A P R I L 2 0 1 8

2

The Hemisphere Strategy

Focused on creating long-term shareholder value by continually developing our low cost / high rate of return oil assets

Geographic Focus Production and landbase located in friendly jurisdiction of southeast Alberta Strategic acquisitions of offsetting production and drilling opportunities

Control of Assets & Development 100% owner & operator of land, wells & facilities Adjustable pace of development

Maximize Oil Recovery Develop pools with horizontal wells drilled off pads to minimize surface impact No hydraulic fracturing required due to high reservoir porosity and permeability Use proven, highly effective waterflood enhanced oil recovery methods to maximize ultimate oil

recovery per well and minimize capital invested

Drive Capital Efficiency Continue to lower development and operating costs as we increase the size of drilling programs

and improve well performance with increasing reservoir pressure

The Hemisphere Snapshot

3

TSX Venture HME

Share Price April 6, 2017

$0.20

52 Week Range $0.18 - $0.36

Basic Shares Outstanding 89.8 MM

FD Shares Outstanding 111.8 MM

Insider Ownership ~13%

Enterprise Value $36.6 MM

Dec. 31, 2017 Net Debt Est. $18.6 MM

Term Loan Facility* 5 years; Matures September 15, 2022

US$35.0 MM

Current Production** Field-estimated; Nov 25 – Dec 9, 2017

~950 boe/d 94% oil

2017 Production 659 boe/d 95% oil

Proved + Probable Reserves*** 7.2 MMboe

NPV10 (before tax)*** $116.7 MM

Liability Management Rating as at April 7, 2018

5.60

* The lender under Hemisphere’s Term Loan Facility has commitment of up to US$20.0 million. ** As disclosed in Hemisphere’s news release dated Dec 13, 2017. *** Reserve volumes and net present values are as attributed by McDaniel & Associates Consultants Ltd. ("McDaniel") in the reserve report of McDaniel dated March 9, 2018 and effective as of December 31, 2017("McDaniel Reserve Report"). See Advisory Statements – Oil and Gas Information – Net Present Values.

2.2 2.8 3.1

4.9 1.1

1.1 1.4

2.3

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

Dec 312014

Dec 312015

Dec 312016

Dec 312017

MM

boe

The Long-Term Value Growth

4

* Reserve volumes and net present values are attributed in each of the independent reserve reports prepared for Hemisphere effective as of the date noted above.

Proved

Probable

2.3 2.3

57% GROWTH THROUGH

WATERFLOOD RECOGNITION

57% GROWTH 57% GROWTH 57% GROWTH

Reserves* NPV10 BT**

1P $40.3

1P $34.3

1P $45.7

1P $80.4

2P $22.2 2P

$14.1

2P $20.2

2P $36.3

$1.02

$0.64

$0.77

$1.30

$0.00

$0.25

$0.50

$0.75

$1.00

$1.25

$1.50

$0.0

$20.0

$40.0

$60.0

$80.0

$100.0

$120.0

$140.0

Dec 312014

Dec 312015

Dec 312016

Dec 312017

Per s

hare

(bas

ic)

$MM

5

The Southern Alberta Focus

ALB

ERTA

SASK

ATC

HEW

AN

Journey Energy

Cor4 Oil

Cardinal Energy

Harvest

Lundin Group IPC

CNRL

Torxen Energy

HEMISPHERE ENERGY

SASK

ATC

HEW

AN

ALB

ERTA

Calgary

HME Land HME Wells

The Foundation Assets

6

ATLEE BUFFALO

Suffield Military Base

JENNER

HME Land

SOUTHERN ALBERTA

100% Working Interest

~35,000 undeveloped net acres

Mannville & Pekisko oil

900 - 1,000 m deep

Conventional horizontal wells

No fracs required

7

Jenner: The Stable Cash Flow

S

B

S

B

S

HME Land Battery Satellite Pipeline 3D Seismic

o 100% average working interest o 100% operator of production

o ~24,000 net acres of land

o 8 oil pools defined by 3D seismic

o 30 drilling locations identified*

o 9 booked locations*

o Operated oil processing and water disposal facilities

o Expansion capability for growth in production

* See Advisory Statements – Oil and Gas Information – Drilling Locations.

8

Atlee Buffalo: The Growth Opportunity

o Upper Mannville F Pool o 28 MMbbl OOIP* o Only 5% current oil recovery factor

o Upper Mannville G Pool o 38 MMbbl OOIP* o Only 3% current oil recovery factor

o Working Interest – 100% in both pools

o Excellent Geological Control – Oil pools delineated by over 50 vertical wells

o 3D Seismic – Coverage over both pools

o Waterflood – Expanding in both pools

o Oil Recovery Factors** – Analogue pools have reached up to 40% with water and chemical floods. HME’s Dec.31/17 Reserve Report reflects total 2P booked reserves of just 12% of the estimated oil in place

* Based on McDaniel’s reservoir mapping for the purposes of the McDaniel Reserve Report. See Advisory Statements – Oil and Gas Information – OOIP. ** See Advisory Statements – Oil and Gas Information – Analogous Information.

F POOL

G POOL

Hz producer Hz water injector Vertical injector

F POOLF POOL

9

2017 Accomplishments Drilled 4 producers and 2 injectors

Expanded F pool facility to enhance water separation and increase oil production

Constructed and initiated a new water separation and re-injection facility at G pool

Acquired 7,433 acres of new land

2018 Plans Q1 2018: Drilled 1 producer and 2

injectors in Upper Mannville G Pool

o Prepare follow-up program with intentions to fully develop the pools through 2018-19

o Continue to expand field-wide reservoir simulation study as more production and pressure data is incorporated from new wells

2017 Accomplishments

Atlee Buffalo: The Development Plan

F POOL

G POOL

Hz producer Hz water injector Q1 2018 producer Q1 2018 injector Future Hz wells**** Vertical injector

WELL ECONOMICS – Reservoir Simulation Model***

Atlee Buffalo

Capital Drill, Complete,

Equip & Tie-in

Estimated Ultimate

Recovery*

Initial

Production*

Payout**

NPV10**

ROR**

Capital

Efficiency**

Area $MM Mbbl bbl/d Years $MM % $/bbl/d

F Pool 0.9 305 115 0.8 3.5 200 8,000

G Pool 0.85 320 130 0.7 6.3 320 6,500 * See Advisory Statements – Oil and Gas Information – Initial Production Rates. ** Assumptions: McDaniel Q1 2018 Commodity Price Deck; $3 quality differential from WCS; Average ~$15.40/boe and $14.50/boe operating and transportation expenses, and ~$10.80/boe and ~$8.80/boe royalties for F pool and G pool, respectively. *** Reservoir Simulation Models for both Atlee Buffalo F and G Pools have been internally generated as of January 31, 2018 by a qualified reserves evaluator in accordance with National Instrument 51-101 assuming the development shown on this slide and represents the economics of an average producing well. **** See Advisory Statements – Oil and Gas Information – Drilling Locations.

10

UPPER MANN YYY

UPPER MANN N2N

UPPER MANN G

UPPER MANN F

Alberta

Calgary

* Based on Alberta Energy ‘s reservoir mapping as of February 10, 2017. ** Based on McDaniel’s mapping for the purposes of the McDaniel Reserve Report. See Advisory Statements – Oil and Gas Information – OOIP.

Mannville Pools OOIP* API Oil Recovery to-date Waterflood Current

Rate Producing

Wells

Name MMbbl Degree MMbbl RF Type Start Date Boe/d #

Analogue - Upper Mann YYY 15.8* 13o 3.7 23% Water-ASP 1998 445 (Nov ‘17) 11

Analogue - Upper Mann N2N 28.3* 12o 4.1 14% Water 1999 830 (Nov ‘17) 28

Analogue - Upper Mann UU 3.3* 14o 1.3 39% Water-ASP 1998 140 (Nov ‘17) 3

Hemisphere - Upper Mann F 28** 13o 1.3 5% Water Q315 500 (Mar’18 est) 9

Hemisphere - Upper Mann G 38** 14o 1.3 3% Water Q415 205 (Mar’18 est) 2

UPPER MANN UU HME Land

Oil Recovery Current ProducingProducing

Atlee Buffalo: The Waterflood Analogues

1.3 MMbbl

2.7 MMbbl

7.4 MMbbl

1.3 MMbbl

2.9 MMbbl 4.2 MMbbl

Pool

OOIP*

Cumulative

Production to-date

2P Booked Reserves as at

December 31, 2017

Potential Additional (Unbooked) Reserves

At Various RF*** (MMBbl) (MMBbl) (MMBbl) (MMBbl)

20% 30% 40%

Upper Mann F 28 1.3 (5% Recovery Factor) 2.9 (15% Recovery Factor)** 1.4 4.2 7.0

Upper Mann G 38 1.3 (3% Recovery Factor) 2.7 (11% Recovery Factor)** 3.6 7.4 11.2

Atlee Buffalo Total 66 2.6 (4% Recovery Factor) 5.5 (12% Recovery Factor)** 5.1 11.7 18.3

4.2 MMbbl

Potential Additional

1.3 MMbbl1.3 MMbblProduced

* Based on McDaniel’s reservoir mapping for the purposes of the McDaniel Reserve Report. See Advisory Statements – Oil and Gas Information – OOIP. ** Represents the booked recovery factor attributed by McDaniel in the McDaniel Reserve Report. *** The recovery factors (and reserve volumes) as noted are potential recovery factors (and reserve volumes) only and are based on management's estimates (as prepared by a qualified reserves evaluator in accordance with National Instrument 51-101) and assume the successful response to Hemisphere's proposed waterflood operations based on the results of analogous pools under waterflood (See Advisory Statements – Oil and Gas Information – Analogous Information). There is no guarantee that the potential recovery factors will be realized by Hemisphere or that the reserve volumes noted will be attributed by an independent qualified reserves evaluator to Hemisphere.

At a

30% Recovery Factor

Upper Mann F Upper Mann G

7.4 MMbbl7.4 MMbbl

Potential Additional

1.3 MMbbl

2.7 MMbbl2.7 MMbblBooked

1.3 MMbbl1.3 MMbbl1.3 MMbbl1.3 MMbblProduced

11

2.9 MMbbl2.9 MMbblBooked

Atlee Buffalo: The Reserve Upside Potential

The Hemisphere Investment

12

Assets for Growth High rate of return projects with production and reserve growth through strategic low-

risk, low capital expenditure and fast payout projects

Multi-year, low-risk drilling inventory in Atlee Buffalo and Jenner oil pools

Stable, long-life, inclining production through waterflood

Access to Capital Well funded by strategic energy partner to execute growth of HME’s oil assets

Term Loan Facility of up to US$35.0 MM allows HME to organically develop its oil assets over the next 2-3 years

Team to Deliver Competent and experienced management team that has led HME through several

years of marginal commodity prices during the downturn and has positioned the company for growth

Time to Execute Oil market has strengthened and development costs remain low

The Driven Leadership

13

Management Don Simmons, P.Geol.

President & Chief Executive Officer Over 17 years of experience technical, operational and management

experience (AEC, Encana, Sebring)

Ian Duncan, P.Eng.Chief Operating Officer

Over 15 years of experience which includes drilling, completions, facilities, and operations (Talisman and Solaris MCI)

Dorlyn Evancic, CPA, CGA Chief Financial Officer

Over 30 years of experience in corporate finance and management (Guyana Frontier, Northern Continental and Gemco Minerals)

Andrew Arthur, P.Geol. Vice President, Exploration

Over 30 years of experience with several hundred wells drilled across the Western Canadian Sedimentary Basin (Enerplus, Mission, Talisman)

Ashley Ramsden-Wood, P.Eng. Vice President, Engineering

Over 15 years of experience in reservoir engineering, capital planning, and reserves evaluation (NAL, Petro-Canada)

Board of Directors Charlie O’Sullivan, B.Sc. Chairman

Don Simmons, P.Geol.

Frank Borowicz, QC, JP, CPA (Hon)

Bruce McIntyre, P.Geol.

Gregg Vernon, P.Eng.

Richard Wyman, B.Sc., MBA

Advisory Statements

14

Forward-looking Information and Statements

This corporate presentation contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "project", "should", "believe", "plans", "intends", "forecast", "goals" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the forgoing, this presentation contains forward-looking information and statements pertaining to the following: the volumes and estimated value of Hemisphere's oil and gas reserves; resource estimates and volumes in respect of Hemisphere's Jenner and Atlee Buffalo property areas; the anticipated economics of the oil wells at Atlee Buffalo and Jenner, including timing for anticipated payout and rates of return; Hemisphere's proposed development plans for its properties at Atlee Buffalo and Jenner; the potential for increased recovery factors in and reserve additions from the oil pools in which Hemisphere holds an interest; potential future production rates, cash flows; future oil and natural gas prices; future results from operations; future costs, expenses and royalty rates; the exchange rate between the $US and $Cdn; cash flow estimates based on full-scale development plans; the amount and timing of capital projects; corporate costs; the total future capital associated with development of reserves and resources; the anticipated response of Hemisphere's oil assets at the Atlee Buffalo property area to waterflood stimulation operations (including the potential for increased recovery factors and reserve volumes resulting there from); estimated ultimate recoveries of producing wells; initial production rates and the estimated payout from wells to be drilled by Hemisphere, NPV10 values, rates of return and capital efficiencies of Hemisphere’s Jenner and Atlee Buffalo wells.

The recovery, reserve, and resource estimates of Hemisphere's reserves and resources provided herein are estimates only and there is no guarantee that the estimated reserves or resources will be recovered. In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of Hemisphere which have been used to develop such statements and information but which may prove to be incorrect. Although Hemisphere believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Hemisphere can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which Hemisphere operates; the timely receipt of any required regulatory approvals; the ability of Hemisphere to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Hemisphere has an interest in to operate the field in a safe, efficient and effective manner; the ability of Hemisphere to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; risks associated with the degree of certainty in resource assessments; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Hemisphere to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Hemisphere operates; and the ability of Hemisphere to successfully market its oil and natural gas products. There are a number of assumptions associated with the potential of resource volumes estimated herein, including the quality of the reservoir, future drilling programs and the funding thereof, continued performance from existing wells and performance of new wells, well density per section and recovery factors and discovery and development of the lands evaluated in Hemisphere's property areas of operation, which necessarily involves known and unknown risks and uncertainties, including those identified in this presentation and including the risks set forth in Hemisphere's most recent annual information form available for review on SEDAR at www.sedar.com.

The forward-looking information and statements included in this presentation are not guarantees of future performance and should not be unduly relied upon. The forward-looking information and statements contained in this presentation speak only as of the date of this presentation, and Hemisphere does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Oil and Gas Information

Net Present Values

It should not be assumed that the estimates of future net revenues presented or disclosed in this presentation represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions made in estimating such future net revenues will be attained and variances could be material.

BOE

Disclosure provided herein in respect of Boe's 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.

OOIP

Original Oil-In-Place ("OOIP") is used by Hemisphere in this presentation as an equivalent to Discovered Petroleum Initially‐In‐Place ("DPIIP"). DPIIP, as defined in the Canadian Oil and Gas Evaluation Handbook, 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 DPIIP includes production, reserves and contingent resources; the remaining portion of DPIIP is unrecoverable. It should not be assumed that any portion of the OOIP/DPIIP set forth in this presentation is recoverable other than the portion which has been attributed reserves by McDaniel. There is uncertainty that it will be commercially viable to produce any portion of the OOIP/DPIIP other than the portion that is attributed reserves. The OOIP/DPIIP set forth in this presentation has been provided for the sole purpose of highlighting the recovery factors for the reservoirs that have been attributed reserves. The OOIP/DPIIP volumes for Hemisphere's Atlee Buffalo property disclosed in this presentation are from the mapping of the reservoirs by McDaniel (who is independent of Hemisphere) in connection with preparing the McDaniel Reserve Report. All OOIP/DPIIP estimates set forth herein are provided as of December 31, 2016.

Advisory Statements

15

Drilling Locations This presentation discloses drilling locations in two categories: (i) booked locations; and (iii) unbooked locations. Proved locations and probable locations, which are sometimes collectively referred to as "booked locations", are derived from the McDaniel Reserve Report and account for drilling locations that have associated proved or probable reserves, as applicable. Unbooked locations, are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 30 locations identified at Jenner in this presentation, 8 are proved locations, 1 is a probable location and 21 are unbooked locations. Of the 46 drilling locations (producers) shown on the map at Atlee Buffalo, 10 are proved locations, 2 are probable locations, and 34 are unbooked locations. Unbooked locations have specifically been identified by management as an estimation of Hemisphere's anticipated drilling activities based on evaluation of applicable geologic, seismic, and engineering, production and reserves data on prospective acreage and geologic formations. The drilling locations on which Hemisphere will actually drill wells ultimately depends upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, certain unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Analogous Information The information concerning Upper Mannville N2N and YYY analogue pools may be considered to be "analogous information" within the meaning of applicable securities laws. Such information was obtained by Hemisphere management throughout the year ended December 31, 2016 from various public sources including information available to Hemisphere through AccuMap (a mapping, data management and analysis software for companies operating in the Western Canadian Sedimentary Basin). Management believes such information is analogous to the Upper Mannville F and G pools in which Hemisphere has an interest and is relevant as it may help to demonstrate the reaction of such pools (in which Hemisphere has an interest) to waterflood stimulations. Hemisphere is unable to confirm whether the analogous information was prepared by a qualified reserves evaluator or auditor or in accordance with the COGE Handbook and whether such evaluator or auditor was independent and therefore, the reader is cautioned that the data relied upon by Hemisphere may be in error and/or may not be analogous to the oil pools in which Hemisphere holds an interest. Initial Production Rates Initial production rates disclosed herein are not determinative of the rates at which the wells will continue to produce and decline thereafter and may not necessarily be indicative of long-term performance or estimated ultimate recovery. Such rates should be considered preliminary. Non-IFRS Measures This presentation contains terms commonly used in the oil and gas industry which are not defined by or calculated in accordance with International Financial Reporting Standards ("IFRS"), such as: (i) funds flow from operations (including on a per share basis); (ii) operating field netback (including on a per boe basis); (iii) operating netback (including on a per boe basis); and (iv) net debt. The Company considers funds flow from operations to be a key measure that indicates the Company’s ability to generate the funds necessary to support future growth through capital investment and to repay any debt. Funds flow from operations is a measure that represents cash generated by operating activities, before changes in non-cash working capital and may not be comparable to measures used by other companies. Funds flow from operations per share is calculated using the same weighted-average number of shares outstanding as in the case of the earnings per share calculation for the period. Operating field netback is a benchmark used in the oil and natural gas industry and a key indicator of profitability relative to current commodity prices. Operating field netback is calculated as oil and gas sales, less royalties, operating expenses and transportation costs on an absolute and per boe basis. These terms should not be considered an alternative to, or more meaningful than, cash flow from operating activities or net income or loss as determined in accordance with IFRS as an indicator of the Company’s performance. Operating netback is a non-IFRS measure calculated as the operating field netback plus the Company’s realized commodity hedging gain (loss) per barrel of oil equivalent. Net debt (working capital) is closely monitored by the Company to ensure that its capital structure is maintained by a strong balance sheet to fund the future growth of the Company. Net debt is used in this document in the context of liquidity and is calculated as the total of the Company’s bank debt and current liabilities, less current assets. There is no IFRS measure that is reasonably comparable to net debt. Hemisphere has provided information on how these measures are calculated in its Management's Discussion and Analysis, which is available under Hemisphere's SEDAR profile at www.sedar.com.

Don Simmons, President & CEO Telephone: 604.685.9255 Email: simmons@hemisphereenergy.ca

Scott Koyich, Investor Relations Telephone: 403.619.2200 Email: scott@briscocapital.com