Corporate Presentation March 2017
Cautionary Statements Forward Looking Statements. Statements in this presentation may contain forward-looking statements including management s assessment of future plans, operations, expectations of future production and capital expenditures. Information concerning resources is deemed to be forward-looking statements as such estimates involve the implied assessment that the resources described can be economically produced. These statements are based on current expectations that involve numerous risks and uncertainties, which may cause actual results to differ from those anticipated. These risks include, but are not limited to: the risks inherent in the oil and gas industry, operational risks relating to exploration, development and production; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks; and fluctuation in foreign currency exchange rates and commodity price fluctuation. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Undiscovered Petroleum Initially-In-Place ( UPIIP ), equivalent to undiscovered resources, are those quantities of petroleum that are estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of UPIIP is referred to as prospective resources, the remainder as unrecoverable. Undiscovered resources carry discovery risk. There is no certainty that any portion of these resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Discovered Petroleum Initially-In-Place ( DPIIP ), equivalent to discovered resources, is that quantity of oil that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves, and contingent resources; the remainder is unrecoverable. There is no certainty that it will be commercially viable to produce any portion ofthe resources. 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. There is no certainty that undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Test results. There is no representation by Alvopetro that the data relating to any well test results contained in this presentation is necessarily indicative of long-term performance or ultimate recovery. The reader is cautioned not to unduly rely on such data as such data may not be indicative of future performance of the well or of expected production or operational results for Alvopetro in the future. Non-GAAP Measures. This presentation contains financial terms that are not considered measures under International Financial Reporting Standards ( IFRS ), such as funds flow from operations, funds flow per share, operating netback and working capital. These measures are commonly utilized in the oil and gas industry and are considered informative for management and shareholders. We evaluate our performance based on funds flow from operations. Funds flow from operations is a non-ifrs term that represents cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations and funds flow per share important as they help evaluate performance and demonstrate the Alvopetro s ability to have or generate sufficient cash to fund future growth opportunities. Working capital surplus includes current assets (including current restricted cash and assets held for sale) less current liabilities (excluding the current portion of decommissioning liabilities) and is used to evaluate the Company's short-term financial leverage. Operating netback is determined by dividing oil sales less royalties, transportation and operating expenses by sales volume of produced oil. Management considers operating netback important as it is a measure of profitability per barrel sold and reflects the quality of production. Funds flow from operations, funds flow per share, working capital and operating netbacks may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations, net income or other measures of financial performance calculated in accordance with IFRS. Net Present Value. The net present value of future net revenue attributable to Alvopetro s reserves and resources is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves or resources by Sproule or D&M respectively. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Alvopetro s reserves and resources estimated by Sproule and D&M represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery, reserve and resource estimates of the Company's reserves and resources provided herein are estimates only and there is no guarantee that the estimated reserves or resources will be recovered. Actual reserves or resources may be greater than or less than the estimates provided herein. 2
Alvopetro s Vision & Strategy Alvopetro Energy Ltd.'s vision is to be the premier independent exploration and production company in Brazil, maximizing shareholder value by applying innovation to underexploited opportunities. The Alvopetro Opportunity: Known Proven Assets Conventional Exploration Discovered Tight Gas Resource Near-term focus on building a natural gas business by finalizing a unitization agreement and securing a gas sales contract for our Caburé discovery. 3
Seismic Processing is Critical Key to success is reprocessing of existing data Seismic reprocessed across majority of Alvopetro s blocks 1,200 km 2 of reprocessed 3D seismic Reprocessed 2D lines show similar improvement All supported by reprocessed seismic Critical to all core focus areas in Alvopetro Significantly derisks 21 conventional prospects Provides better understanding of tight gas resource concept Identifies development drilling potential on our lower risk Bom Lugar field Before Reprocessing BL-001 ~300 MB EUR Processed Version from BDEP After Reprocessing Reprocessed 3D BL-001 ~300 MB EUR Pojuca Marfim Producing Zone Pre- Rift Processed Version from BDEP Reprocessed 2D 4
The Alvopetro Opportunity Highly under-explored prospective land base (140,509 acres, 123,313 net acres) and a balanced suite of opportunities Experienced team with a strong track record Base 1C/2C Net Asset Value of C$1.47-$1.93/share (1) Known Proven Assets: Caburé gas field (197(2)/198(A1)) D&M estimates 33 BCF contingent resource (2C - ALV share) 182(B1) oil discovery Existing reserves and production on mature fields Strong cash position - US$17.1 million, at Dec 31, 2016 Materials inventory and other assets on hand for use on future projects - US$3.9 million, at Dec 31, 2016 Conventional Exploration: 21 conventional prospects Supported by newly reprocessed/high quality seismic Discovered Tight Gas Resource: 2-well pilot project drilled Defined deep basin natural gas resource over a large mapped area in a non-structural setting (1) Base net asset value includes; financial resources of US$17.1 million as at Dec 31, 2016, contingent resources of Caburé gas discovery, NPV10 before tax as at June 30, 2015, of US$61.9 million (1C) to US$91.3 million (2C), 2P reserves on Block 182 and two mature fields of US$10.3 million (NPV10 before tax as at December 31, 2016), and equipment inventory ($3.7 million) and other assets ($0.2 million) for use on future operations totaling US$3.9 million as at December 31, 2016. 5
Known Assets Caburé Gas Discovery Strong gas demand and robust pricing in Brazil support favourable economics Next steps finalize unitization agreement and secure gas sales contract 197(2) Well Tested gas in 3 intervals of Caruacu Formation (tested 15 m of a total 78 m of potential encountered pay) Combined unstimulated flow test rates of 8.7MMcf/d ALV 197(2) Average Forecasted Daily Deliverability First 30 days 19.8 MMcf/d (3,300 boepd) First 90 days 15.9 MMcf/d (2,650 boepd) First 365 days 10.2 MMcf/d (1,700 boepd) D&M 33 BCF contingent resource, NPV10 $91.3 million (2C share) 198(A1) Well Drilled to 1,480 metres TMD in January 2017 31 metres of potential net pay in Caruacu Formation and 26 metres in a series of up-hole Pojuca sands First production test completed in lower-most Caruacu interval 7 metres of net pay in tighter reservoir just above the gas water contact Tested 534 mcfpd + 45 o API condensate Forecast deliverability 835 mcfpd after 3 months Main Caruacu interval tested 2.7 mmfpd + 64 o API condensate 21 metres of potential net pay, 11.5% average porosity, 15.4% maximum porosity 6
Known Assets Bom Lugar Development Potential Bom Lugar and Jiribatuba mature fields Sproule estimated 465,000 bbls recoverable for the BL(A1) probable development location Existing single well production suggests larger pool First well planned 400 m horizontal leg at 2,414 m TVD 4+ follow-up locations Surface location built Caruacu Time structure 2 ms Contour Interval ALV-BL-B1 ALV-BL- A1 Horizontal BL1 Loc. ALV-BL-C1 Block 107 Follow-up locations 7
Agua Grande Candeias Known Assets 182(B1) Drilled to 2,095m encountering 6 m of net hydrocarbon pay in Agua Grande Formation The well was offline from May to Sept to transition to company owned equipment and reduce production expenses. Average production rate in the fourth quarter of 2016 of 30 bopd 2 additional conventional exploration prospects Candeias fractured shale potential Structural closure 182 Agua Grande time structure 5 ms Contour Interval 8
Conventional Exploration Inventory Highly under-explored prospective land base (140,509 acres, 123,313 net acres) 21 conventional exploration prospects identified, all supported by reprocessed seismic Two conventional discoveries Average shallow conventional well cost expected to be $2MM to $3MM Portfolio of conventional prospects in an area of developed oil and gas infrastructure, close to national and state grids, industry, and coastline Next planned exploration well is 177-A1 located on block 177. This well targets conventional prerift targets. Waiting on INEMA environmental permit 9
Conventional Exploration Prospect 177-A1 Targets Agua Grande and Sergi Formations trapped against Candeias Shale in a similar structural configuration to the Buracica Pool to the south that has produced over 180MMBBLS Sergi well depth 850m, $0.75 million well cost Nearest offset well with 109 metres of reservoir quality sands and porosities exceeding 20% in the Sergi Formation + downhole Boipeba potential Boipeba Shallow aquifer above angular unconformity Candeias Candeias Candeias 80 m shale Basement high separating Tucano and Reconcavo basins Basement Basement 10
Buracica Field Reservoir Parameters 3 way fault traps with Agua Grande and Sergi Reservoir juxtaposed against Candeias Shale Central block has produced 76% of the oil from the field from mainly Sergi Eolian & fluvial sand stones (14 production zones). 35 API oil. Sergi reservoir porosity between 22-25%. Permeability ranging from 150-900mD. Agua Grande in southern block with porosity ranges of 21-27% and Permeability ranging from 850-1450mD. Shallowest Sergi production at -305m with oil water contact at -525m indicates a 220m possible gross column height in the central block CO2 injection to maintain gas cap; water injection at GOC to prevent coning down into oil in the central block. 30 % recovery factor at injection start up. North block 7.8% ROIP from Sergi Fm. Central block 76.6% ROIP from Agua Grande & Sergi. South block 13.1% ROIP from Agua Grande North Central South North Central -525m Water Contact South Source: Ulysses de R. A. Lino. Case History of Breaking a Paradigm: Improvement of an Immiscible Gas- Injection Project in Buracica Field by Water Injection at the Gas/Oil Contact. SPE 94978-PP 2005.
Discovered Gomo Tight Gas Resource 197-1 Well Encountered 43 m potential net hydrocarbon pay Recovered 78 m of core Lower zone flowed natural gas at an average rate of 40 mcf/d (unstimulated) 183-1 Well Encountered 189 m potential net hydrocarbon pay (3 zones) Recovered over 40 m of core Upper Gomo 96 m of net pay including: o Thick 46 m interval with average porosity of 10% o 3 m zone with 14% porosity Deep Gomo 93 m of net pay, average porosity of 7% 12
Block 197/183 Geobodies A A Jan2 183-1 197-1 Tested Gas 3275m A 3550m 18 31 A 19 Gas Geobody7-Isopach 20 m C.I. 1 Defined deep basin natural gas resource over a 5,460 acre mapped area in a non-structural setting 13
Brazil Gas Marketing Environment High demand for natural gas in Brazil, 80.3 million m 3 /day in 2016. In 2016, on average, Brazil imported 28.3 million m 3 /day of natural gas from Bolivia and 5.1 million m 3 /day from LNG National gas infrastructure close to Alvopetro s natural gas discovery (see below) Fuel oil linked natural gas prices Petrobras eliminated price discounts in 2015 Sources: Brazilian Association of Large Industrial Energy Consumers and Free Consumer, and Brazil Ministry of Mines and Energy (http://www.mme.gov.br/) 14
Gas Sales Options Compressed natural gas Thermal power plants 125 MW ~ 30 mmcf/d Bahia Gas local State distribution company Large industrial users, largest consumes ~35 mmcf/d Petrobras tie into national grid 15
Brazil Macro Fundamentals Political climate improving Improving investment climate Economic outlook positive Petrobras asset divestitures 16
The Alvopetro Opportunity Experienced Team Well capitalized - US$17.1 million (1) of financial resources Highly under-explored prospective land base Attractive valuation Base Net Asset Value 1C/2C of C$1.47-1.93/share (2) before exploration prospects and Gomo tight gas resource potential. 1) As at December 31, 2016, includes cash and other working capital resources, including current restricted cash and assets held for sale. 2) Base net asset value includes; financial resources of US$17.1 million as at December 31, 2016, contingent resources of Caburé gas discovery, NPV10 before tax as at June 30, 2015, of US$61.9 million (1C) to US$91.3 million (2C), 2P reserves on Block 182 and two mature fields of US$10.3 million (NPV10 before tax as at December 31, 2016), and equipment inventory ($3.7 million) and other assets ($0.2 million) for use on future operations as at December 31, 2016. 17
Contact us: Calgary, Canada: Alvopetro Energy Ltd. Suite 1700, 525 8 th Avenue SW Calgary, Alberta, Canada T2P 1G1 Tel: (587) 794-4224 Email: info@alvopetro.com Salvador, Brazil: Alvopetro S/A Extração de Petróleo e Gás Natural Rua Ewerton Visco, 290, Boulevard Side Empresarial, Sala 2004, Caminho das Árvores, Salvador-BA CEP 41.820-022 Tel: + 55 (71) 3432-0917 Email: info@alvopetro.com www.alvopetro.com TSX-V: ALV