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F E B R U A R Y 2 0 1 8
The State of the Crude Oil Market
2
o Prices continue to strengthen
o Declining inventories, tighter supplies, stronger demand
o OPEC/NON OPEC compliance
o Increasing US & Canadian production
Canadian Oil Industry
o Increased price spread to WTI (WCS Differential)
o Supply > Pipeline capacity
o Short term solution – more oil by rail
o Long term solution – more pipelines (Trans Mountain, Keystone XL, Line 3 etc)
HEMISPHERE’S KEY TO SUCCESS = BE A LOW COST OPERATOR
To support the Canadian Energy Industry and learn more about our vital role in
the Canadian economy, please visit www.energycitizens.ca
3
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
4
TSX Venture HME
Share Price
January 30, 2017
$0.24
52 Week Range $0.18 - $0.36
Basic Shares Outstanding 89.8 MM
FD Shares Outstanding 111.8 MM
Insider Ownership ~13%
Enterprise Value $36.0 MM
Q3 2017 Net Debt $14.4 MM
Term Loan Facility*
5 years; Matures September 15, 2022
US$35.0 MM
Current Production**
Field-estimated; November 25 - December 9, 2017
~950 boe/d
94% oil
Q3 2017 Production 681 boe/d
95% oil
Proved + Probable Reserves*** 4.5 MMboe
NPV10 (before tax)*** $65.9 MM
Liability Management Rating
as at January 6, 2018
5.03
* 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 December 13, 2017.
*** Reserve volumes and net present values are as attributed by McDaniel & Associates Consultants Ltd. ("McDaniel") in the reserve report of McDaniel dated February 10, 2017 and effective as
of December 31, 2016 ("McDaniel Reserve Report"). See Advisory Statements – Oil and Gas Information – Net Present Values.
The Long-Term Value Growth
5
* Reserve volumes are as attributed in each of the independent reserve reports prepared for Hemisphere effective as of the date noted above.
** 2017 outlines the activity Hemisphere completed during the year and is not to be construed as reserves data.
1.3
2.2
2.8
3.1
0.8
1.1
1.1
1.4
0.0
1.0
2.0
3.0
4.0
5.0
Dec 31 2013 Dec 31 2014 Dec 31 2015 Dec 31 2016
Reserves*
MMboe
Proved
Probable
2017**
Drilled
6 wells
Added
facilities
Expanded
waterfloods
Acquired
land
Grew
production
6
The Southern Alberta Focus
ALBERTA
SASKATCHEWAN
Journey
Energy
Cor4 Oil
Cardinal
Energy
Harvest
Lundin Group
IPC
CNRL
Torxen
Energy
HEMISPHERE
ENERGY
SASKATCHEWAN
ALBERTA
Calgary
HME Land
HME Wells
The Foundation Assets
7
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
8
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.
9
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.31/16 Reserve Report reflects total
2P booked reserves of just 8% 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
10
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
o Q1 2018: Drill 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
information is obtained from 2017 program
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.
11
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* 13
o
3.7 23% Water-ASP 1998 445 (Nov ‘17) 11
Analogue - Upper Mann N2N 28.3* 12
o
4.1 14% Water 1999 830 (Nov ‘17) 28
Analogue - Upper Mann UU 3.3* 14
o
1.3 39% Water-ASP 1998 140 (Nov ‘17) 3
Hemisphere - Upper Mann F 28** 13
o
1.3 5% Water Q315 455 (Dec ’17) 9
Hemisphere - Upper Mann G 38** 14
o
1.3 3% Water Q415 202 (Dec ’17) 2
UPPER MANN UU
HME Land
Atlee Buffalo: The Waterflood Analogues
1.3 MMbbl
0.7 MMbbl
5.6 MMbbl
1.3 MMbbl
2.1 MMbbl
2.2 MMbbl
Pool OOIP*
Cumulative
Production to-date
2P Booked
Reserves as at
December 31, 2016
Potential Additional
(Unbooked) Reserves
At Various RF***
(MMBbl) (MMBbl) (MMBbl) (MMBbl)
20% 30% 40%
Upper Mann F 28 1.3 (5% Recovery Factor) 2.1 (12% Recovery Factor)** 2.2 5.0 7.8
Upper Mann G 38 1.3 (3% Recovery Factor) 0.7 (5% Recovery Factor)** 5.6 9.4 13.2
Atlee Buffalo Total 66 2.6 (4% Recovery Factor) 2.8 (8% Recovery Factor)** 7.8 14.4 21.0
Potential
Additional
Produced
* 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 just a
20%
Recovery Factor
Upper Mann F Upper Mann G
Potential
Additional
Booked
Produced
12
Booked
Atlee Buffalo: The Reserve Upside Potential
The Hemisphere Investment
13
o 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
o 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
o 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
o Time to Execute
 Oil market has strengthened and development costs remain low
14
Appendices
The Driven Leadership
15
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
The Q3 2017 Highlights
16
Financial Three Months Ended
September 30
Petroleum and natural gas revenue $ 2,733,656
Operating netback (1) 1,208,106
Funds flow from operations (2) 657,840
Per share, basic and diluted 0.01
Net loss (142,254)
Per share, basic and diluted (0.00)
Capital expenditures 3,107,979
Net debt (3) 14,426,091
Term loan $ 11,589,132
Operating Three Months Ended
September 30
Average daily production
Oil (bbl/d) 644
Natural gas (Mcf/d) 217
NGL (bbl/d) 1
Combined (boe/d) 681
Oil and NGL weighting 95%
Average sales prices
Oil ($/bbl) $ 45.58
Natural gas (Mcf/d) 1.48
NGL ($/bbl) 42.62
Combined ($/boe) $ 43.62
Operating netback ($/boe)
Petroleum and natural gas revenue $ 43.62
Royalties 9.36
Operating costs 12.78
Transportation costs 2.71
Operating field netback (4) $ 18.77
Realized commodity hedging gain (loss) 0.51
Operating netback (1) $ 19.28
(1) 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. Operating netback per boe 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 per barrel of oil equivalent.
(2) Funds flow from operations is a non-IFRS 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.
(3) Net debt is a non-IFRS measure calculated as current assets minus current liabilities including term loan or bank indebtedness and excluding fair value of financial instruments and any flow-through share premium.
(4) Operating field netback per boe is a non-IFRS measure calculated as the Company’s oil and gas sales, less royalties, operating expenses and transportation costs per barrel of oil equivalent.
The Hedging Program
17
Product Type Volume Price Index Term
Crude Oil Swap 300 bbl/d US$50.67 WTI-NYMEX September 1, 2017 – December 31, 2017
Crude Oil Swap(2) 150 bbl/d US$54.65 WTI-NYMEX November 1, 2017 – June 30, 2018
Crude Oil Option(2) 150 bbl/d US$54.65 WTI-NYMEX July 1, 2018 – February 28, 2019
Crude Oil Swap 300 bbl/d US$50.67 WTI-NYMEX January 1, 2018 – December 31, 2018
Crude Oil Swap 250 bbl/d US$50.67 WTI-NYMEX January 1, 2019 – December 31, 2019
Crude Oil Swap 200 bbl/d US$50.67 WTI-NYMEX January 1, 2020 – December 31, 2020
Crude Oil Collar 200 bbl/d US$40.00-$67.05 WTI-NYMEX September 1, 2020 – December 31, 2020
o Hedging Program protects against price volatility and
supports capital growth plan while ensuring debt repayment
o Approximately 55% of currently booked Proved Developed
Producing volumes(1) hedged for a 3 year period
(1) Reserve volumes are as attributed by McDaniel in the McDaniel Reserve Report.
(2) The counter-party to this contract holds a one-time option no later than June 30, 2018 to extend a swap on 150 bbl/d of crude oil at US$54.65 for the term indicated.
Advisory Statements
18
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
19
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

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February 2018 Corporate Presentation - World Outlook Conference

  • 1. F E B R U A R Y 2 0 1 8
  • 2. The State of the Crude Oil Market 2 o Prices continue to strengthen o Declining inventories, tighter supplies, stronger demand o OPEC/NON OPEC compliance o Increasing US & Canadian production Canadian Oil Industry o Increased price spread to WTI (WCS Differential) o Supply > Pipeline capacity o Short term solution – more oil by rail o Long term solution – more pipelines (Trans Mountain, Keystone XL, Line 3 etc) HEMISPHERE’S KEY TO SUCCESS = BE A LOW COST OPERATOR To support the Canadian Energy Industry and learn more about our vital role in the Canadian economy, please visit www.energycitizens.ca
  • 3. 3 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
  • 4. The Hemisphere Snapshot 4 TSX Venture HME Share Price January 30, 2017 $0.24 52 Week Range $0.18 - $0.36 Basic Shares Outstanding 89.8 MM FD Shares Outstanding 111.8 MM Insider Ownership ~13% Enterprise Value $36.0 MM Q3 2017 Net Debt $14.4 MM Term Loan Facility* 5 years; Matures September 15, 2022 US$35.0 MM Current Production** Field-estimated; November 25 - December 9, 2017 ~950 boe/d 94% oil Q3 2017 Production 681 boe/d 95% oil Proved + Probable Reserves*** 4.5 MMboe NPV10 (before tax)*** $65.9 MM Liability Management Rating as at January 6, 2018 5.03 * 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 December 13, 2017. *** Reserve volumes and net present values are as attributed by McDaniel & Associates Consultants Ltd. ("McDaniel") in the reserve report of McDaniel dated February 10, 2017 and effective as of December 31, 2016 ("McDaniel Reserve Report"). See Advisory Statements – Oil and Gas Information – Net Present Values.
  • 5. The Long-Term Value Growth 5 * Reserve volumes are as attributed in each of the independent reserve reports prepared for Hemisphere effective as of the date noted above. ** 2017 outlines the activity Hemisphere completed during the year and is not to be construed as reserves data. 1.3 2.2 2.8 3.1 0.8 1.1 1.1 1.4 0.0 1.0 2.0 3.0 4.0 5.0 Dec 31 2013 Dec 31 2014 Dec 31 2015 Dec 31 2016 Reserves* MMboe Proved Probable 2017** Drilled 6 wells Added facilities Expanded waterfloods Acquired land Grew production
  • 6. 6 The Southern Alberta Focus ALBERTA SASKATCHEWAN Journey Energy Cor4 Oil Cardinal Energy Harvest Lundin Group IPC CNRL Torxen Energy HEMISPHERE ENERGY SASKATCHEWAN ALBERTA Calgary HME Land HME Wells
  • 7. The Foundation Assets 7 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
  • 8. 8 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.
  • 9. 9 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.31/16 Reserve Report reflects total 2P booked reserves of just 8% 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
  • 10. 10 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 o Q1 2018: Drill 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 information is obtained from 2017 program 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.
  • 11. 11 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* 13 o 3.7 23% Water-ASP 1998 445 (Nov ‘17) 11 Analogue - Upper Mann N2N 28.3* 12 o 4.1 14% Water 1999 830 (Nov ‘17) 28 Analogue - Upper Mann UU 3.3* 14 o 1.3 39% Water-ASP 1998 140 (Nov ‘17) 3 Hemisphere - Upper Mann F 28** 13 o 1.3 5% Water Q315 455 (Dec ’17) 9 Hemisphere - Upper Mann G 38** 14 o 1.3 3% Water Q415 202 (Dec ’17) 2 UPPER MANN UU HME Land Atlee Buffalo: The Waterflood Analogues
  • 12. 1.3 MMbbl 0.7 MMbbl 5.6 MMbbl 1.3 MMbbl 2.1 MMbbl 2.2 MMbbl Pool OOIP* Cumulative Production to-date 2P Booked Reserves as at December 31, 2016 Potential Additional (Unbooked) Reserves At Various RF*** (MMBbl) (MMBbl) (MMBbl) (MMBbl) 20% 30% 40% Upper Mann F 28 1.3 (5% Recovery Factor) 2.1 (12% Recovery Factor)** 2.2 5.0 7.8 Upper Mann G 38 1.3 (3% Recovery Factor) 0.7 (5% Recovery Factor)** 5.6 9.4 13.2 Atlee Buffalo Total 66 2.6 (4% Recovery Factor) 2.8 (8% Recovery Factor)** 7.8 14.4 21.0 Potential Additional Produced * 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 just a 20% Recovery Factor Upper Mann F Upper Mann G Potential Additional Booked Produced 12 Booked Atlee Buffalo: The Reserve Upside Potential
  • 13. The Hemisphere Investment 13 o 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 o 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 o 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 o Time to Execute  Oil market has strengthened and development costs remain low
  • 15. The Driven Leadership 15 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
  • 16. The Q3 2017 Highlights 16 Financial Three Months Ended September 30 Petroleum and natural gas revenue $ 2,733,656 Operating netback (1) 1,208,106 Funds flow from operations (2) 657,840 Per share, basic and diluted 0.01 Net loss (142,254) Per share, basic and diluted (0.00) Capital expenditures 3,107,979 Net debt (3) 14,426,091 Term loan $ 11,589,132 Operating Three Months Ended September 30 Average daily production Oil (bbl/d) 644 Natural gas (Mcf/d) 217 NGL (bbl/d) 1 Combined (boe/d) 681 Oil and NGL weighting 95% Average sales prices Oil ($/bbl) $ 45.58 Natural gas (Mcf/d) 1.48 NGL ($/bbl) 42.62 Combined ($/boe) $ 43.62 Operating netback ($/boe) Petroleum and natural gas revenue $ 43.62 Royalties 9.36 Operating costs 12.78 Transportation costs 2.71 Operating field netback (4) $ 18.77 Realized commodity hedging gain (loss) 0.51 Operating netback (1) $ 19.28 (1) 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. Operating netback per boe 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 per barrel of oil equivalent. (2) Funds flow from operations is a non-IFRS 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. (3) Net debt is a non-IFRS measure calculated as current assets minus current liabilities including term loan or bank indebtedness and excluding fair value of financial instruments and any flow-through share premium. (4) Operating field netback per boe is a non-IFRS measure calculated as the Company’s oil and gas sales, less royalties, operating expenses and transportation costs per barrel of oil equivalent.
  • 17. The Hedging Program 17 Product Type Volume Price Index Term Crude Oil Swap 300 bbl/d US$50.67 WTI-NYMEX September 1, 2017 – December 31, 2017 Crude Oil Swap(2) 150 bbl/d US$54.65 WTI-NYMEX November 1, 2017 – June 30, 2018 Crude Oil Option(2) 150 bbl/d US$54.65 WTI-NYMEX July 1, 2018 – February 28, 2019 Crude Oil Swap 300 bbl/d US$50.67 WTI-NYMEX January 1, 2018 – December 31, 2018 Crude Oil Swap 250 bbl/d US$50.67 WTI-NYMEX January 1, 2019 – December 31, 2019 Crude Oil Swap 200 bbl/d US$50.67 WTI-NYMEX January 1, 2020 – December 31, 2020 Crude Oil Collar 200 bbl/d US$40.00-$67.05 WTI-NYMEX September 1, 2020 – December 31, 2020 o Hedging Program protects against price volatility and supports capital growth plan while ensuring debt repayment o Approximately 55% of currently booked Proved Developed Producing volumes(1) hedged for a 3 year period (1) Reserve volumes are as attributed by McDaniel in the McDaniel Reserve Report. (2) The counter-party to this contract holds a one-time option no later than June 30, 2018 to extend a swap on 150 bbl/d of crude oil at US$54.65 for the term indicated.
  • 18. Advisory Statements 18 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.
  • 19. Advisory Statements 19 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.
  • 20. Don Simmons, President & CEO Telephone: 604.685.9255 Email: simmons@hemisphereenergy.ca Scott Koyich, Investor Relations Telephone: 403.619.2200 Email: scott@briscocapital.com