oryx petroleum: building an upstream leader in africa & the ......2020/03/24 · demir dagh for...

CORPORATE PRESENTATION

March 2020

Founded in 2010 by AOG

► AOG previously established, developed and sold Addax Petroleum

► March 2016 strategic investment by Zeg Oil and Gas, a Kurdistan Region of Iraq based company

► Current Ownership: AOG 65%, Zeg Oil 22%, Other 13%

Appraisal and development of three oil fields in the Hawler license area (Kurdistan Region of Iraq)

► 103 MMbbl 2P Oil Reserves(1) with Future Net Revenue(2) of $732 million

► Average gross (100%) oil production of 14,400 bbl/d in February 2020 with planned drilling in 2020 expected to add to production

Exploration offshore Senegal / Guinea-Bissau

► 23 prospective intervals in six structures identified with unrisked gross (100%) prospective oil resources of 2.7 billion barrels (risked: 255 MMbbl)(3)

► 3D seismic data interpretation and prospect ranking complete; environmental impact assessment nearing completion with exploration drilling planned in 2021

TSX listed (ticker: OXC)

2

BUILDING A FULL CYCLE E&P COMPANY

Key License Areas

1) Gross (working interest) proved plus probable oil reserves as at December 31, 2019. Gross refers to volumes before applicable PSC deductions.

2) After-tax net present value of related future net revenue using forecast prices and costs assumed by NSAI and a 10% discount rate as at December 31, 2019. Gross proved plus probable oil reserves estimates used to calculate futurenet revenue are estimated based on economically recoverable volumes within the development/exploitation period specified in the production sharing contract or fiscal regime applicable to each license area. The estimated valuesdisclosed do not represent fair market value.

3) The prospective oil resources data is based upon evaluations by NSAI, and the classification of such resources as “prospective oil resources” by NSAI, with effective date as at December 31, 2019. Prospective oil resources estimatesare volumetric estimates prior to economic calculations.

3

HAWLER LICENSE (KURDISTAN REGION OF IRAQ)

Four discoveries with production from the Demir Dagh, Zey Gawra and Banan fields (14,400 bbl/d in February 2020)

Working Interests

► 65% Oryx Petroleum (Operator)

► 35% KEPCO (Kurdistan Regional Government)

► Unrisked 2C Gross (100%) contingent Oil Resources -

Development Pending of 59 MMbbl (Risked: 26 MMbbl)

► Appraisal / Exploration potential

• Unrisked Gross 2C (100%) contingent Oil Resources - Development

Unclarified of 213 MMbbl (Risked: 71 MMbbl)

• Unrisked Best Estimate Gross (100%) Prospective Oil Resources of

161 MMbbl (Risked: 6 MMbbl)

(1) The oil reserves, contingent resources and prospective resources data is based upon an evaluation by NSAI with effective date as at December 31, 2019. See material change report dated February 19, 2020 filed on SEDAR.

(2) Gross refers to volumes before applicable PSC deductions.(3) After-tax net present value of related future net revenue using forecast prices and costs assumed by NSAI and a 10% discount rate as at

December 31, 2019. The estimated values disclosed do not represent fair market value. See material change report dated February 19, 2020 filed on SEDAR.

Wells

Completed

Appraisal

Discovery

Discovery: Oct 2013

Discovery: Dec 2013Currently producing

Discovery: Feb 2013Currently producing

Discovery: Mar 2014Currently producing

Gross(2) Proved Plus Probable

Oil Reserves(1)

Future Net

Revenue(1)(3)

100% Working Interest

Field (MMbbl) (MMbbl) (US$MM)

Demir Dagh Cretaceous 80 52

Zey Gawra Cretaceous 17 11

Banan East Cretaceous 35 23

Banan West Tertiary 8 5

Banan West Cretaceous 19 12

Total† 159 103 732

4

HAWLER LICENSE: FIELD OVERVIEW

Tertiary & Cretaceous

Reservoirs

Jurassic Reservoirs

Possible Triassic Reservoirs

Ain Al-Safra

220 km2

Zey Gawra

160 km2

Demir Dagh

197 km2

Relinquished Area

850 km2

AAS-1

BAN-2

BAN-1

ZAB-1

ZEG-1

DD-3&9

DD-10&11DD-2DD-5

DD-7

DD-8DD-4&6

AAS-2

Banan

211 km2

BAN-4

BAN-3

ZEG-3ZEG-4

ZEG-2

ZAB-1 ST

DD-1

BAN-6BAN-7

BAN-5

Demir Dagh (Cretaceous)► Four wells currently producing

► Medium grade crude (24º API average) with very

small quantities of gas and H2S

► Matrix and fracture porosity

► One horizontal well planned in 2020

Gross (100%) 2P Oil Reserves: 80 MMbbl(1)

Demir Dagh (Jurassic)► One producing well for most of 2016 but shut-in

in December 2016

► Light crude with gas and H2S treatment required

► Fracture porosity only

► No reserves booked at 31 December 2019

Zey Gawra (Cretaceous)► Five wells drilled to date with three currently

producing

► Light sweet crude (35º API average)



Demir Dagh and Zey Gawra producing from Cretaceous, with Banan producing from both the Cretaceous and Tertiary

Banan (Cretaceous)► Five wells drilled to date with four producing

► Medium grade crude similar to Demir Dagh

Cretaceous (22º API average)


► Drilling of two wells planned in 2020


(1) As at December 31, 2019 per evaluation conducted by Netherland Sewell &

Associates, Inc. (‘NSAI’). See Material Change Report dated February 19, 2020

filed on SEDAR.

Banan (Tertiary)► Two wells successfully completed as producers

in Banan West with additional well planned in

Banan East 2020

► Medium grade crude (27º API average)

► No reserves booked in Banan East Tertiary at

December 31, 2019


Zey Gawra (Tertiary)► ZAB-1 re-entry in late 2016 unsuccessful but

new well planned in 2020


Ain Al Safra► Two wells drilled with one tested

► Completion of AAS-2 targeting Triassic planned

in 2020


DD-2

DD-7

DD-8

DD-3

DD-9

DD-4

DD-6

DD-5

DD-10

DD-11

BAN-1

5

DEMIR DAGH FIELD APPRAISAL AND DEVELOPMENT

Cretaceous map

► One horizontal well planned in

2020

► Seven wells completed for production with four wells currently producing• DD-2, 3, 4, 6, 7, 8 & 10 completed in

Cretaceous

• DD-3 previously completed in Jurassic

• DD-2 and DD-3 (Jurassic) shut-in due to high water production

• DD-4 and DD-7 shut-in due to marginal production levels relative to operating costs

► Ten wells drilled to date

• Two deep wells to evaluate all

reservoirs (DD-2 & 3)

• Eight shallow wells appraising

Cretaceous (DD-4, 5, 6, 7, 8, 9,

10 & 11)

• Vertical / deviated well designs

► Two wells drilled in 2014• BAN-1 (Drill Stem Test)

• BAN-2 (no Drill Stem Test)

► Both wells confirmed oil in Cretaceous reservoir (Reserves)• 54 MMbbl Gross (100%) Proved plus Probable Oil

Reserves(1)

• Medium grade crude similar to Demir DaghCretaceous (22° API average)

• Matrix and fracture porosity

► Data collected during drilling of BAN-2 indicated presence of oil column in Tertiary reservoir. Reserves confirmed with drilling of BAN-3• 8 MMbbl Gross (100%) Proved plus Probable Oil

Reserves(1)

• Average 26° API and 4% Sulphur

► Interpretation of data is that Banan is actually two fields separated by a fault (Banan West and Banan East)

6

BANAN DISCOVERY AND EARLY APPRAISAL

BAN-2

BAN-1

Bakhtiari - Fars

Pila Spi – Gercus - Sinjar

Kolosh

Shiranish – Kometan – Qamchuqa

Sarmord - Garagu

Najmah

Mus - Adayiah - Butmah

Triassic

BAN-2S N

Reserves

Contingent Resources

Pilaspi map(1) As of December 31, 2019

► BAN-3 and BAN-4 wells targeting Tertiary in western fault block drilled and placed on production in 2018

► BAN-2 and BAN-6, BAN-7 and BAN-5 wells in the Cretaceous successfully completed and placed on production in 2018 and 2019

► Workover of BAN-1 in eastern fault block completed in early 2020• Data obtained during drilling indicate Tertiary

reservoir contact oil similar to Tertiary in western fault block (No reserves booked at December 31, 2019)

• Attempts to complete well as producer in Cretaceous were unsuccessful

► Additional two wells planned in 2020• One well targeting Tertiary reservoir in eastern fault

block

• One well targeting Cretaceous reservoir in eastern or western fault block (to be determined)

7

BANAN APPRAISAL AND EARLY PRODUCTION

BAN-3

BAN-2

BAN-4

BAN-6BAN-7

BAN-5

► ZEG-1 discovery in the Cretaceous in

2013

• 17 MMbbl Gross (100%) Proved Plus

Probable Oil Reserves(1)

• Light sweet crude (35º API average)

• Matrix porosity similar to Demir Dagh

• Higher recovery rates than Demir Dagh

► ZEG-1 ST, ZAB-1 ST, ZEG-2, ZEG-3 and

ZEG-4 successfully completed as

producers in Cretaceous reservoir in 2016

- 2018

• ZAB-1 ST and ZEG-2 shut-in

► ZAB-1 re-entry in Tertiary reservoir

concluded in late 2016 but unable to be

completed as a producer in that reservoir

• No reserves

8

ZEY GAWRA DISCOVERY AND EARLY APPRAISAL

(1) As at December 31, 2019.

ZEG-1

Pila Spi – Avanah - Khurmala

Bakhtiari - Fars

Kolosh

Shiranish

Qamchuqa – Sarmord - Garagu

Najmah - Sargelu

AlanMus Adaiyah

Butmah

Triassic

ZAB-1-ST

ZEG-1-ST

NW SE

Reserves

Contingent Resources

9

ZEY GAWRA APPRAISAL & EARLY PRODUCTION

► ZEG-2 well targeting Cretaceous drilled and completed as a producer in Q1 2018

• Shut in in Q3 2018 due to water production (lack of isolation from water)

► ZEG-3 and ZEG-4 wells targeting Cretaceous drilled and placed on production in 2018

• Horizontal well design enabled isolation of the producing interval from overlying gas and underlying water in the reservoir

► No wells drilled in 2019 but drilling planned in 2020

• One well targeting Tertiary

ZAB-1

ZAB-1ST

ZEG-1

ZEG-2

ZEG-3H

ZEG-4H

► October 2013 discovery in the Lower Jurassic

• Average flow rates of 675 bbl/d and 850 bbl/d of oil using two

choke sizes (16/64” and 20/64”) over 8 hour flow periods(3) ‡

• Well performance impaired by heavy mud rising during tests

• Heavy oil

► AAS-2 appraisal well spudded March 2014

• Targeting Jurassic and Triassic reservoirs

• Drilling completed but unable to be tested due to security

developments in 2014

• Positive observations during drilling in Triassic

► Completion of AAS-2 planned in 2020 targeting Triassic

(1) As at December 31, 2019. Gross refers to reserves and resources before applicable PSC deductions

(2) Classified as Development Unclarified at December 31, 2019

(3) DST in the Alan and Mus formations.

10

AIN AL SAFRA

Gross (100%) (MMbbls)(1)

84 Unrisked

Oil ReservesContingent Oil

Resources(2)

Prospective Oil

Resources

1P 2P 3P 1C 2C 3C Low Best High

Tertiary - - - - - - - - -

Cretaceous - - - - - - - - -

Jurassic - - - 15 43 165 6 20 79

Triassic - - - - - - 18 40 77

TOTALS† - - - 15 43 165 24 60 166

AAS-1

AAS-2

Fracture network

South North

5km

0

1000

2000

3000

Depth TVDSS (m)

AAS-1&2

Contingent

Resources

Prospective

Resources

Pila Spi

Shiranish

Qamchuqa

Najmah

Alan

Mus-Adayiah

Kurra Chine

Butmah

Upr Fars

11

HAWLER PRODUCTION FACILITIES

► Facilities with processing capacity of 40,000 bbl/d at Demir Dagh

• Two trains to accommodate both crude oil with and without H2S treatment requirements

► ~1km tie-in pipeline from production facilities to Kurdistan Oil Export Pipeline

► 25,000 bbl of storage capacity, and 15,000 bbl/d truck unloading capacity at Demir Dagh

► Leased processing facilities installed at Zey Gawra in 2016 and at Banan in 2018, with

trucking to Demir Dagh for export pipeline entry

• Development plan for Banan field contemplates construction of pipeline transport back to facilities at

Demir Dagh for processing and export

ITP

40” & 46” pipelines, 600 & 900 Mbbl/d capacity(1)

KEOP

24/36” oil pipeline, 700 Mbbl/d capacity

12

KURDISTAN REGION: SUPPLY DYNAMICS

Export Sales:

► Via Turkey by Kurdistan Oil Export

Pipeline

► Recent KRI exports of oil ~450,000

bbl/d

► Monthly payments from the KRG to

oil exporters since September 2015

(current through September 2019)

► Realisation referenced to

international prices

Domestic Sales:

► Limited demand

To Ceyhan

Oryx Petroleum is currently exporting all production by pipeline

(1) Iraq portion of ITP currently non-operational

Illustrative Netback ($/bbl)

Contractor Netback

Realised Price $25.00 $35.00 $45.00

Royalties 10% (2.50) (3.50) (4.50)

Net revenue 22.50 31.50 40.50

Cost oil 40% 9.00 12.60 16.20

Profit oil 13.50 18.90 24.30

Contractor share 28% 3.78 5.29 6.80

Government share 72% 9.72 13.61 17.50

Total Contractor (Cost + Profit oil) 12.78 17.89 23.00

Less: Opex(1) (8.00) (8.00) (8.00)

Contractor Netback 4.78 9.89 15.00

Oryx Petroleum Netback

Revenue 65% 16.25 22.75 29.25

Less: Royalties & Government share

of Profit oil65% (7.94) (11.12) (14.30)

Less: Capacity Payment(2) (0.37) (0.52) (0.66)

Less: Opex(4) 85% (6.80) (6.80) (6.80)

Plus: Carry Recovery(3) 1.80 2.52 3.24

Oryx Petroleum After-tax Netback 2.94 6.83 10.73

► Realised Prices (Export via pipeline):

• Brent less $7.88/bbl transport / location discount with adjustment for API gravity and sulphur content

• Total differential to Brent currently of ~$15.00/bbl

► Contractor Profit oil and Oryx Petroleum capacity building payment assumes R factor <1

► Lower Opex expected to be achieved as production increases and processing / transport infrastructure is developed• ~$7.50 - $8.00 bbl at current production levels

► Opex and Capex carries

• Oryx Petroleum carries 20% KRG share

• Oryx Petroleum carries KRG capex up to $300 million

• Recoverable from KRG share of cost oil

► Brent price of $32.50/bbl required for a positive Oryx Petroleum After-tax Netback

13

HAWLER NEAR TERM NETBACKS

(1) Assumes gross (100%) production of 14,000 - 15,000 bbl/d

(2) 15% of Oryx Petroleum Share of Profit oil

(3) Government share of cost oil

(4) Assumes $8.00/bbl

14

AGC CENTRAL (SENEGAL / GUINEA BISSAU)

► 3,150 km2 licence area in water depths of 100 - 1,500m

► Carbonate edge play type similar to SNE-1 discovery identified from seismic data

► 750 km2 of seismic obligation in initial 3-year exploration phase

• 1,921 km2 3D Seismic survey and fast track processing completed in early 2017

• Full processing with interpretation and prospect ranking completed

• 23 prospective intervals in 6 structures identified with gross unrisked (100%) best estimate prospective oil resources of 2.7 billion barrels (risked 255 MMbbl)(1)

► Two well work commitment prior to October 2020

• Request submitted in Q3 2019 for suspension of first renewal period until Senegal and Guinea-Bissau agree on long term renewal of AGC Accord with amendment to Production Sharing Contract expected to be finalised in the coming months

► Environmental impact assessment nearing completion

Significant light oil potential in an area with a working petroleum system and recent discoveries in adjoining areas

► 80%(1) Oryx Petroleum (Operator)

► 20%(2) AGC

(1) As at December 31, 2019 per evaluation conducted by Netherland Sewell & Associates, Inc. (‘NSAI’). See Material Change Report dated February 19, 2020

(2) Assumes AGC exercises option to acquire an additional 5% interest

► A “missing piece” along the Albian / Aptian shelf

margin acquired in 2016 / 2017

► Significant light oil potential in an area with a

working petroleum system

► 1,921 km2 3D Volume

• Data owner / licensor - GeoPartners Ltd.

• Data acquisition by BGP Inc. / CNPC

• Data processed by DownUnder GeoSolutions

• Detailed Reconnaissance Study by Lyme Bay Consulting

• Quantitative Interpretation by RSI Geophysical

15

AGC CENTRAL:

SEISMIC ACQUISITION, PROCESSING & INTERPRETATION

SNE

NEW 3D

TOP ALBIAN

SUBCROP

SINAPA

DOME FLORE

PLAY TYPES

1) Maastrichtian – clastic play

2) Santonian - clastic play

3) Albian / L. Cenomanian – clastic play (SNE analogue)

4) Albian / Aptian – carbonate / clastic play

16

AGC CENTRAL: PLAY TYPES

2

1

3

4

AGC Central 3D (2017)

Note: Oryx Petroleum

has relinquished its

interest in the AGC

Shallow license

17

AGC CENTRAL: INITIAL INTERPRETATION OF SEISMIC DATA

AGC Central Risk Assessment

Play Type Reservoir Trap Source Seal

Maastrichtian Clastics Low High Low (Albian) Medium

Santonian Clastics Medium Medium Low (Turonian) Medium

Albian / L. Cenomanian Clastics Medium Low Low (Turonian & Albian) Low

Albian / Aptian Carbonates Medium Low Low (Albian) Low

W E

LOWER SENONIAN

UNCONFORMITY

2018 2019

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Average Daily Gross (100%)

Production (bbl/d)3,800 4,400 7,200 10,500 10,800 11,300 11,700 13,100

Realised Oil Price ($/bbl) 56.31 61.51 61.33 52.37 48.35 53.47 46.05 47.33

Oryx Petroleum Revenue ($MM) 13.9 17.9 29.4 36.5 34.0 39.9 35.7 40.9

Operating Cost per Barrel 14.04 13.86 12.93 11.03 11.48 10.33 10.27 9.73

Field Netback(1) ($/bbl) 16.76 19.45 20.07 17.15 14.84 18.22 14.65 16.05

Oryx Petroleum Netback(2) ($/bbl) 19.70 23.00 23.82 20.36 17.49 21.71 17.33 19.00

Operating Funds Flow(3) ($MM) 1.4 4.3 8.4 9.1 9.2 11.9 9.8 (3.9)(4)

18

RECENT FINANCIAL PERFORMANCE

1) Field Netback is a non-IFRS measure that represents the Group’s working interest share of oil sales net of the Group’s working interest share of royalties, the Group’s working interest share of operating expenses and the Group’s

working interest share of taxes. Management believes that Field Netback is a useful supplemental measure to analyse operating performance and provides an indication of the results generated by the Group’s principal business

activities prior to the consideration of production sharing contract and joint operating agreement financing characteristics, and other income and expenses. Field Netback does not have a standard meaning under IFRS and may not be

comparable to similar measures used by other companies.

2) Oryx Petroleum Netback is a non-IFRS measure that represents Field Netbacks adjusted to reflect the impact of carried costs incurred and recovered through the sale of cost oil during the reporting period. Management believes that

Oryx Petroleum Netback is a useful supplemental measure to analyse the net cash impact of the Group’s principal business activities prior to the consideration of other income and expenses. Oryx Petroleum Netback does not have a

standard meaning under IFRS and may not be comparable to similar measures used by other companies.

3) Operating Funds Flow is a non-IFRS measure that represents cash generated from operating activities before changes in non-cash assets and liabilities. The term Operating Funds Flow should not be considered an alternative to or

more meaningful than “cash flow from operating activities” as determined in accordance with IFRS. Management considers Operating Funds Flow to be a key measure as it demonstrates the Group’s ability to generate the cash flow

necessary to fund future growth through capital investment. Operating Funds Flow does not have any standardised meaning prescribed by IFRS and may not be comparable to similar measures used by other companies.

4) In Q4 2019 Operating Funds flow was negatively impacted by a $15.7 million provision resulting from the arbitration and judgement related to the Corporation’s former interest in the Haute Mer B license

Banan Drilling

► Two wells targeting the Cretaceous reservoir in 2020 including one workover of an existing well (completed)

► One new well targeting Tertiary reservoir in 2020

Demir Dagh Drilling

► One new horizontal well targeting the Cretaceous reservoir (additional well targeting Cretaceous deferred)

Zey Gawra Drilling

► One well targeting Tertiary reservoir in 2020

Ain Al Safra Drilling

► Completion of AAS-2 well targeting Triassic reservoir in 2020

Facilities

► Banan - Demir Dagh pipeline in 2020 (Banan processing facilities deferred)

► Flowlines and field infrastructure improvements

► Drilling preparations / Studies (drilling of one exploration well deferred)

19

2020 CAPITAL EXPENDITURE FORECAST / BUDGET

Note:

1) The above table excludes license acquisition costs. Totals in rows and columns may not add-up due to rounding

2) Other is comprised primarily of studies and license maintenance costs

Hawler

AGC Central

LocationLicense / Field /

Activity

Q1 2020

Forecast

2020

Budget

$ millions

Kurdistan

RegionHawler

Banan - Drilling 14 14

Zey Gawra - Drilling 4 5

Demir Dagh - Drilling 8 14

Ain Al Safra - Drilling 2 2

Facilities 19 26

Other(2) 3 3

Total Hawler 50 63

West Africa AGC Central 3 43

Capex Total(1) 53 106

AOG Credit Facility

► $80 million balance of principal plus accrued

interest

► Currently scheduled to mature in July 2021

Contingent Consideration

► Payable to vendor of Hawler license area

upon a second commercial discovery

► $76 million balance of principal plus accrued

interest

Liquidity

► $8.9 million cash on hand at December 31,

2019

► $5.0 million undrawn interim credit facility

20

KEY BALANCE SHEET ITEMS (DECEMBER 31, 2019)

AND LIQUIDITY OUTLOOK

► Production Ramp-up in the Kurdistan Region of Iraq expected to continue• February 2020 Gross (100%) average oil production of

14,400 bbl/d

• Revenue payments for oil exports paid through September 2019

• Five additional wells planned to be drilled, worked over or completed before the end of 2020

► Significant Potential Resource Upside in AGC Central license area offshore Senegal / Guinea-Bissau• Based on interpretation of 3D seismic 23 oil prospective

intervals in six structures identified with gross unrisked(100%) best estimate prospective oil resources of 2.7 billion barrels (risked 255 MMbbl)(1)

• Prospect selection complete; environmental impact assessment largely completed with drilling to follow

► Improved financial performance

► Supportive major shareholders

21

POSITIONED FOR GROWTH

(1) As at December 31, 2019 per evaluation conducted by Netherland Sewell & Associates, Inc. (‘NSAI’). See Material Change Report

dated February 19, 2020

This document has been prepared by Oryx Petroleum Corporation Limited (“Oryx Petroleum” or the “Corporation”) for information purposes only. This document should be read in conjunction with the annual information form of Oryx Petroleum dated March 23, 2019 (the

“AIF”). Additional information about Oryx Petroleum is available on its website at www.oryxpetroleum.com and Oryx Petroleum’s profile at www.sedar.com.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Statements that are not reported financial results or other historical information are forward-looking information within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of applicable United States securities laws

(collectively, “forward-looking statements”). This presentation includes forward-looking statements regarding Oryx Petroleum and the industry in which it operates, including statements about, among other things, exploration and drilling activities, expectations, beliefs, plans,

future oil prices, business and acquisition strategies, opportunities, objectives, prospects, assumptions, including those related to trends, prospects, future events and performance. Sentences and phrases containing or modified by words such as “anticipate”, “plan”,

“continue”, “estimate”, “intend”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targets”, “projects”, “is designed to”, “strategy”, “should”, “believe” and similar expressions, and the negative of such expressions, are not historical facts and are intended to identify forward-

looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Forward-looking statements should not be read as

guarantees of future events, future performance or results, and will not necessarily be accurate indicators of the times at, or by which, such events, performance or results will be achieved, if achieved at all. Forward-looking statements are based on information available at

the time and/or management’s expectations with respect to future events that involve a number of risks and uncertainties, any of which could cause actual results to differ materially from those expressed in or implied by the forward-looking statements. The factors described

under the heading “Risk Factors” in the AIF provide examples of the risks, uncertainties and events that may cause Oryx Petroleum’s actual results to differ materially from the expectations it describes in its forward-looking statements. Readers should be aware that the

occurrence of the events described in such risk factors could have an adverse effect on, among other things, Oryx Petroleum’s business, prospects, operations, results of operations and financial condition.

Specific forward-looking statements contained in this presentation include, among others, statements, management’s beliefs, expectations or intentions regarding the following: the ability of each of the Corporation and its partners to fund ongoing exploration and meet their

respective financing and carry obligations with respect to the license areas of Oryx Petroleum; the performance characteristics and discovery potential of Oryx Petroleum’s properties; the Corporation’s expectations of current and future production levels; exploration work

plans, conceptual development and marketing plans; the reserve and resource potential of Oryx Petroleum’s license areas; the political, economic, regulatory and business stability of the jurisdictions in which Oryx Petroleum operates; export pipeline options and export

capacity; the Corporation’s re-forecasted capital expenditure program and the Corporation’s expectations regarding the use of existing capital, its ability to raise capital, develop reserves and resources and to add reserves and resources through exploration, acquisitions and

development; the amount, nature, timing and effects of the Corporation’s capital expenditures; the Corporation’s plans for drilling wells and chance of success; the Corporation’s plans for completion or acquisition of seismic data; market prices and supply and demand

fundamentals for oil and other commodities; timing and amount of the Corporation’s potential future production, forecasts of capital expenditures, net revenues, future development plans and the sources of financing thereof; the Corporation’s operating and other costs and

expenses; business strategies and plans of management; anticipated benefits and enhanced shareholder value resulting from prospect development and acquisitions; and oil reserves and resources quantities and the discounted present value of future net cash flows from

these reserves and resources.

Readers are cautioned that the foregoing list of forward-looking statements should not be construed as being exhaustive.

In making the forward-looking statements in this presentation, the Corporation has made assumptions regarding: timing and results of exploration activities; the enforceability of the Corporation’s production sharing contracts and risk exploration contracts; treatment under the

fiscal terms of production sharing contracts, risk exploration contracts, governmental regulatory regimes and royalty laws; the timing and terms of government approvals and the timing and terms of any renewal or extension of any of the Corporation’s license areas; the cost

of expenditures to be made by Oryx Petroleum; future crude oil prices and prices realised by Oryx Petroleum on oil production sold; the amount of oil production sold domestically in the Kurdistan Region and the amount of oil production sold as export; oil from the Kurdistan

Region refining capacity in the local jurisdiction and access to local and international markets for crude oil production; the Corporation’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the political situation and stability in

jurisdictions in which Oryx Petroleum has licenses, will not adversely disrupt the Corporation’s production and development activities in the Kurdistan Region; the regulatory, legal and political framework governing the production sharing contracts, risk exploration contracts,

royalties, taxes and environmental matters in the jurisdictions in which the Corporation conducts and will conduct its business and the interpretations of applicable laws; the ability to renew its licenses on attractive terms; the Corporation’s current and future production levels

and the timing and payment mechanism for export oil from the Kurdistan Region; the market for domestic oil sales in the Kurdistan Region and the timing and payment mechanism for such domestic sales in the Kurdistan Region; the applicability of technologies for the

recovery and production of the Corporation’s oil reserves and resources; ability to gain access to existing facilities or to build necessary facilities to sell oil production; operating costs; availability of equipment and qualified contractors and personnel; future capital

expenditures to be made by the Corporation; future sources of funding for the Corporation’s capital programs; the Corporation’s future debt levels; geological and engineering estimates in respect of the Corporation’s reserves and resources; the geography of the areas in

which the Corporation is conducting exploration and development activities; the impact of increasing competition on the Corporation; the ability of the Corporation to obtain financing and, if obtained, to obtain acceptable terms; and government/state participation in the

Corporation’s development activities through the exercise of back-in rights.

Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indicators of whether or not such events, performance or results will be achieved. Forward-

looking statements are based on information available at the time and/or management’s expectations with respect to future events that involve a number of risks and uncertainties. Any forward-looking statements concerning prospective results of operations, financial

position, production, expectations of cash flows and future cash flows that are based upon assumptions about future results, economic conditions and courses of action and are presented for the purpose of providing prospective purchasers with a more complete perspective

on Oryx Petroleum’s present and planned future operations and such information may not be appropriate for other purposes and actual results may differ materially from those anticipated in such forward-looking statements.

Actual results could differ materially from those anticipated in or implied by any forward-looking statements, including without limitation, as a result of the risk factors, which are described in detail under “Risk Factors” in the AIF. Readers should reference the factors

discussed under the heading “Risk Factors” in the AIF. The forward-looking statements included in this presentation are expressly qualified by this cautionary statement and readers are cautioned that any forward-looking statement speaks only as of the date of this

presentation. The Corporation does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable securities laws. If the Corporation does update

one or more forward-looking statements, it is not obligated to, and no inference should be drawn that it will, make additional updates with respect thereto or with respect to other forward-looking statements.

22

DISCLAIMER

RESERVES AND RESOURCES ADVISORY

The reserves and resources and associated future net revenue information presented herein are estimates only. In general, estimates of oil reserves and resources and the future net revenue therefrom are based upon forward-looking statements and a number of variable

factors and assumptions, such as production rates, ultimate reserve recovery, timing and amount of capital expenditures, ability to transport production, marketability of oil, royalty rates, the assumed effects of regulation by governmental and other regulatory agencies and

future operating costs, all of which may vary materially from actual results, and for resources, additional variable factors and assumptions such as discovery and commerciality. For those reasons, estimates of the oil reserves and resources attributable to any particular group

of properties, as well as the classification of such reserves and resources (based on risk of recovery) and estimates of future net revenues associated with such reserves and resources prepared by different engineers (or by the same engineers at different times) may vary.

The actual reserves and resources of Oryx Petroleum may be greater or less than those estimated and such variation may be material.

In addition, Oryx Petroleum’s actual production, revenues, development, capital and operating expenditures, as applicable, with respect to its reserves and resources will vary from estimates thereof and such variations could be material. Any activities undertaken by Oryx

Petroleum to develop or permit the reclassification of its reserves and resources will be subject to the terms of the applicable contractual arrangement.

Statements relating to “net present value”, “future net revenues”, “reserves” and “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions (including, without limitation, pricing

assumptions), that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. Readers should refer to the AIF for information regarding the assumptions related to the reserves and resources reported

herein. There is no assurance that forecast price and cost assumptions will be attained and variances could be material.

Proved oil reserves are those reserves which are most certain to be recovered. There is at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved oil reserves. Probable oil reserves are those additional reserves that are less

certain to be recovered than proved oil reserves. There is at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable oil reserves. Possible oil reserves are those additional reserves that are less certain

to be recovered than probable oil reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible oil reserves.

Contingent oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially

recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. Contingent oil resources are further subdivided in accordance with the level of certainty

associated with recoverable estimates assuming their discovery and development and may be sub classified based on project maturity. Contingent oil resources entail additional commercial risk than reserves. There is no certainty that it will be commercially viable to

produce any portion of the contingent oil resources. Moreover, the volumes of contingent oil resources reported herein are sensitive to economic assumptions, including capital and operating costs and commodity pricing.

Prospective oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective oil resources have both an associated chance of discovery

and a chance of development. Prospective oil resources entail more commercial and exploration risks than those relating to oil reserves and contingent oil resources. The risked prospective oil resources reported in this presentation are risked resources that have been

risked for chance of discovery, for chance of development. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing or cost of such development.

The reserves estimates and evaluation and resource estimates and evaluation contained herein are derived from the NSAI Report which was prepared with reference to NI 51-101 relying on the COGE Handbook definitions. Reserves and resources provided herein are as at

December 31, 2019 and are only valid as of such date.

The estimates of reserves and resources and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and resources and future net revenue for all properties, due to the effects of aggregation. The estimated future net

revenues contained herein are valid only as at December 31, 2019 and do not necessarily represent the fair market value of Oryx Petroleum’s reserves and resources.

As used herein, unless otherwise indicated, “gross” means, in respect of reserves, resources, production, area, capital expenditures or operating expenses, the total reserves, resources, production, area, capital expenditures or operating expenses, as applicable, attributable

to either (i) 100% of the license area, field, prospect or lead; or, (ii) the Corporation’s working interest in the license area, field, prospect or lead, as indicated, prior to the deductions specified in the applicable production sharing contract, risk exploration contract or fiscal

regime for each license area.

In addition to the general advisory language above, the below notes qualify certain reserves and resources volumes and other oil and gas information disclosed in this document:

“†”: This volume is an arithmetic sum of multiple estimates of reserves or resources, as applicable, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of

reserves or resources, as applicable, and appreciate the differing probabilities of recovery associated with each class as explained above.

“‡”: All field fluid measurements will require laboratory analysis to confirm results and should be considered preliminary until such analysis has been done. The test results are not necessarily indicative of long-term performance or of ultimate recovery.

23

DISCLAIMER

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