Building New Platforms. www.parexresources.com | TSX:PXT | - - PowerPoint PPT Presentation

1 Corporate Presentation | March 2017

Corporate Presentation | June 2017 1

Solid Foundation. Building New Platforms.

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

2 Corporate Presentation | March 2017

Corporate Presentation | June 2017 2

Operating results 2016 2017E Production (boe/d) FY Average 29,715 34,000-36,000 Capital Expenditures(1) (million) US $112 US $200-$225 Exploration Drilling (# prospects) 7 14 Appraisal Drilling (# wells) 4 15-20 Development Drilling (# wells) 6 12 Total (# wells) 17 41-46 Reserves (2016 year end) 2P Reserves (Dec. 31)(2) 112 Mmboe 2P Reserve Life Index (RLI) 10 years Capital structure Net Working Capital(3) US $131 MM US $100 MM Credit Facility(4) Undrawn – No Debt Market Capitalization(3)(5) ~ CAD $2.5 Billion Common Shares Basic Outstanding (TSX listed) (3) 153MM

CORPORATE SNAPSHOT

(1) Assuming US $50/bbl Brent oil price in 2017 (2) Parex’ working interest, as per the independent reserve report prepared by GLJ Petroleum Consultants effective Dec. 31, 2016 (3) As at March 31, 2017 (4) As at May 30, 2017 (5) Assuming CAD $16 share price See “Advisories” at the end of this presentation

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REASONS TO OWN PAREX

• 1. No debt and positive WC of US$131MM
• 2. High margins: Q1’17 Cash Flow ~US$22.47/bbl @ Brent $55
• 3. Ability to grow within cash flow:
• 2016 Growth: production 8.4% y-y & RLI increases to 10 years from 8 years
• 2017 Growth guidance of 15%-21% self-funded
• 4. Exploration Upside:
• Drilled YTD 5 exploration wells with 4 oil discoveries
• Scheduled to drill additional 10 exploration prospects in 2017
• Llanos
• Middle Magdalena & Lower Magdalena

5. Focused management: ability to growth within single country  Colombia

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2017 GUIDANCE: CASH FLOW FUNDED GROWTH

Assumptions Oil (Brent) US $50/bbl FFO netback(1)(2) US $17/boe Production 34,000-36,000 bopd Capital Expenditure US $200-225MM Funds Flow From Operations US $211-223MM YOY 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 ALLOCATION

(1) FFO netback is defined as Funds Flow From Operations per bopd. (2) Netback is a non-GAAP Measure.

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$18.74 $22.47 $14 $17 $21 $0 $10 $20 $30 $40 $50 $60 Q4 2016 Q1 2017 2017 Guidance REALIZED PRICE (USD/BOE)

Brent $51.13

2017 TARGET CASH NETBACKS** Brent $45 Brent $50 Brent $55

Royalties Differential Transportation Opex G&A/Fin. & Other Costs Tax

Cash Netback

Brent ~$30/bbl generates sufficient cash flow to maintain production

*Cash netbacks are non-GAAP measure defined as Funds Flow From Operations per bopd. ** 2017 Target Cash Netbacks are based on production guidance mid-point excluding hedges.

PAREX CASH NETBACK*

($3.75) ($6.29) ($11.13) ($5.56) ($4.23) ($1.43) Brent $54.61 ($4.38) ($5.89) ($11.11) ($5.09) ($3.77) ($1.90)

Cash Netback

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$2 $4 $6 $8 $10 $12 $14 $16 $18 $20 Q1'14 Q2'14 Q3'14 Q4'14 Q1'15 Q2'15 Q3'15 Q4'15 Q1'16 Q2'16 Q3'16 Q4'16 Q1'17 $/boe Transportation Brent Differential

MARKETING COSTS TRENDING DOWNWARD

Brent $45/bbl Brent $56/bbl Brent $100/bbl Brent $55/bbl

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PAREX’ TRANSPORTATION ALTERNATIVES:

1.Export Cargo – 60% Volume

• Truck/Pipeline – Tender process

2.Magdalena River - 35% Volume

• Truck/Barge
• Wellhead sales

3.Casanare Refinery - 5% volume

Multiple Evacuation Routes Surplus Take-away Capacity TRANSPORTATION

BARRANQUILLA CARTAGENA BARRANCABERMEJA VASCONIA MONTERREY TERMINAL COVENAS HIDROCASANARE CUSIANA

Trucking Parex Blocks Pipeline River

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In a $50/bbl environment, our portfolio supports reaching 50,000* bopd during 2019

CONSISTENT & SUSTAINABLE GROWTH: PATH TO 50,000 BOPD

11,407 15,854 22,526 27,434 29,715 34,000-36,000 38,500-43,500

• 5,000

10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 2012 2013 2014 2015 2016 2017E 2018E AVERAGE DAILY PRODUCTION (BOE/D)

RLI 3 yr RLI 5 yr RLI 7 yr RLI 8 yr RLI 10 yr

Q2E

* Refer to February 6, 2017 Press Release “ Parex announces executive and board of directors appointments”

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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

*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

169 mmboe  ~46,500 boe/d & 10 yr RLI

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CONVENTIONAL OIL RESERVES: INDUSTRY LEADING RESULTS

Total Company(1) 2016 PDP 1P 2P FD&A $/boe $6.47 $6.99 $3.40 Recycle Ratio (FD&A) 2.9x 2.7x 5.5x

(1) 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. (2) Finding, development and acquisition costs per barrel of oil equivalent are calculated by dividing capital expenditures, acquisition costs and disposition proceeds by reserve additions for the reported period. (3) Source: Peters & Co. March 30, 2017. Reserves Comparison – E&P Producers Peer Companies: RRX, BNE, WCP, CPG, SGY, CJ, TOG, SPE, GXE, GTE, BTE (4) All values are in US$ based on 3 year average CAD/USD rates.

$0 $3 $6 $9 $12 $15 $18 2014 2015 2016 2P FD&A (USD/BOE)

1 Year $/boe 3 Year $/boe

Company(3) 2P Reserves per share Growth YoY

• Incl. FDC

3 Yr 2P FD&A

• Incl. FDC

3 Yr PDP FD&A 3 Yr 2P Recycle Ratio Total FDC/2017E Cash Flow Parex(4) 35% $7.90 $13.48 1.9 1.5 Median Cdn Oil E&P 3% $14.02 $23.76 1.2 3.8

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CABRESTERO (100% WI, operator)

• Akira: swing producer
• Successful Bacano appraisal in 2017 (4 wells to date)

SOUTHERN LLANOS: FOUNDATION FOR GROWTH

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

• Current production ~45,000 bopd gross (25,000 bopd net)
• Drill 7 exploration wells and 12 dev. wells in 2017
• Objective in 2017 to test extent of Jacana-Tigana trend to SW

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

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Cabrestero & LLA-34: 2017 FOCUS - TEST EXTENT

Field

(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

As per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective

• Dec. 31, 2016

Cabrestero

Akira

2015 GLJ 3P Outline 2016 GLJ 3P Outline 2017 Prospective Area YTD

Bacano Jacana

2017 Exploration 2017 Appraisal Potential Stratigraphic Edge

1 2 4 3 5 6 7

Bacano-2

8

Bacano-3

JS1

Jacamar

Bacano-4

Jacana-11 Jacana Sur-2 LLA-34

Bacano-5

2017YTD: Expanding prospective area with results from Jacana-11, Jacana-8 & Bacano-3

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Corporate Presentation | June 2017 13 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-6

500 1000 1500 2000 2500 3000 3500 4000 4500 5000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

LLA-34 GUAD TREND – PRODUCTION HISTORY

PRODUCING DAY BOPD TREND AVERAGE

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

GLJ Tigana 2P Representative Well

Source: GLJ 2016 Report; internal company reports as at April 19, 2017

GLJ Jacana 2P Representative Well

PRODUCING MONTHS

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SUR CENTRO NORTE NORESTE

NORTE-1 EXPLORATION CAPACHOS-2 CAPACHOS SUR-2 NORESTE-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

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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)

• Drill follow-up to Boranda-1

VIM-1

• Interpreting 525 km2 of 3D

seismic

• 1 exploration well

VMM-9

• Environmental Impact

Assessment underway

• Acquire 290 km2 of 3D Seismic

VMM-11

• 3 exploration wells

De MARES(1)

• Re-enter and test Coyote-1

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2017 PROGRAM

• 1. Identify oil in place; 35 API.
• 2. Develop production strategy.
• 3. Understanding waterflood potential.

DEFINITION OF SUCCESS

• 1. 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
• f 10% to waterflood recovery > 25%
• 4. Demonstrate Development Phase Capital
• Per well cost: $1.2 million
• Fully loaded capex per producing well: $2 million

AGUAS BLANCAS OBJECTIVES

MUGROSA C RESERVOIR

570’ 700’

AB-5 AB-9 Drilled 1964 Drilled 2016

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SUMMARY OF THE AGUAS BLANCAS OPPORTUNITY

• 1. Increase Field Size (area):
• Total delineated YE 2016 2P Area 2,388

acres (~30% of total area)

• 2. Demonstrate development

capital efficiencies & stimulation rates

• 3. Increase Field Recovery Factor:
• Primary: 10%
• Waterflood: potentially 20-30%

Source: GLJ 2016 Report. See “Advisories” at the end of this presentation.

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

TOTAL FIELD (Parex W.I.)

YE 2016 2P Area

AB 12 225 ac AB 25 1095 ac AB 24 521 ac AB 10 222 ac AB 11 578 ac AB 15 453 ac AB 14 159 ac AB 14 360 ac AB 13 353 ac AB 17 410 ac AB 18 110 ac AB 16 327 ac AB 23 267 ac AB 24 268 ac AB 25 147 ac

YE 2016 2P Area

AB-2 AB-5 AB-3

Injection Well Producing WF Pilot Well Delineation wells Next Phase Delineation Core Location

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SUMMARY: EXCEL AT WHAT WE DO

CORE COMPETENCIES

• 1. Identify and acquire large prospective

resources.

• 2. Engage stakeholders.
• 3. Focus on being a low cost operator.

Bacano Field

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APPENDIX – BLOCK SUMMARY

# Block Operated/Non-Operated Working Interest Partners Gross Acres(1) Basin

1 LLA-10 Operated 50% Gran Tierra 189,544 Llanos 2 LLA-16 Operated 100% N/A 11,736 Llanos 3 LLA-20 Operated 100% N/A 2,891 Llanos 4 LLA-26 Operated 100% N/A 184,061 Llanos 5 LLA-29 Operated 100% N/A 69,915 Llanos 6 LLA-30 Operated 100% N/A 117,322 Llanos 7 LLA-32 Operated 70% Geopark & Pluspetrol 57,040 Llanos 8 LLA-34 Non-operated 55% Geopark 68,382 Llanos 9 LLA-40 Operated 50% Pluspetrol 83,465 Llanos 10 Balay Non-operated 10% Perenco 4,500 Llanos 11 Cabrestero Operated 100% N/A 29,562 Llanos 12 Capachos(2) Operated 50% Ecopetrol 64,073 Llanos 13 El Eden Operated 100% N/A 6,397 Llanos 14 Los Ocarros Operated 100% N/A 31,066 Llanos 15 VIM-1 Operated 100% N/A 223,651 Lower Magdalena 16 Aguas Blancas(2) Operated 50% Ecopetrol 13,386 Middle Magdalena 17 De Mares(2) Operated 50% Ecopetrol 174,387 Middle Magdalena 18 Morpho(3) Operated 100% N/A 51,420 Middle Magdalena 19 Playon(2) Operated 50% Ecopetrol 43,200 Middle Magdalena 20 Sogamoso Operated 100% N/A 3,695 Middle Magdalena 21 VMM-9 Operated 100% N/A 152,412 Middle Magdalena 22 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.

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APPENDIX – SUMMARY OF QUARTERLY RESULTS

• Values have been round up or down to the nearest dollar figure.
• Net Debt is defined as Bank Debt - Working Capital. Current Borrowing limit of US $100 million ($175million at March 31, 2017, $200 million at March 31, 2016 and December 31, 2015)

(Unaudited Results)

2017 2016 2015 Q1 FY Q4 Q3 Q2 Q1 FY Q4 Q3 Q2 Q1

OPERATING

Production (thousands of boe/d) 32.6 29.7 31.1 29.8 29.1 28.9 27.4 28.6 27.4 27.0 26.7 Brent Price ($/bbl) 55 45 51 47 47 35 54 45 51 64 55 Average realized prices, prior to hedging ($/boe) 49 38 45 40 40 27 47 37 45 56 49 Royalty ($/boe) 4 3 4 3 3 2 4 3 4 5 4 Opex ($/boe) 5 5 6 5 5 5 7 7 7 8 8 Transportation ($/boe) 11 12 11 12 12 12 14 13 13 14 16 Operating Netback ($/boe) 28 18 24 21 20 8 22 15 21 30 22 Funds Flow Netback ($/boe) 23 13 19 16 13 5 13 12 5 20 14

FINANCIAL

(millions of USD, except per share amounts) Funds flow from operations 68 144 52 45 32 16 130 34 14 50 33 Net income (loss) 40 (46) (45) 6.8 (0.2) (8) (45) (4) (27) 2 (16) EBITDA 71 134 56 43 30 6 170 36 41 52 41 Cash and cash equivalents 185 149 149 132 94 92 95 95 75 104 33 Working Capital 131 93 93 118 98 80 77 77 63 90 10 Net Debt (Surplus) (131) (93) (93) (118) (98) (80) (77) (77) (63) (90) 30 Capital Expenditures 36 112 67 26 14 5 126 24 38 37 27 Weighted average shares outstanding 153 152 153 153 152 152 145 151 150 144 135

TRADING STATISTICS (CAD) – PXT

(based on intra-day trading) Share Price High 17.73 18.22 18.22 17.40 14.61 11.96 11.55 11.55 10.57 11.10 9.24 Low 14.64 7.74 14.86 12.00 10.50 7.74 5.97 9.07 7.15 8.05 5.97 Close (end of period) 16.95 16.90 16.90 16.65 12.51 10.95 10.16 10.16 9.25 10.47 8.07 Average daily volume (thousands) 808 693 679 547 678 970 821 729 742 906 907

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COLOMBIA – CURRENT LAND BASE

Source: Divestco, February 2017

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ADVISORIES

HOW TO REACH US

This presentation is provided for informational purposes only as of June 2, 2017, is not complete, and may not contain certain material information about Parex Resources Inc. ("Parex" or the "Company"), including important disclosures and risk factors associated with an investment in Parex. This presentation does not take into account the particular investment objectives or financial circumstances

• f any specific person who may receive it and does not constitute an offer to sell or a solicitation of an
• ffer to buy any security in Canada, the United States or any other jurisdiction. The contents of this

presentation have not been approved or disapproved by any securities commission or regulatory authority in Canada, the United Sates or any other jurisdiction, and Parex expressly disclaims any duty on Parex to make disclosure or any filings with any securities commission or regulatory authority, beyond that imposed by applicable laws. Forward-Looking Statements and FOFI Certain information regarding Parex set forth in this document contains forward-looking statements that involve substantial known and unknown risks and uncertainties. The use of any of the words "plan", "expect", “prospective”, "project", "intend", "believe", "should", "anticipate", "estimate" or other similar words, or statements that certain events or conditions "may" or "will" occur are intended to identify forward-looking statements. Such statements represent Parex' internal projections, estimates or beliefs concerning, among other things, future growth, results of operations, production, future capital and

• ther expenditures (including the amount, nature and sources of funding thereof), plans for and results
• f drilling activity, business prospects and opportunities. These statements are only predictions and

actual events or results may differ materially. Although the Company’s management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Parex' actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Parex. In particular, forward-looking statements contained in this document include, but are not limited to, statements with respect to the performance characteristics of the Company's oil properties; the Company's vision, strategy and values; Parex' estimated 2017 capital budget, including the expected allocation

• f

such budget to the number

• f

wells and capital expenditures for each of development/appraisal in existing fields, exploration, appraisal and maintenance;

PAREX RESOURCES INC. 2700 Eighth Avenue Place, West Tower 585 8th Av SW Calgary AB T2P 1G1 Canada Tel: 403-265-4800 Fax: 403-265-8216 Email: investor.relations@parexresources.com Website: www.parexresources.com MIKE KRUCHTEN

Vice President, Corporate Planning & Investor Relations

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ADVISORIES

the Company's forecasted 2017 average production range; the Company's estimated average daily production for Q2 2017, full year 2017 and full year 2018; the Company's planned capital program, including anticipated amounts focused on existing discoveries and the appraisal programs and the timing of drilling key exploration prospects, seismic programs and development drilling; anticipated cash flow, cash flow per share, funds flow from operations netback, capital expenditures, and funds flow from operations for 2017; the Company's exploration, development and appraisal program for 2017 including anticipated number and type of wells, drill ready prospects, the focus of development/appraisal drilling and the potential for drilling of additional follow-up appraisal wells and facilities in 2017; exploration prospects; the Company's exploration schedule; the Company's drilling plans and production capability/potential; anticipated drilling locations, including the Company's delineation and drilling plans; the Company's plans to target additional growth opportunities; the Company's future plans for its business, including plans to complete further acquisitions and increase production; financial and business prospects and financial outlook; and activities to be undertaken in various areas. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future.

• These forward-looking statements are subject to numerous risks and uncertainties, including but not limited to, the impact of general economic conditions in Canada and Colombia; industry conditions

including changes in laws and regulations including adoption of new environmental laws and regulations, and changes in how they are interpreted and enforced, in Canada and Colombia; competition; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; risks related to obtaining required approvals of regulatory authorities, in Canada and Colombia and partner and community approvals in Colombia; risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities; volatility in market prices for oil; fluctuations in foreign exchange or interest rates; environmental risks; changes in income tax laws, tax rates and/or incentive programs relating to the oil industry; changes to pipeline capacity; ability to access sufficient capital from internal and external sources; risks related to the lawsuit brought in Texas against Parex and certain foreign subsidiaries; failure of counterparties to perform under the terms of their contracts; and other factors, many of which are beyond the control of the Company. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could effect Parex' operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).

• 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. With respect to forward-looking statements contained in this document, Parex has made assumptions regarding, among other things: current commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the price of oil, including the anticipated Brent oil price; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; receipt of partner, regulatory and community approvals; royalty rates; future operating costs; effects of regulation by governmental agencies; uninterrupted access to areas of Parex' operations and infrastructure; recoverability of reserves and future production rates; the status of litigation; timing of drilling and completion of wells; on-stream timing of production from successful exploration wells; operational performance of non-operated producing fields; pipeline capacity; that Parex will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that Parex' conduct and results of operations will be consistent with its expectations; that Parex will have the ability to develop it's oil and gas properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of Parex' reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; that Parex will be able to obtain contract extensions or fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its undeveloped properties; and other matters.

• Management has included the above summary of assumptions and risks related to forward-looking information provided in this document in order to provide shareholders with a more complete perspective
• n Parex' current and future operations and such information may not be appropriate for other purposes. Parex' actual results, performance or achievement could differ materially from those expressed in, or

implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits Parex will derive. These forward-looking statements are made as of the date of this document and Parex disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. The forward-looking statements contained in this presentation are expressly qualified by this cautionary statement.

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ADVISORIES

• This document also contains a financial outlook, in particular the information set forth on slides 3 and 4. Such financial outlook has been prepared by Parex' management to provide an outlook of the

Company's activities and results. The financial outlook has been prepared based on a number of assumptions including the assumptions discussed above and assumptions with respect to the costs and expenditures to be incurred by the Company, capital equipment and operating costs, foreign exchange rates, taxation rates for the Company, general and administrative expenses and the prices to be paid for the Company's production. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such

• perating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of
• perations of the Company and the resulting financial results will likely vary from the amounts set forth in the analysis presented in this presentation, and such variation may be material. The Company and its

management believe that the financial outlook has been prepared on a reasonable basis, reflecting the best estimates and judgments, and represent, to the best of management's knowledge and opinion, Parex's expected expenditures and results of operations. However, because this information is highly subjective and subject to numerous risks including the risks discussed above, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Parex undertakes no obligation to update such financial outlook. Oil and Gas Information

• The estimates of Parex' December 31, 2016 reserves set forth in this presentation have been prepared by GLJ Petroleum Consultants Ltd. ("GLJ") as of December 31, 2016 with a preparation date of February

6, 2017 (the "GLJ 2016 Report") in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluations Handbook (the "COGEH") and using GLJ's forecast prices and costs as at January 1, 2017. The estimates of Parex' December 31, 2015 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2015 with a preparation date of February 5, 2016 in accordance with NI 51-101 and the COGEH and using GLJ's forecast prices and costs as at January 1, 2016. The estimates of Parex' December 31, 2014 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2014 with a preparation date of February 13, 2015 in accordance with NI 51-101 and the COGEH and using GLJ's forecast prices and costs as at January 1, 2015. The estimates of Parex' December 31, 2013 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2013 with a preparation date of February 20, 2014 in accordance with NI 51-101 and the COGEH and using GLJ's forecast prices and costs as at January 1, 2014. The estimates of Parex' December 31, 2012 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2012 with a preparation date of February 28, 2013 in accordance with NI 51-101 and the COGEH and using GLJ's forecast prices and costs as at January 1, 2013. The estimates of Parex' December 31, 2011 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2011 with a preparation date February 10, 2012 in accordance with NI 51-101 and the COGEH and using GLJ's forecast prices and costs as at January 1, 2012 . The estimates of Parex' December 31, 2010 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2010 with a preparation date of January 11, 2011 in accordance with NI 51-101 and the COGEH and using GLJ's forecast prices and costs as at January 1, 2011.

• Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum
• f proved plus probable plus possible reserves.
• Estimates of the net present value of the future net revenue from Parex' reserves do not represent the fair market value of Parex' reserves. The estimates of reserves and future net revenue from individual

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

• This presentation contains certain oil and gas metrics, including F&D, FD&A, FD&A/boe, reserves life index (or RLI), operating netbacks, cash netbacks, funds flow from operations netback, and recycle ratios,

which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. Management uses these

• il and gas metrics for its own performance measurements and to provide investors with measures to compare the Company's operations over time.

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ADVISORIES

Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented herein, should not be relied upon for investment or other purposes. A summary of the calculations of such metrics are as follows:

• FD&A costs represent the costs of property acquisition, exploration, and development incurred. The aggregate of the exploration and development costs incurred in the most recent financial year and

the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

• FD&A costs are calculated as capital expenditures plus change in F&D costs. FD&A per boe is calculated as FD&A costs divided by reserves additions for the applicable period.
• Reserves life index is calculated as proved plus probable reserves divided by annualized fourth quarter production.
• Recycle ratio is calculated as cash netback per boe (or Funds Flow From Operations per boe) divided by F&D or FD&A, as applicable.
• Cash netback per boe (or Funds Flow From Operations netback per boe) is calculated as Funds Flow From Operations divided by production for the period.
• Operating netback is calculated as oil & gas revenue less expenses (royalties, production and transportation) divided by production for the period.
• "BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (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.

• All of Parex’ crude oil reserves disclosed herein are located in Colombia. The Company does have light, medium and heavy crude oil and natural gas liquids. The recovery and reserve estimates of crude oil

reserves provided in this document are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil reserves may eventually prove to be greater than, or less than, the estimates provided herein. All evaluations and reviews of future net revenue contained in GLJ's reports are stated prior to any provision for interest costs or general and administrative costs and after the deduction of royalties, development costs, production costs, well abandonment costs and estimated future capital expenditures for wells to which reserves have been assigned.

• This presentation discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) possible locations. Proved locations, probable locations and possible locations are derived

from the GLJ 2016 Report and account for drilling locations that have associated proved and/or probable and/or possible reserves, as applicable. Of the 195 drilling locations identified herein, 74 are proved locations, 83 are probable locations and 38 are possible locations. The drilling locations on which the Company actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.

• Further, this presentation includes estimates of pay thickness, which are considered to be anticipated results or information that indicate the potential value or quantities of resources under NI 51-101. Such

estimates have been prepared internally by Parex by a non-independent qualified reserves evaluator and have not been prepared or reviewed by an independent qualified reserves evaluator or auditor. The risks associated with these estimates include, but are not limited to, the risk that Parex' exploration and development drilling and related activities may provide different results; the risk that Parex may encounter unexpected drilling results; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas; delays in anticipated timing of drilling and completion of wells; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and the risk that if any resources are discovered that it will not be commercially viable to produce any portion thereof. There is no certainty that Parex will achieve the estimated results or that any portion of the resources will be discovered. If discovered, there is also no certainty that it will be commercially viable to produce any portion of the resources.

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ADVISORIES

• Further, this presentation includes estimates of pay thickness, which are considered to be anticipated results or information that indicate the potential value or quantities of resources under NI 51-101. Such

estimates have been prepared internally by Parex by a non-independent qualified reserves evaluator and have not been prepared or reviewed by an independent qualified reserves evaluator or auditor. The risks associated with these estimates include, but are not limited to, the risk that Parex' exploration and development drilling and related activities may provide different results; the risk that Parex may encounter unexpected drilling results; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas; delays in anticipated timing of drilling and completion of wells; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and the risk that if any resources are discovered that it will not be commercially viable to produce any portion thereof. There is no certainty that Parex will achieve the estimated results or that any portion of the resources will be discovered. If discovered, there is also no certainty that it will be commercially viable to produce any portion of the resources.

• Certain information in this document may constitute "analogous information" as defined in NI 51-101. Such information includes production estimates, drilling results, test rates, reserves estimates and other

information retrieved from other publicly available sources, including but not limited to IHS. Management of Parex believes the information is relevant as it may help to define the reservoir characteristics and production profile of lands in which Parex may hold an interest. Parex is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor and is unable to confirm that the analogous information was prepared in accordance with NI 51-101. Such information is not an estimate of the production, reserves or resources attributable to lands held or to be held by Parex and there is no certainty that the production, reserves or resources data and economic information for the lands held or to be held by Parex will be similar to the information presented herein. The reader is cautioned that the data relied upon by Parex may be in error and/or may not be analogous to such lands held or to be held by Parex.

• Certain other information contained in this presentation has been prepared by third-party sources, which information has not been independently audited or verified by Parex. No representation or warranty,

express or implied, is made by Parex as to the accuracy or completeness of the information contained in this document, and nothing contained in this presentation is, or shall be relied upon as, a promise or representation by Parex.

• This presentation contains references to type well production and economics, which are derived, at least in part, from available information respecting the well economics of other companies and, as such,

there is no guarantee that Parex will achieve the stated or similar results, capital costs and return costs representative per well.

• References in this presentation to initial production test rates, initial "flow" rates, initial flow testing, and "peak" rates are useful in confirming the presence of hydrocarbons, however such rates are not

determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, investors are cautioned not to place reliance on such rates in calculating the aggregate production for Parex. Parex has not conducted a pressure transient analysis or well-test interpretation on the wells referenced in this

• presentation. As such, all data should be considered to be preliminary until such analysis or interpretation has been done.

Financial Matters

• The Company discloses several financial measures that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS"). These financial measures include
• perating netbacks, cash netbacks, funds flow netbacks and funds flow from operations. Management believes that these financial measures are useful supplemental information to analyze operating

performance and provide an indication of the results generated by the Company’s principal business activities. Investors should be cautioned that these measures should not be construed as an alternative to net income or other measures of financial performance as determined in accordance with IFRS. Parex’s method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies. Please see the Company’s most recent Management’s Discussion and Analysis, which is available at www.sedar.com for additional information about these financial measures.

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