Parex _Corporate_Presentation _March_72017

1Corporate Presentation | March 2017Corporate Presentation | March 2017 1

Solid Foundation.Building New Platforms.

www.parexresources.com | TSX:PXT | Corporate Presentation | March 2017


Operating results 2016 2017EProduction (boe/d) FY Average 29,715 34,000-36,000Capital Expenditures(1) (million) US $112 US $200-$225Exploration Drilling (# prospects) 7 14Appraisal Drilling (# wells) 4 15-20Development Drilling (# wells) 6 12Total (# wells) 17 41-46

Reserves (2016 year end)2P Reserves (Dec. 31)(2) 112 Mmboe2P Reserve Life Index (RLI) 10 years

Capital structure Net Working Capital(3) US $93 MMUS $175MM Credit Facility Undrawn – No DebtMarket Capitalization(3)(4) ~ CAD $2.5 BillionCommon Shares Outstanding (TSX listed)

• Basic(3) • Fully Diluted(5)

153 MM164 MM

CORPORATE SNAPSHOT

(1) Assuming $50/bbl Brent oil price in 2017 (2) Parex’ working interest, as per the independent reserve reports prepared by

GLJ Petroleum Consultants Ltd. effective December 31, 2016(3) As at December 31, 2016(4) Assuming CAD $16 share price (5) Diluted shares include the effects of common shares and in-the-money stock

options outstanding at December 31, 2016; closing stock price at the end of the period was CAD $16.90.


2017 GUIDANCE: CASH FLOW FUNDED GROWTH

AssumptionsOil (Brent) US $50/bblFFO netback(1) US $17/boeProduction 34,000-36,000 bopdCapital Expenditure US $200-225MMFunds Flow From Operations US $211-223MMYOY Production growth/share 16-21%Annualized CF/Basic Share US $1.42 (C$1.92)

Exploration Capex 14 wells 2,000-3,000 boe/d$85-90MM

Maintenance Capex 12 wells 30,000 boe/d$45-55MM

Appraisal Capex 15-20 wells 2,000-3,000 boe/d$70-80MM

CAPEX ALLOCATIO

N

(1) FFO netback is defined as Funds Flow From Operations divided by production for the period


Basin & Block H1/2017 H2/2017 Total WellsExploration Dev/Appraisal Exploration Dev/Appraisal

LLANOS LLA-34 5 4 2 8 19Capachos - 1 - 2 3Other Llanos 3 2 - - 5

MAGDALENA Aguas Blancas - 9 - 1-6 10-15VMM-11 2 - 1 - 3Other Magdalena - - 1 - 1

TOTAL 10 16 4 11-16 41-46

2017 DRILLING PROGRAM


2016FY Q4 2016 2017 Guidance$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

$50

$55

$13.20 $18.74 $14 $17 $20

REAL

IZED

PRI

CE (U

SD/B

OE)

Brent $51.13

Brent $45.12

2017 TARGET CASH NETBACKS

Brent $45Brent $50

Brent $55

Differential ($6.29)

Royalties ($3.75)

Opex ($5.56)

Transportation ($11.13)

G&A/Finance ($4.23)Tax ($1.43)

Cash Netback

(excluding hedges)

* Cash netback is defined as funds flow from operations per bopd

($7.49)

($3.14)

($4.88)

($11.58)

($4.32)($0.51)

Cash Netback

PAREX CASH NETBACK*


Q1 2017 GUIDANCE 32,000 BOE/D

CONSISTENT GROWTH: PATH TO 50,000 BARRELS

2012 2013 2014 2015 2016 2017E -

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

11,407

15,854

22,526

27,43429,715

34,000-36,000

AVER

AGE

DAIL

Y PR

ODU

CTIO

N (B

OE/

D)


Proved + Probable + Possible

(mmboe)

Proved + Probable (mmboe)

Proved(mmboe)

Annual Production (mmboe)

2P Reserve Life Index based on annualized

Q4 Production

31-Dec-11 18 11 5 2 3 years

31-Dec-12 23 16 10 4 4 years

31-Dec-13 50 32 17 6 5 years

31-Dec-14 104 68 40 8 7 years

31-Dec-15 125 82 46 10 8 years

31-Dec-16 169 112 64 11 10 years

Gross 2P Development Locations (#)

FDC (USD MM)

FDC Per Boe (USD/boe)

31-Dec-15 102 318 $3.90

31-Dec-16 157 347 $3.10 99% OIL

*Per the independent reserve reports prepared by GLJ Petroleum Consultants Ltd. effective December 31 of the reported year

TRACK RECORD OF PROGRESSING RESERVES* FROM 3P TO CASH FLOW

SOLID FOUNDATION SUPPORTS GROWTH


CONVENTIONAL OIL RESERVES: INDUSTRY LEADING RESULTS

Total Company* 2016 3 Year

PDP 1P 2P 2PFD&A $/boe $6.47 $6.99 $3.40 $7.69Recycle Ratio (FD&A) 2.9x 2.7x 5.5x 2.5x

* Per the independent reserve reports prepared by GLJ Petroleum Consultants Ltd. effective Dec. 31, 2014; Dec. 31, 2015 and Dec. 31, 2016, including Future Development Cost. Recycle Ratio is calculated using Q4 2016 Funds Flow From Operations per barrel divided by annual F&D or FD&A as applicable, except for 3 Year which uses 3 year average Funds Flow From Operations.

2014 2015 2016$0

$3

$6

$9

$12

$15

$18

1 Year $/boe 3 Year $/boe2P

FD&

A (U

SD/B

OE)


CABRESTERO (100% WI, operator)• Akira: swing producer• Bacano-2 producing ~575 bopd

• Added 2 appraisal wells in H1/17

SOUTHERN LLANOS: FOUNDATION FOR GROWTH

LLA-34 (55% WI, Non-operated)

• Chiricoca-1 producing ~940 bopd • Drill 7 exploration wells and 12 development wells in 2017• Objective in 2017 to test extent of Jacana-Tigana trend to

South West

Explore core position, appraise & develop discoveries, and leverage Parex’ costs and exploration strengths

As per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective Dec. 31/16

Faults GLJ 3P (YE 2016) New pads

LLA-34

Cabrestero

LLA-32

Chachalaca

Tilo

Tigana

Jacana

Akira

Tua

Tarotaro

Aruco

Max

Kananaskis

Calona

Chiricoca

Bacano

Carmentea


BLOCK LLA-34: TEST EXTENT & FIELD DEVELOPMENTField

(Parex’ WI)GLJ 3P Reserves

(MMBO)GLJ 2P Reserves

(MMBO)

YEAR END 2015 2016 2015 2016

Tigana Guadalupe 41 51 28 34

Jacana Guadalupe 14 45 5 30

Other LLA 34 41 33 27 23

LLA 34 TOTAL 96 129 60 87

Cabrestero 8 18 6 11

2017 Exploration

2017 Appraisal

2017 Drilled

2017 Dry Season Pads

Guadalupe Stratigraphic Edge

2015 GLJ 3P Outlines

2016 GLJ 3P OutlinesAs per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective Dec. 31, 2016

Chiricoca

Sinsonte

Jacamar

Curucucu

Tigana

Tua

Akira

Tarotaro

Aruco

Bacano

Jacana

Cabrestero

LLA-34JACANA-11

JACANA SUR-1

JACANA SUR-2

JACANA-12

BACANO 3


Tigana Norte-1

Tigana Sur-1

Tigana Sur Oeste-1

Tigana Sur-2

Tigana-3

Tigana-4

Tilo-1

Tilo-2

Jacana-1

Jacana-2

Jacana-3

Jacana-4

Jacana-5

Jacana-60

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

1 3 5 7 9 11 13 15 17 19 21 23PRODUCING MONTHS

TIGANA GUAD TREND – PRODUCTION HISTORYPR

ODU

CIN

G DA

Y BO

PD

TREND AVERAGE

• IP Range: 500-3,500 bopd• Flat production profile • Low decline


SUR

CENTRO

NORTE

NORESTE

NORTE-1 EXPLORATION

CAPACHOS-2

CAPACHOS SUR-2

NORTESTE-1 EXPLORATION

GUADALUPE DEPTH STRUCTURE

2017 PLAN

• Drill 2 firm development wells (Capachos–2 and Capachos Sur–2) to earn 50% in the block.

• Disposal well.

• Development wells are targeting proven structural compartments that have produced ~2 mmbbls.

• Targeting ~34 API Oil in the Guadalupe Formation.

Future exploration targets at Capachos Norte and Capachos Noreste targeting the Guadalupe and Une formations.

CAPACHOS DEVELOPMENT AND EXPLORATION POTENTIAL

Future Exploration

2017 Development

Legacy Wells


MAGDALENA BASIN: NEXT GROWTH PLATFORM

(1) Farm-in on Ecopetrol

VIM-1

PLAYON

DE MARES

VMM-9

VMM-11

MORPHO

AGUAS BLANCAS

SOGAMOSO

2017 ACTIVITIES

Pipeline

Oil fields

Gas fields

AGUAS BLANCAS(1)

• Light oil opportunity• Drill 10-15 appraisal wells

PLAYON(1) • Boranda-1: drilled & cased;

ongoing testing

VIM-1• Interpreting 525 km2 of 3D

seismic • 1 exploration well

VMM-9• Environmental Impact

Assessment underway• Acquire 290 km2 of 3D Seismic

in 2017

VMM-11 • 3 exploration wells

De MARES(1) • Re-enter and test Coyote-1


2017 PROGRAM1. Identify oil in place; 35 API.

2. Develop production strategy.

3. Understanding waterflood potential.

DEFINITION OF SUCCESS1. Achieve Unstimulated IP Rates = 50-200 bopd

• Target stimulated rates 1.5x to 2x

2. Primary Recovery per well = 100 – 250 mbbls

3. Increase Recovery Factor from current primary of 10% to waterflood recovery > 25%

4. Demonstrate Development Phase Capital • Per well cost: $1.2 million • Fully loaded capex per producing well: $2.0 million

AGUAS BLANCAS OBJECTIVES

MUGROSA C RESERVOIR

570’

700’

AB-5

AB-9

Drilled 1964 Drilled 2016


*2P PRIMARY RECOVERY AT 10%

AGUAS BLANCAS: IDENTIFYING RESERVE* POTENTIAL

Footwall “B” Area

2P Area (ac)

2P OOIP (MMBO)

2P Reserves (MMBO)

YE 2015 789 33.5 2.8

YE 2016 832 34.7 3.0

TOTAL FIELD (Parex W.I.)

* Per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective December 31, 2016

Footwall “C” Area

2P Area (ac)

2P OOIP (MMBO)

2P Reserves (MMBO)

YE 2015 0 0 0

YE 2016 847 32.7 3.1

Hanging Wall Area

2P Area (ac)

2P OOIP (MMBO)

2P Reserves (MMBO)

YE 2015 266 6.5 0.5

YE 2016 709 14.7 1.4

Potential Area (ac)

2P Area (ac)

2P OOIP (MMBO)

2P Reserves (MMBO)

YE 2015 5800 - 8400 1055 40 3.3

YE 2016 5800 - 8400 2388 82 7.5

Prospective Resource Area

AB-26

AB-9

AB-34AB-32

AB-14

AB-2

AB-5

AB-3AB-15

GLJ 2015 2P

GLJ 2016 2P

Legacy Wells

H2/2017 Location

H1/2017 Location

Drilled

Max Potential Area

Min Potential Area


PAREX’ TRANSPORTATION ALTERNATIVES: 1. Export Cargo – 60% Volume

• Truck/Pipeline – Tender process

2. Magdalena River - 35% Volume• Truck/Barge • Wellhead sale to Trafigura

3. Casanare Refinery - 5% volume

Multiple Evacuation Routes Surplus Take-away Capacity

TRANSPORTATION

Trucking

Parex Blocks

Pipeline

River

BARRANQUILLA

CARTAGENA

BARRANCABERMEJA

VASCONIA

MONTERREY

TERMINAL COVENAS

HIDROCASANARE

CUSIANA


SUMMARY: EXCEL AT WHAT WE DOCORE COMPETENCIES1. Identify and acquire large prospective resources.

2. Engage stakeholders.

3. Focus on being a low cost operator.


APPENDIX – BLOCK SUMMARY# Block Operated/Non-Operated Working Interest Partners Gross Acres(1) Basin

1 LLA-10 Operated 50% Gran Tierra 189,544 Llanos2 LLA-16 Operated 100% N/A 11,736 Llanos3 LLA-20 Operated 100% N/A 2,891 Llanos4 LLA-24 Operated 100% N/A 147,100 Llanos5 LLA-26 Operated 100% N/A 184,061 Llanos6 LLA-29 Operated 100% N/A 69,915 Llanos7 LLA-30 Operated 100% N/A 117,322 Llanos

8 LLA-32 Operated 70% Geopark & Pluspetrol 57,040 Llanos

9 LLA-34 Non-Operated 55% Geopark 68,382 Llanos10 LLA-40 Operated 50% Pluspetrol 83,465 Llanos11 LLA-57 Operated 100% N/A 52,285 Llanos12 Cabrestero Operated 100% N/A 29,562 Llanos13 Capachos(2) Operated 50% Ecopetrol 64,073 Llanos 14 Cebucan Operated 100% N/A 109,185 Llanos15 Cerrero Operated 100% N/A 83,903 Llanos 16 El Eden Operated 100% N/A 6,397 Llanos17 Los Ocarros Operated 100% N/A 31,066 Llanos18 VIM-1 Operated 100% N/A 223,651 Lower Magdalena19 Aguas Blancas(2) Operated 50% Ecopetrol 13,386 Middle Magdalena20 De Mares(2) Operated 50% Ecopetrol 174,387 Middle Magdalena21 Morpho(3) Operated 100% N/A 51,420 Middle Magdalena22 Playon(2) Operated 50% Ecopetrol 43,200 Middle Magdalena23 Sogamoso Operated 100% N/A 3,695 Middle Magdalena 24 VMM-9 Operated 100% N/A 152,412 Middle Magdalena25 VMM-11 Operated 100% N/A 116,826 Middle Magdalena

1) Exploration properties deemed non-commercial will be relinquished in due course. Accordingly, the gross acres described above may decrease as non-commercial lands are relinquished.2) Working interests are subject to regulatory approval.3) Morpho is subject to a 4% Net Profit Interest.


APPENDIX – SUMMARY OF QUARTERLY RESULTS

Notes: • Values have been round up or down to the nearest dollar figure. • Net Debt is defined as Bank Debt + Convertible Denture Face Value ( C$ 85 million) - Working Capital. Current Borrowing limit of US $175 million ($200 million at March 31, 2016 and December 31, 2015; $175 million at December 31,

2014). convertible debentures with a face value of Cdn$85 million with a conversion price of Cdn$10.15 per share were fully redeemed on September 25, 2014.

(Unaudited Results) 2016 2015 2014

FY Q4 Q3 Q2 Q1 FY Q4 Q3 Q2 Q1 FY Q4 Q3 Q2 Q1

OPERATING

Production (thousands of boe/d) 29.7 31.1 29.8 29.1 28.9 27.4 28.6 27.4 27.0 26.7 22.5 26.5 25.2 19.9 18.4

Brent Price ($/bbl) 45 51 47 47 35 54 45 51 64 55 100 77 104 110 108Average realized prices, prior to hedging ($/boe) 38 45 40 40 27 47 37 45 56 49 88 60 94 105 103

Royalty ($/boe) 3 4 3 3 2 4 3 4 5 4 11 7 11 15 15Opex ($/boe) 5 6 5 5 5 7 7 7 8 8 11 11 12 11 10Transportation ($/boe) 12 11 12 12 12 14 13 13 14 16 17 17 18 16 18

Operating Netback ($/boe) 18 24 21 20 8 22 15 21 30 22 48 25 53 62 61Funds Flow Netback ($/boe) 13 19 16 13 5 13 12 5 20 14 37 21 39 46 45

FINANCIAL (millions of USD, except per share amounts)

Funds flow from operations 144 52 45 32 16 130 34 14 50 33 294 50 89 77 77Net income (loss) (46) (45) 6.8 (0.2) (8) (45) (4) (27) 2 (16) (109) (147) 17 11 10EBITDA 134 56 43 30 6 170 36 41 52 41 340 45 114 84 97Cash and cash equivalents 149 149 132 94 92 95 95 75 104 33 39 39 34 63 40Working Capital 93 93 118 98 80 77 77 63 90 10 3 3 45 31 37Net Debt (Surplus) (93) (93) (118) (98) (80) (77) (77) (63) (90) 30 32 32 (3) 110 52Capital Expenditures 112 67 26 14 5 126 24 38 37 27 297 84 57 95 62

Weighed average shares outstanding 152 153 153 152 152 145 151 150 144 135 120 135 126 111 109

TRADING STATISTICS (CAD) – PXT(based on intra-day trading)

High 18.22 18.22 17.40 14.61 11.96 11.55 11.55 10.57 11.10 9.24 15.49 12.88 15.49 13.25 9.50Low 7.74 14.86 12.00 10.50 7.74 5.97 9.07 7.15 8.05 5.97 6.07 6.07 11.98 9.33 6.57Close (end of period) 16.90 16.90 16.65 12.51 10.95 10.16 10.16 9.25 10.47 8.07 7.58 7.58 12.45 12.55 9.50Average daily volume (thousands) 693 679 547 678 970 821 729 742 906 907 872 1,140 982 808 553


COLOMBIA – CURRENT LAND BASE

Source: Divestco, February 2017


LEGAL ADVISORY HOW TO REACH USCertain statements in this document are “forward-looking statements”. Forward-looking statements are frequently characterized by words such as “prospective”, “plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “forecast”, or other similar words, or statements that certain events or conditions “may” or “will” occur. Forward-looking statements are not based on historical facts but rather on the expectations of management of the Company ("Management") regarding the Company's future growth, results of operations, production, plans for and results of drilling activity, business prospects and opportunities. Such forward-looking statements reflect Management's current beliefs and assumptions and are based on information currently available to Management. In particular, this document contains forward-looking statements regarding, but not limited to, the Company's expected production rates and Parex' drilling plans. Forward-looking statements involve significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements including the risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities, competition, the ability to generate revenue and exploit operating margins, capital resources, the use of certain technologies and materials, annual impairment tests, labour relations, insurance, damage from weather and other disasters, operating and maintenance risks and environmental risks, new information regarding reserves, changes in demand for and volatility of commodity prices of oil and natural gas, failure to receive all required regulatory approvals for acquisition, the risk that the acquisition may not be completed as contemplated or at all, legislative, regulatory and political changes, the risks discussed under "Risk Factors" in Parex' annual information form (“AIF”) and other factors, many of which are beyond the control of the Company. The risks outlined should not be construed as exhaustive. Although the forward-looking statements contained in this document are based upon assumptions which Management believes to be reasonable, the Company cannot assure investors that actual results will be consistent with these forward-looking statements. These forward-looking statements are made as of the date hereof, and the Company assumes no obligation to update or revise them to reflect new events or circumstances, except as required by law.

Statements relating to “reserves” are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. With respect to forward-looking statements contained in this presentation, the Company has made assumptions regarding: future exchange rates; the price of oil and natural gas; the impact of increasing competition; conditions in general economic and financial markets; availability of equipment; availability of skilled labour; current technology; cash flow; commodity prices; production rates; timing and amount of capital expenditures; royalty rates; effects of regulation by governmental agencies; future operating costs; receipt of all required regulatory approvals for the acquisition; successful completion of the acquisition; and the Company's ability to obtain financing on acceptable terms. Management has included the above summary of assumptions and risks related to forward-looking information provided in this presentation in order to provide shareholders with a more complete perspective on the Company's future operations and such information may not be appropriate for other purposes.

This is not an offer to sell or a solicitation of an offer to purchase securities by Parex. Before making an investment, investors should refer to the Offering Documents for more complete information, including investment risks, fees and expenses and should also thoroughly and carefully review Parex' public disclosure documents available on SEDAR at www.sedar.com with their financial, legal and tax advisors to determine whether an investment is suitable for them.

PAREX RESOURCES INC.2700 Eighth Avenue Place, West Tower585 8th Av SW Calgary AB T2P 1G1 Canada

Tel: 403-265-4800Fax: 403-265-8216Email: [email protected] Website: www.parexresources.com

MIKE KRUCHTENVice President, Corporate Planning & Investor Relations


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