects may become uneconomic as a result of a decline in world oil prices and
natural gas prices, leading to a reduction in the volume of Bengal’s oil and gas reserves. Bengal might also
elect not to produce from certain wells at lower prices. All of these factors could result in a material
decrease in Bengal’s future net production revenue, causing a reduction in its oil and gas acquisition and
development activities. In addition to establishing markets for its oil and natural gas, Bengal must also
successfully market its oil and natural gas to prospective buyers. The marketability and price of oil and
natural gas which may be acquired or discovered by Bengal will be affected by numerous factors beyond its
control. The ability of Bengal to market its natural gas may depend upon its ability to acquire space on
pipelines which deliver natural gas to commercial markets. Bengal will also likely be affected by
deliverability uncertainties related to the proximity of its reserves to pipelines and processing facilities and
related to operational problems with such pipelines and facilities and extensive government regulation
relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and
many other aspects of the oil and natural gas business.
Substantial Capital Requirements and Liquidity
Bengal’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From
time to time, Bengal may require additional financing in order to carry out its oil and gas acquisition,
exploration and development activities. Failure to obtain such financing on a timely basis could cause
Bengal to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or
terminate its operations. If Bengal’s revenues from its reserves decrease as a result of lower oil and natural
gas prices or otherwise, it will affect Bengal’s ability to expend the necessary capital to replace its reserves
or to maintain its production. If Bengal’s funds from operations are not sufficient to satisfy its capital
expenditure requirements, there can be no assurance that additional debt or equity financing will be
available to meet these requirements or available on terms acceptable to Bengal.
Bengal monitors and updates its cash projection models on a regular basis which assists in the timing
decision of capital expenditures. Farm outs of projects may be arranged if capital constraints are an issue or
if the risk profile dictates that Bengal wishes to hold a lesser working interest position. Equity, if available
and if on favorable terms, may be utilized to help fund Bengal’s capital program.
Health, Safety and Environment
All phases of the oil and natural gas business present environmental risks and hazards and are subject to
environmental regulation pursuant to a variety of federal, provincial and local laws and regulations.
Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases
or emissions of various substances produced in association with oil and natural gas operations. The
legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to
the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant
expenditures and a breach of applicable environmental legislation may result in the imposition of fines and
penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement,
larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of
oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and
third parties and may require the Company to incur costs to remedy such discharge.
26
Bengal Energy Ltd.
Insurance
2015 Annual Report
Bengal’s involvement in the exploration for and development of oil and gas properties may result in the
Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other
hazards. Although Bengal has insurance in accordance with industry standards to address such risks, such
insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In
addition, such risks may not, in all circumstances be insurable or, in certain circumstances, Bengal may
elect not to obtain insurance to deal with specific risks due to the high premiums associated with such
insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to
Bengal. The occurrence of a significant event that Bengal is not fully insured against, or the insolvency of
the insurer of such event, could have a material adverse effect on Bengal’s financial position, results of
operations or prospects.
Competition
Bengal actively competes for reserve acquisitions, exploration leases, licenses and concessions and skilled
industry personnel with a substantial number of other oil and gas companies, many of which have
significantly greater financial and personnel resources than Bengal. Bengal's competitors include major
integrated oil and natural gas companies and numerous other independent oil and natural gas companies
and individual producers and operators.
Bengal’s ability to successfully bid on and acquire additional property rights, to discover reserves, to
participate in drilling opportunities and to identify and enter into commercial arrangements with customers
will be dependent upon developing and maintaining close working relationships with its future industry
partners and joint operators and its ability to select and evaluate suitable properties and to consummate
transactions in a highly competitive environment.
ADDITIONAL INFORMATION
Additional information relating to Bengal is filed on SEDAR and can be viewed at www.sedar.com.
Information can also be obtained by contacting the Company at Bengal Energy Ltd., Suite 1810, 801 6th
Avenue SW., Calgary, Alberta T2P 3W2, by email to info@bengalenergy.ca or by accessing Bengal’s
website at www.bengalenergy.ca.
Forward-looking Statements - Certain statements contained within the Management’s Discussion and Analysis, and
in certain documents incorporated by reference into this document, constitute forward-looking statements. These
statements relate to future events or Bengal’s future performance. All statements other than statements of historical fact
may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of
words such as "seek,” "anticipate,” "budget,” "plan,” "continue,” "estimate,” "expect,” "forecast,” "may,” "will,” "project,”
"predict,” "potential,” "targeting,” "intend,” "could,” "might,” "should,” "believe" and similar expressions. These statements
involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ
materially from those anticipated in such forward-looking statements. Bengal believes the expectations reflected in
those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to
be correct and such forward-looking statements included in, or incorporated by reference into, this MD&A should not be
unduly relied upon.
In particular, this Management’s Discussion and Analysis, and the documents incorporated by reference, contain
forward-looking statements pertaining to the following:
●
●
●
Oil and natural gas production levels;
The size of the oil and natural gas reserves;
Projections of market prices and costs;
BENGAL ENERGY LTD.
●
●
●
●
●
●
●
●
●
●
●
Expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and
development;
Expectations that cash generation to increase throughout the coming year
Treatment under governmental regulatory regimes and tax laws;
Capital expenditures programs and estimates of costs;
Completion of the four development wells is anticipated to run from mid-July through early August 2014, with
the wells expected to be tied in through September 2014.
Funding of working capital requirements, commitments and other planned expenses will be by cash on hand,
cash flows, farm-outs, joint ventures or share issues and funds will be sufficient to meet requirements;
Expectations that cash flow from the new production volumes to begin in the fourth quarter of calendar 2014;
Expectation of the drilling of a exploration at ATP 752 well in calendar Q3 2014;
Obtaining Ministerial Grant of the tenement on ATP 934P in Australia and commencement of exploration
activities;
Expectation that the selection of three drilling locations in India expected to begin drilling in 2015
That Beach Energy will perform the work agreed to under the Farm-out and that further drilling activities on
ATP 732P will occur in the second half of calendar 2014;
That the wells drilled on ATP 752P will be completed and tied-in and that these wells will commence
production and that production from all wells will continue as expected.
With respect to the forward looking statements contained in the MD&A, Bengal has made assumptions regarding: future
commodity prices; the impact of royalty regimes; the timing and the amount of capital expenditures; production of new
and existing wells and the timing of new wells coming on stream; future operating expenses including processing and
gathering fees; the performance characteristics of oil and natural gas properties; the size of oil and natural gas
reserves; the ability to raise capital; the continued availability of undeveloped land and skilled personnel; the ability to
obtain equipment in a timely manner to carry out exploration and development activities; the ability to obtain financing
on acceptable terms; the ability to add production and reserves through exploration and development activities; and the
continued stability of political, regulatory; tax and fiscal regimes in which the Company has operations.
The actual results could differ materially from those anticipated in these forward-looking statements as a result of the
risk factors set forth below and elsewhere in this Management’s Discussion and Analysis:
●
●
●
●
●
●
●
●
●
●
Volatility in market prices for oil and natural gas;
Liabilities inherent in oil and natural gas operations;
Uncertainties associated with estimating oil and natural gas reserves;
Competition
for, among other
things: capital, acquisitions of
reserves, undeveloped
lands and
skilled personnel;
Incorrect assessment of the value of acquisitions;
Unable to meet commitments due to inability to raise funds or complete farm-outs;
Geological, technical, drilling and processing problems;
Changes in income tax laws or changes to royalty and environmental regulations relating to the oil and
gas industry;
The risk that Bengal may not be successful in raising funds by an equity issue; and
Counter-party credit risk, stock market volatility and market valuation of Bengal’s stock.
Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the
implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be
profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The
forward-looking statements contained in this MD&A and the documents incorporated by reference herein are expressly
qualified by this cautionary statement. The forward-looking statements contained in this document speak only as of the
date of this document and Bengal does not assume any obligation to publicly update or revise them to reflect new
events or circumstances, except as may be required pursuant to applicable securities laws. Additional information on
28
Bengal Energy Ltd.
2015 Annual Report
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.
BENGAL ENERGY LTD.
MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL REPORTING
The accompanying consolidated financial statements are the responsibility of management. The
consolidated financial statements have been prepared by management in accordance with International
Financial Reporting Standards outlined in the notes to the consolidated financial statements. The
consolidated financial statements include certain estimates that reflect the management’s best judgments.
Management has determined such amounts on a reasonable basis in order to ensure that the consolidated
financial statements are presented fairly, in all material respects. In the opinion of management, the
consolidated financial statements have been prepared within acceptable limits of materiality and are in
accordance with International Financial Reporting Standards. The financial information contained in the
annual report is consistent with that in the consolidated financial statements.
Management is also responsible for establishing and maintaining appropriate systems of internal control
over the company’s financial reporting. The internal control system was designed to provide reasonable
assurance to management regarding the preparation and presentation of the consolidated financial
statements. Management tested and evaluated the effectiveness of its disclosure controls and procedures
and internal controls over financial reporting as at March 31, 2015. During this evaluation Management
identified weaknesses due to the limited number of finance and accounting personnel at the Corporation
dealing with complex and non-routine accounting transactions that may arise and due to a lack of
segregation of duties and as a result the controls are not considered effective. All internal control systems,
no matter how well designed, have inherent limitations. Therefore, these systems provide reasonable but
not absolute assurance that financial information is accurate and complete.
KPMG LLP, an independent firm of Chartered Accountants, has been engaged, as approved by a vote of
the shareholders at the Company’s most recent annual general meeting, to examine the consolidated
financial statements in accordance with Canadian generally accepted auditing standards and provide an
independent professional opinion.
The audit committee of the Board of Directors with all of its members being independent directors, have
reviewed the consolidated financial statements including notes thereto with management and KPMG LLP.
The consolidated financial statements have been approved by the Board of Directors on the
recommendation of the Audit Committee.
(signed) “ Chayan Chakrabarty”
Chayan Chakrabarty
President & Chief Executive Officer
(signed) “ Jerrad Blanchard”
Jerrad Blanchard
Chief Financial Officer
30
Bengal Energy Ltd.
2015 Annual 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, 2015 and March 31, 2014, the
consolidated statements of income (loss) and comprehensive income (loss), changes in equity and cash
flows for the years then ended, and notes, comprising a summary of significant accounting policies and
other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial
statements in accordance with International Financial Reporting Standards, and for such internal control as
management determines is necessary to enable the preparation of consolidated financial statements that
are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those
standards require that we comply with ethical requirements and plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are free from material
misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on our judgment, including the
assessment of the risks of material misstatement of the consolidated financial statements, whether due to
fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s
preparation and fair presentation of the consolidated financial statements in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on
the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of
accounting policies used and the reasonableness of accounting estimates made by management, as well
as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a
basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated
financial position of Bengal Energy Ltd. as at March 31, 2015 and March 31, 2014, and its consolidated
financial performance and its consolidated cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered Accountants
June 18, 2015
Calgary, Canada
BENGAL ENERGY LTD.
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Thousands of Canadian dollars)
As at March 31,
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Prepaid expenses and deposits
Fair value of financial instruments
Non-current assets:
Exploration and evaluation assets
Petroleum and natural gas properties
Property, plant and equipment
Fair value of financial instruments
Total assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Current portion of notes payable
Non-current liabilities:
Decommissioning liability
Credit facility
Notes payable
Other long-term liabilities
Shareholders’ equity:
Share capital
Contributed surplus
Warrants
Accumulated other comprehensive income
Deficit
Total liabilities and shareholders’ equity
Commitments and contingencies (note 19)
Subsequent events (note 22)
Notes
2015
2014
5
16
6
7
8
16
10
12
11
10
10
13
10
$
$
1,749
140
3,109
348
2,164
7,510
28,245
27,122
-
2,802
58,169
65,679
$
$
2,289 $
-
2,289
1,454
16,982
-
3
18,439
5,984
140
3,821
490
-
10,435
26,821
21,669
3,500
-
51,990
62,425
4,174
3,158
7,332
358
-
6,085
61
6,504
94,151
7,341
167
(130)
(56,578)
44,951
65,679
$
93,151
7,141
167
1,536
(53,406)
48,589
62,425
$
See accompanying notes to the consolidated financial statements.
On behalf of the Board:
Director
Chayan Chakrabart
Director
James B. Howe
32
Bengal Energy Ltd.
2015 Annual Report
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Thousands of Canadian dollars, except per share amounts)
For the years ended March 31,
Notes
2015
2014
Income
Petroleum and natural gas revenue
Royalties
Realized gain on financial instruments
Unrealized gain on financial instruments
Operating expenses
General and administrative
Transaction costs
Operating and transportation
Depletion and depreciation
Pre-licensing & impairment
Share-based compensation
Operating income
Other (expenses)
Other
Finance (expenses) income
Foreign (loss) exchange
Net (loss) income
Exchange differences on translation of foreign operations
Total comprehensive income (loss) for the year
(Loss) earnings per share
- Basic & diluted
$15,669
(1,057)
14,612
891
4,962
20,465
3,407
-
6,247
5,162
4,762
170
19,748
717
(334)
(1,745)
(1,810)
(3,889)
(3,172)
(1,666)
(4,838)
(0.05)
7,8
6,8
15
13
$19,822
(1,334)
18,488
-
-
-
3,822
261
5,290
4,531
3,101
498
17,503
985
-
(855)
(35)
(890)
150
(45)
105
0.00
Weighted average number of shares outstanding (000s)
13
- Basic & diluted
65,349
63,134
See accompanying notes to the consolidated financial statements.
BENGAL ENERGY LTD.
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Thousands of Canadian dollars)
Shares
outstanding
Share
capital Warrants
Contributed
surplus
Equity
component of
convertible
debentures
Accumulated
other
comprehensive
income
Total
shareholders’
equity
Deficit
52,110,177
$ 86,246
$
−
$
6,466
$
25
$ 1,581 $
(53,556)
$ 40,762
-
-
-
-
12,556,905
7,327
-
-
-
-
(422)
-
-
-
-
-
-
-
-
-
-
-
-
-
498
152
-
-
-
-
-
-
167
25
(25)
-
(45)
150
150
-
(45)
-
-
-
-
-
-
7,327
-
(422)
-
-
-
498
152
167
64,667,082
$ 93,151
$ 167 − $
7,141
$
-
$ 1,536 $
(53,406)
$ 48,589
64,667,082
$
93,151
$ 167 − $
7,141
$
-
-
-
-
3,510,714
1,000
-
-
-
-
-
-
-
-
-
-
-
(10)
170
40
68,177,796
94,151
167
7,341
-
-
$ 1,536 $
(53,406)
$ 48,589
-
(3,172)
(3,172)
-
(1,666)
-
(1,666)
-
-
-
-
-
-
-
-
-
-
990
170
40
(130)
(56,578)
44,951
Balance at
April 1, 2013
Net income for the year
Comprehensive (loss) for
the year
Issuance of common
shares
Share issue costs
Share-based
compensation –
expensed
Share-based
compensation –
capitalized
Warrants
Balance at
March 31, 2014
Balance at
April 1, 2014
Net loss for the year
Comprehensive (loss) for
the year
Issuance of common
shares
Share-based
compensation –
expensed
Share-based
compensation –
capitalized
Balance at
March 31, 2015
See accompanying notes to the consolidated financial statements.
34
Bengal Energy Ltd.
2015 Annual Report
BENGAL ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Canadian dollars)
For the years ended March 31
Notes
2015
2014
Operating activities
Net (loss) income for the year
Non-cash items:
Depletion and depreciation
Pre-licensing & impairment
Accretion on decommissioning liability
Accretion on notes payable and credit facility
/change in fair value of VARs
Settlement of decommissioning liability
Share-based compensation
Deferred income tax recovery
Unrealized gain on financial instruments
Unrealized foreign exchange loss (gain)
Change in non-cash working capital
Net cash from (used in) operating activities
Investing activities
Exploration and evaluation expenditures
Petroleum and natural gas properties
Property, plant and equipment
Changes in non-cash working capital
Net cash used in investing activities
Financing activities
Proceeds from issuance of shares,
net of issuance costs
Proceeds from issuance of credit facility, net of issuance costs
Repayment of notes
Changes in non-cash working capital
Net cash from financing activities
Impact of foreign exchange
on cash and cash equivalents
Net increase (decrease) in cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
See accompanying notes to consolidated financial statements.
$ (3,172)
$
150
5,162
4,762
15
4,531
3,101
(8)
551
(19)
170
-
(4,962)
2,082
4,589
2,332
6,921
(3,189)
(10,274)
-
(2,642)
(16,105)
18
6
7
8
18
13
11
10
18
14
14,520
(8,774)
(673)
5,087
(138)
93
-
498
(55)
-
(127)
8,183
(592)
7,591
(1,963)
(14,313)
(371)
(808)
(17,455)
5,405
7,743
(250)
(5)
12,893
341
(4,235)
3,370
5,984
$ 1,749
2,614
$ 5,984
BENGAL ENERGY LTD.
BENGAL ENERGY LTD.
Notes to Consolidated Financial Statements (the “financial statements”)
Years ended March 31, 2015 and 2014
(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, 2015 and 2014 and for the years ended March 31, 2015 and 2014 are
comprised of the Company and its wholly owned subsidiaries Bengal Energy International Inc., which
are incorporated in Canada and Bengal Energy Australia (Pty) Ltd., Avery Resources (Northern Ireland)
Ltd. and Northstar Energy Pty Ltd. which are incorporated in Australia respectively. The Company
conducts many of its activities jointly with others; these financial statements reflect only the Company’s
proportionate interest in such activities.
Bengal’s principal place of business and registered office is located at 1810, 801 6th Ave SW, Calgary,
Alberta, Canada, T2P 3W2.
2.
BASIS OF PREPARATION
a) Statement of compliance
These consolidated financial statements have been prepared in accordance with International
Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board
(IASB).
The consolidated financial statements were approved and authorized for issuance by the Board of
Directors on June 18, 2015.
b) Basis of measurement
These consolidated financial statements have been prepared on a historical cost basis.
c) Functional and presentation currency
The Company’s presentation currency is Canadian dollars ($). The functional currency of the
Canadian parent entity is Canadian dollars, the functional currency of the India subsidiary is US
dollars and the functional currency of the Australian subsidiary is Australian dollars.
3.
SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently to all periods presented in these
consolidated financial statements, and have been applied consistently by the Company and its
subsidiaries.
(a) Basis of consolidation:
The consolidated interim financial statements incorporate the financial statements of the Company
and its wholly and majority owned subsidiaries, Bengal Energy Australia (Pty) Ltd., Bengal Energy
International Inc., Avery Resources (Northern Ireland) Ltd. and Northstar Energy Pty Ltd.
respectively.
36
Notes to Consolidated Financial Statements
Subsidiaries are entities controlled by the Company. Control exists when the Company has the
power to govern the financial and operating policies of an entity so as to obtain the benefits from its
activities. In assessing control, potential voting rights that currently are exercisable are taken into
account. The financial statements of subsidiaries are included in the consolidated financial
statements from the date that control commences until the date that control ceases.
The Company recognizes in its financial statements its proportionate share of the assets, liabilities,
revenues, and expenses of its joint operations.
All intra-group transactions, balances, income and expenses are eliminated in full on consolidation.
(b) Cash and cash equivalents
Cash and cash equivalents include cash and all investments with a maturity of three months or less.
(c) Provisions
A provision is recognized if, as a result of a past event, the Company has a present legal or
constructive obligation that can be estimated reliably, and it is probable that an outflow of economic
benefits will be required to settle the obligation. Provisions are determined by discounting the
expected future cash flows at a pre-tax “risk-free” rate that reflects current market assessments of
the time value of money and the risks specific to the liability. The unwinding of the discount is
recognized as a finance expense. Provisions are not recognized for future operating losses.
Decommissioning and restoration liabilities:
The Company’s activities give rise to dismantling, decommissioning and site disturbance
remediation activities. Provision is made for the estimated cost of site restoration and capitalized in
the relevant asset category.
Decommissioning obligations are measured at the present value of management’s best estimate of
the expenditures required to settle the present obligation at the period end date. Subsequent to the
initial measurement, the obligation is adjusted at the end of each period to reflect the passage of
time and changes in the estimated future cash flows underlying the obligation. The increase in the
provision due to the passage of time is recognized as finance costs whereas increases/decreases
due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon
settlement of the asset retirement obligations are charged against the provision to the extent the
provision was established.
(d) Oil and natural gas exploration and evaluation expenditures
Exploration and evaluation costs (“E&E” assets”)
All costs incurred prior to obtaining the legal right to explore an area are expensed when incurred.
Generally, costs directly associated with the exploration and evaluation of crude oil and natural gas
reserves are initially capitalized. Exploration and evaluation costs are those expenditures for an
area where technical feasibility and commercial viability has not yet been demonstrated. These
costs generally include unproved property acquisition costs, geological and geophysical costs,
sampling and appraisals, drilling and completion costs and capitalized decommissioning costs.
Costs are held in exploration and evaluation until the technical feasibility and commercial viability of
the project is established. Amounts are generally reclassified to petroleum and natural gas
properties once probable reserves have been assigned to the field. If probable reserves have not
BENGAL ENERGY LTD.
been established through the completion of exploration and evaluation activities and there are no
future plans for activity in that field, then the exploration and evaluation expenditures are
determined to be impaired and the amounts are charged to profit or loss.
(e) Petroleum and natural gas properties
Carrying value
Costs incurred subsequent to the determination of technical feasibility and commercial viability are
recognized as petroleum and natural gas properties in the specific asset to which they relate.
Petroleum and natural gas properties are stated at cost less accumulated depreciation and
depletion and accumulated impairment losses. The initial cost of a petroleum and natural gas
property is comprised of its purchase price or construction cost, any costs directly attributable to
bringing the asset into operation, the initial estimate of the decommissioning obligation, and for
qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount
paid and the fair value of any other consideration given up to acquire the asset.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability and
the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas
interests only when they increase the future economic benefits embodied in the specific asset to
which they relate. All other expenditures are recognized in profit or loss as incurred. Such
capitalized oil and natural gas interests generally represent costs incurred in developing proved
and/or probable reserves and bringing in or enhancing production from such reserves, and are
accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold
component is derecognized. The costs of the day-to-day servicing of property, plant and equipment
are recognized in profit or loss as incurred.
Depletion and depreciation
The net book value of producing assets are depleted on a field-by-field basis using the unit of
production method with reference to the ratio of production in the year to the related proved and
probable reserves, taking into account estimated future development costs necessary to bring those
reserves into production. For purposes of these calculations, production and reserves of natural gas
are converted to barrels on an energy equivalent basis.
Other assets are depreciated on a declining basis at rates ranging from 20% to 30%.
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) Property and equipment – drilling rig
Recognition and measurement
Initial costs related to the acquisition or construction of property and equipment are capitalized and
accumulated by rig or a component thereof.
Subsequent to initial recognition, items of property and equipment are measured at cost less
accumulated depreciation and accumulated impairment losses. When significant parts of an item of
property and equipment have different useful lives, they are accounted for as separate items (major
components).
38
Notes to Consolidated Financial Statements
Subsequent costs are included in the related asset’s carrying amount or recognized as a separate
asset, as appropriate, only when is it probable that future economic benefits associated with the
item will flow to the group and the cost of the item can be measured reliably. All other repairs and
maintenance are recorded in profit and loss.
Gains and losses on disposal of an item of property and equipment are determined by comparing
the proceeds from disposal with the carrying amount of property and equipment and are recognized
in profit and loss.
(g) Impairment
E&E and Petroleum and Natural Gas Properties
E&E assets are assessed for impairment when facts and circumstances suggest that the carrying
amount exceeds the recoverable amount and when they are reclassified to Development and
Production (“D&P”) assets. For the purpose of impairment testing, E&E assets are grouped by
concession or field with other E&E assets belonging to the same concession or field. The
impairment loss will be calculated as the excess of the carrying value over recoverable amount of
the E&E impairment grouping and any resulting impairment loss is recognized in profit or loss.
Recoverable amount is determined as the higher of the value in use or fair value less costs to sell.
At the end of each reporting period, the Company reviews the petroleum and natural gas properties
for circumstances that indicate that the assets may be impaired. Assets are grouped together into
cash generating units (“CGU”s) for the purpose of impairment testing, which is the lowest level at
which there are identifiable cash inflows that are largely independent of the cash flows of other
groups of assets. If any such indication of impairment exists, the Company makes an estimate of its
recoverable amount. A CGUs recoverable amount is the higher of its fair value less selling costs
and its value in use. In assessing value in use, the estimated future cash flows are discounted to
their present value using a pre-tax discount rate that reflects current market assessments of the
time value of money and the risks specific to the asset. Value in use is generally computed by
reference to the present value of future cash flows expected to be derived from the production of
proved and probable reserves.
Fair value less cost to sell is determined as the amount that would be obtained from the sale of a
CGU in an arm’s length transaction between knowledgeable and willing parties. The fair value less
cost to sell of oil and gas assets is generally determined as the net present value of the estimated
future cash flows expected to arise from the continued use of the CGU, including any expansion
prospects, and its eventual disposal, using assumptions that an independent market participant may
take into account. These cash flows are discounted by an appropriate discount rate which would be
applied by such a market participant to arrive at a net present value of the CGU. Where the carrying
amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written
down. Consideration is given to acquisition metrics or recent transactions completed on similar
assets to those contained with the relevant CGU.
When the recoverable amount is less than the carrying amount, the asset or CGU is impaired. For
impairment losses identified based on a CGU, the loss is allocated on a pro rata basis to the assets
within the CGU(s). The impairment loss is recognized as an expense in profit or loss.
At the end of each subsequent reporting period these impairments are assessed for indicators of
reversal. Where an impairment loss subsequently reverses, the carrying amount of the asset or
CGU is increased to the revised estimate of its recoverable amount, but so that the increased
carrying amount does not exceed the carrying amount that would have been determined had no
BENGAL ENERGY LTD.
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.
Property and Equipment
At the end of each reporting period, the Company reviews property and equipment for
circumstances that indicate that the assets may be impaired. If any such indication of impairment
exists, the Company makes an estimate of its recoverable amount, which is the higher of its fair
value less selling costs and its value in use.
Fair value less cost to sell is determined as the amount that would be obtained from the sale of an
asset in an arm’s length transaction between knowledgeable and willing parties. Consideration is
given to recent transactions related to similar assets.
When the recoverable amount is less than the carrying amount, the asset is impaired and the
resulting impairment loss is recognized as an expense in profit or loss.
At the end of each subsequent reporting period these impairments are assessed for indicators of
reversal. Where an impairment loss subsequently reverses, the carrying amount of the asset is
increased to the revised estimate of its recoverable amount, but so that the increased carrying
amount does not exceed the carrying amount that would have been determined had no impairment
loss have been recognized for the asset in prior years. A reversal of an impairment loss is
recognized immediately in profit or loss.
Financial assets
A financial asset is assessed at each reporting date to determine whether there is any objective
evidence that it is impaired. A financial asset is considered to be impaired if objective evidence
indicates that one or more events have had a negative effect on the estimated future cash flows of
that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the
difference between its carrying amount and the present value of the estimated future cash flows
discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The
remaining financial assets are assessed collectively in groups that share similar credit risk
characteristics.
All impairment losses are recognized in profit or loss.
An impairment loss is reversed if the reversal can be related objectively to an event occurring after
the impairment loss was recognized. For financial assets measured at amortized cost the reversal is
recognized in profit or loss.
(h) Financial instruments
Financial assets and liabilities are classified as either financial assets or liabilities at fair value
through profit and loss (“FVTPL”), loans and receivables, held to maturity investments, available for
sale financial assets, or other liabilities, as appropriate. Financial assets and liabilities are
recognized initially at fair value.
Subsequent measurement of financial instruments is based on their initial classification. FVTPL
financial assets and liabilities are measured at fair value and changes in fair value are recognized in
profit or loss. Available-for-sale financial instruments are measured at fair value with changes in fair
value recorded in other comprehensive loss until the instrument is derecognized or impaired. The
40
Notes to Consolidated Financial Statements
remaining categories of financial instruments are recognized at amortized cost using the effective
interest rate method.
The transaction costs that are directly attributable to the acquisition or issue of a financial asset or
financial liability classified as FVTPL are expensed immediately. For a financial asset or financial
liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the
asset or liability are added to or deducted from the fair value on initial recognition and amortized
through profit or loss income over the term of the financial instrument.
(i) Non-derivative financial instruments
Cash and cash equivalents, restricted cash as well as accounts receivable are classified as loans
and receivables, which are measured at amortized cost. Accounts payable and accrued liabilities,
notes payable and the credit facility are classified as other financial liabilities, which are measured
at amortized cost.
(ii) Derivative financial instruments
The Company enters into certain financial derivative contracts in order to manage the exposure to
market risks from fluctuations in commodity prices. These instruments are not used for trading or
speculative purposes. The Company does not designate its financial derivative contracts as
effective accounting hedges and therefore will not apply hedge accounting, even though the
Company considers all commodity contracts to be economic hedges. As a result, all derivative
contracts are classified as FVTPL and are recorded on the statement of financial position at fair
value. Transaction costs are recognized in profit or loss when incurred. Subsequent to initial
recognition, derivatives are measured at fair value, and changes therein will be recognized
immediately in profit or loss.
The Company may enter into physical delivery sales contracts for the purposes of receipt or delivery
of nonfinancial items in accordance with its expected purchase, sale or usage requirements as
executory contracts. As such, these contracts are not considered to be derivative financial
instruments and will not be recorded at fair value on the statement of financial position. Settlements
on these physical delivery contracts will be recognized in petroleum and natural gas revenue in the
period of settlement.
Fair value
The fair value of financial instruments that are actively traded in organized financial markets is
determined by reference to quoted market bid prices at the valuation date. For financial instruments
that have no active market, fair value is determined using valuation techniques including the use of
recent arm’s length market transactions, reference to the current market value of equivalent
financial instruments and discounted cash flow analysis.
Share capital
Common shares are classified as equity. Incremental costs directly attributable to the issue of
common shares and stock options are recognized as a deduction from equity, net of any tax effects.
(i) Foreign currency translation:
The consolidated financial statements are presented in Canadian dollars, which is the Company’s
functional and presentation currency. For the accounts of foreign operations, assets and liabilities
are translated at period end exchange rates, while revenues and expenses are translated using
average rates over the period. Translation gains and losses relating to the foreign operations are
included in accumulated other comprehensive income, a component of equity. Foreign currency
BENGAL ENERGY LTD.
transactions are translated into the legal entity’s functional currency at the exchange rate in effect at
the transaction; and any gains or losses are recorded in profit or loss.
(j) Share-based compensation:
The Company accounts for stock-based compensation granted to directors, officers, employees and
consultants using the Black-Scholes option-pricing model to determine the fair value of the plan at
grant date. An estimated forfeiture rate is incorporated into the fair value calculated and adjusted to
reflect the actual number of options that vest. Stock-based compensation expense is recorded and
reflected as stock-based compensation expense over the vesting period with a corresponding
amount reflected in contributed surplus. At exercise, the associated amounts previously recorded as
contributed surplus are reclassified to common share capital.
(k) Revenue recognition:
Revenue from the sale of natural gas, natural gas liquids and crude oil is recognized when the
significant risks and rewards of ownership is transferred, which is when title passes to the customer
in accordance with the terms of the sales contract. This generally occurs when the product is
physically transferred into a pipe, truck or other delivery mechanism.
(l) Per share amounts:
Basic per share amounts are computed by dividing net income (loss) by the weighted average
number of common shares outstanding for the period. Diluted per share amounts are calculated
giving effect to the potential dilution that would occur if stock options or other dilutive instruments
were exercised into common shares. The treasury stock method assumes that any proceeds upon
the exercise of dilutive instruments, including remaining unamortized compensation costs, would be
used to purchase common shares at the average market price of the common shares during
the period.
(m) Income taxes:
Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit
or loss except to the extent that it relates to items recognized directly in equity, in which case it is
recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted
or substantively enacted at the reporting date, and any adjustments to tax payable in respect of
previous years.
Deferred tax is recognized providing for temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for taxation purposes.
Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is
not a business combination. In addition, deferred tax is not recognized for taxable temporary
differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates
that are expected to be applied to temporary differences when they reverse, based on the laws that
have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities
are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by
the same tax authority on the same taxable entity, or on different tax entities, but they intend to
settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized
simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be
42
Notes to Consolidated Financial Statements
available against which the temporary difference can be utilized. Deferred tax assets are reviewed
at each reporting date and are reduced to the extent that it is no longer probable that the related tax
benefit will be realized.
(n) Finance income and expenses:
Finance income consists of interest earned on term deposits. Finance expenses include fees on
Performance Security Guarantees issued by Export Development Canada, bank fees on Bank
Guarantees issued to the Government of India, letter of credit charges, interest on notes payable
and the credit facility, accretion on notes payable and change in fair value of VARS, and accretion
of the discount on decommissioning obligations.
(o) Determination of fair value:
A number of the Company’s accounting policies and disclosures required the determination of fair
value, both for financial and non-financial assets and liabilities. Fair values have been determined
for measurement and/or disclosure purposes based on the following methods. When applicable,
further information about the assumptions made in determining fair values is disclosed in the notes
specific to that asset or liability.
Fair Value Hierarchy
Financial instruments that are measured subsequent to initial recognition at fair value are grouped
into three categories based on the degree to which fair value is observable:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the
reporting date. Active markets are those in which transactions occur in sufficient frequency and
volume to provide pricing information on an ongoing basis;
Level 2 - Valuations are based on inputs other than quoted prices included in Level 1 that are
observable for the asset or liability, either directly or indirectly; including forward prices for
commodities, time value and volatility factors which can be substantially observed or corroborated
in the marketplace;
Level 3 - Inputs that are not based on observable data for the asset or liability.
Financial instruments comprise cash, cash equivalents, restricted cash, accounts receivable,
accounts payable and accrued liabilities, credit facility, notes payable 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:
BENGAL ENERGY LTD.
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. Notes payable
The fair value of notes payable is estimated as the present value of future cash flows,
discounted at the market rate of interest at the reporting date. At March 31, 2015 and 2014,
the fair value of these balances approximated their carrying value due to their short term to
maturity.
iv. 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.
(p) Adoption of new accounting policies
The following new accounting policies were adopted as at April 1, 2014, both of which were applied
retrospectively:
The IASB issued International Financial Reporting Interpretations Committee Interpretation
("IFRIC") 21, “Levies” which was adopted by the Company on April 1, 2014. The IFRIC clarifies that
an entity should recognize a liability for a levy when the activity that triggers payment occurs. The
adoption of this interpretation had no impact on the Company's consolidated financial statements.
IAS 32, “Financial Instruments: Presentation”, which clarifies the requirements for offsetting
financial assets and liabilities. The amendments clarify when an entity has a legally enforceable
right to offset and certain other requirements that are necessary to present a net financial asset or
liability. There was no impact on the Company’s consolidated financial statements on adoption of
this standard.
(q) New standards and interpretations not yet adopted:
Standards that are issued but not yet effective and that the Company reasonably expects to be
applicable at a future date are listed below.
Accounting for acquisitions of interests in joint operations
In May 2014, the IASB issued amendments to IFRS 11 “Joint Arrangements” to clarify that the
acquirer of an interest in a joint operation in which the activity constitutes a business is required to
apply all of the principles of business combinations accounting in IFRS 3 “Business Combinations”.
Prospective application of this interpretation is effective for annual periods beginning on or after
January 1, 2016, with earlier application permitted. The adoption of this amendment could impact
the Company in the event that it increases or decreases its ownership share in an existing joint
operation or invests in a new joint operation.
44
Notes to Consolidated Financial Statements
Sale or contribution of assets between an investor and its associate or joint venture
In September 2014, the IASB issued amendments to address an inconsistency between the
requirements in IFRS 10 “Consolidated Financial Statements” and those in IAS 28 “Investments in
Associates and Joint Ventures” regarding the sale or contribution of assets between an investor and
its associate or joint venture. The amendment clarified that a full gain or loss is recognized when a
transaction involves a business. A partial gain or loss is recognized when a transaction involves
assets that do not constitute a business. Prospective application of this interpretation is effective for
annual periods beginning on or after January 1, 2016, with earlier application permitted. The
adoption of this amendment could impact the Company in the event that it has transactions with
associates or joint ventures.
Disclosure initiative
In December 2014, the IASB issued narrow-focus amendments to IAS 1 “Presentation of Financial
Statements” to clarify existing requirements relating to materiality, order of notes, subtotals,
accounting policies and disaggregation. Retrospective application of this standard is effective for
fiscal years beginning on or after January 1, 2016, with earlier application permitted. The adoption
of this amended standard is not expected to have a material impact on the Company’s disclosure.
Revenue from contracts with customers
In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers”. It replaces
existing revenue recognition guidance and provides a single, principles-based five-step model to be
applied to all contracts with customers. Retrospective application of this standard was to be
effective for fiscal years beginning on or after January 1, 2017, with earlier application permitted.
On May 19, 2015, the IASB published the expected exposure draft aimed at deferring the effective
date of IFRS 15 “Revenue from Contracts with Customers” to January 1, 2018. The Company is
currently assessing the impact of this standard.
Financial instruments: recognition and measurement
In July 2014, IFRS 9 “Financial Instruments” was issued as a complete standard, including the
requirements previously issued related to classification and measurement of financial assets and
liabilities, and additional amendments to introduce a new expected loss impairment model for
financial assets including credit losses. Retrospective application of this standard with certain
exemptions is effective for fiscal years beginning on or after January 1, 2018, with earlier application
permitted. The Company is currently assessing the impact of this standard.
4.
MANAGEMENT JUDGMENTS AND ESTIMATES
The timely preparation of the financial statements requires management to make judgments,
estimates and assumptions that affect the application of accounting policies and reported amounts
of assets and liabilities and income and expenses. Accordingly, actual results may differ from these
estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to
accounting estimates are recognized in the period in which the estimates are revised and in any
future periods affected. Significant estimates and judgments made by management in the
preparation of these financial statements are out-lined below.
BENGAL ENERGY LTD.
Critical judgments in applying accounting policies
The following are the critical judgments, apart from those involving estimations (see below), that
management has made in the process of applying the Company’s accounting policies and that
have the most significant effect on the amounts recognized in these financial statements.
i) Identification of Cash-generating Units
Bengal’s assets are aggregated into cash-generating units, for the purpose of calculating
impairment, based on their ability to generate largely independent cash flows. By their nature, these
estimates and assumptions are subject to measurement uncertainty and may impact the carrying
value of the Company's assets in future periods.
ii) Impairment Indicators
Judgments are required to assess when impairment indicators exist and impairment testing is
required. The application of the Company’s accounting policy for exploration and evaluation,
petroleum and natural gas properties and PP&E assets required management to make certain
judgments as to future events and circumstances as to whether economic quantities of reserves
have been found.
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 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.
46
Notes to Consolidated Financial Statements
iii) Current and deferred income taxes
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could
affect amounts recognized in profit or loss both in the period of change, which would include any
impact on cumulative provisions, and in future periods. To the extent assumptions regarding future
profitability change, there can be an increase or decrease in the amounts recognized in respect of
deferred tax assets as well as the amounts recognized in profit or loss in the period which the
change occurs.
The deferred tax asset is based on estimates as to the timing of the reversal of temporary
differences, substantively enacted tax rates and the likelihood of assets being realized.
iv) Reserves
The estimate of petroleum and natural gas reserves is integral to the calculation of the amount of
depletion charged to the statement of operations and is also a key determinant in assessing
whether the carrying value of any of the Company’s development and production assets has been
impaired. Changes in reported reserves can impact asset carrying values due to changes in
expected future cash flows.
The Company’s reserves are evaluated and reported on by independent reserve engineers at least
annually in accordance with Canadian Securities Administrators’ National Instrument 51-101.
Reserve estimation is based on a variety of factors including engineering data, geological and
geophysical data, projected future rates of production, commodity pricing and timing of future
expenditures, all of which are subject to significant judgment and interpretation.
v) Share-based payments
The Company measures the cost of its share-based payments to directors, officers, employees and
certain consultants by reference to the fair value of the equity instruments at the date at which they
are granted. The assumptions used in determining fair value include: share price, expected lives of
options, risk-free rates of return, share price volatility and the estimated forfeiture rate. Changes to
assumptions may have a material impact on the amounts presented.
5.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash on hand and in banks and investments with an original
maturity date of 90 days or less. Cash and cash equivalents at the end of the reporting period as shown
in the statement financial position are comprised of:
As at
($000s)
Cash and bank balances
Short-term deposits
March 31, 2015
March 31, 2014
$
$
1,743
6
1,749
$
$
5,164
820
5,984
BENGAL ENERGY LTD.
6.
EXPLORATION AND EVALUATION ASSETS (E&E ASSETS)
($000s)
Balance at April 1, 2013
Additions
Capitalized share-based compensation
E&E impairment loss
Exchange adjustments
Balance at March 31, 2014
Additions
Capitalized share-based compensation
E&E impairment loss
Exchange adjustments
Balance at March 31, 2015
Exploration and Evaluation
Expenditures
$
$
$
26,416
1,963
59
(1,367)
(250)
26,821
3,189
10
(1,592)
(183)
28,245
Exploration and evaluation assets consist of the Company’s exploration projects in Australia and India
which are pending the determination of proved or probable reserves. Costs primarily consist of
acquisition costs, geological & geophysical work, seismic and drilling and completion costs until the
drilling of wells is complete and the results have been evaluated.
During June 2014, the Koki-1 exploration well was drilled to a vertical depth of 2,573 meters and did not
encounter the targeted Murta DC70 reservoir. Its secondary target indicated minor, non-commercial oil
shows and it was agreed to suspend and abandon this well. Based on these results, the Company has
recorded an impairment charge of $0.8 million equal to its share of drilling costs associated with this
well.
During December 2014, Bengal drilled the Wicho East exploration well primarily targeting the deeper
Jurassic Hutton horizon. This well failed to intersect a commercial hydrocarbon accumulation and was
plugged and abandoned during the quarter. Based on these results, the Company has recorded an
impairment charge of $0.8 million equal to its share of drilling costs associated with this well.
A summary of E&E assets is shown in the table below:
($000s)
ATP 732P – Tookoonooka – Note 1
ATP 752P
CY-ONN-2005/1 – onshore
Other – Note 2
March 31, 2014 ($000)
ATP 732P – Tookoonooka – Note 1
ATP 752P
CY-ONN-2005/1 – onshore
Other – Note 2
March 31, 2015 ($000)
Australia
$ 20,126
-
1,423
$ 21,549
Australia
$ 18,825
1,044
1,605
$ 21,474
$
India
$ 5,272
-
5,272
Exploration and Evaluation Assets
Total
$ 20,126
-
5,272
1,423
$ 26,821
Exploration and Evaluation Assets
Total
$ 18,825
1,044
6,771
1,605
$ 28,245
-
6,771
$ 6,771
India
$
Note 1: The Company entered into a farm-out agreement that requires a 2-well drilling program of which one remains to be
drilled at March 31, 2015. Once the final well is drilled, the joint venture partner will earn a 50% interest in this permit and the
Company will record a gain or loss on this 50% disposition.
Note 2: Other includes ATP 934P, capitalized G&A and stock-based compensation and foreign exchange effects on assets
denominated in foreign currencies.
48
7.
PETROLEUM AND NATURAL GAS PROPERTIES
$000s
Cost:
Balance at April 1, 2013
Additions
Acquisitions
Capitalized share-based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2014
Additions
Non-cash additions
Capitalized share-based compensation
Change in decommissioning obligation
Exchange adjustments
Balance at March 31, 2015
Petroleum and
Natural Gas
Properties
$
13,810
7,448
6,964
93
120
(31)
28,404
10,274
53
30
1,118
(1,178)
38,701
Notes to Consolidated Financial Statements
Corporate
Assets
Total
$
$
427
(99)
-
-
-
14,237
7,349
6,964
93
120
(10) (41)
28,722
10,274
53
30
1,118
24 (1,154)
39,043
318
-
-
-
-
342
Accumulated depletion, depreciation and
impairment losses:
Balance at April 1, 2013
Depletion and depreciation charge
Exchange adjustments
Balance at March 31, 2014
Depletion and depreciation charge
Exchange adjustments
Balance at March 31, 2015
Net carrying value
At March 31, 2014
At March 31, 2015
Petroleum and
Natural Gas
Properties
$000s
Corporate
Assets
$ 000s
$
$
2,447
4,455
(83)
6,819
4,800
59
11,678
$
160
76
(2)
234
32
(23)
243
Total
$000s
2,607
4,531
(85)
7,053
4,832
36
11,921
$ 21,585
$ 27,023
$
84
$ 99
$ 21,669
$ 27,122
The calculation of depletion for the year ended March 31, 2015 included $123.8 million and $nil million
for estimated future development costs associated with proved and probable reserves in Australia and
Canada respectively (March 31, 2014 - $83.5 million and $0.5 million).
BENGAL ENERGY LTD.
8.
PROPERTY, PLANT AND EQUIPMENT
($000s)
Balance at March 31, 2013
Additions
Capitalized share-based compensation
Balance at March 31, 2014
Additions
Balance at March 31, 2015
Rig Equipment
$ 4,756
374
-
$ 5,130
-
5,130
Accumulated depletion, depreciation and impairment losses:
Balance at March 31, 2013
Impairment
Balance at March 31, 2014
Depreciation and impairment
Balance at March 31, 2015
Net book value
Balance at March 31, 2014
Balance at March 31, 2015
$ 73
1,557
$ 1,630
3,500
$ 5,130
$ 3,500
$ -
On April 5, 2012 the Company purchased an Ideco H-44 drilling rig. The purchase price of the Rig was
US $1.75 million. Additional costs were incurred to transport the rig from its point of purchase, prepare
the rig and acquire certain ancillary equipment required for drilling operations. This rig was used to drill,
case and test the Caracal-1 well on permit ATP 732.
As at December 31, 2014, the Company recognized the significant decrease in market crude prices and
the excess of drilling rigs in the local and international market as an indicator of impairment for its
drilling rig. The Company evaluated current drilling activity and rig sale activity both locally in Australia
and internationally to determine that under current market conditions its drilling rig should be fully
impaired at December 31, 2014.
The recoverable amount of nil was determined using fair value less cost to sell based on level 3 fair
value inputs as described by IFRS 13, specifically the frequency of asset sales in the Australian and
international markets, internal estimates of fair value of component parts as well as transpirations costs.
There were no benchmark transactions identified through management’s review of sales markets,
based on low transaction volumes and high volume of equipment available for sale. This, along with
management’s internal estimates determined that the expected proceeds from disposition are less than
the expected cost to transport.
9.
INCOME TAXES
The provision for income taxes differs from the amount obtained in applying the combined Federal and
Provincial income tax rates to the loss for the year. The difference relates to the following items:
50
Years Ended March 31 ($000s)
(Loss) income before taxes
Statutory tax rate
Expected income tax expense (recovery)
Foreign exchange
Stock-based compensation
Effect of change in tax rate & other
Other
Changes in unrecognized tax asset
Income tax recovery
Notes to Consolidated Financial Statements
2015
(3,172)
25%
(793)
(614)
51
(394)
194
1,556
$
-
2014
95
25%
(24)
83
(121)
(300)
(11)
428
55
$
The temporary deductible differences included in the Company’s unrecognized deferred income tax
assets are as follows:
As of March 31 ($000s)
Non-capital losses
Net capital losses
P&NG properties
Share issue costs
Decommissioning obligations
$
$
2015
27,373
5,890
8,288
742
99
42,392
2014
$ 26,395
6,033
5,033
720
358
$ 38,539
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
2015
14,515
1,490
(416)
(400)
(15,189)
-
$
2014
12,737
331
-
-
(13,068)
-
$
At March 31, 2015, the Company had approximately $29.5 million and $50.6 million of non-capital
losses in Canada and Australia respectively (2014- $23.7 million and $46.5 million), available to reduce
future taxable income. The Canadian non-capital losses expire at various dates from March 31, 2016 to
2035. The Australian non-capital losses have no term to expiry. The Company’s ongoing drilling
activities continue to generate deferred assets related to Petroleum Resource Rent Tax (“PRRT”) in its
Australia subsidiary, which has not been recognized.
The Company has temporary differences associated with its investments in its foreign subsidiaries,
branches, and interests in joint ventures. At March 31, 2015, the Company has no deferred tax liabilities
in respect of these temporary differences.
BENGAL ENERGY LTD.
10.
NOTES PAYABLE
Non-Convertible Notes –
Issued July 5, 2013 ( $000s)
Total
Debt
Component
Other long-term
liability
Warrants
Gross proceeds
Total cash fees
Accretion on debt/change in fair
value of VARs
Deferred tax impact
Balance at March 31, 2014
Accretion on debt/change in fair
value of VARs
Repayment
Balance at March 31, 2015
8,000
(257)
7,743
33
(55)
7,721
449
(8,000)
170
7,593
(256)
7,337
156
-
7,493
507
(8,000)
-
178
6
184
(123)
-
61
(58)
-
3
229
(7)
222
-
(55)
167
-
-
167
In October 5, 2014, the Company repaid $0.5 million of outstanding principal of notes issued July 5,
2013. In November 2014, the Company redeemed the remaining principal of $7.5 million for an early
redemption price equal to $1.03 per $1.00 (booked as interest expense) of outstanding principal amount
plus all accrued and unpaid interest thereon. Interest expense recorded during the year on the July 5,
2013 notes totaled $0.7 million, including the early redemption fee.
In conjunction with the $8.0 million notes issued July 5, 2013, 546,845 VARs and 703,125 warrants
remain outstanding. Each whole warrant entitles the holder thereof, until July 5, 2016, to acquire one
common share in the capital of the Company at a purchase price equal to $0.75 per share. Each whole
VAR entitles the holder thereof, until July 5, 2016, to exercise the VAR and thereby receive a cash
payment equal to the difference between the market price of one common share on the exercise date
and $0.75. The warrants and initial VAR valuation are valued based on the following key assumptions:
a term of 3 years, volatility of 73% and a price of $0.75/share.
On January 21, 2015 the Company redeemed its January 25, 2013 notes payable for a redemption
price of $2.0 million including principal and accrued and unpaid interest. Approximately $0.8 million of
the aggregate was paid in cash, and certain holders of the remaining $0.9 million of aggregate principal
received the redemption price through the issuance of common shares of the Company at a price of
$0.28 per common share in lieu of cash. Interest expense recorded during the year on the January 25,
2013 notes totaled $0.1 million.
11.
CREDIT FACILITIY
Facility Agreement – Issued November 12, 2014 ($000s)
Gross proceeds
Total cash fees
Unrealized foreign exchange loss
Accretion
Balance at March 31, 2015
15,364
(844)
14,520
2,307
16,827
155
16,982
In October 2014, Bengal closed its US $25 million secured credit facility with Westpac Institutional Bank
and placed an initial draw on November 12, 2014 of US $14.0 million. The facility is secured by and
available to the Company’s producing assets in the Cuisinier field in Australia’s Cooper Basin, has a
three-year term and carries an interest rate of US Libor plus 3.2% to 3.5% depending on certain reserve
52
Notes to Consolidated Financial Statements
forecast parameters. During the year $0.3 million has been charged to financing expenses related to
interest on the credit facility.
The credit facility is structured as a reserves based revolving facility under a predetermined reduction
schedule, to be evaluated based on existing reserves at each calculation date. Calculation dates
commence December 31, 2015 and occur every six months thereafter until June 30, 2017 with a
nominal reduction of $6.25 million to the facility limit at each calculation date based on the Company’s
existing reserve profile. The facility limit at March 31, 2015 is US $25 million.
The credit facility’s covenants extend only to the Company’s ability to secure its debt as a percentage of
reserve forecasts to be evaluated at each calculation date. There are no financial covenants
associated with this credit facility.
12.
DECOMMISSIONING AND RESTORATION LIABILITY
The total decommissioning and restoration obligations were estimated by management based on the
estimated costs to reclaim and abandon the wells, well sites and certain facilities based on the
Company’s contractual requirements.
Changes to decommissioning and restoration obligations were as follows:
($000s)
Decommissioning liabilities, beginning of year
Revision
Decommissioning expenditures
Additions
Accretion
Exchange adjustments
Decommissioning liabilities, end of year
$ 358
901
(19)
217
15
(18)
$ 1,454
March 31, 2015 March 31, 2014
$ 320
(82)
-
120
8
(8)
$ 358
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, 2015 is approximately
$1,990,000 (March 31, 2014 – $567,000) which will be incurred between 2015 and 2038. An inflation
factor ranging between 1.3% and 2.5% (2014 – 1.0% and 2.5%) and a risk free discount rate ranging
between 2.3% and 4.1% (2014 – 1.5% and 4.1%) have been applied to the decommissioning liability at
March 31, 2015.
Revisions are entirely related to a change in cost estimates.
13.
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:
BENGAL ENERGY LTD.
The following provides a continuity of share capital:
($000s)
Balance at March 31, 2013
Shares issued for cash
Issued on conversion of convertible
debentures
Issued on exercise of stock options for cash
Issued on cashless exercise of stock options
Share issue costs
Balance at March 31, 2014
Issued on conversion of debt
Issued on exercise of stock options for cash
Issued from contributed surplus on exercise of
stock options
At March 31, 2015
Number of Shares
52,110,177
9,500,666
Amount
$ 86,246
5,700
2,678,572
351,667
26,000
-
64,667,082
3,485,714
25,000
-
68,177,796
1,500
127
-
(422)
93,151
976
14
10
94,151
On January 23, 2015 two insiders were issued 3,485,714 common share of the Company valued at
$0.28 per share in lieu of a cash settlement of $976,000 on repayment of notes payable.
(c) Share-based compensation – stock options:
The Company has a share option plan for directors, officers, employees and consultants of the
Company whereby share options representing up to 10% of the issued and outstanding common
shares can be granted by the Board of Directors. Share options are granted for a term of three to
five years and vest one-third immediately and one-third on each of the next two anniversary dates.
The exercise price of each option equals the market price of the Company’s common shares on the
date of the grant. Effective with the option grant on December 21, 2012, vesting occurs one third
after the first year and one third on each of the two subsequent anniversaries.
Bengal accounts for its share-based compensation plan using the fair value method. Under this
method, each grant results in three instalments. The fair value of the first instalment is charged to
profit or loss immediately. The remaining two instalments are charged to profit or loss over their
respective vesting period of one and two years respectively. For options that vest one-third each
year after the first year anniversary, the fair value of the options are charged to profit and loss over
the three year vesting period. Stock options granted under the plan can be exercised on a cashless
basis, whereby the employee receives a lesser amount of shares in lieu of paying the exercise price
based on the deemed market price of the shares on the exercise date, and withholding taxes if the
employee so elects.
A summary of stock option activity is presented below:
Outstanding at March 31, 2013
Granted
Expired
Forfeited
Exercised
Outstanding at March 31, 2014
Granted
Forfeited
Expired
Exercised
54
Options
Weighted Average
Exercise Price
4,196,665
1,195,000
(846,664)
(270,001)
(401,667)
3,873,333
-
(116,667)
(216,666)
(25,000)
$
$
0.98
0.62
1.23
0.71
0.36
0.89
-
0.62
0.99
0.58
Notes to Consolidated Financial Statements
Outstanding at March 31, 2015
Exercisable at March 31, 2015
3,515,000
2,938,341
0.89
$
$ 0.95
Options Outstanding
Options Exercisable
Option Price (1)
$0.47 - $0.65
$0.66 - $1.25
$1.26 - $1.32
Total
Number
Outstanding
1,855,000
1,080,000
580,000
3,515,000
Exercise
Price (2)
$0.60
$1.17
$1.32
$0.89
Remaining
Life (3)
3.08
1.84
1.25
2.40
Number
Exercisable
1,278,341
1,080,000
580,000
2,938,341
Exercise
Price (2)
$0.60
$1.17
$1.32
$0.95
(1)
(2)
(3)
Range of option exercise prices
Weighted average exercise price of options
Weighted average remaining contractual life of options in years
The fair value of options granted were estimated on the date of grant using the Black-Scholes
option-pricing model with the following weighted average assumptions and resulting values:
For the Year Ended
Assumptions:
Risk free interest rate (%)
Expected life (years)
Expected volatility (%)(1)
Estimated forfeiture rate (%)
Weighted average fair value of options granted
Weighted average share price on date of grant
March 31,
2015
March 31,
2014
-
-
-
-
-
-
2.0%
5 yr
73%
7.1%
$0.37
$0.62
(1)
Expected volatility is estimated by considering historic average share price volatility.
The fair value of stock options granted during the year ended March 31, 2015 was $nil (2014 -
$417,000). No options were granted during the year ended March 31, 2015.
(d) Per share amounts:
Income (loss) per share is calculated based on net income (loss) and the weighted-average number
of common shares outstanding.
For the Year Ended ($000s)
Income (loss) for the year
Weighted average number of common shares (basic)
Weighted average number of common shares (diluted)
Basic and diluted income (loss) per share
March 31,
2015
(3,172)
65,349
65,349
(0.05)
March 31,
2014
150
63,134
63,209
0.00
At March 31, 2015, there were 3,515,000 (March 31, 2014 – 2,683,000) options considered anti-
dilutive. In addition, there were 703,125 warrants and 546,875 value appreciation rights considered
anti-dilutive.
14.
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:
BENGAL ENERGY LTD.
Year ended March 31 ($000s)
Salaries & employee benefits
Share-based compensation(1)
General & administrative expenses
2015
$ 840
80
$ 920
2014
$ 930
208
$ 1,138
(1) Represents the amortization of share-based payment expense associated with the Company’s share-based compensation plans
granted to key management personnel.
Salaries and benefits for the year ended March 31, 2015 include a non-recurring retirement payment to
former employees of $nil million (2014 - $0.2 million).
15.
FINANCE INCOME/EXPENSES
Year ended March 31 ($000s)
Interest income
Accretion on decommissioning obligations
Performance Security Guarantee fee (1)
Letter of credit charges
Interest on notes payable and credit facility
Accretion on notes payable and change in
fair value of VARs
Finance income (expenses)
2015
$ 18
(15)
(55)
(32)
(1,212)
2014
$ 74
8
(72)
-
(771)
(449)
$ (1,745)
(94)
$ (855)
(1) Fees paid to Export Development Canada and ICICI Bank for security guarantees for onshore and offshore India work programs.
16.
FINANCIAL RISK MANAGEMENT
The Company has exposure to credit, liquidity and market risk from its use of financial instruments. This
note presents information about the Company’s exposure to these risks, the Company’s objectives and
policies and processes for measuring and managing risk.
The Board of Directors has overall responsibility for identifying the principal risks of the Company and
ensuring the policies and procedures are in place to appropriately manage these risks. Bengal’s
management identifies, analyzes and monitors risks and considers the implication of the market
condition in relation to the Company’s activities.
(a) Credit risk:
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial
instrument fails to meet its contractual obligations, and arises principally from Bengal’s cash calls
paid to joint venture partners and receivables from petroleum and natural gas marketers. As at
March 31, 2015, Bengal’s receivables consisted of $2.6 million (March 31, 2014 - $3.5 million) from
joint venture partners and $0.5 million (March 31, 2014 - $0.3 million) of other trade receivables of
which $0.5 million has been subsequently collected.
Production from the Canadian operations is marketed by the operator. Bengal established a
payment schedule with the operator of the property and considers the entire amount to be
receivable.
In Australia, production is purchased by a consortium led by one of Australia’s largest public oil and
gas companies which is also the operator of Bengal’s production. Bengal has a Crude Oil Purchase
Agreement with this purchaser and has not experienced any collection problems to date.
Cash calls paid to Bengal’s Australian joint venture partners are held in trust accounts by the
partner until spent. Bengal attempts to mitigate the risk from joint venture receivables by approving
significant spending by partners prior to expenditure and only paying the cash call shortly before the
funds are to be spent.
56
Notes to Consolidated Financial Statements
At March 31, 2015, the Company had no accounts considered past due (past due is considered
greater than 90 days outstanding). Bengal believes these receivables will be collected.
The carrying amount of accounts receivable and cash and cash equivalents and the carrying value
of its financial instruments represent the Company’s 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, 2015 and did
not provide for any doubtful accounts nor was it required to write-off any receivables during the year
ended March 31, 2015. Exposure to the carrying value of its financial instruments relate to the
Company’s commodity based derivatives held by Westpac Banking Corporation, which carries a
Standard & Poors credit rating of AA-. Management considers the credit risk of these instruments
to be adequately mitigated by the credit stating of their holder, therefore no allowance has been
established.
Cash and cash equivalents, when held, consist of cash bank balances and guaranteed investment
certificates redeemable at any time. Bengal manages the credit exposure related to guaranteed
investments by selecting counterparties based on credit ratings and monitors all investments to
ensure a stable return, avoiding complex investment vehicles with higher risk such as asset backed
commercial paper.
(b) Liquidity risk:
Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including
work commitments, as they are due. Bengal prepares an annual budget and updates forecasts for
operating, financing and investing activities on an ongoing basis to ensure it will have sufficient
liquidity to meet its liabilities when due.
Bengal’s financial liabilities consist of accounts payable and accrued liabilities and credit facility and
amounted to $19.3 million at March 31, 2015 (March 31, 2014 - $13.4 million).
At March 31, 2015 the Company had $5.2 million of working capital, including cash and short-term
deposits of $1.7 million and restricted cash of $0.1 million.
During the year, Bengal finalized a US $25.0 million secured credit facility drawing US $14.0 million
in November and subsequently redeeming its $8.0 million notes payable. Proceeds from this facility
are restricted for use within the Cuisinier production licence. As at March 31, 2017, US$ 11.0
million remains available and undrawn on this facility.
During the year ended March 31, 2015, there has been a significant decrease in market crude
prices. The Company’s oil sales are benchmarked on dated Brent prices. The Company incurs
most of its expenditures in Australian dollars which have depreciated significantly relative to the US
dollar, in which the Company generates revenues. To mitigate net impact of declining crude prices,
, the Company is acting with its joint venture partners to reduce discretionary spending and focus
capital towards lower risk projects with near near-term cash flow upside. The Company has also
entered into derivative commodity contracts, to reduce the impacts 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.
The table below indicates the payment schedule for the credit facility:
BENGAL ENERGY LTD.
Credit facility (US$000s)
Fiscal year 2017
Fiscal year 2018
(c) Market risk:
7,750
6,250
14,000
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate
because of changes in market prices. Market risk comprises three types of risk: currency risk,
interest rate risk and other price risk. The Company is exposed to market risks resulting from
fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of
operations. A variety of derivative instruments may be used to reduce exposure to these risks.
Foreign Currency Risk
Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate
as a result of changes in foreign exchange rates. Bengal receives Canadian dollars for sales in
Canada, U.S. dollars for Australian oil sales and incurs expenditures in Australian, Canadian and
U.S. currencies. Having sales and expenditures denominated in three currencies spreads the
impact of individual currency fluctuations.
The Company may enter into derivative foreign currency contracts in order to manage foreign
currency exchange rate risk, but has not done so to date.
The table below shows the Company’s exposure to foreign currencies for its financial instruments:
As at March 31, 2015 ($000s)
Cash and short-term deposits
Restricted cash
Accounts receivable
Accounts payable and accrued liabilities
Notes payable and other long-term
liability
Credit facility
Fair value of financial instruments
Commodity Price Risk
CAD
AUD
USD
$ 130
140
70
(250)
(3)
-
-
$ 87
$ 1,094
-
3,039
(2,008)
$ 525
-
-
(31)
-
-
(16,982)
4,966
$ 2,125 $ (11,522)
Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of a
change in commodity prices. Commodity prices for petroleum and natural gas are impacted by not
only the relationship between the Canadian and United States dollar, as outlined above, but also
world economic events that dictate the levels of supply and demand. Australian oil prices are based
on the Daily Brent reference price, which trades at a premium to WTI.
At March 31, 2015, the following derivative contracts were outstanding and recorded at estimated
fair value:
58
Notes to Consolidated Financial Statements
Time Period
Type of Contract
Apr 1, 2015 – May 31, 2017
Apr 1, 2015 – May 31, 2017
($000s)
Current fair value of financial instruments
Non-current fair value of financial instruments
Total
Oil - Swap
Oil – Put option
Quantity
Contracted
(bbls)
130,252
106,569
Oil - swap
1,161
1,359
2,520
Price Floor
(US$/bbl)
Fixed Price
(US$/bbl)
N/A
80.00
Oil – put
1,003
1,443
2,446
80.00
-
Total
2,164
2,802
4,966
A US$1.00 increase in the future crude oil price per barrel would result in an approximate US
$237,000 decrease in the fair value of financial instruments at March 31, 2015 while a $US1
decrease would result in an increase of approximately US$237,000 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 material interest rate risk on its cash and cash
equivalents at March 31, 2015 as the funds are not invested in an interest bearing instrument. The
Company is exposed to interest rate risk on its credit facility. 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, 2015.
For the year ended March 31, 2015, a 1% increase in LIBOR would increase interest expense on
the credit facility by $66.
17.
CAPITAL MANAGEMENT
The Company’s policy is to maintain a strong capital base for the objectives of maintaining financial
flexibility which will allow it to execute on its capital investment program, provide creditor and market
confidence and to sustain future development of the business.
The Company manages its capital structure and makes adjustments by continually monitoring its
business conditions, including: changes in economic conditions, the risk profile of its drilling inventory,
the efficiencies of past investments, the efficiencies of forecasted investments and the timing of such
investments, the forecasted cash balances, the forecasted commodity prices and resulting cash flow.
In order to maintain or adjust the capital structure, the Company may from time to time issue shares (if
available on reasonable terms), issue debt instruments, sell assets, farm out properties and adjust its
capital spending to manage current and projected cash levels. There can be no assurance that equity
financing will be available or sufficient to meet capital commitments, or for other corporate purposes, or
if equity financing is available, that it will be on terms acceptable to the Company.
The Company has drawn US $14 million from its US $25 million available credit facility and typically
structures its debt position below 2.0 times projected 12 month net operating cash flows. The Company
is within these parameters at March 31, 2015.
BENGAL ENERGY LTD.
18.
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
$
$
$
$
2015
712
142
(1,885)
48
(983)
2,332
(673)
(2,642)
(983)
The following represents the cash interest paid and received in each period.
Year ended March 31 ($000s)
Cash interest paid
Cash interest received
$
$
2015
1,201
13
$
$
$
$
$
$
19.
COMMITMENTS AND CONTINGENCIES
Commitments:
2014
(271)
(380)
(449)
(305)
(1,405)
(592)
(808)
(5)
(1,405)
2014
708
74
Pursuant to current production sharing contracts (“PSC”), the Company is required to perform minimum
exploration activities that include various types of surveys, acquisition and processing of seismic data
and drilling of exploration wells. Additional commitments are reflected where the Company has agreed
with joint venture partners to proceed with activities. The costs of these activities are based on minimum
work budgets included in bid documents and have not been provided for in the financial statements.
Actual costs will vary from budget.
Country and
Permit
Work Program
Obligation
Period Ending
Estimated
Expenditure (net)
(millions CAD$)(1)
Onshore India – CY-
ONN-2005/1
Three wells
Currently under Force
Majeure(2)
$5.3
(1) Translated at March 31, 2015 at an exchange rate of US $1.00 = CAD $1.2642
(2) If the Company did not participate in the drilling of three wells, costs of $5.3 million would be impaired and the
Company’s interest in the permit would decline.
At March 31, 2015 the Company had the following lease commitment for office space in Canada.
($000s)
April 2015 to March 2017
Office lease
Total
$ 595
Less than
1 Year
263
1-3
Years
332
4-5
Years
-
After
5 Years
-
Effective April 1, 2012 the Company entered into a head lease in Calgary, Canada for a term of five
years.
60
Notes to Consolidated Financial Statements
Contingencies:
Effective March 1, 2015 ATP 934 has been granted for a period of 12 years comprised of 3, 4 year
terms. In the first four year work program Bengal is committed to capital spending of approximately
$22.6 million dollars (net $11.3 million) dedicated to acquisition of new 2D and 3D seismic as well as
drilling of up to 8 new wells. Bengal has made application to the Queensland Government for a smaller
work program to reflect geographical conditions that may preclude surface access to parts of ATP 934.
Country and
Permit
Work Program
Obligation
Period Ending
Estimated
Expenditure (net)
(millions CAD$)
Onshore Australia –
ATP 934P
Awaiting Ministerial approval before
granting of ATP
4 years after grant of
ATP
$ 11.3
20.
SUPPLEMENTAL DISCLOSURE
Bengal’s consolidated statement of income (loss) and comprehensive income (loss) is prepared
primarily by nature of expense. All salaries for the Company are included in general and administrative
expenses and for the year ended March 31, 2015 amount to $1.4 million (March 31, 2014 - $1.4
million).
21.
RELATED PARTY TRANSACTIONS
On July 5, 2013, the Company issued $8.0 million of 10% non-convertible notes with warrants or value
appreciation rights. Members of the Board of Directors of the Company subscribed for approximately
44% of the principal amount of the notes issued pursuant to the private placement. In October 2014,
the Company repaid $500,000 of outstanding principal of notes issued July 5, 2013 (“Notes”). In
November 2014, the Company redeemed the Notes for a redemption price equal to $1.03 per $1.00 of
outstanding principal amount plus all accrued and unpaid interest thereon.
On January 24, 2014 the Company extended its $1.75 million notes payable to January 23, 2015.
Members of the Board of Directors of the Company held 100% of this facility, which was fully redeemed
on January 21, 2015. Two directors were issued 3,485,714 shares of the Company valued at $0.28 per
share in lieu of a cash settlement of $976,000.
22.
SUBSEQUENT EVENTS
Effective April 1, 2015 Bengal acquired an additional 30% working interest in ATP 934 from one of its
Joint Venture partners for a total acquisition price of $0.1 million. This acquisition is subject to
ministerial approval. The remaining joint venture partner, effective June 19, 2015 exercised its option to
purchase 8.6% of this interest; therefore Bengal’s current working interest is 71.4%.
23.
SEGMENTED INFORMATION
As at March 31, 2015, the Company has three reportable operating segments being the Australian,
Canadian and India oil and gas operations.
Revenue reported below represents revenue generated from external customers. There were not inter-
segment sales in any of the reported periods.
The accounting policies of the reportable segments are the same as the group’s accounting policies.
Segment profit represents the profit earned by each segment without allocation of central administration
BENGAL ENERGY LTD.
costs and directors’ salaries, finance costs and income tax expense. This is the measure reported to the
chief operating decision maker for the purposes of resource allocation and assessment of segment
performance.
62
For the year ended March 31, 2015 ($000s)
Revenue
Interest revenue
Interest expense
Depletion and depreciation
Net (earnings) loss
Exploration and evaluation expenditures
Petroleum and natural gas property
expenditures
Property, plant & equipment expenditures
Impairment losses (recovery)
March 31, 2015 ($000s)
Petroleum and natural gas properties
Cost
Impairment loss
Accumulated depletion, depreciation and
accretion
Net book value
Exploration and evaluation assets
Accumulated impairment losses
Net book value
Property, plant & equipment
Accumulated depletion, depreciation and
accretion
Impairment
Net book value
For the year ended March 31, 2014 ($000s)
Revenue
Interest revenue
Interest expense
Depletion and depreciation
Net (earnings) loss
Exploration and evaluation expenditures
Petroleum and natural gas property
expenditures
Property, plant & equipment expenditures
Impairment losses (recovery)
March 31, 2014 ($000s)
Petroleum and natural gas properties
Cost
Impairment loss
Accumulated depletion, depreciation and
accretion
Net book value
Exploration and evaluation assets
Accumulated impairment losses
Net book value
Property, plant & equipment
Accumulated depletion, depreciation and
accretion
Impairment
Net book value
Notes to Consolidated Financial Statements
Canada
274
1
880
413
(6,964)
-
India
-
-
-
-
(562)
105
Total
15,669
18
1,212
5,036
(3,172)
3,189
Australia
15,395
17
332
4,623
4,354
3,084
10,274
-
1,592
-
-
3,296
-
-
-
-
-
-
-
10,274
-
4,888
39,044
(1,233)
(10,689)
27,122
40,616
(12,371)
28,245
5,130
(403)
(4,727)
-
34,407
(796)
4,637
(437)
(6,586)
27,025
(4,103)
97
32,653
(11,179)
21,474
-
-
-
-
-
-
5,130
(403)
(4,727)
-
7,963
(1,192)
6,771
-
-
-
Australia
19,480
73
-
4,435
6,802
767
14,313
-
-
Canada
342
1
777
96
(4,976)
-
India
-
-
-
-
(1,676)
1,196
-
371
1,928
-
-
1,173
Total
19,822
74
777
4,531
150
1,963
14,313
371
3,101
24,105
-
4,617
-
(3,034)
21,071
30,619
(9,621)
20,998
(4,019)
598
-
-
-
-
-
-
-
28,722
-
(7,053)
21,669
6,993
(1,170)
5,823
37,612
(10,791)
26,821
-
-
-
-
5,127
(70)
(1,557)
3,500
-
-
-
5,127
(70)
(1,557)
3,500
BENGAL ENERGY LTD.
CORPORATE INFORMATION
AUDITORS
KPMG LLP • Calgary, Canada
LEGAL COUNSEL
Burnet, Duckworth & Palmer LLP • Calgary, Canada
Johnson Winter Slattery • Brisbane, Australia
BANKERS
Royal Bank of Canada • Calgary, Canada
West Pac Bank • Brisbane, Australia
Commonwealth Bank • Brisbane, Australia
ICICI Bank Ltd. • Calgary, Canada and Mumbai, India
REGISTRAR AND TRANSFER AGENT
Valiant Trust Corporation • Calgary, Canada
INVESTOR RELATIONS
5 Quarters Investor Relations, Inc. • Calgary, Canada
DIRECTORS
Chayan Chakrabarty
Peter D. Gaffney
James B. Howe
Dr. Brian J. Moss
Robert D. Steele
Ian J. Towers (Chairman)
W.B. (Bill) Wheeler
DISCLOSURE COMMITTEE
All Directors are members of the Committee
AUDIT COMMITTEE
James B. Howe (Chairman)
Robert D. Steele
W.B. (Bill) Wheeler
RESERVES COMMITTEE
Peter D. Gaffney (Chairman)
Dr. Brian J. Moss
GOVERNANCE AND COMPENSATION COMMITTEE
Peter D. Gaffney
Dr. Brian J. Moss
Robert D. Steele (Chairman)
Ian J. Towers
OFFICERS
Chayan Chakrabarty, President & Chief Executive Officer
Richard N. Edgar, Executive Vice President
Jerrad Blanchard, Chief Financial Officer
Gordon R. MacMahon, Vice President, Exploration
Bruce Allford, Secretary
STOCK EXCHANGE LISTING – TSX: BNG
64