Bengal Energy Ltd.
Annual Report 2017

Plain-text annual report

International Exploration & Production Annual Report Twelve Months Ended March 31, 2017 BENGAL ENERGY LTD. TABLE OF CONTENTS Message to Shareholders ........................................................................... 3 Fiscal 2017 Highlights ................................................................................. 5 Management’s Discussion and Analysis .................................................. 6 Consolidated Financial Statements ......................................................... 28 Notes to the Consolidated Financial Statements .................................... 35 Corporate Information .............................................................................. 58 2 BENGAL ENERGY LTD. BENGAL ENERGY LTD. MESSAGE TO SHAREHOLDERS During fiscal 2017, Bengal continued to focus on a balance of low-risk development and near field exploration drilling in the face of volatile oil prices. Our prudent 2017 capital program was underpinned by our attractive hedge position, which allowed the company to execute meaningful advancement on several core assets. Bengal’s operational activities were specifically focused in the Cuisinier field within ATP 752 Barta Block (30% working interest), and all wells achieved geological success. I am pleased with the progress Bengal made over the past year to further develop and grow our reserves and future production base, while we also remain especially bullish on our high-impact natural gas exploration assets which could deliver significant long-term optionality for shareholders. The Cuisinier drilling campaign consisted of five wells, including three low-risk development locations in the central/south part of Petroleum Lease (“PL”) 303, one appraisal well (Cuisinier-22) and a near field exploration well (Shefu-1). All five wells drilled were successful in locating oil-bearing sands, but were not connected and producing during the fiscal year. Four of these wells were completed and commenced production in May of 2017, while the fifth well (Cuisinier-23) is a future fracture stimulation candidate following the evaluation of nearby well performance. Our exploration well, Shefu-1, was situated on the western flank of PL 303 and encountered 7 meters of net pay; the discovery was also structurally lower than previous rounds of appraisal drilling at Cuisinier and further confirmed our view of incremental reserves and production potential in the area. Production for 2017 averaged 379 bopd, a decrease of 25% over fiscal 2016 due to natural production declines, but the successful drilling of the appraisal and exploration locations increased reserves through the expansion of pool boundaries. Bengal grew its Proved plus Probable (“2P”) reserves during the fiscal year by 14% to 7,056 Mbbls and proved reserves increased by 25% to 2,761 Mbbls. The net present value (NPV10, before tax) of Bengal’s 2P reserves increased to $118 million, or $1.15 per share and the Company’s net asset value, which deducts net debt is $108.5 million or 1.06 per share. W e remain confident in our ability to further grow the size and value of our reserves base through future drilling programs. In late December 2016, the Company successfully completed a $4.1 million rights offering, of which approximately 39% was subscribed for by insiders of Bengal, which will be used to fund the development program on the Barta Sub-Block of ATP 752. This program includes the completion and tie-in of the wells drilled in calendar 2016 (Cuisinier-22, Cuisinier-24, Cuisinier-25 and Shefu-1) and the acquisition of Barta West 3D seismic to allow further definition of the Shefu-1 oil discovery. Planning for the 3D seismic program has been finalized, with activities expected to commence shortly, and will cover an estimated 250 square kilometers. Bengal views the Barta West area as a continuing natural extension from the de-risked Cuisinier pool area and our technical team has mapped numerous prospects on existing 2D seismic. During the year, Bengal completed the reprocessing of 500+ line kilometers of 2D seismic over the ATP 934 Barrolka permit and the most favourable areas have been high-graded for additional detailed geophysical work. We are encouraged by recent natural gas discoveries surrounding the Barrolka permit, which suggest the presence of a basin centered gas play in the region, as well as significant conventional potential for natural gas in the Permian Toolachee and Patchawarra sandstone reservoirs. Neighboring gas fields offsetting ATP 934 are producing approximately 18 mmcf/d with 400 bbls/d of condensate. Infrastructure is developed with numerous gas pipelines crossing the Bengal permit. Bengal holds a 71% working interest and operatorship in the ATP 934 permit and has commenced discussions with third parties who may have an interest in farming in on this block. The permit is now in Year 2, having met the Year 1 permit commitment with the reprocessing of the existing 2D data, and planning for the Year 2 commitment program (260 square kilometer 3D seismic acquisition program) has begun with favourable contractor bids already secured. Bengal's view of the potential for significant gas discoveries on the ATP 934 permit is supported by both 2D and 3D seismic data and our team has identified and mapped a total of five individual ‘conventional’ drilling prospects to date. 3 BENGAL ENERGY LTD. The near-term outlook for crude oil and natural gas prices in the Australian market has become somewhat two pronged due to unique domestic dynamics. While Brent and WTI oil prices remain volatile and under pressure, natural gas prices have reached record highs in eastern Australia due to the significant increase in demand associated with several newly commissioned LNG export projects. We are encouraged on the outlook for natural gas demand continuing to grow over the medium term and we are also bullish on the multiple marketing opportunities to optimize ATP 934 natural gas pricing and returns. Bengal has also recently executed a new Crude Oil Sale and Purchase Agreement (“COSPA”) with the South Australia Cooper Basin Joint Venture, which will provide improved pricing over previous levels based on a direct pass-through mechanism. Exploration is also incentivized in the new agreement, with incremental volumes attracting further improved pricing. We are also revising our agreement with the Aquitaine B Joint Venture parties for crude oil produced at the Cuisinier Field, which is expected to reduce transportation tariffs. The impact of both the transportation tariff reductions and the new COSPA pricing are expected to be realized in improved netbacks commencing in fiscal Q2 2018 and will partially offset the impact of the company’s US$80/bbl hedges that expire in June 2017. Bengal will continue to maintain a prudent approach to our fiscal 2018 capital program in light of the oil price uncertainty, while also focusing on risk management strategies and protecting cash flow. We remain bullish on our core Australian market which is a very strong platform for future growth given the unique combination of fiscal stability, attractive gas market fundamentals, established infrastructure and high- impact exploration potential. I want to thank our strong and supportive Board of Directors, our diligent and talented technical team, as well as each of our shareholders for your support as we continue to methodically develop our world-class assets. Sincerely, (signed) “Chayan Chakrabarty” Chayan Chakrabarty President & CEO Note: this Message to Shareholders contains forward-looking statements and is subject to the forward looking statement disclaimer in the Management’s Discussion & Analysis for the Years Ended March 31, 2017 and 2016. 4 2017 Annual Report FISCAL 2017 HIGHLIGHTS Financial Highlights:  Continued Reserve Growth - The Company’s independently evaluated year-end corporate reserve volumes have increased by 25% and 14% to 2,761 thousand barrels (Mbbls) and 7,056 Mbbls for the Proved (“1P”) and Proved plus Probable (“2P”) reserve categories respectively. These increases result from the impacts of the Company’s ongoing capital programs. Based on 1P and 2P reserves additions, Bengal has replaced approximately 5 times and 7 times its annual corporate production, respectively.  Revenue – Crude oil sales revenue was $2.2 million in the fourth quarter of fiscal 2017, which is 4% lower than the $2.3 million recorded in Q3 2017 and 3% lower than crude oil sales during fiscal Q4 2016. The decreases are driven by natural production declines, partially offset by increases in benchmark crude oil prices. Annual crude oil sales for fiscal 2017 were $9.3 million compared to $11.2 million during fiscal 2016. The 17% decline is due primarily to natural production declines.  Hedging – At March 31, 2017, the Company had 29,000 barrels of oil (“bbls”) remaining in its US $80 hedging program, which is comprised of a blend of puts and swaps with a floor price of US $80/bbl that expire on June 30, 2017.  Funds Flow from Operations – Funds flow from operations generated during Q4 2017 was $1.6 million compared to $1.4 million during the previous quarter and during fiscal Q4 2016. The increase is due to reductions in operating expenses and royalty credits realized during the quarter. Annual funds from operations were $6.2 million in fiscal 2017 compared to $4.0 million in fiscal 2016. The 57% increase was the result of a 23% increase in realized gain on financial instruments and royalty credits described above.  Earnings - The Company recorded net income of $1.9 million for the fourth quarter of fiscal 2017, compared to a $2.3 million net loss in the preceding quarter and a net loss $11.7 million during Q4 fiscal 2016. Annual net losses were $2.8 million during fiscal 2017 compared to losses of $10.4 million recorded in the previous year. Excluding the impact of unrealized foreign exchange and unrealized hedging gains and losses, adjusted net earnings were $1.2 million for the fourth quarter of fiscal 2017 compared to an adjusted net loss of $0.8 million during the previous quarter and an adjusted net loss of $10.7 million recorded in fiscal Q4 2016. Annual adjusted net income was $3.6 million compared to an adjusted net loss of $12.3 million recorded during the previous year.  Rights Offering – On December 29, 2016, the Company completed a rights offering raising $4.0 million net of $0.1 million of share issue costs. OPERATIONAL HIGHLIGHTS:  Production Volumes – Production (net to Bengal) in the fourth quarter of fiscal 2017 averaged 344 barrels of oil per day (“bopd”), a 3% and 27% decrease compared to the preceding quarter and fiscal Q4 2016, respectively. These decreases were due to natural production declines. Four of the five wells drilled during fiscal 2017 were connected in May of 2017 with initial combined production rates of approximately 245 bopd (gross). These initial rates are less than pre connection expectations and continued optimization and well cleanup work is ongoing. With recent positive results from fracture stimulation programs, the Joint Venture will review the 2016 wells for stimulation in addition to planning frac programs to occur immediately after completion in future drilling campaigns. In Bengal’s opinion, operational delays experienced between completion and tie-in during the 2017 5 2017 Annual Report campaign may have been a contributor to longer well clean up timing and on initial reservoir performance. Bengal will continue to closely monitor production rates of the newly connected wells.  Cuisinier 2016 drilling program – All five wells drilled during the year were successful in locating oil-bearing sands and four of these wells were completed and commenced production in May 2017. The fifth well, Cuisinier-23 was suspended as a future fracture stimulation candidate following the evaluation of nearby well performance. This drilling program included one appraisal well (“Cuisinier- 22”) and one exploration well (“Shefu-1”). Successful drilling of the appraisal and exploration locations have materially increased the Company’s reserve volumes by expanding the pool boundaries.  Credit Facility Update - On August 26, 2016, the Company extended its credit facility with Westpac Banking Corporation by 18 months with a borrowing base of US $15 million. The borrowing base, if not further extended, will follow a reduction schedule of US $5 million in December 2017, US $5 million in June 2018, and US $5 million in December 2018. All associated terms and covenants are consistent with the existing facility.  Onshore India – Effective June 1, 2016, Bengal and its partners provided notice to the applicable Government of India Authorities of its intention to exit the CY-ONN-2005/1 exploration block. The joint venture was unable to acquire the land rights required for exploration causing a force majeure condition for the duration of the first term of exploration, and is therefore entitled to exit the permit without penalty for unfinished work program commitments. Subsequent to the year-end, this application was accepted by the Director General of Hydrocarbons and is awaiting final approval from the Ministry of Petroleum and Natural Gas. With the exit from the permit, the Company has effectively ceased all operations in India. MANAGEMENT’S DISCUSSION AND ANALYSIS – JUNE 15, 2017 Bengal’s producing assets are predominantly situated in Australia’s Cooper Basin, a region featuring large hydrocarbon pools. The Company’s core Australian assets, Cuisinier, Barrolka and Tookoonooka, are situated within an area of the Cooper Basin. Still in early stages, in terms of appraisal and development, Bengal believes these assets offer attractive upside potential. Australia features a stable political, fiscal and economic environment in which to operate, with a favorable royalty regime for oil and gas production. OUTLOOK AUSTRALIA ATP 752 Barta Block Cuisinier During the second half of calendar 2017, the Joint Venture will commence a fracture stimulation program on the Cuisinier North 1, Cuisinier 2 and Cuisinier 19 wells. Production testing at these new and stimulated wells will assist the Joint Venture in planning for its next drilling campaign. The Cuisinier 23 well has encountered hydrocarbon bearing sands based on logging results, however estimated deliverability is uncertain, therefore future completion and potential stimulation of this well will be evaluated along with production rates from the recently tied-in wells. Given the current crude pricing environment, the Company plans to defer the selection of wells for its next drilling program until the results from the recent fracture stimulation program have been fully evaluated and there is sufficient production history on the newly connected wells (Cuisinier 22, Cuisinier 24, Cuisinier 25 and Shefu 1) 6 2017 Annual Report The Barta Joint Venture have commenced preliminary discussions on the implementation of a pilot pressure maintenance scheme following receipt of a preliminary Field Development Plan from the operator. The Joint Venture is also in the preliminary stages of planning for a 3D seismic program in the Barta West area, immediately west of Cuisinier PL303. The 3D will cover an area of approximately 250 km2 with timing to be finalized in the coming months pending resolution of surface access and Native Title Cultural Heritage surveys. Initial estimates are that the seismic acquisition portion of the survey will be done during Q3 2017 with processing and interpretation to follow. ATP 934 Barrolka Bengal has completed reprocessing of 500+ line kilometers of 2D seismic over the permit and interpretation of this data is now complete. Seismic amplitude inversion studies are underway and the most favorable areas of the permit have been high-graded for additional detailed geophysical work that may include the acquisition of 3D seismic in 2017. The Company is encouraged by recent natural gas discoveries near the Barrolka permit, which suggest the presence of a basin centered gas play in the region, as well as significant conventional potential for natural gas occurrence in the Permian Toolachee and Patchawarra sandstone reservoirs. Bengal is operator with a 71% working interest in this permit and has held preliminary discussions with third parties who may have an interest in farming in on this block. ATP 732 Tookoonooka Block The Tookoonooka Permit (ATP 732 – 100% WI effective January 28, 2016) is located in the emerging East Flank oil fairway of the Cooper Basin. Beach Energy Ltd. (“Beach”) completed the acquisition of 300 km 2 3D seismic in Tookoonooka in February 2014 and subsequently relinquished its interest in the permit; Bengal was fully carried for the cost of this seismic program. The Company made application for the required regulatory relinquishment of 1/3 of the block and filed a revised Later Work Program (LWP) application covering the period March 2017 through March 2019. Among other things, this LWP will allow Bengal to study the Permian gas potential along the northern flank of the permit as well as the largely unexplored oil potential in the southern part of the permit closer to the producing Jackson/Jackson South Field which has produced greater than 49.4 million barrels of oil to date. Regulatory approval of the LWP application was received May 30, 2017. ATP 752 Wompi The Nubba-1 well encountered multiple oil shows within the Jurassic, as well as up to 6 metres of Permian Toolachee gas. Pressure testing, as well as logging, suggests that this Toolachee gas well could be part of a gas column that may be up to 70 metres in height. This suggests the prospective gas pay extends down dip of the Nubba well where seismic indicates the Toolachee section thickens. A Potential Commercial Area (PCA) will be applied for which will allow for commercialization. The produced natural gas would likely be pipeline connected to the nearest gas transmission line in the area, which is approximately 5 kilometres from the Nubba-1 well. Wompi (38% Bengal interest) offers Bengal moderate risk exploration in a well- established, oil-producing fairway with multi-zone potential and the Joint Venture is currently evaluating the appropriate timing to continue the development of this discovery, which is not expected to occur during the first half of calendar 2017. 7 2017 Annual Report AC/RL 10 (formerly AC/P 24), Ashmore Cartier Area, Timor Sea, Offshore Australia Bengal holds a 10% working interest in the Ashmore Cartier Retention License 10 ("AC/RL 10") located in the Ashmore Cartier area offshore Australia comprised of approximately 168 square kilometers (41,514 acres). Bengal is partnered with PTTEP Australia Timor Sea Pty Ltd. (90% working interest) and operator. This permit was granted as a five year Petroleum Retention Lease, AC/RL 10 on March 22, 2013 expiring March 21, 2018. Subject to fulfilling acceptable later work programs, AC/RL10 may be continued for two further five year terms. The operator continues to reprocess existing 3D seismic data and evaluate commercialization options. OPERATING HIGHLIGHTS $000s except per share, volumes and netback amounts Oil sales revenue Realized gain on financial instruments Royalties % of revenue Operating & transportation Operating netback(1) Cash from operations: Funds from operations: Per share ($) (basic & diluted) Net income (loss) Per share ($) (basic & diluted) Adjusted net (loss) income (2) Per share ($) (basic & diluted) Capital expenditures Oil Volumes (bopd) Netback(1) ($/boe) Revenue Realized gain on financial instruments Royalties Operating & transportation Three Months Ended March 31 Twelve Months Ended March 31 2017 2016 % Change 2017 2016 % Change $2,179 $ 2,253 (3) $ 9,294 $ 11,187 (17) $971 $ 1,833 $(347) (16) $ 987 $ $ 106 5 1,474 (47) (427) (420) (33) $2,510 $ 2,506 - 1,496 1,439 0.02 (57) 14 - $643 $ $ $1,639 0.02 $1,931 $ 0.02 $1,181 0.01 (11,704) (0.17) $ (10,685) (0.16) (117) (112) (111) (106) $681 $ 332 105 344 469 (27) $4,712 $(213) (2) $4,864 $9,355 $4,515 $6,196 0.08 $ 3,840 23 $ 728 7 $ 6,480 (129) (129) (25) $ 7,819 20 $ 5,398 (16) $ 4,048 0.06 53 33 $(2,768) $ (10,380) (0.04) $3,605 0.05 $5,618 379 (73) (0.15) (73) $ (12,270) (0.18) (129) (128) $ 3,347 68 505 (25) $70.40 $ 52.83 33 $67.17 $ 60.54 11 31.37 (11.21) 31.89 42.98 2.49 34.57 (27) (550) (8) 34.06 20.78 3.94 (1.54) 35.07 35.16 64 (139) - Netback/boe $81.09 $ 58.75 38 $67.61 $ 42.31 60 (1) Operating netback is a non-IFRS measure. Netback per boe is calculated by dividing the revenue (including gain on financial instruments) less royalties, operating and transportation costs by the total production of the Company measured in boe. (2) Adjusted net (loss) is a non-IFRS measure. The comparable IFRS measure net loss. A reconciliation of the two measures can be found in the table on page 6. BASIS OF PRESENTATION This MD&A and accompanying financial statements and notes are for the three and twelve months ended March 31, 2017 and 2016. The terms “current quarter”, Q4 2017 and “the quarter” are used throughout the MD&A and in all cases refer to the period from January 1, 2017 through March 31, 2017. The terms “prior year’s quarter”, Q4 2016 and “2016 quarter” are used throughout the MD&A for comparative purposes and refer to the period from January 1, 2016 through March 31, 2016. The fiscal year for the Company is the twelve-month period ended March 31, 2017. The terms “fiscal 2017,” “current year” and “the year” are used in the MD&A and in all cases refer to the period from April 1, 2016 8 2017 Annual Report through March 31, 2017. The terms “previous year,” “prior year” and “fiscal 2016” are used in the MD&A for comparative purposes and refer to the period from April 1, 2015 through March 31, 2016. The term YTD means year-to-date. For the purpose of calculating unit costs, natural gas volumes have been converted to barrels of oil equivalent (“boe”) using a conversion ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel (“bbl”) of oil. This conversion ratio of 6:1 is based on an energy equivalency conversion for the individual products, primarily at the burner tip, and is not intended to represent a value equivalency at the wellhead. Such disclosure of boe may be misleading, particularly if used in isolation. The following abbreviations are used in this MD&A: boepd means barrels of oil equivalent per day; bpd means barrels per day; mcfpd means thousand cubic feet of natural gas per day; $/boe means Canadian dollars per boe; and NGL means natural gas liquids. NON-IFRS MEASUREMENTS Within the MD&A references are made to terms commonly used in the oil and gas industry. Netbacks and adjusted net earnings do not have any standardized meaning under IFRS and are referred to as non-IFRS measures. Netbacks equal total revenue (including realized gain on financial instruments) less royalties and operating and transportation expenses calculated on a boe basis. Management utilizes these measures to operational performance. Adjusted net earnings is a non-IFRS measure, which should not be considered an alternative to “Net income (loss)” as presented in the consolidated statement of income (loss) and comprehensive income (loss), and is presented in the Company’s financial reports to assist management and investors in analyzing financial performance net of gains and losses outside of management’s immediate control. Adjusted net earnings equal net income (loss) less unrealized losses/gains on foreign exchange and unrealized losses/gains on financial instruments. Adjusted net earnings per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of earnings (loss) per share. The following table reconciles net income (loss) to adjusted net earnings (loss), which is used in the MD&A: Three Months Ended March 31 Twelve Months Ended March 31 $000s Net income (loss) Unrealized loss (gain) on financial Instruments Unrealized foreign exchange loss (gain) 2017 1,931 241 (991) 2016 % Change 2017 2016 % Change (11,704) (117) (2,768) (10,380) (73) 1,941 (88) 6,308 (1,861) (922) 8 65 (29) (439) (324) (129) Adjusted net (loss) earnings 1,181 (10,685) (111) 3,605 (12,270) RESULTS OF OPERATIONS - AUSTRALIA Netbacks Production Three Months Ended March 31 2016 2017 % Change Twelve Months Ended March 31 2016 2017 % Change Oil Production (boepd) 344 469 (27) 379 505 (25) ($000s) Oil sales Realized gain on financial instrument Royalties Operating and transportation 971 (347) 1,833 106 (47) 4,712 (427) (213) expenses 987 1,469 (33) 4,864 2,179 2,253 (3) 9,294 11,187 (17) 3,840 728 6,463 23 (129) (25) 9 Netback ($000s) 2,510 2,511 Oil sales ($/bbl) Realized gain on financial instrument Royalties ($/bbl) Operating and transportation expenses ($/bbl) Netback ($/bbl) 70.40 52.83 31.37 (11.21) 31.89 81.09 42.98 2.49 34.45 58.87 Production, Commodity Pricing and Sales Production 2017 Annual Report - 33 9,355 7,836 67.17 60.54 (27) 34.06 (550) (1.54) (7) 38 35.16 67.61 20.78 3.94 34.98 42.40 19 11 64 (139) 1 59 Quarterly production during fiscal Q4 2017 decreased 27% compared to fiscal Q4 2016 and 3% compared to the preceding quarter. These decreases in production are due primarily to natural declines as production from the Cuisinier 2016 drilling program did not come on stream until May of 2017. Pricing The price received for Bengal’s Australian oil sales is benchmarked on Dated Brent quotes as published by Platts Crude Oil Marketwire for the month in which the Bill of Lading occurs, plus a Platts Tapis premium. Brent typically has traded at a premium to West Texas Intermediate (WTI) and the Platts Tapis premium received has averaged US $1.68 bbl over Brent for the twelve months ended March 31, 2017 (2016 – US $2.10). Realized crude oil prices in Q4 2017 increased by 33% compared to Q4 2016 and decreased by 1% compared to Q3 2017 due to corresponding fluctuations in benchmark pricing and a decrease to the Tapis premium realized in fiscal Q4 2017. Annual average realized prices increased by 11% compared to the prior fiscal year. The declines in Brent crude prices through fiscal 2017 have been partially offset by foreign exchange gains as the value of Canadian and Australian dollars has decreased relative to the U.S. dollar. The Company’s reported sales include approximately 30,000 bbls of crude for which prices were not yet determined at March 31, 2017 and therefore valued at year-end pricing. The following table outlines average benchmark prices compared to Bengal’s realized prices: Prices and Marketing Three Months Ended March 31 Twelve Months Ended March 31 Average Benchmark Price 2017 2016 % Change 2017 2016 % Change Bengal realized crude oil price before realized gain on financial instruments($CAD/bbl) Realized gain on financial Instruments ($CAD/bbl) Dated Brent oil ($CAD/bbl) Dated Brent oil ($US/bbl) Number of CAD$ for 1 AUS$ Number of CAD$ for 1 US$ Risk Management Activities 70.40 $ 52.83 33 $67.17 $ 60.54 31.37 71.18 53.78 1.00 1.32 42.98 46.53 33.89 0.99 1.37 (27) 53 59 1 (4) 34.06 63.88 48.66 0.99 1.31 20.78 62.20 47.44 0.96 1.31 11 64 3 3 3 - Bengal has entered into financial commodity contracts as part of its risk management program to manage commodity price fluctuations related to its primary producing assets being the Cuisinier field in Australia’s Cooper Basin. With respect to financial contracts, which are derivative financial instruments, management has elected not to use hedge accounting and consequently records the fair value of its crude oil financial contracts on the 10 2017 Annual Report statement of financial position at each reporting period with the change in fair value being classified as unrealized gains and losses in the consolidated statement of income. The Company has managed the price application to production volumes through the following contracts: Time Period Type of Contract Quantity Contracted (bbls) Price Floor (US$/bbl) Price Ceiling (US$/bbl) April 1, 2017 – May 31, 2017 Oil - Swap April 1, 2017 – May 31, 2017 Oil – Put option 15,814 12,937 80.00 80.00 80.00 - Time Period Type of Contract Quantity Contracted (bbls) Price Floor (US$/bbl) Price Ceiling (US$/bbl) July 1, 2017 – December 31, 2018 Oil - Swap July 1, 2017 – December 31, 2018 Oil – Put option 67,373 67,373 47.00 47.00 47.00 - The fair value of the financial contracts outstanding as at March 31, 2017 is an estimated asset of $0.7 million. The fair value of these contracts is based on an approximation of the amounts that would have been paid or received from counterparties to settle the contracts outstanding at the end of the period having regard to forward prices and market values provided by independent sources. Due to the inherent volatility in commodity prices, actual amounts realized may differ from these estimates. For the three months ended March 31, 2017, the Company’s derivative commodity contracts resulted in a realized gain of $1.0 million (2016 - $1.8 million) and an unrealized loss of $0.2 million (2016 - $1.9 million). Realized gains were impacted by increased benchmark crude oil prices during fiscal Q4 2017 compared to Q4 2016. For the twelve months ended March 31, 2017, the derivative commodity contracts resulted in a realized gain of $4.7 million (2016 - $3.8 million) and an unrealized loss of $6.3 million (2016 – gain of $1.8 million). Realized gains were impacted by increased benchmark crude oil prices during fiscal 2017 compared to fiscal 2016. A total of 120,000 barrels were hedged during fiscal 2017 compared to 88,000 in fiscal 2016 resulting in a net 23% increase in annual realized gain on financial instruments. Royalties Royalties ($000s) Royalty Expense $/bbl % of revenue Three Months Ended Twelve Months Ended March 31 March 31 2017 2016 % Change (347) (11.21) (16) 106 2.49 5 (427) (550) (420) 2017 (213) (1.54) (2) 2016 % Change 728 3.94 7 (129) (139) (129) In Australia, oil royalties are based on a government-established rate of 10% plus a Native Title royalty which is typically 1%. The royalty rate is applied to gross revenues after deducting an allowance for transportation operating and allowable capital costs, resulting in an effective rate of less than 10%. During the year, the Barta Joint Venture operator revised its allowable capital calculation submitted to the relevant authorities. Due to uncertainties regarding the acceptance of the Operator’s revised royalty calculation, the Company had accrued royalty expenses based on the previously accepted methodology. The period for royalty assessment has expired without adjustment, thus Bengal is satisfied that the royalty calculation as submitted by the Joint Venture operator is acceptable. The Company reversed its Royalty accrual during fiscal Q4 2017. Due to this credit, Royalties per barrel are in a credit position for both the quarter and year ended March 31, 2017. 11 2017 Annual Report OPERATING & TRANSPORTATION EXPENSES Operating & trans. expenses ($000s) Operating Transportation Operating - $/boe Transp. - $/boe Three Months Ended Twelve Months Ended March 31 2017 2016 % Change 53 934 987 1.71 30.18 31.89 159 1,310 1,469 3.73 30.72 34.45 (67) (29) (33) (54) (2) (7) 2017 563 4,301 4,864 4.07 31.09 35.16 March 31 2016 % Change 994 5,469 6,463 5.38 29.60 (43) (21) (25) (24) 5 34.98 1 Operating costs per barrel decreased by 67% compared to Q4 2016 and 76% compared to the prior quarter. Total operating expenses for the Cuisinier field, which comprises a majority of the Company’s operations are accrued based on the Operator’s annual budget. Actual operating costs incurred during the year were below budget expectations due to a general reduction costs across Australia’s Cooper Basin, therefore a portion of the Company’s operating expense accrual was reversed during Q4 2017. Annual operating costs per barrel have decreased by 43%, which reflects basin wide cost reductions as well as the Operator’s focus on cost control. Transportation costs on a boe basis decreased 2% compared to Q4 2016 and 7% compared to the prior quarter. Annual transportation costs have increased by 5% compared the prior fiscal year. These fluctuations relate primarily to foreign exchange fluctuations between the Australian and Canadian dollars. GENERAL AND ADMINISTRATIVE (G&A) EXPENSES AND SHARE-BASED COMPENSATION (“SBC”) G&A Expenses and SBC ($000s) Three Months Ended Twelve Months Ended Net G&A Capitalized G&A Total G&A Expensed share-based compensation Capitalized share-based compensation Total share-based compensation March 31 2016 690 91 % Change 4 (9) 781 17 - 17 3 (76) - (71) 2017 721 83 804 4 1 5 March 31 2016 % Change 3 2,663 1 335 2,998 3 91 10 101 (68) (30) (64) 2017 2,740 338 3,078 29 7 36 Total G&A expenditures increased by 3% compared to fiscal Q4 2016 and by 10% compared to the prior quarter while annual G&A expenditures have increased by 3%. These minor increases reflect increased travel costs associated with the Company’s business development initiatives. The Company uses the Black-Scholes pricing model to estimate the fair value of options on the date of grant and amortizes the estimated expense over the vesting period with a corresponding charge to contributed surplus. Options expire three to five years from the grant date; they vest one-third on the grant date and one-third on each of the following two annual anniversaries. Options granted in July of 2015 vest conditionally based on certain performance criteria on their first, second and third anniversaries. 12 2017 Annual Report DEPLETION AND DEPRECIATION (DD&A) DD&A Expenses ($000s) PNG – Australia Corporate Total Three Months Ended Twelve Months Ended 2017 443 4 447 March 31 2016 % Change 766 5 771 (42) (20) (42) 2017 2,291 18 2,309 March 31 2016 4,519 24 4,543 $/boe – PNG Australia 14.31 17.96 (20) 16.56 24.46 % Change (49) (25) (49) (32) Australian depletion per barrel decreased by 20% for Q4 2017 compared to Q4 2016 and decreased by 32% comparing fiscal year 2017 to fiscal year 2016. The decrease to depletion per barrel resulted from the following two factors; the Company’s 2P reserve volumes increased by 14% compared to the prior year and drilling costs have materially decreased in Australia, reducing the costs associated with future development of the Company’s reserves. IMPAIRMENT Impairment ($000s) Total Three Months Ended Twelve Months Ended March 31 March 31 2017 - 2016 % Change 2017 2016 % Change 11,223 (100) - 11,223 (100) The 2016 impairment charges related to petroleum and natural gas exploration properties in India and Toparoa, Australia. During the twelve months ended March 31, 2017, the Company recorded no impairment charges. FINANCE INCOME/EXPENSES Finance Expenses ($000s) Three Months Ended Twelve Months Ended Interest income Accretion expense on decommissioning liabilities Change in FV of VARs Letter of credit charges Interest on credit facility Total 2017 8 (10) - - (178) (180) March 31 2016 % Change 2 300 (9) 1 - (348) (354) 11 (100) - (49) (49) 2017 12 (37) - (55) (947) (1,027) March 31 2016 % Change 9 (33) 3 14 (1,311) (1,318) 33 12 (100) (493) (28) (22) Interest on the credit facility is based on US dollar Libor + 3.2% margin. 13 CAPITAL EXPENDITURES Capital Expenditures ($000s) Geological and geophysical Drilling Completions Cuisinier working interest purchase Total expenditures Exploration & evaluation expenditures Development & production expenditures Total net expenditures 2017 Annual Report Three Months Ended Twelve Months Ended March 31 2016 % Change 2017 March 31 2016 1,320 (14) 1,931 110 3,347 % Change (33) (21343) (9) (100) 68 107 (365) 151 - 105 883 2,974 1,761 - 5,618 2017 230 (53) 504 - 681 97 584 681 111 20 201 - 332 95 237 332 2 407 761 146 105 5,211 5.618 2,586 3,347 (47) 102 68 Development expenditures during the year related primarily to the Cuisinier 2016 drilling, completion and tie- in program. CREDIT FACILITY In October 2014, Bengal closed its US $25.0 million secured credit facility with WestPac Banking Corporation (“WestPac”) and placed an initial draw on November 12, 2014 of US $14.0 million. On August 26, 2016 following a US $1.5 million repayment, the Company extended the credit facility by 18 months to December 2018 with a borrowing base of US $15 million. The facility is secured by the Company’s producing assets in the Cuisinier field in Australia’s Cooper Basin, has a three-year term and carries an interest rate of US Libor plus 3.2%. The credit facility is structured as a reserves-based revolving facility under a predetermined reduction schedule, to be evaluated based on existing reserves at each calculation date. In the event that the facility is not further extended, the reduction schedule would commence on December 31, 2017 and occur every six months thereafter until December 31, 2018 with a nominal reduction of US $5 million to the facility limit at each calculation date based on the Company’s existing reserve profile. The facility limit at March 31, 2017 is US $15 million, of which US $12.5 million is currently drawn. The repayment schedule is US $2.5 million in fiscal 2018 and US $10.0 million in fiscal 2019, respectively. The credit facility’s reserves based covenants include a debt service coverage ratio (cash available for debt payments divided by mandatory debt repayments) as well as a loan life coverage ratio (net present value of future cash available for debt service divided by the available facility). These covenants impact the Company’s available facility limit, and therefore the ability to secure its debt as a percentage of reserve forecasts and are evaluated at each calculation date. These covenants are calculated using inputs as prescribed by WestPac, and a default event triggered by a breach of covenants may result in a full redemption of all outstanding borrowings under the terms of the credit facility. The Company was in compliance with the stated covenants at March 31, 2017. 14 2017 Annual Report SHARE CAPITAL At June 15, 2017, there were 102,266,694 common shares issued and outstanding, together with 2,702,500 outstanding options. Trading History Three Months Ended Twelve Months Ended High Low Close Volume (000s) Shares outstanding (000s) Weighted average shares outstanding (000s) Basic Diluted 2017 $0.23 $0.13 $0.14 3,546 102,267 102,267 102,267 March 31 March 31 2016 % Change 2017 2016 % Change $ 0.15 $ 0.11 $ 0.13 1,682 68,178 68,178 68,178 53 18 8 111 50 50 50 $0.24 $0.11 $0.14 12,725 $ 0.32 $ 0.10 $ 0.13 15,329 102,267 68,178 76,770 76,770 68,178 68,178 (25) 10 8 (17) 50 13 13 LIQUIDITY AND CAPITAL RESOURCES Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including work commitments, as they are due. Bengal prepares an annual budget and updates forecasts for operating, financing and investing activities on an ongoing basis to ensure it will have sufficient liquidity to meet its liabilities when due. The Company completed a rights offering which closed on December 29, 2016. Total proceeds were $4.1 million. Related share issuance costs were $142,000. Bengal’s financial liabilities consist of accounts payable and accrued liabilities, fair value of financial instruments, and credit facility and amounted to $18.1 million at March 31, 2017, (March 31, 2016- $20.6 million). At March 31, 2017 the Company had $3.8 million of working capital, including cash and short-term deposits of $3.9 million and restricted cash of $0.1 million, compared to a working capital deficiency of $0.4 million at March 31, 2016. The Company has a limit of US $15 million on its Westpac Credit facility, of which US $12.5 million is currently drawn. Proceeds from this facility are restricted for use within the Cuisinier production licence. Refer to Notes Payable and Credit Facility on page 11 for covenants related to the credit facility. The majority of the Company’s oil sales are benchmarked on dated Brent prices which averaged US $48.66/bbl for the twelve months ended March 31, 2017. The Company incurs most of its expenditures in Australian dollars whereas the Company generates most of its revenues in US dollars. To mitigate the net impact of low crude prices, the Company is acting with its joint venture partners to reduce discretionary spending and focus capital towards lower risk projects with near-term cash flow upside. The Company has also entered into derivative commodity contracts to reduce the impact of price volatility. Bengal will continue to monitor trends in commodity prices to ensure its financial obligations are met, while continuing to grow its asset base where appropriate. Under the current commodity price environment, the Company has no plans to use its internal source of cash to fund exploration activities. These are expected to be financed through farm-out or alternative financing sources. 15 The table below indicates the payment schedule for the credit facility: Credit facility (US$000s) Fiscal year 2018 Fiscal year 2019 COMMITMENTS 2017 Annual Report 2,500 10,000 12,500 The Queensland Government regulatory authority granted the Company the Authority To Prospect 934 ("ATP 934") under a revised work program on March 1, 2015. The Company acquired an additional 21.43 % working interest and received ministerial approval for the acquisition on August 11, 2015. Currently, the Company holds a 71.43% operating interest in this permit. Work program consists of 200 square kilometers of 3D seismic and up to three wells, which would require a capital spend of $2.1 million in 2017 and a further $2.1 million in 2018 net to Bengal. Country and Permit Work Program Obligation Period Ending Estimated Expenditure (net) (millions CAD$)(1) Onshore Australia – ATP 934P Onshore Australia – ATP 752 200 km2 of 3D seismic and up to three wells March 2021 Barta West 3D seismic program November 2017 (1) Translated at March 31, 2017 at an exchange rate of AUS $1.00 = CAD $1.0187 $16.3 $1.5 OTHER At March 31, 2017, the contractual obligations for which the Company is responsible are as follows: Contractual Obligations ($000s) Office lease Decommissioning obligations Total contractual obligations Total 944 1,516 2,460 $ $ Less than 1 Year $ $ 52 - 52 $ $ 1-3 Years 311 237 548 4-5 Years After 5 Years $ $ 311 117 428 $ 270 1,162 $ 1,432 OFF BALANCE SHEET TRANSACTIONS The Company does not have any off balance sheet transactions other than its office lease, which is classified as an operating lease. 16 2017 Annual Report 2017 379 - 67.17 9,294 (2,768) (0.04) 4,515 6,196 0.08 16,500 57,706 3,815 2016 505 - 60.54 11,187 (10,380) (0.15) 5,398 4,048 0.06 17,865 58,903 (420) 2015 480 4.10 93.35 15,669 (3,172) (0.05) 6,921 4,589 0.07 16,982 65,679 5,221 SELECTED ANNUAL INFORMATION Year Ended March 31 Total production volumes (boepd) Natural gas prices ($/mcf) Oil and liquids prices ($/boe) Total production revenue Net income (loss) Per share – basic and diluted Cash from operations Funds from operations (1) Per share – basic and diluted Balance drawn on credit facility Total assets Working capital (deficiency)(2) (1) See “Non-IFRS Measurements” on page 6 of this MD&A. (2) Calculated as current assets minus current liabilities. SELECTED QUARTERLY INFORMATION ($000s, except per share amounts) Fiscal quarter Mar. 31 2017 Mar. 31 2016 Q4 2017 Q3 2017 Q2 2017 Q1 2017 Q4 2016 Dec. 31 2016 Sep. 30 2016 Jun. 30 2016 Dec.31 2015 Q3 2016 Sep. 30 2015 Q2 2016 Jun. 30 2015 Q1 2016 Petroleum and natural gas sales Cash from (used in) operations Funds from (used in) operations(1) 2,179 643 1,639 2,325 934 1,412 2,301 1,982 1,797 2,489 956 1,348 2,253 1,496 1,439 1,838 935 105 3,392 2,318 1,282 3,704 649 1,222 Per share Basic and diluted 0.02 0.02 0.03 0.02 0.02 0.00 0.02 0.02 Net income (loss) Per share 1,931 (2,288) 325 (2,736) (11,704) 1,413 1,167 (1,256) Basic and diluted 0.02 (0.03) 0.00 (0.04) (0.17) 0.02 0.02 (0.02) Capital expenditures Working capital (deficiency) 681 3,816 1,234 3,291 3,320 383 4,421 (9,171) 332 (420) 1,311 (1,487) 596 5,775 1,108 3,087 Total assets 57,706 56,020 55,552 54,108 58,903 72,353 66,583 62,926 Shares outstanding (000s) 102,267 102,267 68,178 68,178 68,178 68,178 68,178 68,178 Operations Oil Volumes (bopd) Netback ($/boe) 344 355 386 431 469 81.09 69.01 67.30 56.09 58.75 439 27.54 592 520 36.97 46.23 (1) See “Non-IFRS Measurements” on page 6 of this MD&A. Production over the last eight quarters initially climbed with the addition of 2014 Phase One wells during fiscal Q3 2015. Production declined naturally for the subsequent quarters, offset partially during fiscal Q1 2016 as 2014 Phase Two wells were brought on stream near the end of the quarter. Production increased to 592 bopd during fiscal Q2 2016 before decreasing to 439 bopd during the quarter as a result of five wells which were temporarily offline during the quarter. These wells were brought back online post fracture stimulation during Q4 2016 increasing production. Due to delays in tieing in Cuisinier wells drilled in 2016, production has continued to decline since fiscal Q4 2016. 17 2017 Annual Report Crude oil sales and associated cash and funds from operations has been driven primarily by production rates and underlying commodity price fluctuations. Capital expenditures have been driven by drilling programs at the Company’s Cuisinier field, which peaked during fiscal Q2 2017 due to a five well drilling campaign commencing during the quarter. Total assets have increased through drilling activities at Cuisinier and were significantly reduced during fiscal Q4 2016 and fiscal Q1 2017 due to impairments of associated with the Tookoonooka exploration permit in Australia and CY-ONN-2005/1 exploration block in India respectively. Working capital reached a deficit of $9.1 at Q1 2017 prior to the extension of the Company’s Westpac credit facility in August 2017. During fiscal Q3 2017 $3.4 million of the credit facility became current, but this decrease to working capital was offset by the Company’s issuance of $4 million in common shares. Netbacks during the past eight quarters have been impacted primarily by fluctuations in benchmark crude prices. FINANCIAL INSTRUMENTS Financial instruments comprise cash, restricted cash and short term deposits, accounts receivable and accounts payable and accrued liabilities and debt. The fair values of these financial instruments approximate their carrying amounts due to their short-term maturities, and floating interest rate associated with the Company’s credit facility. The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of derivative instruments may be used by the Company to reduce its exposure to fluctuations in commodity prices, foreign exchange rates and interest rates. Refer to section “Risk Management Activities” for discussion of the Company’s financial instruments. Financial assets and liabilities are classified as either financial assets or liabilities at fair value through profit and loss (“FVTPL”), loans and receivables, held to maturity investments, available for sale financial assets, or other liabilities, as appropriate. Financial assets and liabilities are recognized initially at fair value. Subsequent measurement of financial instruments is based on their initial classification. FVTPL financial assets and liabilities are measured at fair value and changes in fair value are recognized in profit or loss. Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in other comprehensive loss until the instrument is derecognized or impaired. The remaining categories of financial instruments are recognized at amortized cost using the effective interest rate method. The transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability classified as FVTPL are expensed immediately. For a financial asset or financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to or deducted from the fair value on initial recognition and amortized through profit or loss income over the term of the financial instrument. (i) Non-derivative financial instruments Cash and cash equivalents, restricted cash as well as accounts receivable are classified as loans and receivables, which are measured at amortized cost. Accounts payable and accrued liabilities, and the credit facility are classified as other financial liabilities, which are measured at amortized cost. (ii) Derivative financial instruments The Company enters into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company does not designate its financial derivative contracts as effective accounting hedges and therefore will not apply hedge accounting, even though the Company considers all commodity contracts 18 2017 Annual Report to be economic hedges. As a result, all derivative contracts are classified as FVTPL and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred. Subsequent to initial recognition, derivatives are measured at fair value, and changes therein will be recognized immediately in profit or loss. The Company may enter into physical delivery sales contracts for the purposes of receipt or delivery of nonfinancial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and will not be recorded at fair value on the statement of financial position. Settlements on these physical delivery contracts will be recognized in petroleum and natural gas revenue in the period of settlement. Fair value The fair value of financial instruments that are actively traded in organized financial markets is determined by reference to quoted market bid prices at the valuation date. For financial instruments that have no active market, fair value is determined using valuation techniques including the use of recent arm’s length market transactions, reference to the current market value of equivalent financial instruments and discounted cash flow analysis. Share capital Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and stock options are recognized as a deduction from equity, net of any tax effects DISCLOSURE CONTROLS & PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING (ICFR) Disclosure Controls and Procedures Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and includes controls and procedures designed to ensure that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the Company’s management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure. The Chief Executive Officer and Chief Financial Officer oversee this evaluation process and have concluded that the design and operation of these disclosure controls and procedures are not effective due to the material weaknesses identified in internal controls over financial reporting as noted below. The Chief Executive Officer and Chief Financial Officer have individually signed certifications to this effect. Internal Controls over Financial Reporting The Chief Executive Officer and Chief Financial Officer of Bengal are responsible for designing and ensuring the operating effectiveness of internal controls over financial reporting (“ICFR”) or causing them to be designed and operating effectively under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. Bengal’s certifying officers have assessed the design and operating effectiveness of internal controls over financial reporting and concluded that the Company’s ICFR were not effective at March 31, 2017 due to the material weaknesses noted below. No changes in internal controls over financial reporting were identified during the period that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting. 19 2017 Annual Report While Bengal’s Chief Executive Officer and Chief Financial Officer believe the Company’s internal controls and procedures provide a reasonable level of assurance that they are reliable, an internal control system cannot prevent all errors and fraud. It is management’s belief that any control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. During the design and operating effectiveness assessment certain material weaknesses in internal controls over financial reporting were identified, as follows:  Management is aware that there is a lack of segregation of duties due to the small number of employees dealing with general and administrative and financial matters. However, management believes that at this time the potential benefits of adding employees to clearly segregate duties do not justify the costs;  Bengal does not have full-time in-house personnel to address all complex and non-routine financial accounting issues and tax matters that may arise. It is not deemed as economically feasible at this time to have such personnel. Bengal relies on external experts for review and advice on complex financial accounting issues and for tax planning, tax provision and compilation of corporate tax returns. These material weaknesses in internal controls over financial reporting result in a reasonable possibility that a material misstatement will not be prevented or detected on a timely basis. Management and the Board of Directors work to mitigate the risk of material misstatement; however, Management and the Board do not have reasonable assurance that this risk can be reduced to a remote likelihood of a material misstatement. APPLICATION OF CRITICAL ACCOUNTING ESTIMATES The timely preparation of the financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of these financial statements are out-lined below. The following are the critical judgments, apart from those involving estimations (see below), that management has made in the process of applying the Company’s accounting policies and that have the most significant effect on the amounts recognized in these financial statements. i. Identification of Cash-generating units Bengal’s assets are aggregated into cash-generating units, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company's assets in future periods. ii. Impairment indicators Judgments are required to assess when impairment indicators exist and impairment testing is required. The application of the Company’s accounting policy for exploration and evaluation, petroleum and natural gas properties and PP&E assets required management to make certain judgments as to future events and circumstances as to whether economic quantities of reserves have been found. iii. Recognition of deferred income tax assets 20 2017 Annual Report The recognition of deferred income tax assets requires judgments regarding the likelihood and applicability of future income tax deductions. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and ability to apply income tax deductions. KEY SOURCES OF UNCERTAINTY The following are the key assumptions concerning the sources of estimation uncertainty at the end of the reporting period that have a significant risk of causing adjustments to the carrying amounts of the assets and liabilities. i. Decommissioning provisions The Company estimates future remediation costs of production facilities, wells and pipelines at different stages of development and construction of assets or facilities. In most instances, removal of assets occurs many years into the future. This requires judgment regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and liability-specific discount rates to determine the present value of these cash flows. ii. Impairment of petroleum and natural gas assets For the purposes of determining whether impairment of petroleum and natural gas assets occurred, and the extent of any impairment or its reversal, the key assumptions the Company uses in estimating future cash flows are future petroleum and natural gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change as new information becomes available. Changes in economic conditions can also affect the rate used to discount future cash flow estimates. Changes in the aforementioned assumptions could affect the carrying amount of assets, and impairment charges and reversal will affect profit or loss. iii. Reserves The estimate of petroleum and natural gas reserves is integral to the calculation of the amount of depletion charged to the statement of operations and is also a key determinant in assessing whether the carrying value of any of the Company’s development and production assets has been impaired. Changes in reported reserves can impact asset carrying values due to changes in expected future cash flows. The Company’s reserves are evaluated and reported on by independent reserve engineers at least annually in accordance with Canadian Securities Administrators’ National Instrument 51-101. Reserve estimation is based on a variety of factors including engineering data, geological and geophysical data, projected future rates of production, commodity pricing and timing of future expenditures, all of which are subject to significant judgment and interpretation. iv. Share-based payments The Company measures the cost of its share-based payments to directors, officers, employees and certain consultants by reference to the fair value of the equity instruments at the date at which they are granted. The assumptions used in determining fair value include: expected lives of options, risk-free rates of return, share price volatility and the estimated forfeiture rate. Changes to assumptions may have a material impact on the amounts presented. 21 2017 Annual Report NEW ACCOUNTING STANDARDS AND PRONOUNCEMENTS New standards and interpretations not yet adopted Standards that are issued but not yet effective and that the Company reasonably expects to be applicable at a future date are listed below. Revenue from contracts with customers In April 2016, the IASB issued its final amendments to IFRS 15 Revenue from Contracts with Customers, which replaces IAS 18 Revenue, IAS 11 Construction Contracts and related interpretations. The new standard contains a single model that applies to contracts with customers and two approaches to recognizing revenue; at appoint in time or over time. The model features a contract-based five-step analysis of transactions to determine whether, how much and when revenue is to be recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and timing of the revenue recognized. The new standard applies to contracts with customers and does not apply to insurance contracts, financial instruments or lease contracts. The new standard is to be adopted either retrospectively or using a modified retrospective approach for annual periods beginning on or after January 1, 2018, with early adoption permitted. The extent of the impact of adoption of the standard has not yet been determined. Financial instruments: recognition and measurement In July 2014, the IASB issued the complete IFRS 9 Financial Instruments to replace IAS 9 Financial Instruments: Recognition and Measurement. IFRS 9 includes a principle-based approach for the classification and measurement of financial assets, a single ‘expected credit loss’ impairment model and a new hedge accounting standard which aligns hedge accounting more closely with risk management. The new standard is to be adopted retrospectively with some exemptions for annual periods on or after January 1, 2018, with early adoption permitted. Bengal intends to adopt IFRS 9 on a retrospective basis on April 1, 2018. The extent of the adoption of IFRS 9 on the classification and measurement of the Company’s financial assets and financial liabilities and related disclosures has not yet been determined. Bengal does not currently apply hedge accounting to its financial instrument contracts and does not currently intend to apply hedge accounting to any of its financial instrument contracts upon adoption of IFRS 9. Leases In January 2016, the IASB issued IFRS 16 Leases. This standard introduces a single recognition and measurement model for leases, which would require the recognition of assets and liabilities for most leases with a term of more than 12 months. The new standard is effective for annual periods beginning on or after January 1, 2019. Earlier application is permitted for entities that apply IFRS 15 Revenue from Contracts with Customers at or before the initial adoption date of January 1, 2018. The new standard is to be adopted either retrospectively or using a modified retrospective approach. The Company intends to adopt IFRS 16 in its financial statements for the annual period beginning on April 1, 2019. The extent of the impact of adoption of the standard has not yet been determined. RISK FACTORS Companies engaged in the oil and gas industry are exposed to a number of business risks which can be described as operational, financial and political risks, many of which are outside of the Company’s control. More specifically, these include risks of economically finding reserves and producing oil and gas in commercial quantities, marketing the production, commodity prices, environmental and safety risks, and risks associated with the foreign jurisdiction in which the Company operates. In order to mitigate these risks, the Company has an experienced base of qualified technical and financial personnel in both Canada and Australia. Further, the Company has focused its foreign operations and plans to target future foreign 22 2017 Annual Report operations in known and prospective hydrocarbon basins in jurisdictions that have previously established long-term oil and gas ventures with foreign oil and gas companies. An investment in the shares of the Company should be considered speculative due to the nature of the Company's involvement in the exploration for and the acquisition, development and production of oil and natural gas in foreign countries, and its current stage of development. An investor should consider carefully the risk factors set out below and consider all other information contained herein and in the Company's other public filings before making an investment decision. Additional risks and uncertainties not currently known to the management of the Company may also have an adverse effect on Bengal’s business and the information set out below does not purport to be an exhaustive summary of the risks affecting Bengal. Exploration, Development and Production Risks Oil and natural gas exploration involves a high degree of risk, for which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that expenditures made on future exploration by Bengal will result in new discoveries of oil or natural gas in commercial quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over-pressured zones, tools lost in the hole and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. The long-term commercial success of Bengal will depend on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. No assurance can be given that Bengal will be able to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, Bengal may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. In addition, oil and gas operations are subject to the risks of exploration, development and production of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence of any of these risks could have a materially adverse effect on future results of operations, liquidity and financial condition. Bengal attempts to minimize exploration, development and production risks by utilizing a high-end technical team with extensive experience and multidisciplinary skill sets to assure the highest probability of success in its drilling efforts. Bengal’s collaboration of a team of seasoned veterans in the oil and gas business, each with a unique expertise in the various upstream to downstream technical disciplines of prospect generation to operations, provides the best assurance of competency, risk management and drilling success. A full cycle economic model is utilized to evaluate all hydrocarbon prospects. Detailed geological and geophysical techniques are regularly employed including 3D seismic, petrography, sedimentology, petrophysical log analysis and regional geological evaluation. 23 2017 Annual Report Risks Associated with Foreign Operations International operations are subject to political, economic and other uncertainties, including, among others, risk of war, risk of terrorist activities, border disputes, expropriation, renegotiations or modification of existing contracts, restrictions on repatriation of funds, import, export and transportation regulations and tariffs, taxation policies, including royalty and tax increases and retroactive tax claims, exchange controls, limits on allowable levels of production, currency fluctuations, labor disputes, sudden changes in laws, government control over domestic oil and gas pricing and other uncertainties arising out of foreign government sovereignty over the Company's international operations. With respect to taxation matters, the governments and other regulatory agencies in the foreign jurisdictions in which Bengal operates and intends to operate in the future may make sudden changes in laws relating to taxation or impose higher tax rates, which may affect Bengal’s operations in a significant manner. These governments and agencies may not allow certain deductions in calculating tax payable that Bengal believes should be deductible under applicable laws or may have differing views as to values of transferred properties. This can result in significantly higher tax payable than initially anticipated by Bengal. In many circumstances, readjustments to tax payable imposed by these governments and agencies may occur years after the initial tax amounts were paid by Bengal, which can result in the Company having to pay significant penalties and fines. Furthermore, in the event of a dispute arising from international operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of courts in Canada. Prices, Markets and Marketing of Crude Oil and Natural Gas Oil and natural gas are commodities that have prices determined based on world demand, supply and other factors, all of which are beyond the control of Bengal. World prices for oil and natural gas have fluctuated widely in recent years. Any material decline in prices could result in a reduction of net production revenue. Certain wells or other projects may become uneconomic as a result of a decline in world oil prices and natural gas prices, leading to a reduction in the volume of Bengal’s oil and gas reserves. Bengal might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in Bengal’s future net production revenue, causing a reduction in its oil and gas acquisition and development activities. In addition to establishing markets for its oil and natural gas, Bengal must also successfully market its oil and natural gas to prospective buyers. The marketability and price of oil and natural gas which may be acquired or discovered by Bengal will be affected by numerous factors beyond its control. The ability of Bengal to market its natural gas may depend upon its ability to acquire space on pipelines which deliver natural gas to commercial markets. Bengal will also likely be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing facilities and related to operational problems with such pipelines and facilities and extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business. Substantial Capital Requirements and Liquidity Bengal’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From time to time, Bengal may require additional financing in order to carry out its oil and gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause Bengal to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If Bengal’s revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect Bengal’s ability to expend the necessary capital to replace its reserves or to maintain its production. If Bengal’s funds from operations are not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available on terms acceptable to Bengal. 24 2017 Annual Report Bengal monitors and updates its cash projection models on a regular basis which assists in the timing decision of capital expenditures. Farm outs of projects may be arranged if capital constraints are an issue or if the risk profile dictates that Bengal wishes to hold a lesser working interest position. Equity, if available and if on favorable terms, may be utilized to help fund Bengal’s capital program. Health, Safety and Environment All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Insurance Bengal’s involvement in the exploration for and development of oil and gas properties may result in the Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although Bengal has insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, Bengal may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to Bengal. The occurrence of a significant event that Bengal is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on Bengal’s financial position, results of operations or prospects. Competition Bengal actively competes for reserve acquisitions, exploration leases, licenses and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial and personnel resources than Bengal. Bengal's competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators. Bengal’s ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon developing and maintaining close working relationships with its future industry partners and joint operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. ADDITIONAL INFORMATION Additional information relating to Bengal is filed on SEDAR and can be viewed at www.sedar.com. Information can also be obtained by contacting the Company at Bengal Energy Ltd., 2000, 715 5th Avenue SW., Calgary, Alberta T2P 2X6, by email to info@bengalenergy.ca or by accessing Bengal’s website at www.bengalenergy.ca. 25 2017 Annual Report Forward-looking Statements - Certain statements contained within the Management’s Discussion and Analysis, and in certain documents incorporated by reference into this document, constitute forward-looking statements. These statements relate to future events or Bengal’s future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek,” "anticipate,” "budget,” "plan,” "continue,” "estimate,” "expect,” "forecast,” "may,” "will,” "project,” "predict,” "potential,” "targeting,” "intend,” "could,” "might,” "should,” "believe" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Bengal believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this MD&A should not be unduly relied upon. In particular, this Management’s Discussion and Analysis, and the documents incorporated by reference, contain forward-looking statements pertaining to the following: ● ●   ● ●  ● ● ● Oil and natural gas production levels; The size of the oil and natural gas reserves; The expected timing of the completion and tie-ins of the successful 5 well at Barta Block Cuisinier Timing of the finalization of the credit facility extension Projections of market prices and costs; Expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; The Company expects netbacks to remain above $35/bbl under current market conditions; Treatment under governmental regulatory regimes and tax laws; Capital expenditures programs and estimates of costs; Funding of working capital requirements, commitments and other planned expenses will be by cash on hand, cash flows, farm-outs, joint ventures or share issues and funds will be sufficient to meet requirements; and With respect to the forward looking statements contained in the MD&A, Bengal has made assumptions regarding: future commodity prices; the impact of royalty regimes; the timing and the amount of capital expenditures; production of new and existing wells and the timing of new wells coming on stream; future operating expenses including processing and gathering fees; the performance characteristics of oil and natural gas properties; the size of oil and natural gas reserves; the ability to raise capital; the continued availability of undeveloped land and skilled personnel; the ability to obtain equipment in a timely manner to carry out exploration and development activities; the ability to obtain financing on acceptable terms; the ability to add production and reserves through exploration and development activities; and the continued stability of political, regulatory; tax and fiscal regimes in which the Company has operations. The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this Management’s Discussion and Analysis: ● ● ● ● ● ● ● ● ● ● Volatility in market prices for oil and natural gas; Liabilities inherent in oil and natural gas operations; Uncertainties associated with estimating oil and natural gas reserves; Competition for, among other things: capital, acquisitions of reserves, undeveloped lands and skilled personnel; Incorrect assessment of the value of acquisitions; Unable to meet commitments due to inability to raise funds or complete farm-outs; Geological, technical, drilling and processing problems; Changes in income tax laws or changes to royalty and environmental regulations relating to the oil and gas industry; The risk that Bengal may not be successful in raising funds by an equity issue; and Counter-party credit risk, stock market volatility and market valuation of Bengal’s stock. 26 2017 Annual Report Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, which the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this MD&A and the documents incorporated by reference herein are expressly qualified by this cautionary statement. The forward-looking statements contained in this document speak only as of the date of this document and Bengal does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable securities laws. Additional information on these and other factors that could affect Bengal’s operations and financial results are included in reports on file with Canadian securities authorities and may be accessed through the SEDAR website (www.sedar.com) and at Bengal’s website (www.bengalenergy.ca). These statements speak only as of the date of this MD&A or as of the date specified in the documents incorporated by reference into this Management’s Discussion and Analysis, as the case may be. 27 2017 Annual Report MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL REPORTING financial statements are The accompanying consolidated the responsibility of management. The consolidated financial statements have been prepared by management in accordance with International Financial Reporting Standards outlined in the notes to the consolidated financial statements. The consolidated financial statements include certain estimates that reflect management’s best judgments. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly, in all material respects. In the opinion of management, the consolidated financial statements have been prepared within acceptable limits of materiality and are in accordance with International Financial Reporting Standards. The financial information contained in the annual report is consistent with that in the consolidated financial statements. Management is also responsible for establishing and maintaining appropriate systems of internal control over the Company’s financial reporting. The internal control system was designed to provide reasonable assurance to management regarding the preparation and presentation of the consolidated financial statements. Management tested and evaluated the effectiveness of its disclosure controls and procedures and internal controls over financial reporting as at March 31, 2017. During this evaluation, management identified material weaknesses due to the limited number of finance and accounting personnel at the Company dealing with complex and non-routine accounting transactions that may arise and due to a lack of segregation of duties and as a result the controls are not considered effective. All internal control systems, no matter how well designed, have inherent limitations. Therefore, these systems provide reasonable but not absolute assurance that financial information is accurate and complete. KPMG LLP, an independent firm of Chartered Professional Accountants, has been engaged, as approved by a vote of the shareholders at the Company’s most recent annual general meeting, to examine the consolidated financial statements in accordance with Canadian generally accepted auditing standards and provide an independent professional opinion. The audit committee of the Board of Directors with all of its members being independent directors, have reviewed the consolidated financial statements including notes thereto with management and KPMG LLP. The consolidated the recommendation of the Audit Committee. financial statements have been approved by the Board of Directors on (signed) “Chayan Chakrabarty” Chayan Chakrabarty President & Chief Executive Officer (signed) “Jerrad Blanchard” Jerrad Blanchard Chief Financial Officer 28 2017 Annual Report INDEPENDENT AUDITORS’ REPORT To the Shareholders of Bengal Energy Ltd. We have audited the accompanying consolidated financial statements of Bengal Energy Ltd. which comprise the consolidated statements of financial position as at March 31, 2017 and March 31, 2016, the consolidated statements of loss and comprehensive loss, changes in equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information. Management’s Responsibility for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditors’ Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion. 29 Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Bengal Energy Ltd. as at March 31, 2017 and March 31, 2016, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards. 2017 Annual Report Chartered Professional Accountants June 15, 2017 Calgary, Canada 30 2017 Annual Report BENGAL ENERGY LTD. CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Thousands of Canadian dollars) As at March 31, ASSETS Current assets: Cash and cash equivalents Restricted cash Accounts receivable Prepaid expenses and deposits Fair value of financial instruments Non-current assets: Exploration and evaluation assets Petroleum and natural gas properties Fair value of financial instruments Notes 3 12 4 5 12 2017 2016 $ 3,903 140 3,575 193 820 8,631 20,529 28,546 - 49,075 $ 3,010 140 3,187 155 5,806 12,298 19,626 24,875 1,294 45,795 Total assets $ 57,706 $ 58,093 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable and accrued liabilities Current portion of credit facility 7 8 7 12 9 Non-current liabilities: Decommissioning liability Credit facility Fair value of financial instruments Shareholders’ equity: Share capital Contributed surplus Warrants Accumulated other comprehensive income Deficit Total liabilities and shareholders’ equity Commitments and contingencies (note 15) Subsequent event (note 16) $ 1,484 3,332 4,816 1,516 13,168 102 14,786 98,100 7,645 - 2,085 (69,726) 38,104 $ 57,706 See accompanying notes to the consolidated financial statements. On behalf of the Board: Director Chayan Chakrabarty Director James B. Howe $ 2,669 10,049 12,718 1,422 7,816 - 9,238 94,151 7,442 167 1,335 (66,958) 36,137 $ 58,093 31 2017 Annual Report BENGAL ENERGY LTD. CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS (Thousands of Canadian dollars, except per share amounts) For the years ended March 31, 2017 2016 Income Petroleum and natural gas revenue Royalties Realized gain on financial instruments Unrealized (loss) gain on financial instruments Operating expenses General and administrative Operating and transportation Depletion and depreciation Pre-licensing & impairment Share-based compensation Operating loss Other expenses Other Finance expenses Foreign exchange Net loss Notes 5 4,5 11 $9,294 213 9,507 $11,187 (728) 10,459 4,712 (6,308) 7,911 2,740 4,864 2,309 - 29 9,942 (2,031) 3,840 1,861 16,160 2,663 6,480 4,543 11,223 91 25,000 (8,840) 378 (1,027) (88) (737) (2) (1,318) (220) (1,540) (2,768) (10,380) Exchange differences on translation of foreign operations 750 1,465 Total comprehensive loss for the year $(2,018) $(8,915) Loss per share - Basic & diluted Weighted average number of shares outstanding (000s) - Basic & diluted See accompanying notes to the consolidated financial statements. 9 9 $(0.04) $(0.15) 76,770 68,178 32 2017 Annual Report BENGAL ENERGY LTD. CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Thousands of Canadian dollars) Shares outstanding Share capital Warrants Contributed surplus Accumulated other comprehensive income Total shareholders’ equity Deficit 68,177,796 $94,151 $167 $7,341 $ (130) $(56,578) $44,951 - - - - - - - - - - - - - - (10,380) (10,380) - 1,465 91 10 - - - - - 1,465 91 10 68,177,796 $94,151 $167 $7,442 $1,335 $(66,958) $36,137 68,177,796 $94,151 $167 $7,442 $1,335 $(66,958) $36,137 Balance at April 1, 2015 Net loss for the year Comprehensive income for the year Share-based compensation – expensed Share-based compensation – capitalized Balance at March 31, 2016 Balance at April 1, 2016 Net loss for the year Comprehensive income for the year - - - - Rights offering 34,088,898 4,091 Share issue costs Expiry of warrants Share-based compensation – expensed Share-based compensation – capitalized Balance at March 31, 2017 (142) - - - - - - - - - - - - - - 750 - - (167) 167 - - - 29 7 - - - (2,768) (2,768) - - - - 750 4,091 (142) - - 29 - 7 102,266,694 $98,100 $ - $7,645 $2,085 $(69,726) $38,104 See accompanying notes to the consolidated financial statements. 33 BENGAL ENERGY LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS (Thousands of Canadian dollars) 2017 Annual Report For the years ended March 31, 2017 2016 Operating activities Net loss for the year Non-cash items: Depletion and depreciation Pre-licensing & impairment Accretion on decommissioning liability Accretion on notes payable and credit facility /change in fair value of VARs Share-based compensation Loss (profit) on disposition of petroleum and natural gas properties Unrealized loss (gain) on financial instruments Unrealized foreign exchange (gain) loss Funds from operations Change in non-cash working capital Net cash from operating activities Investing activities Exploration and evaluation expenditures Petroleum and natural gas properties Changes in non-cash working capital Net cash (used) in investing activities Financing activities Proceeds from issuance of shares, net of issuance costs Repayment of credit facility Facility extension fees Changes in non-cash working capital Net cash (used in) from financing activities Impact of foreign exchange on cash and cash equivalents Net increase (decrease) in cash equivalents Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year Notes $ (2,768) $ (10,380) 2,309 - 37 278 29 4,543 11,223 33 428 91 (62) 6,308 65 6,196 (1,681) 4,515 - (1,861) (29) 4,048 1,350 5,398 (407) (5,211) (178) (5,796) (761) (2,586) (579) (3,926) 3,949 (1,984) (150) 285 2,100 - - - (282) (282) 74 893 3,010 $ 3,903 71 1,261 1,749 $ 3,010 14 4 5 14 9 7 7 14 See accompanying notes to the consolidated financial statements. 34 BENGAL ENERGY LTD. Notes to Consolidated Financial Statements (the “financial statements”) Years ended March 31, 2017 and 2016 (Tabular amounts are stated in thousands of Canadian dollars except share and per share amounts) 2017 Annual Report 1. REPORTING ENTITY Bengal Energy Ltd. (the “Company” or “Bengal”) is incorporated under the laws of the Province of Alberta and is involved in the exploration for and development and production of oil and gas reserves in Australia, India and Canada. The consolidated financial statements (the “financial statements”) of the Company as at March 31, 2017 and 2016 and for the years ended March 31, 2017 and 2016 are comprised of the Company and its wholly owned subsidiaries Bengal Energy International Inc., which are incorporated in Canada and Bengal Energy Australia (Pty) Ltd., Avery Resources (Northern Ireland) Ltd. and Northstar Energy Pty Ltd. which are incorporated in Australia respectively. The Company conducts many of its activities jointly with others; these financial statements reflect only the Company’s proportionate interest in such activities. Bengal’s principal place of business and registered office is located at 2000, 715 5th Ave SW, Calgary, Alberta, Canada, T2P 2X6. 2. BASIS OF PREPARATION a) Statement of compliance These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The financial statements were approved and authorized for issuance by the Board of Directors on June 15, 2017. b) Basis of measurement These financial statements have been prepared on a historical cost basis, except for commodity contracts as discussed in Note 19. c) Functional and presentation currency The Company’s presentation currency is Canadian dollars. The functional currency of the Canadian parent entity is Canadian dollars; the functional currency of the Indian subsidiary is US dollars; and the functional currency of the Australian subsidiary is Australian dollars. 3. CASH AND CASH EQUIVALENTS Cash and cash equivalents include cash on hand and in banks and investments with an original maturity date of 90 days or less. Cash and cash equivalents at the end of the reporting period as shown in the statement financial position are comprised of: As at ($000s) Cash and bank balances Short-term deposits March 31, 2017 March 31, 2016 1,655 2,248 3,903 3,003 7 3,010 35 4. EXPLORATION AND EVALUATION ASSETS (E&E ASSETS) ($000s) Balance at March 31, 2015 Additions Acquisition Capitalized share-based compensation E&E impairment loss Exchange adjustments Balance at March 31, 2016 Additions Capitalized share-based compensation Exchange adjustments Balance at March 31, 2017 2017 Annual Report 28,245 651 110 4 (10,475) 1,091 19,626 407 3 493 20,529 Exploration and evaluation assets consist of the Company’s exploration projects in Australia which are pending the determination of proved or probable reserves. Costs primarily consist of acquisition costs, geological & geophysical work, seismic and drilling and completion costs until the drilling of wells is complete and the results have been evaluated. In the process of management’s internal analysis of prospectivity and planning for scheduled relinquishment in 2017 for ATP 732 Tookoonooka, Bengal identified several areas deemed to have low potential for future exploration at March 31, 2016. All historical costs associated with exploration in these select areas were impaired during fiscal 2016. No further impairments were incurred during fiscal 2017. A summary of E&E assets is shown in the table below: ($000s) ATP 732 - Tookoonooka ATP 752 - Barta ATP 934 - Barrolka Other(1) March 31, 2016 ($000) ATP 732 - Tookoonooka ATP 752 - Barta ATP 934 - Barrolka Other(1) March 31, 2017 ($000) Australia 16,163 1,243 781 1,439 19,626 Australia 16,573 1,273 1,114 1,569 20,529 (1) Other includes capitalized G&A, share-based compensation and foreign exchange effects on assets denominated in foreign currencies. 36 5. PETROLEUM AND NATURAL GAS PROPERTIES 2017 Annual Report $000s Cost: Balance at April 1, 2015 Additions Capitalized share-based compensation Change in decommissioning obligation Exchange adjustments Balance at March 31, 2016 Additions Capitalized share-based compensation Change in decommissioning obligation Exchange adjustments Balance at March 31, 2017 $000s Accumulated depletion, depreciation and impairment losses: Balance at April 1, 2015 Depletion and depreciation charge Impairment Exchange adjustments Balance at March 31, 2016 Depletion and depreciation charge Exchange adjustments Balance at March 31, 2017 Net carrying value At March 31, 2016 At March 31, 2017 Petroleum and Natural Gas Properties Corporate Assets 38,701 2,586 6 (95) 622 41,820 5,211 4 80 760 47,875 342 - - - 2 344 - - - - 344 Petroleum and Natural Gas Properties Corporate Assets 11,678 4,519 748 75 17,020 2,291 75 19,386 24,800 28,489 243 24 - 2 269 18 - 287 75 57 Total 39,043 2,586 6 (95) 624 42,164 5,211 4 80 760 48,219 Total 11,921 4,543 748 77 17,289 2,309 75 19,673 24,875 28,546 The calculation of depletion for the year ended March 31, 2017 included $73.4 million for estimated future development costs associated with proved and probable reserves in Australia (March 31, 2016 - $83.6 million). At March 31, 2016, the reserves relating to the Toparoa CGU were determined to be uneconomic. As a result, the carrying value of $0.7 million relating to the Toparoa CGU was impaired at March 31, 2016. Toparoa CGU was disposed of in September 2016. No impairment triggers requiring an impairment test to be performed were determined to exist relating to the Cuisinier CGU at March 31, 2017. 37 6. INCOME TAXES The provision for income taxes differs from the amount obtained in applying the combined federal and provincial income tax rates to the loss for the year. The difference relates to the following items: 2017 Annual Report Years Ended March 31, ($000s) (Loss) income before taxes Statutory tax rate Expected income tax expense (recovery) Foreign exchange Stock-based compensation Effect of change in tax rate & other Other Changes in unrecognized tax asset Income tax recovery 2017 (2,768) 27% (747) (269) 8 (45) - 1,053 - 2016 (10,380) 26.5% (2,751) (258) 24 768 (50) 2,267 - The temporary deductible differences included in the Company’s unrecognized deferred income tax assets are as follows: As of March 31, ($000s) Non-capital losses Net capital losses P&NG properties Share issue costs Decommissioning obligations 2017 32,915 5,740 13,150 557 102 52,464 2016 30,976 5,742 14,386 764 101 51,969 The components of the Company’s and its subsidiaries deferred income tax liabilities are as follows: As of March 31, ($000s) Property, plant & equipment Fair value of financial instruments Foreign exchange Decommissioning obligations Non-capital losses 2017 14,651 216 (942) (418) (13,507) - 2016 13,286 2,130 (673) (390) (14,353) - At March 31, 2017, the Company had approximately $29.3 million and $48.7 million of non-capital losses in Canada and Australia respectively (2016- $23.9 million and $49.8 million), available to reduce future taxable income. The Canadian non-capital losses expire at various dates from March 31, 2026 to 2037. The Australian non-capital losses have no term to expiry. The Company’s ongoing drilling activities continue to generate deferred assets related to Petroleum Resource Rent Tax (“PRRT”) in its Australia subsidiary, which has not been recognized. The Company has temporary differences associated with its investments in its foreign subsidiaries, branches, and interests in joint ventures. At March 31, 2017, the Company has no deferred tax liabilities in respect of these temporary differences. 38 7. CREDIT FACILITY Facility Agreement – Issued November 12, 2014 ($000s) Gross proceeds Total cash fees Unrealized foreign exchange loss Accretion Balance at March 31, 2016 Repayment Facility extension fees Unrealized foreign exchange loss Accretion Balance at March 31, 2017 Current portion of credit facility Non-current portion of credit facility 2017 Annual Report 15,364 (844) 14,520 2,747 17,267 598 17,865 (1,984) (150) 491 278 16,500 March 31, 2017 March 31, 2016 3,332 13,168 10,049 7,816 In October 2014, Bengal closed its US $25.0 million secured credit facility with WestPac Banking Corporation (“WestPac”) and placed an initial draw on November 12, 2014 of US $14.0 million. On August 26, 2016 following a US $1.5 million repayment, the Company extended the credit facility by 18 months to December 2018 with a borrowing base of US $15 million. The facility is secured by the Company’s producing assets in the Cuisinier field in Australia’s Cooper Basin, has a three-year term and carries an interest rate of US Libor plus 3.2%. The credit facility is structured as a reserves-based revolving facility under a predetermined reduction schedule, to be evaluated based on existing reserves at each calculation date. The next calculation date will occur on June 30, 2017. In the event that the facility is not further extended, the reduction schedule would commence on December 31, 2017 and occur every six months thereafter until December 31, 2018 with a nominal reduction of US $5 million to the facility limit at each calculation date based on the Company’s existing reserve profile. The facility limit at March 31, 2017 is US $15 million, of which US $12.5 million is currently drawn. Refer to Note 12(b) for a repayment schedule. The credit facility’s reserves based covenants include a debt service coverage ratio (cash available for debt payments divided by mandatory debt repayments) as well as a loan life coverage ratio (net present value of future cash available for debt service divided by the available facility). These covenants impact the Company’s available facility limit, and therefore the ability to secure its debt as a percentage of reserve forecasts and are evaluated at each calculation date. These covenants are calculated using inputs as prescribed by WestPac, and a default event triggered by a breach of covenants may result in a full redemption of all outstanding borrowings under the terms of the credit facility. The Company was in compliance with the stated covenants at March 31, 2017. 39 8. DECOMMISSIONING AND RESTORATION LIABILITY 2017 Annual Report The total decommissioning and restoration obligations were estimated by management based on the estimated costs to reclaim and abandon the wells, well sites and certain facilities based on the Company’s contractual requirements. Changes to decommissioning and restoration obligations were as follows: March 31, ($000s) Decommissioning liability, beginning of year Change in estimate net of disposals Additions Accretion Exchange adjustments Decommissioning liability, end of year 2017 1,422 (259) 278 37 38 1,516 2016 1,454 (95) - 33 30 1,422 The Company’s decommissioning liability results from ownership interests in petroleum and natural gas properties. The Company estimates the total inflation-adjusted undiscounted amount of cash flows required to settle its decommissioning and restoration costs at March 31, 2017 is approximately $2.3 million (March 31, 2016 – $1.9 million) which will be incurred between 2020 and 2044. An inflation factor of 1.5% – 1.6% and a risk-free discount rate ranging between 1.63% and 2.49% have been applied to the decommissioning liability at March 31, 2017. 9. SHARE CAPITAL (a) Authorized: Unlimited number of common shares with no par value. Unlimited number of preferred shares, of which none have been issued. (b) Issued: The following provides a continuity of share capital: ($000s) Balance at March 31, 2015 and 2016 Issued on exercise of rights offering Share issue costs Balance at March 31, 2017 Number of Shares 68,177,796 34,088,898 - 102,266,694 Amount 94,151 4,091 (142) 98,100 The Company completed a rights offering (the "Rights Offering") which closed on December 29, 2016. Under the terms of the Rights Offering, each registered holder of common shares, at the close of business on December 2, 2016, received one Right for each common share held. Two Rights, plus the sum of $0.12 (the "Subscription Price"), entitled the holder thereof to acquire one common share. The Rights Offering resulted in 34,088,898 common shares being issued (16,056,853 common shares were issued to officers and directors) for total proceeds of $4.1 million. Share issuance costs of $142,000 were incurred related to the Rights Offering and have been recognized in the carrying value of share capital on the consolidated statement of financial position. 40 2017 Annual Report (c) Share-based compensation – stock options: The Company has a share option plan for directors, officers, employees and consultants of the Company whereby share options representing up to 10% of the issued and outstanding common shares can be granted by the Board of Directors. Share options are granted for a term of three to five years and vest one-third immediately and one-third on each of the next two anniversary dates. The exercise price of each option equals the market price of the Company’s common shares on the date of the grant. Effective with the option grant on December 21, 2012, vesting occurs one third after the first year and one third on each of the two subsequent anniversaries. Effective with the option grant of July 30, 2015, performance criteria were introduced, which allow for the vesting of stock options contingent on meeting pre-established targets based on internal and external metrics. Bengal accounts for its share-based compensation plan using the fair value method. Under this method, each grant results in three instalments. The fair value of the first instalment is charged to profit or loss immediately. The remaining two instalments are charged to profit or loss over their respective vesting period of one and two years respectively. For options that vest one-third each year on the first year anniversary, the fair value of the options are charged to profit and loss over the three year vesting period. Stock options granted under the plan can be exercised on a cashless basis, whereby the employee receives a lesser amount of shares in lieu of paying the exercise price based on the deemed market price of the shares on the exercise date, and withholding taxes if the employee so elects. A summary of stock option activity is presented below: Options Weighted Average Exercise Price Outstanding at March 31, 2015 Granted Forfeited Expired Exercised Outstanding at March 31, 2016 Granted Forfeited Expired Exercised Outstanding at March 31, 2017 Exercisable at March 31, 2017 3,515,000 1,072,500 - (230,000) - 4,357,500 - - (1,655,000) - 2,702,500 1,808,756 $ $ 0.89 0.18 - 0.86 - 0.72 - - 1.19 - $ 0.43 $ 0.55 Options Outstanding Options Exercisable Option Price (1) $0.18 - $0.46 $0.47 - $0.65 Total Number Outstanding Exercise Price (2) Remaining Life (3) Number Exercisable Exercise Price (2) 1,072,500 1,630,000 2,702,500 $0.18 $0.59 $0.43 3.33 1.09 1.98 178,756 1,630,000 1,808,756 $0.18 $0.59 $0.55 (1) Range of option exercise prices (2) (3) Weighted average exercise price of options Weighted average remaining contractual life of options in years The fair value of options granted on July 30, 2015, were estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values: 41 For the Year Ended March 31, Assumptions: Risk free interest rate (%) Expected life (years) Expected volatility (%)(1) Estimated forfeiture rate (%) Weighted average fair value of options granted Weighted average share price on date of grant 2017 Annual Report 2016 1.5% 5 yr 78% - $0.18 $0.18 (1) Expected volatility is estimated by considering historic average share price volatility. The fair value of stock options granted during the year ended March 31, 2016 was $122. No options were granted during the year ended March 31, 2017. (d) Per share amounts: Loss per share is calculated based on net loss and the weighted-average number of common shares outstanding. For the Year Ended ($000s) Loss for the year 2017 2016 $ (2,768) $ (10,380) Weighted average number of common shares (basic) Weighted average number of common shares (diluted) Basic and diluted loss per share 76,770 76,770 $(0.04) 68,178 68,178 $(0.15) For the twelve months ended March 31, 2017, there were 2,702,500 (March 31, 2016 – 4,357,000) options respectively considered anti-dilutive. 10. COMPENSATION OF KEY MANAGEMENT PERSONNEL The Company considers its directors and executives to be key management personnel. The key management personnel compensation is comprised of the following: Year ended March 31, ($000s) Salaries & employee benefits Share-based compensation(1) General & administrative expenses 2017 986 33 1,019 2016 974 79 1,053 (1) Represents the amortization of share-based payment expense associated with the company’s share-based compensation plans granted to key management personnel. 42 11. FINANCE INCOME/EXPENSES Year ended March 31, ($000s) Interest income Accretion on decommissioning obligations Letter of credit charges Interest on notes payable and credit facility Accretion on notes payable and change in fair value of VARs Finance income (expenses) 12. FINANCIAL RISK MANAGEMENT 2017 Annual Report 2017 2016 12 (37) (55) (947) - (1,027) 9 (33) 14 (1,311) 3 (1,318) The Company has exposure to credit, liquidity and market risk from its use of financial instruments. This note presents information about the Company’s exposure to these risks, the Company’s objectives and policies and processes for measuring and managing risk. The Board of Directors has overall responsibility for identifying the principal risks of the Company and ensuring the policies and procedures are in place to appropriately manage these risks. Bengal’s management identifies, analyzes and monitors risks and considers the implication of the market condition in relation to the Company’s activities. (a) Credit risk: Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from Bengal’s cash calls paid to joint venture partners and receivables from petroleum and natural gas marketers. As at March 31, 2017, Bengal’s receivables consisted of $3.1 million (March 31, 2016 - $2.6 million) from joint venture partners and $0.4 million (March 31, 2016 - $0.6 million) of other trade receivables of which $2.8 million has been subsequently collected. In Australia, production is purchased by a consortium led by one of Australia’s largest public oil and gas companies which is also the operator of Bengal’s production. Bengal has a Crude Oil Purchase Agreement with this purchaser and has not experienced any collection problems to date. Cash calls paid to Bengal’s Australian joint venture partners are held in trust accounts by the partner until spent. Bengal attempts to mitigate the risk from joint venture receivables by approving significant spending by partners prior to expenditure and only paying the cash call shortly before the funds are to be spent. The Company had no accounts considered past due at March 31, 2017, (March 31, 2016 - $nil million). Past due is considered greater than 90 days outstanding. The carrying amount of accounts receivable and cash and cash equivalents and fair value of financial instruments represents the maximum credit exposure. Bengal establishes an allowance for doubtful accounts as determined by management based on their assessment of collection. Bengal does not have an allowance for doubtful accounts as at March 31, 2017 and did not provide for any doubtful accounts, nor was it required to write-off any receivables during the twelve months ended March 31, 2017. Exposure to the carrying value of its financial instruments relates to the Company’s commodity-based derivatives held by WestPac, which carries a Standard & Poor’s credit rating of AA-. Management considers the credit risk of these instruments to be adequately mitigated by the credit stating of their holder, therefore no allowance has been established. Cash and cash equivalents, when held, consist of cash bank balances and guaranteed investment certificates redeemable at any time. Bengal manages the credit exposure related to guaranteed 43 investments by selecting counterparties based on credit ratings and monitors all investments to ensure a stable return, avoiding complex investment vehicles with higher risk such as asset-backed commercial paper. 2017 Annual Report (b) Liquidity risk: Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including work commitments, as they are due. Bengal prepares an annual budget and updates forecasts for operating, financing and investing activities on an ongoing basis to ensure it will have sufficient liquidity to meet its liabilities when due. Bengal’s financial liabilities consist of accounts payable and accrued liabilities, fair value of financial instruments, and credit facility and amounted to $18.1 million at March 31, 2017, (March 31, 2016- $20.6 million). At March 31, 2017 the Company had $3.8 million of working capital, including cash and short-term deposits of $3.9 million and restricted cash of $0.1 million, compared to a working capital deficiency of $0.4 million at March 31, 2016. The Company has a limit of US $15 million on its WestPac credit facility, of which US $12.5 million is currently drawn. The remaining US $2.5 million is available to be drawn. Proceeds from this facility are restricted for use within the Cuisinier production licence. Refer to Note 7 for discussion on repayment terms and covenants related to the credit facility. The majority of the Company’s oil sales are benchmarked on dated Brent prices which averaged US $48.66/bbl for the twelve months ended March 31, 2017. The Company incurs most of its expenditures in Australian dollars whereas the Company generates most of its revenues in US dollars. To mitigate the net impact of low crude prices, the Company is acting with its joint venture partners to reduce discretionary spending and focus capital towards lower risk projects with near- term cash flow upside. The Company has also entered into derivative commodity contracts to reduce the impact of price volatility. Bengal will continue to monitor trends in commodity prices to ensure its financial obligations are met, while continuing to grow its asset base where appropriate. Under the current commodity price environment, the Company has no plans to use its internal source of cash to fund exploration activities. These are expected to be financed through farm-out or alternative financing sources. The table below indicates the payment schedule for the credit facility: Credit facility (US $000s) Fiscal year 2018 Fiscal year 2019 (c) Market risk: 2,500 10,000 12,500 Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk comprises three types of risk: currency risk, interest rate risk and other price risk. The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of derivative instruments may be used to reduce exposure to these risks. Foreign Currency Risk Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in foreign exchange rates. Bengal receives Canadian dollars for sales in Canada, US dollars for Australian oil sales and incurs expenditures in Australian, Canadian and US 44 currencies. Having sales and expenditures denominated in three currencies spreads the impact of individual currency fluctuations. The Company may enter into derivative foreign currency contracts in order to manage foreign currency exchange rate risk, but has not done so to date. The table below shows the Company’s exposure to foreign currencies for its financial instruments: 2017 Annual Report As at March 31, 2017 ($000s) Cash and short-term deposits Restricted cash Accounts receivable Accounts payable and accrued liabilities Credit facility Fair value of financial instruments Commodity Price Risk CAD AUD USD Total 112 140 19 (278) - - (7) 2,458 - 3,556 (1,201) - - 4,813 1,333 - - (5) (16,500) 718 (14,454) 3,903 140 3,575 (1,484) (16,500) 718 (9,648) Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of a change in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the relationship between the Canadian and United States dollar, as outlined above, but also world economic events that dictate the levels of supply and demand. Australian oil prices are based on the Dated Brent reference price, which trades at a premium to WTI. At March 31, 2017, the following derivative contracts were outstanding and recorded at estimated fair value: Time Period Type of Contract April 1, 2017 – May 31, 2017 April 1, 2017 – May 31, 2017 ($000s) Current fair value of financial instruments Non-current fair value of financial instruments Total Oil - Swap Oil – Put option Time Period Type of Contract July 1, 2017 – December 31, 2018 July 1, 2017 – December 31, 2018 ($000s) Current fair value of financial instruments Non-current fair value of financial instruments Total Oil - Swap Oil – Put option Quantity Contracted (bbls) 15,814 12,937 Oil - swap 561 - 561 Quantity Contracted (bbls) 67,373 67,373 Oil - swap (295) (291) (586) Price Floor (US$/bbl) Price Ceiling (US$/bbl) 80.00 80.00 Oil – put 459 - 459 80.00 - Total 1,020 - 1,020 Price Floor (US$/bbl) Price Ceiling (US$/bbl) 47.00 47.00 Oil – put 95 189 284 47.00 - Total (200) (102) (302) A US $1.00 increase in the future crude oil price per barrel would result in an approximate US $163,000 decrease in the fair value of financial instruments at March 31, 2017 while a $ US1.00 decrease would result in an increase of approximately US $163,000 in the fair value of the instruments. 45 2017 Annual Report Interest Rate Risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is not exposed to interest rate risk on its cash and cash equivalents at March 31, 2017 as the funds are not invested in interest-bearing instruments. The Company’s credit facility carries a floating interest rate based on quoted US dollar Libor rates. The Company had no interest rate derivatives at March 31, 2017. For the year ended March 31, 2017, a 1% increase in US Libor would increase interest expense by $164,000. 13. CAPITAL MANAGEMENT The Company’s policy is to maintain a strong capital base for the objectives of maintaining financial flexibility which will allow it to execute on its capital investment program, provide creditor and market confidence and to sustain future development of the business. The Company manages its capital structure and makes adjustments by continually monitoring its business conditions, including: changes in economic conditions, the risk profile of its drilling inventory, the efficiencies of past investments, the efficiencies of forecasted investments and the timing of such investments, the forecasted cash balances, the forecasted commodity prices and resulting cash flow. In order to maintain or adjust the capital structure, the Company may from time to time issue shares (if available on reasonable terms), issue debt instruments, sell assets, farm out properties and adjust its capital spending to manage current and projected cash levels. There can be no assurance that equity financing will be available or sufficient to meet capital commitments, or for other corporate purposes, or if equity financing is available, that it will be on terms acceptable to the Company. The Company has drawn US $12.5 million from its US $15.0 million available credit facility and typically structures its debt position below 2.0 times projected 12-month net operating cash flows. The Company is within these parameters at March 31, 2017. 14. CHANGES IN NON-CASH WORKING CAPITAL Year ended March 31, ($000s) Accounts receivable Prepaid expenses and deposits Accounts payable and accrued liabilities Impact of foreign exchange Total Relating to: Operating Financing Investing Total 2017 (388) (38) (1,185) 37 (1,574) (1,681) 285 (178) (1,574) 2016 (78) 193 380 (6) 489 1,350 (282) (579) 489 The following represents the cash interest paid and received in each period. Year ended March 31, ($000s) Cash interest paid Cash interest received 2017 2016 705 12 870 9 46 15. COMMITMENTS AND CONTINGENCIES 2017 Annual Report Pursuant to current production sharing contracts (“PSC”), the Company is required to perform minimum exploration activities that include various types of surveys, acquisition and processing of seismic data and drilling of exploration wells. Additional commitments are reflected where the Company has agreed with joint operating partners to proceed with activities. The costs of these activities are based on minimum work budgets included in bid documents and have not been provided for in the financial statements. Actual costs will vary from budget. The Queensland Government regulatory authority granted the Company Authority to Prospect 934 ("ATP 934") under a revised work program on March 1, 2015. The Company acquired an additional 21.43% working interest and received ministerial approval for the acquisition on August 11, 2015. Currently the Company holds a 71.43% operating interest in this permit. Work program consists of 200 kilometers of 3D seismic and up to three wells, which would require a discretionary capital spend of $2.1 million in 2017 and a further discretionary $2.1 million in 2018 net to Bengal. Country and Permit Work Program Obligation Period Ending Estimated Expenditure (net) (millions CAD$)(1) Onshore Australia – ATP 934P 200 km2 of 3D seismic and up to three wells March 2021 $16.3 Onshore Australia – ATP 752 Barta West 3D seismic program November 2017 $1.5 (1) Translated at March 31, 2017 at an exchange rate of AUS $1.00 = CAD $1.0187. At March 31, 2017 the Company had the following lease commitment for office space in Canada. ($000s) April 2017 to November 2023 Office lease 16. SUBSEQUENT EVENT Total 944 Less than 1 Year 52 1-3 Years 311 4-5 Years 311 After 5 Years 270 Effective June 1, 2016, Bengal and its joint venture partner unanimously agreed and provided notice to the applicable Government of India authorities of its intention to exit the CY-ONN-2005/1 exploration block. The joint venture was unable to acquire the land rights required for exploration causing a force majeure condition for the duration of the first term of exploration, and is therefore entitled to exit the permit without penalty for unfinished work program commitments. Subsequent to March 31, 2017, this exit without penalty has been approved by the Director General of Hydrocarbons and is awaiting final approval from the Indian Ministry of Petroleum and Natural Gas. With the exit from the permit, the Company will effectively cease all operations in India. 17. SUPPLEMENTAL DISCLOSURE Bengal’s consolidated statement of income (loss) and comprehensive income (loss) is prepared primarily by nature of expense. All salaries for the Company are included in general and administrative expenses and for the year ended March 31, 2017 amount to $1.3 million (March 31, 2016 - $1.3 million). 18. SEGMENTED INFORMATION As at March 31, 2017, the Company has three reportable operating segments being the Australian and Indian oil and gas operations, and corporate. 47 2017 Annual Report Revenue reported below represents revenue generated from external customers. There were no inter- segment sales in any of the reported periods. The accounting policies of the reportable segments are the same as the group’s accounting policies. Segment profit represents the profit earned by each segment without allocation of central administration costs and directors’ salaries, finance costs and income tax expense. This is the measure reported to the chief operating decision maker for the purposes of resource allocation and assessment of segment performance. For the year ended March 31, 2017 ($000s) Australia Corporate India Total Revenue Interest revenue Interest expense Depletion and depreciation Net earnings (loss) Exploration and evaluation expenditures Petroleum and natural gas property expenditures March 31, 2017 Petroleum and natural gas properties Cost Accumulated impairment losses Accumulated depletion and depreciation Net book value Exploration and evaluation assets Accumulated impairment losses Net book value 9,294 11 947 2,291 (1,425) 407 5,211 43,582 (796) (14,297) 28,489 29,850 (9,321) 20,529 - 1 - 18 (1,153) - - 4,637 (310) (4,270) 57 - - - - (190) - 9,294 12 947 2,309 (2,768) 407 - - - - - 5,211 48,219 (1,106) (18,567) 28,546 - - - 8,415 (8,415) - 38,265 (17,736) 20,529 For the year ended March 31, 2016 ($000s) Revenue Interest revenue Interest expense Depletion and depreciation Net (earnings) loss Exploration and evaluation expenditures Petroleum and natural gas property expenditures Impairment losses (recovery) March 31, 2016 ($000s) Petroleum and natural gas properties Cost Accumulated impairment losses Accumulated depletion and depreciation Net book value Exploration and evaluation assets Accumulated impairment losses Net book value Australia 11,187 8 1,311 4,519 (1,342) 741 2,586 3,848 37,527 (796) (11,931) 24,800 28,831 (9,205) 19,626 Canada - 1 - 24 (1,305) - - - 4,638 (310) (4,253) 75 - - - India - - - - (7,733) 20 - 7,375 - - - - 8,188 (8,188) - Total 11,187 9 1,311 4,543 (10,380) 761 2,586 11,223 42,165 (1,106) (16,184) 24,875 37,019 (17,393) 19,626 48  19. SIGNIFICANT ACCOUNTING POLICIES The accounting policies set out below have been applied consistently to all periods presented in these financial statements, and have been applied consistently by the Company and its subsidiaries. 2017 Annual Report (a) Basis of consolidation: The financial statements incorporate the financial statements of the Company and its wholly and majority-owned subsidiaries Bengal Energy Australia (Pty) Ltd., Bengal Energy International Inc., and Northstar Energy Pty Ltd. respectively. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity so as to obtain the benefits from its activities. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the financial statements from the date that control commences until the date that control ceases. The Company recognizes in the financial statements its proportionate share of the assets, liabilities, revenues and expenses of its joint operations. All intra-group transactions, balances, income and expenses are eliminated in full on consolidation. (b) Cash and cash equivalents Cash and cash equivalents include cash and all investments with a maturity of three months or less. (c) Provisions A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax “risk-free” rate that reflects current market assessments of the time value of money and the risks specific to the liability. The unwinding of the discount is recognized as a finance expense. Provisions are not recognized for future operating losses. Decommissioning and restoration liabilities: The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category. Decommissioning obligations are measured at the present value of management’s best estimate of the expenditures required to settle the present obligation at the period end date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the asset retirement obligations are charged against the provision to the extent the provision was established. (d) Oil and natural gas exploration and evaluation expenditures Exploration and evaluation costs (“E&E” assets) All costs incurred prior to obtaining the legal right to explore an area are expensed when incurred. 49 2017 Annual Report Generally, costs directly associated with the exploration and evaluation of crude oil and natural gas reserves are initially capitalized. Exploration and evaluation costs are those expenditures for an area where technical feasibility and commercial viability have not yet been demonstrated. These costs generally include unproved property acquisition costs, geological and geophysical costs, sampling and appraisals, drilling and completion costs and capitalized decommissioning costs. Costs are held in exploration and evaluation until the technical feasibility and commercial viability of the project is established. Amounts are generally reclassified to petroleum and natural gas properties once probable reserves have been assigned to the field. If probable reserves have not been established through the completion of exploration and evaluation activities and there are no future plans for activity in that field, then the exploration and evaluation expenditures are determined to be impaired and the amounts are charged to profit or loss. (e) Petroleum and natural gas properties Carrying value Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as petroleum and natural gas properties in the specific asset to which they relate. Petroleum and natural gas properties are stated at cost less accumulated depreciation and depletion and accumulated impairment losses. The initial cost of a petroleum and natural gas property is comprised of its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation, and for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given up to acquire the asset. Subsequent costs Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred. Depletion and depreciation The net book value of producing assets are depleted on a field-by-field basis using the unit of production method with reference to the ratio of production in the year to the related proved and probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. For purposes of these calculations, production and reserves of natural gas are converted to barrels on an energy equivalent basis. Other assets are depreciated on a declining basis at rates ranging from 20% to 30% per annum. Gains and losses on disposal of an item of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized as separate line items in profit or loss. (f) Impairment E&E and petroleum and natural gas properties E&E assets are assessed for impairment when facts and circumstances suggest that the carrying 50 2017 Annual Report amount exceeds the recoverable amount and when they are reclassified to Development and Production (“D&P”) assets. For the purpose of impairment testing, E&E assets are grouped by concession or field with other E&E assets belonging to the same concession or field. The impairment loss will be calculated as the excess of the carrying value over recoverable amount of the E&E impairment grouping and any resulting impairment loss is recognized in profit or loss. Recoverable amount is determined as the higher of the value in use or fair value less costs to sell. At the end of each reporting period, the Company reviews the petroleum and natural gas properties for circumstances that indicate that the assets may be impaired. Assets are grouped together into cash generating units (“CGU”s) for the purpose of impairment testing, which is the lowest level at which there are identifiable cash inflows that are largely independent of the cash flows of other groups of assets. If any such indication of impairment exists, the Company makes an estimate of its recoverable amount. A CGU’s recoverable amount is the higher of its fair value less selling costs and its value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of future cash flows expected to be derived from the production of proved and probable reserves. Fair value less cost to sell is determined as the amount that would be obtained from the sale of a CGU in an arm’s length transaction between knowledgeable and willing parties. The fair value of oil and gas assets is generally determined as the net present value of the estimated future cash flows expected to arise from the continued use of the CGU, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted by an appropriate discount rate which would be applied by such a market participant to arrive at a net present value of the CGU. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down. Consideration is given to acquisition metrics or recent transactions completed on similar assets to those contained with the relevant CGU. When the recoverable amount is less than the carrying amount, the asset or CGU is impaired. For impairment losses identified based on a CGU, the loss is allocated on a pro rata basis to the assets within the CGU(s). The impairment loss is recognized as an expense in profit or loss. At the end of each subsequent reporting period these impairments are assessed for indicators of reversal. Where an impairment loss subsequently reverses, the carrying amount of the asset or CGU is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss have been recognized for the asset or CGU in prior years. A reversal of an impairment loss is recognized immediately in profit or loss. Financial assets A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk 51 characteristics. All impairment losses are recognized in profit or loss. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in profit or loss. (g) Financial instruments 2017 Annual Report Financial assets and liabilities are classified as either financial assets or liabilities at fair value through profit and loss (“FVTPL”), loans and receivables, held-to-maturity investments, available-for - sale financial assets, or other liabilities, as appropriate. Financial assets and liabilities are recognized initially at fair value. Subsequent measurement of financial instruments is based on their initial classification. FVTPL financial assets and liabilities are measured at fair value and changes in fair value are recognized in profit or loss. Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in other comprehensive loss until the instrument is derecognized or impaired. The remaining categories of financial instruments are recognized at amortized cost using the effective interest rate method. The transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability classified as FVTPL are expensed immediately. For a financial asset or financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to or deducted from the fair value on initial recognition and amortized through profit or loss income over the term of the financial instrument. (i) Non-derivative financial instruments Cash and cash equivalents, restricted cash as well as accounts receivable are classified as loans and receivables, which are measured at amortized cost. Accounts payable and accrued liabilities, and the credit facility are classified as other financial liabilities, which are measured at amortized cost. (ii) Derivative financial instruments The Company enters into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company does not designate its financial derivative contracts as effective accounting hedges and therefore will not apply hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, all derivative contracts are classified as FVTPL and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred. Subsequent to initial recognition, derivatives are measured at fair value, and changes therein will be recognized immediately in profit or loss. The Company may enter into physical delivery sales contracts for the purposes of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and will not be recorded at fair value on the statement of financial position. Settlements on these physical delivery contracts will be recognized in petroleum and natural gas revenue in the period of settlement. 52 2017 Annual Report Fair value The fair value of financial instruments that are actively traded in organized financial markets is determined by reference to quoted market bid prices at the valuation date. For financial instruments that have no active market, fair value is determined using valuation techniques including the use of recent arm’s length market transactions, reference to the current market value of equivalent financial instruments and discounted cash flow analysis. Share capital Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and stock options are recognized as a deduction from equity, net of any tax effects. (h) Foreign currency translation: The financial statements are presented in Canadian dollars, which is the Canadian parent entity’s functional and presentation currency; the functional currency of the Indian subsidiary is US dollars and the functional currency of the Australian subsidiary is Australian dollars. For the accounts of foreign operations, assets and liabilities are translated at period end exchange rates, while revenues and expenses are translated using average rates over the period. Translation gains and losses relating to the foreign operations are included in accumulated other comprehensive income, a component of equity. Foreign currency transactions are translated into the legal entity’s functional currency at the exchange rate in effect at the transaction; and any gains or losses are recorded in profit or loss. (i) Share-based compensation: The Company accounts for share-based compensation granted to directors, officers, employees and consultants using the Black-Scholes option-pricing model to determine the fair value of the plan at grant date. An estimated forfeiture rate is incorporated into the fair value calculated and adjusted to reflect the actual number of options that vest. Share-based compensation expense is recorded and reflected as share-based compensation expense over the vesting period with a corresponding amount reflected in contributed surplus. At exercise, the associated amounts previously recorded as contributed surplus are reclassified to common share capital. (j) Revenue recognition: Revenue from the sale of natural gas, natural gas liquids and crude oil is recognized when the significant risks and rewards of ownership are transferred, which is when title passes to the customer in accordance with the terms of the sales contract. This generally occurs when the product is physically transferred into a pipe, truck or other delivery mechanism. (k) Per share amounts: Basic per share amounts are computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted per share amounts are calculated giving effect to the potential dilution that would occur if stock options or other dilutive instruments were exercised into common shares. The treasury stock method assumes that any proceeds upon the exercise of dilutive instruments, including remaining unamortized compensation costs, would be used to purchase common shares at the average market price of the common shares during the period. (l) Income taxes: Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit 53 2017 Annual Report or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity. Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustments to tax payable in respect of previous years. Deferred tax is recognized providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously. A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. (m) Finance income and expenses: Finance income consists of interest earned on term deposits. Finance expenses include fees on Performance Security Guarantees issued by Export Development Canada, bank fees on Bank Guarantees issued to the Government of India, letter of credit charges, interest on notes payable and the credit facility, and accretion of the discount on decommissioning obligations. (n) Determination of fair value: A number of the Company’s accounting policies and disclosures required the determination of fair value, both for financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability. Fair Value Hierarchy Financial instruments that are measured subsequent to initial recognition at fair value are grouped into three categories based on the degree to which fair value is observable: Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis; Level 2 - Valuations are based on inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; including forward prices for commodities, time value and volatility factors which can be substantially observed or corroborated in the marketplace; Level 3 - Inputs that are not based on observable data for the asset or liability. Financial instruments comprise cash, cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, credit facility and derivatives. 54 2017 Annual Report The Company's policy is to recognize transfers in and out of the fair value hierarchy as of the date of the event or change in circumstances that caused the transfer. There were no such transfers during the period. Fair values have been determined for measurement and disclosure purposes as follows: i. Cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities The fair values of these financial instruments approximate their carrying amounts due to their short-term maturity. ii. Credit facility The fair value of the Company’s credit facility approximates its carrying value as it bears interest at floating rates and the applicable margin is indicative of the Company’s current credit risk. iii. Derivatives The Company’s commodity contracts (swaps and put options) are measured at level 2 of the fair value hierarchy. The fair value of the swap component is determined by discounting the difference between the contracted prices and published forward price curves as at the period end date, using the remaining contracted oil volumes and a risk-free interest rate. The fair value of puts are based on option models that use publish information with respect to volatility, prices and interest rates. (o) New standards and interpretations not yet adopted: Standards that are issued but not yet effective and that the Company reasonably expects to be applicable at a future date are listed below. Revenue from contracts with customers In April 2016, the IASB issued its final amendments to IFRS 15 Revenue from Contracts with Customers, which replaces IAS 18 Revenue, IAS 11 Construction Contracts, and related interpretations. The new standard contains a single model that applies to contracts with customers and two approaches to recognizing revenue; at appoint in time or over time. The model features a contract-based five-step analysis of transactions to determine whether, how much and when revenue is to be recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and timing of the revenue recognized. The new standard applies to contracts with customers and does not apply to insurance contracts, financial instruments or lease contracts. The new standard is to be adopted either retrospectively or using a modified retrospective approach for annual periods beginning on or after January 1, 2018, with early adoption permitted. The extent of the impact of adoption of the standard has not yet been determined. Financial instruments: recognition and measurement In July 2014, the IASB issued the complete IFRS 9 Financial Instruments to replace IAS 9 Financial Instruments: Recognition and Measurement. IFRS 9 includes a principle-based approach for the classification and measurement of financial assets, a single ‘expected credit loss’ impairment model and a new hedge accounting standard which aligns hedge accounting more closely with risk management. The new standard is to be adopted retrospectively with some exemptions for annual periods on or after January 1, 2018, with early adoption permitted. Bengal intends to adopt IFRS 9 on a retrospective basis on April 1, 2018. The extent of the adoption of IFRS 9 on the classification and measurement of the Company’s financial assets and financial liabilities and related disclosures has not yet been determined. Bengal does not currently apply hedge accounting to its financial instrument contracts and does not currently intend to apply hedge accounting to any of its financial instrument contracts upon adoption of IFRS 9. 55 2017 Annual Report Leases In January 2016, the IASB issued IFRS 16 Leases. This standard introduces a single recognition and measurement model for leases, which would require the recognition of assets and liabilities for most leases with a term of more than 12 months. The new standard is effective for annual periods beginning on or after January 1, 2019. Earlier application is permitted for entities that apply IFRS 15 Revenue from Contracts with Customers at or before the initial adoption date of January 1, 2018. The new standard is to be adopted either retrospectively or using a modified retrospective approach. The Company intends to adopt IFRS 16 in its financial statements for the annual period beginning on April 1, 2019. The extent of the impact of adoption of the standard has not yet been determined. 20. MANAGEMENT JUDGMENTS AND ESTIMATES The timely preparation of the financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of these financial statements are out-lined below. Critical judgments in applying accounting policies The following are the critical judgments, apart from those involving estimations (see below), that management has made in the process of applying the Company’s accounting policies and that have the most significant effect on the amounts recognized in these financial statements. i) Identification of Cash-generating units Bengal’s assets are aggregated into cash-generating units, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company's assets in future periods. ii) Impairment indicators Judgments are required to assess when impairment indicators exist and impairment testing is required. The application of the Company’s accounting policy for exploration and evaluation, petroleum and natural gas properties required management to make certain judgments as to future events and circumstances as to whether economic quantities of reserves have been found. iii) Recognition of deferred income tax assets The recognition of deferred income tax assets requires judgments regarding the likelihood and applicability of future income tax deductions. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and ability to apply income tax deductions. Key sources of uncertainty The following are the key assumptions concerning the sources of estimation uncertainty at the end of the reporting period that have a significant risk of causing adjustments to the carrying amounts of assets and liabilities. 56 i) Decommissioning provisions 2017 Annual Report The Company estimates future remediation costs of production facilities, wells and pipelines at different stages of development and construction of assets or facilities. In most instances, removal of assets occurs many years into the future. This requires judgment regarding abandonment date, future environmental and regulatory the engineering methodology for estimating cost, future removal technologies in determining the removal cost and liability-specific discount rates to determine the present value of these cash flows. the extent of reclamation activities, legislation, ii) Impairment of petroleum and natural gas assets For the purposes of determining whether impairment of petroleum and natural gas assets occurred, and the extent of any impairment or its reversal, the key assumptions the Company uses in estimating future cash flows are future petroleum and natural gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change as new information becomes available. Changes in economic conditions can also affect the rate used to discount future cash flow estimates. Changes in the aforementioned assumptions could affect the carrying amount of assets, and impairment charges and reversal will affect profit or loss. iii) Reserves The estimate of petroleum and natural gas reserves is integral to the calculation of the amount of depletion charged to the statement of operations and is also a key determinant in assessing whether the carrying value of any of the Company’s development and production assets has been impaired. Changes in reported reserves can impact asset carrying values due to changes in expected future cash flows. The Company’s reserves are evaluated and reported on by independent reserve engineers at least annually in accordance with Canadian Securities Administrators’ National Instrument 51-101. Reserve estimation is based on a variety of factors including engineering data, geological and geophysical data, projected future rates of production, commodity pricing and timing of future expenditures, all of which are subject to significant judgment and interpretation. iv) Share-based payments The Company measures the cost of its share-based payments to directors, officers, employees and certain consultants by reference to the fair value of the equity instruments at the date at which they are granted. The assumptions used in determining fair value include: share price, expected lives of options, risk-free rates of return, share price volatility and the estimated forfeiture rate. Changes to assumptions may have a material impact on the amounts presented. 57 CORPORATE INFORMATION AUDITORS KPMG LLP • Calgary, Canada LEGAL COUNSEL Burnet, Duckworth & Palmer LLP • Calgary, Canada Johnson Winter Slattery • Brisbane, Australia BANKERS Royal Bank of Canada • Calgary, Canada WestPac • Sydney, Australia ICICI Bank Ltd. • Calgary, Canada and Mumbai, India REGISTRAR AND TRANSFER AGENT Computershare • Toronto, Canada INVESTOR RELATIONS 5 Quarters Investor Relations, Inc. • Calgary, Canada DIRECTORS Chayan Chakrabarty Peter D. Gaffney James B. Howe Dr. Brian J. Moss Robert D. Steele Ian J. Towers (Chairman) W.B. (Bill) Wheeler DISCLOSURE COMMITTEE All Directors are members of the Committee AUDIT COMMITTEE James B. Howe (Chairman) Robert D. Steele W.B. (Bill) Wheeler RESERVES COMMITTEE Peter D. Gaffney (Chairman) Dr. Brian J. Moss GOVERNANCE AND COMPENSATION COMMITTEE Peter D. Gaffney Dr. Brian J. Moss Robert D. Steele (Chairman) Ian J. Towers OFFICERS Chayan Chakrabarty, President & Chief Executive Officer Richard N. Edgar, Executive Vice President Jerrad Blanchard, Chief Financial Officer Gordon R. MacMahon, Vice President, Exploration Bruce Allford, Secretary STOCK EXCHANGE LISTING – TSX: BNG 2017 Annual Report 58 

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