INVESTMENT HIGHLIGHTS

Transcription

1 HIGH IMPACT INTERNATIONAL EXPLORATION & PRODUCTION OCTOBER 2013 INVESTMENT HIGHLIGHTS Material production and cash flow growth potential through near-term development / appraisal Large acreage positions; inventory of underdeveloped pools & significant resource play potential Experienced, well-capitalized local partners Multiple near-term high impact drilling catalysts Limited capital at risk near term; majority of WI% carried through farm-out agreements Experienced management team with a track record of value creation Note: See the cautionary statement regarding Forward-Looking Statements and Netbacks at the end of this presentation. (1) Operating Netback in Fiscal Q1, 2014 of $79.82/bbl High-quality light oil & gas assets in lowrisk, stable countries: Australia & India Top-tier operating netbacks: $80/bbl (1) Recycle ratio: 3X 2 1

2 CORPORATE PROFILE Financial TSX Ticker TSX: BNG Common Shares Outstanding Basic -Fully Diluted (FD) 64.3MM 69.8MM Insider Holdings (FD) 24.5% Net Debt ~$7MM Market Cap $0.67 / share) $43MM Australia only P+P Reserve Value PV (1) % interest $48.7MM Operational Average daily production (88% light oil) (2) 356 boe/d Operating netback (2,3) $79.82/boe Forecast Q2 fiscal 2014 production estimate (4) boe/d Est. current production: ~565boe/d (1) As per March 31, 2013 GLJ reserve report; 25% working interest in Cuisinier (2) Q1 fiscal 2014 actuals (3) Q1 fiscal 2014 operating netback based on revenue / boe of $114.83; See the cautionary statement regarding Netback definition at the end of this presentation (4) Estimate based on average production for quarterly period ending September 30, BENGAL LEADERSHIP TEAM Management Chayan Chakrabarty, PhD (Pet Eng), MBA - President, CEO & Director Formerly Daylight Resources, Verenex, Ross Smith Energy Group Bryan Goudie, CA CFO Formerly Avery Resources, Ranger Oil, Emerging Equities, KPMG Richard Edgar, P.Geol. - Executive VP Formerly Avery Resources, Shelton Canada, Energy North Inc. Gordon MacMahon, P.Geol. - VP, Exploration Formerly Trident, APF Energy Trust, Canada Northwest Energy Decades of experience operating internationally & domestically; track record of advancing projects from exploration to production Strong corporate governance with significant operational, financial, and capital markets expertise Board of Directors Ian Towers, P.Eng Chairman President, CEO & Director Dolomite Energy Peter Gaffney, P.Eng, P.Geol Founding partner Gaffney, Cline & Associates (international reservoir engineering firm) James Howe, CA Director, Ensign Energy Services, Pason Systems & Wrangler West Energy Stephen Inbusch President Dynamic Energy Partners; Formerly Managing Director with CIBC, Randall & Dewey / Jeffries Brian Moss, Ph.D. (Geol) Exec VP,COO & Director of Crown Point Ventures; Former Director & Exec VP (Lat Am) of Antrim Energy Robert Steele, P.Eng Director Raise Production Inc.; Formerly Global Energy Services & Marquee Energy (formerly Skywest Energy); Founder of Stellarton Energy & Berens Energy Bill Wheeler, CFA President of Texada Capital Management; Co-founder, Leith Wheeler Investment Counsel; Director of Azabache Energy Chayan Chakrabarty, PhD (Pet Eng), MBA President, CEO & Director of Bengal Energy 4 2

3 DEFINED BUSINESS STRATEGY DEVELOP Capture near term value through low risk inventory of development drilling in proven petroleum systems APPRAISE Leverage experience and core competencies to further de-risk at the prospect level EXPLORE Enhance value through proven expertise, technology utilization and cost effective execution EXPAND Generate returns on investment to fund future growth and maintain portfolio diversification HIGHLIGHTS Successful Cuisinier drilling program of 6 wells yielded 100% success rate Drilled first exploration well in Tookoonooka at Caracal-1, new light oil discovery; 52 API Approval for Petroleum License allows all current & future Cuisinier wells to produce for 21 years Advanced commissioning of Cuisinier to Cook Pipeline, (finalized June 2013) Secured farm-out agreement in Tookoonooka with Beach Energy (up to AUD$11.5MM) Successfully replaced ~18x annual production for year ending March 31, 2013 Transitioned from pure exploration to production Secured Beach Energy farm out, valued up to $11.5 million (AUD) 2P reserves increased year over year 167% 6 3

4 ASSET OVERVIEW Assets in proven, producing basins Large and under-explored acreage offers significant growth opportunity High potential impact without typical international risk Well-established regulatory framework with British common law Management experience in both Australia and India Established and experienced local partners 2.3MM acres total Australia onshore; resource play potential Attractive pricing environments oil priced at premium to Brent India onshore & offshore 7 AUSTRALIA S COOPER BASIN Darwin NORTHERN TERRITORY QUEENSLAND WESTERN AUSTRALIA Gladstone Brisbane SOUTH AUSTRALIA COOPER BASIN Perth Port Bonython Adelaide VICTORIA NEW SOUTH WALES Sydney Melbourne Pipelines (extensive take-away capacity to sales points) 8 4

5 COOPER BASIN HIGHLIGHTS Most prolific onshore basin in Australia Under explored & under exploited: creates opportunity Transfer knowledge and technology from mature basins to enhance recovery & success factors Resource play potential Pipeline and transportation infrastructure sufficient and growing Products priced off global benchmarks 5.05 Tcf of sales gas produced to June 2012 (1) 247MM barrels oil & liquids produced to June 2012 (1) (1) Source: Government of South Australia, Department of Manufacturing, Innovation, Trade, Resources and Energy bid document, Cooper Basin, CO2012-A South Australia Acreage Release. August BENGAL S COOPER BASIN OPERATIONS BARTA BLOCK: 360,000 acres 30.4% working interest (1) Cuisinier light oil discovery (52 API) Partnered with experienced area operator TOOKOONOOKA BLOCK: 654,000 acres 100% working interest (2) Caracal Discovery cased as light oil producer Beach Energy Farm-in (AUD$11.5MM max) CUISINIER DISCOVERY ASPEN MURTEREE BARTA BARROLKA SOUTH AUSTRALIA QUEENSLAND NEW SOUTH WALES TOOKOONOOKA CARACAL-1 DISCOVERY (1) Post-closing of acquisition of additional 5.357% working interest, expected Q4 calendar 2013 (2) Upon completion of the Beach Energy farm-in, working interest reduces to 50% 100km Non-Operated Operated 10 5

6 BARTA PERMIT (PL 303): CUISINIER 2013 PROGRAM SET THE STAGE FOR MORE AGGRESSIVE DEVELOPMENT PROGRAM IN 2014 CUISINIER NORTH 3D Attractive cash flow potential with strong operating netbacks in Cuisinier (1) coupled with rising production Continued reserves growth anticipated as drilling continues Prospects identified on Cuisinier North 3D will be targeted for drilling in 2014 Continued investment in infrastructure will enhance fluid handling, and reduce costs BARTA NORTH DISCOVERY (1) Cuisinier operating netbacks of $89.05/ bbl reported in Bengal s Q1 fiscal 2014 (2) Production volumes cited are cum. to June Source: State of Queensland Department of Employment, Economic Development and Innovation (DEEDI) Cuisiner Discovery Existing wells Cook Field Hutton/ Birkhead Oil 3.1MMbbl (produced to June 2012) (2) 3D Seismic 3D Seismic upcoming projects METER 11 CREATING VALUE IN CUISINIER CONTINUED SUCCESS EXPANDS POOL AREA Petroleum Lease (PL303) granted, Cuisinier oil processed at Cook facility Pipeline connectivity eliminates production curtailments due to trucking capacity 3D seismic to high grade areas of better sand development for appraisal drilling 224 km 2 3D seismic acquisition north of Cuisinier completed; interpretation underway Preliminary capex budget for fiscal 2014 in Cuisinier - AUD$11.3 MM to drill an anticipated 8 development / appraisal wells + 1 exploration well CUISINIER FIELD March 2013 GLJ (1), Best Case 3P Area = 30.1 km 2 (7,439 acres), pre-2013 drilling COOK TO MERRIMELIA PIPELINE August BNG Best Case (2) - Closure on 3D (within Permit) = 36.7 km 2 (9,078 acres) Pre-2013 wells Cook Production facility 2013 wells (1) Based on independent, qualified reserves evaluator GLJ Petroleum Consultants Ltd. s report dated March 31, 2013 entitled Reserves Assessment and Evaluation of Oil and Gas Properties Corporate Summary, prepared in accordance with NI and the COGEH. Cuisinier working interest at 25% (2) Based on management s internal estimates METER 12 6

7 TOOKOONOOKA PERMIT (ATP 732P) KENMORE 13.6MMBbls (1) CARACAL DISCOVERY SUPPORTS ONGOING DEVELOPMENT IPUNDU 4.3MMBbls (2) Amidst some of onshore Australia s largest producing fields Average prospect targeting structures of 20+ km 2 First well, Caracal 1, cased as future light oil producer (52 API) Appraisal locations selected 3D seismic will expand prospective appraisal area of Caracal + evaluate other exploration targets nearby JACKSON 48.2 MMBbls (1) (1) Source: State of Queensland Department of Natural Resources and Mines (DNRM) Production volumes cited are cumulative to June 2012 (2) Source: Operator well completion report Prospects Caracal-1 oil well Pipelines 0 17,820 METER 13 CREATING VALUE IN TOOKOONOOKA BEACH ENERGY FARM-IN SECURED JUNE 2013 Beach (ASX: BPT) - major operator in Cooper Basin; $1.7B market value BPT will fund drilling 2 wells & 300 km 2 of 3D seismic to earn 50% in the permit (up to max of AUD$11.5MM) NOMINAL 3D AREA ~300km 2 (BEACH TO FUND) IPUNDU 4.3MMBbls (2) KENMORE 13.6MMBbls (1) Beach Energy..says the new Tookoonooka oil exploration venture in Queensland has potential as a major revenue earner, building on the rapid growth in oil output the company has seen in the western Cooper Basin (3) JACKSON 48.2 MMBbls (1) (1) Source: State of Queensland Department of Natural Resources and Mines (DNRM) Production volumes cited are cumulative to June 2012 (2) Source: Operator well completion report (3) The Australian Financial Review, 28 August 2013, article by Angela Macdonald-Smith Prospects Caracal-1 oil well Pipelines 0 17,820 METER 14 7

8 ATP 732, CARACAL APPRAISAL & DEVELOPMENT LONGER TERM POTENTIAL AT TOOKOONOOKA Future appraisal wells targeting thicker Lower Wyandra section Second well (Caracal-2) to test both Wyandra and deeper Hutton target TRIODIA-1 WYANDRA OIL SHOW CARACAL-2 WYANDRA APPRAISAL & HUTTON TEST New 3D to be acquired by Beach Energy calendar Q No capital required during farm-in phase; future capital requirements determined by results CARACAL-1 WYANDRA OIL DISCOVERY SWAB RATE BOPD (52 LIGHT OIL) METER Caracal Wyandra Formation - Max Case Prospective Resource Area ~42.7 km 2 Caracal Wyandra Formation - Best case Prospective Pool Area ~16.5 km 2 Untested Birkhead/Hutton formation Closure Best Case Area ~5.2 km 2 15 INDIA OVERVIEW & CAUVERY BASIN BENGAL S ONSHORE BLOCK ~946 km 2 30% working interest INDIA Light oil prone (35-52 API) 600 km 2 3D completed Near term, high impact drilling - 3 wells planned in Q1 calendar 2014 for US$4.1MM (fully funded) Partnered with Gas Authority of India Ltd. and Gujarat State Petroleum Corporation Bengal s Onshore Block CY-ONN-2005/1 Bengal s Offshore Block CY-OSN-2009/1 BENGAL S OFFSHORE BLOCK ~1,362 km 2 100% working interest Seeking JV partner to acquire 3D in 2014 CAUVERY BASIN SRI LANKA 16 8

9 CAUVERY ONSHORE COCHISE PROSPECT 3 prospects to be drilled (2014) Cochise Prospect targets Lower Cretaceous Andimadam Formation which is productive immediately north of the permit Cochise Prospect is analogous to the North Kovilakalapal Field The most recent well, North Kovilakalapal 3 tested 500 Bopd (2) 2 Kms. Syn-rift structure, sequence un-tested on permit North Kovilakalapal Field ~1.6 MMBbls & 6.3 BCF Kovilakalapal Field ~9MMbbls & 98 BCF (1) Cochise Prospect Cochise Location (1) Source: Recoverable reserves data complied from IHS EDIN India general fields database (2) Source - The Oil & Gas Journal, April Note: See cautionary statement on Analogous Information at the end of this presentation. 17 BUILDING THE VALUE CHAIN DEVELOP Cuisinier Current cash flow, near and longer term drilling proven oil potential across a broad area, represents resource play potential APPRAISE Tookoonooka Prospective with substantial partner, discovery / appraisal mode. Future exploration upside EXPLORE India Exploration upside with near term drilling and potential production / cash flows EXPAND 18 9

10 UPCOMING OPERATIONAL CATALYSTS DRILLING Tookoonooka/Beach Farm-In Phase 2 Drill 2 wells Cuisinier Drill 6 wells Drill 1 Drill 2 Onshore Cauvery Drill 3 wells Cuisinier Drill 8 wells: 6 development, 2 appraisal SEISMIC Cuisinier North Exploration Drill Onshore Cauvery Tookoonooka 3D Seismic Offshore Cauvery Barta West 3D Cuisinier Well Tie-in FACILITIES Cuisinier Cook Tie-in Cuisinier Completion & Tie-in 5 wells Tie-In 6 th well Jan 2013 Apr 2013 Jul 2013 Oct 2013 Feb 2014 May 2014 Aug 2014 Dec 2014 Firm Contingent/ Planned (1) (1) Timing, magnitude and scope subject to weather, JV partnership, vessel availability, availability of capital and reprocessing outcomes. Note: See Possible Reserves disclaimer at the end of this presentation. 19 RESERVES GROWTH ANNUAL PROVED PLUS PROBABLE RESERVES (MBOE) AS AT YEAR END MARCH 31 9% growth year over year 167% growth year over year 1,698 BENGAL NET RESERVES (1) 7,465 mboe 1,698 mboe Proved + Probable Possible (1) Based on independent, qualified reserves evaluator GLJ Petroleum Consultants Ltd. s report dated March 31, 2013 entitled Reserves Assessment and Evaluation of Oil and Gas Properties Corporate Summary, prepared in accordance with NI and the COGEH. Cuisinier working interest at 25% 20 10

11 BENGAL PRODUCTION GROWTH NET AVERAGE DAILY PRODUCTION VOLUMES QUARTERLY ACTUALS + FORECAST (BOE/D) Natural Gas (boe/d) Crude Oil & Liquids (boe/d) Production growth directly linked to Cuisinier drilling (1) Sep Dec Mar-13 Jun Sep-13 Est. 487 (1) Forecast average daily production volumes for the quarter ended September 30, 2013, based on a 25% working interest in Cuisinier 21 VALUE CREATION FOR SHAREHOLDERS PRODUCTION PER SHARE GROWTH (NET) Average daily production (boe/d) per million basic shares outstanding (not debt adjusted) (1) Sep Dec Mar Jun Sep-13 Est. (1) Based on forecast average daily production volume range for the quarter ended September 30, Working interest in Cuisinier assumed at 25% with no additional equity issued 22 11

12 BENGAL CASH FLOW GROWTH BENGAL FUNDS FLOW FROM (USED IN) OPERATIONS (1) $3,000 $2,500 Funds from (used in) operations, actuals Funds from operations estimate for Q2 fiscal 2014 Per Share (basic) $2,400 (2) $2,600 $0.08 $0.07 $0.06 Total funds from operations (000) $2,000 $1,500 $1,000 $500 $0 ($471) $481 $0.01 $1,732 $1,151 $0.03 $0.02 (2) $0.04 (2) 30-Sep Dec Mar Jun Sep-13 $0.05 $0.04 $0.03 $0.02 $0.01 $0.00 Per share (basic) ($500) ($1,000) ($0.01) Quarter Ending -$0.01 -$0.02 (1) Funds flow from operations is a non-ifrs measure. The comparable IFRS measure is cash from operations. A reconciliation of the two measures can be found in Bengal s MD&A for the quarter ending June 30, (2) Funds flow from operations estimated range for Q2 fiscal BENGAL OFFERS LOWER RISK WITH HIGHER REWARD COUNTRY RISK RATING SCALE (1) : HIGHER RATING = LOWER RISK Country Risk Rating: Higher Rating = Lower Risk Lower risk, Lower netbacks Higher risk, Lower netbacks SKO SDX BNK TAO VLE SRN Lower risk, higher netbacks (Most desirable) AEN MMT PTA CYG BENGAL 0 $- $10 $20 $30 $40 $50 $60 $70 $80 $90 Operating Netback ($/boe) Data Source: Company Public disclosures for quarter ending June 30, 2013 (1) Country risk provided by Euromoney Country Risk Analysis April Note: See cautionary statements regarding Netbacks and Analogous Information at the end of this presentation Higher risk, Higher netbacks 24 12

13 STRONG CASH FLOW DRIVERS OPERATING NETBACKS FOR TSX/TSXV LISTED INTERNATIONAL PRODUCERS (C$/BOE) $89.05 Cuisinier operating netback as reported in Q1 fiscal 2014 $79.82 $73.97 $71.24 $68.72 $66.07 $51.67 $51.64 $44.11 $42.48 $29.99 $29.17 BNG CYG PTA MMT AEN VLE SRN TAO BNK SKO SDX Source: Company Public disclosures for quarter ending June 30, 2013 See cautionary statements regarding Netbacks and Analogous Information at the end of this presentation 25 WHY BENGAL? Material production, cash flow & reserves growth potential Large acreage positions; sizeable inventory of low risk drilling underpins organic growth Very strong cash flow drivers: high netbacks + production growth Significant near and longer-term high impact operational catalysts Experienced, well-capitalized local partners and limited capital at risk Experienced management team with a track record of value creation CASH FLOW GROWTH EXPANDING PRODUCTION & RESERVES LOW RISK DRILLING INVENTORY OPERATIONAL CATALYSTS 26 13

14 APPENDIX FISCAL 2014 PRELIMINARY APPRAISAL PLAN 2013 drilling program drilled 6 appraisal locations all successful oil wells Program success has now set the stage for more aggressive development program starting in 2014 Prospects identified on Cuisinier North 3D will be targeted for drilling in 2014 Significant reserves growth demonstrated to date with 2013 results not included: 2P & 3P reserves at 1.55 and 7.5 MMbbl net (1) POST DRILL MURTA DEPTH STRUCTURE Chef Prospect All Numbers Gross Lease Basis (MMbbl) (1) Low Best High Total Petroleum Initially in Place Discovered Petroleum Initially in Place Reserves 1P 2.9 2P 6.2 3P 30.0 Murta DC70 - Lowest Interpreted Oil (LKO) Yellow contour is m SS (1) Based on report prepared by GLJ, the Company's independent qualified reserves evaluator, entitled Resource Reserves Assessment and Evaluation of Cuisinier, effective Sept. 30, 2012, prepared in accordance with NI & COGEH Note: See Possible Reserves cautionary statement and Fundamental Resource Definitions at the end of this presentation 28 14

15 TOOKOONOOKA, ATP 732P CARACAL Caracal 1, cased as future oil producer (52 light oil) Located on a large, robust structure Core analysis has highlighted better reservoir development in lowermost Wyandra sand similar to offsetting pools Pool analogies show that the Lower sands exhibit better effective porosity & permeability resulting in strong initial production rates upon completion Appraisal drilling will target areas of thicker, Lower Wyandra sands WYANDRA CORE AT APPROX 1000m MD (with oil weeping into core barrel) Intra-Wallumbilla Depth Structure CARACAL 1 CORE Upper Lower 29 FORWARD-LOOKING STATEMENTS Certain information regarding Bengal set forth in this document contains forward-looking statements or financial outlooks (collectively, "forward-looking statements") under applicable securities law. The use of any of the words plan, expect, project, intend, believe, should, anticipate, estimate or other similar words, or statements that certain events or conditions may or will occur are typically intended to identify forward-looking statements. Forward-looking statements are not based on historical facts, but rather on Bengal s internal projections, estimates or beliefs concerning, among other things, future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities. These statements are only predictions, not guarantees, and actual events or results may differ materially. In particular, forward-looking statements included in this document include, but are not limited to, statements with respect to: Bengal s growth strategy and future work programs, the timing, scope (including, without limitation, the number of wells, target zones and well depths) and the estimated results of current and future work programs; future seismic programs; the drilling, completion, performance of future wells; plans to seek joint venture partners; infrastructure development, including, without limitation, construction of the pipeline to the Cook facility; performance of current wells; estimates of resources, reserves and ultimate recovery per well; demand for oil and natural gas in Australia, India and globally; results of operations; future production, production, including production targets from current and future wells; future production capacity; future netbacks, royalties and operating and transportation costs; oil and gas prices. In addition, statements relating to reserves or resources are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources described can be profitably produced in the future. The forward-looking statements contained herein are subject to numerous known and unknown risks and uncertainties that may cause actual results to vary, including but not limited to risks associated with: the impact of general economic conditions in Canada, Australia, India and globally; industry conditions, including changes in laws and regulations, including adoption of new environmental laws and regulations, and changes in how they are interpreted and enforced, in Canada, Australia and India; competition; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; imprecision in reserve and resource estimates; the production and growth potential of Bengal s assets; production, transportation and marketing constraints; failure to obtain required approvals of regulatory authorities, in Canada, Australia and India; risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities; volatility in market prices for oil and natural gas; fluctuations in foreign exchange or interest rates; environmental risks; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and natural gas industry; ability to access sufficient capital from internal and external sources; and other factors, many of which are beyond the control of the Company

16 FORWARD-LOOKING STATEMENTS Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could effect Bengal s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website ( With respect to forward-looking statements contained in this document, Bengal has made assumptions regarding: current and future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; royalty rates; future operating and transportation costs; and other matters. Although the forward-looking statements contained in this document are based upon assumptions which management believes to be reasonable, the Company cannot assure investors that actual results will be consistent with these forward-looking statements. Management has included the above summary of assumptions and risks related to forward-looking statements provided in this document in order to provide shareholders with a more complete perspective on Bengal s current and future operations and such information may not be appropriate for other purposes. Bengal s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forwardlooking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Bengal will derive there from. These forward-looking statements are made as of the date of this document and Bengal disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. The estimates of capital requirements, reserves and net present value of future net revenues ("NPV") contained in such slides are based on information for the Corporation's booked locations in respect of which reserves have been assigned as well as analogous public information. Readers are cautioned that there is no certainty that any development on Bengal's unbooked locations will be successful to the same extent as its booked locations, or at all, and therefore, the estimates of capital requirements, reserves and NPV should not be relied upon as necessarily indicative of future results or values. The information is also based on certain key assumptions including, without limitation, the assumptions set forth above under the "Forward-Looking Statements" advisory statement. Actual results and values may vary, with such variations being material, as a result of a number of risks and uncertainties, including, without limitation, the risks and uncertainties noted under the "Forward-Looking Statements" advisory set forth herein. 31 FUNDAMENTAL RESOURCE DEFINITIONS Total Petroleum Initially-In-Place (TPIIP) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. All TPIIP, other than DPIIP, set forth in this presentation has been classified as "undiscovered petroleum initially in place. Discovered Petroleum Initially-In-Place (DPIIP) is that quantity of petroleum that is estimated as of a given date, to be contained in known accumulations, prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable. All DPIIP set forth in this presentation, other than production and reserves, has been classified as unrecoverable. Undiscovered Petroleum Initially-In-Place (UPIPP) is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of UPIPP is categorized as prospective resources and the remainder is categorized as unrecoverable. There is no certainty that any portion of the UPIPP resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources

17 CAUTIONARY STATEMENTS Analogous Information: Certain noted drilling, completion, production, reserve and resource data provided in this document may constitute analogous information under applicable securities legislation, such as reserve and resource estimates or the reserves and resources present on the Company s lands, and near by lands, total production and production-rates from wells drilled by the Company or other industry participants located in geographical proximity to lands held by the Company. This information is derived from publicly available information sources (as at the date of this document) that the Company believes are predominantly independent in nature. The Company believes this information is relevant as it helps to define the reservoir characteristics in which the Company may have an interest. The Company is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor or in accordance with the Canadian Oil and Gas Evaluator Handbook and therefore, the reader is cautioned that the data relied upon by the Company may be in error, may not be analogous to the Company s land holdings and/or may not be representative of actual results of wells anticipated to be drilled or completed by the Company in the future. Possible Reserves: Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Barrels of Oil Equivalent: When converting natural gas to equivalent barrels of oil, Bengal uses the widely recognized standard of 6 thousand cubic feet (mcf) to one barrel of oil (boe). However, a boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Netbacks: Netback is a term that is not defined under International Financial Reporting Standards and is used by Bengal as a supplemental measure in evaluating Bengal s financial position and performance. Bengal calculates netbacks as revenues minus royalties and transportation and operation costs Net Present Value: Estimates of the net present value of the future net revenue from Bengal's reserves do not represent the fair market value of Bengal's reserves and are based on information for the Company s booked locations in respect of which reserves have been assigned as well as analogous public information. The estimates of reserves and future net revenue from individual properties or wells may not reflect the same confidence level as estimates of reserves and future net revenue for all properties and wells, due to the effects of aggregation