Delivering Growth & Value www.parexresources.com | TSX:PXT - - PowerPoint PPT Presentation

1 Corporate Presentation | March 2017

Corporate Presentation | July 2018 1

Delivering Growth & Value

www.parexresources.com | TSX:PXT | Corporate Presentation | July 2018

2 Corporate Presentation | March 2017

Corporate Presentation | July 2018 2

Operating results 2016 2017 2018E Production (boe/d) FY Average 29,715 35,541 ~43,000 Capital Expenditures(1) - US$ million $112 $212 ~$290 Drilling Program (# wells) 17 38 45-50 Reserves (year-end) 2P Reserves (Dec. 31)(2) - Mmboe 112 162 2P Reserve Life Index - years 9.9 11.4 Capital structure – March 31, 2018 Net Working Capital(3) - US$ million $206 US$100 MM Undrawn Credit Facility(3) No Debt Market Capitalization(3)(4) C$3.7Bn Common Shares Basic Outstanding (TSX listed)(4) 156 MM

CORPORATE SNAPSHOT

(1) Assuming US$55 Brent Oil Price in 2018 (2) Parex’ working interest, as per the independent reserve report prepared by GLJ Petroleum Consultants effective Dec. 31, 2017 (3) As at March 31, 2018 (4) Assuming CAD $24 share price See “Advisories” at the end of this presentation

3 Corporate Presentation | March 2017

Corporate Presentation | July 2018 3

• 200

400 600 800 1,000 1,200 2013 2014 2015 2016 2017 2P RESERVES (MBOE/MM BASIC SHARES)

2P RESERVES (DE (DEBT ADJU JUSTED)

• 50

100 150 200 250 300 2013 2014 2015 2016 2017 DAPS (BOE/MM BASIC SHARES)

PRODUCTION PER SHA HARE (DE (DEBT ADJU JUSTED)

DELIVERING CONSISTENT SHAREHOLDER VALUE

15% 15% 34% 66% 7% 15%

• 16%
• 25%

40%

• 11%
• 30%
• 15%

0% 15% 30% 45% 60% 75% 2013 2014 2015 2016 2017 TOTAL RETURN

PXT VS. . S&P/TSX ENERGY IND INDEX (T (TTEN)

PXT S&P/TSX Energy Index $- $20.00 $40.00 $60.00 $80.00 $100.00 $120.00 $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 2013 2014 2015 2016 2017 BRENT PRICE (USD/BBL) FUNDS FLOW PER SHARE (USD/BASIC SHARE)

FU FUNDS FL FLOW PER R SH SHARE (B (BASIC IC)

FUNDS FLOW PER SHARE (USD/BASIC SHARE) BRENT (USD/BBL)

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Corporate Presentation | July 2018 4

REASONS TO OWN PAREX

• 1. No debt and positive working capital exceeding US$206MM (1Q18)
• 2. High margins: 1Q18 Operating Netback US$39/boe @ Brent $67/bbl
• 3. Ability to grow within cash flow:
• 2017 Growth: production 19.6% yoy & RLI increased to 11 years from 10
• 2018 Growth Guidance: ~15-20% self-funded
• 4. Exploration Upside:
• Scheduled to drill 15-18 exploration wells in 2018
• 5. Focused management - ability to growth within a single country  Colombia
• 6. Delivering shareholder value

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Corporate Presentation | July 2018 5

2018 GUIDANCE: CASH FLOW FUNDED GROWTH

Period Assumptions Oil (Brent) H2’18 US $75/bbl FFO netback(1)(2)(3) H2’18 US $35/boe Production (high-end) FY ~43,000 boe/d Capital expenditure H2’18 ~US$145MM Funds flow from operations (3) H2’18 ~US$295MM YOY Production growth/share FY ~15-20%

Maintenance Capex 14 wells 38,000 boe/d ~ $90MM Growth Capex 31-36 wells 3,000-5,000 boe/d $170-200MM

CAPEX ALLOCATION

(1) FFO netback is defined as Funds Flow From Operations per bopd. (2) Netback is a non-GAAP Measure. (3) Excluding decommissioning & environmental liabilities

6 Corporate Presentation | March 2017

Corporate Presentation | July 2018 6

2018 DRILLING PROGRAM

BLOCK Exploration/Appraisal Development Wells (#) Base: Llanos Conventional

Cabrestero 1-2 4-5 5-7 LLA-34 4 14 18 Other Llanos 2-3

• 2-3

Exploration – Big “E”

Capachos & VIM-1 2-3 1 3-4

Exploitation: Tight Oil & Large OIP

Aguas Blancas 4 6 10 DeMares 2 3-4 5-6 Other Magdalena 1 1 2

2018 – Total Wells (#) 15-18 30-32 45-50

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PAREX CASH NETBACK(1)

$26.39 $28.10 $26 $29 $32 $35 $38 ($7.60) ($3.40) ($4.24) ($5.35) ($7.29) ($11.29) $- $5 $10 $15 $20 $25 $30 $35 $40 $45 $50 $55 $60 $65 $70 $75 $80 $85 Q4 2017 Q1 2018

REALIZED PRICE (USD/BOE)

2018 H2 Guidance

2018 H2 TARGET CASH NETBACKS(2)

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

(1) Cash netbacks are non-GAAP measure defined as funds flow from operations per barrel of oil per day. (2) 2018 H2 target cash netbacks are based on production guidance mid-point excluding hedges. (3) Prior period transportation expense on a gross dollar and per boe basis were restated as a result of the Company adopting IFRS 15

Cash Netback

Royalties Differential Transportation

(3)

Opex Tax G&A, Finance & Misc. Costs

BRENT PRICE

$61.46 $67.27

$60 $65 $70 $75 $80

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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

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

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• Dec. 31,

Proved + Probable+ Possible Proved + Probable Proved Annual Production 2P Reserve Life Index Millions of Barrels of Oil Equivalent

Based on Annualized Q4 Production

2013 50 32 17 6 5 years 2014 104 68 40 8 7 years 2015 125 82 46 10 8 years 2016 169 112 64 11 10 years

2017 241 162 96 13 11 years TRACK RECORD OF PROGRESSING RESERVES* FROM 3P TO CASH FLOW

*Per the independent reserve reports prepared by GLJ Petroleum Consultants Ltd. effective December 31 of the reported year. Future development capital (FDC) included in the 2017 GLJ Report are: 1P $302 mm, 2P $432 mm & 3P $537 mm

SOLID FOUNDATION SUPPORTS GROWTH

241 Mmboe  ~ 60,000 boe/d & 11 yr RLI

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CONVENTIONAL OIL RESERVES GENERATE VALUE

Total Company - 2017YE Proved Proved + Probable Proved+ Probable+ Possible FD&A USD/boe(1) $6.00 $4.71 $3.87 Recycle Ratio (FD&A)(1) 4.4x 5.6x 6.8x After Tax NPV10% - CAD/sh(2) $12.81 $20.32 $28.92 Working Capital - CAD/Sh(3) $1.33 $1.33 $1.33 Total CAD/Sh(3) $14.14 $21.65 $30.25

(1) Per the independent reserve reports prepared by GLJ Petroleum Consultants Ltd. effective December 31 of the reported year, including Future Development Cost. Recycle Ratio is calculated using Q4 2017 Funds Flow From Operations per barrel divided by annual F&D or FD&A as applicable. (2) Based on GLJ Petroleum Consultants Ltd. price forecast, which assumes $65.40/bbl over 2018-2022 (3) WC of US$163 million (CAD 205 million) and 154.7 million shares at December 31, 2017

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SOUTHERN LLANOS: FOUNDATION FOR GROWTH

As per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective Dec. 31/17

Faults GLJ 3P (2017YE) Exploration

CABRESTERO (100% WI, operator)

• Swing producer block
• Successful Bacano appraisal in 2017
• 4 wells drilled to date
• 2018 Plan: 1-2 exploration wells and 4-5 development wells

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

• Currently producing ~62,000 boe/d gross (~34,100 boe/d net)
• Tested extent of Jacana-Tigana trend to SW in 2017
• Drilled 9 exploration wells & 13 development wells
• 2018 Plan: 4 exploration wells and 14 development wells

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

LLA-32 LLA-34

Chachalaca Tilo Tigana Jacana Akira Tua Tarotaro Aruco Kananaskis Calona Chiricoca

Herradura

Bacano Curucucu Jacamar

Cabrestero

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Corporate Presentation | July 2018 12

Cabrestero & LLA-34: UNDERSTANDING THE POTENTIAL

As per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective December 31, 2017

Expanded reserve area in 2017 with Jacana, Jacamar, Curucucu, Bacano & Tigana Norte.

Exploration Appraisal/Dev Drilled Potential Stratigraphic Edge

Cabrestero

Akira Bacano Jacana

1 2 4 3 5 6

B-2

8

B-3

2017 GLJ 3P Outline 2017 GLJ 2P Outline

JS-1

Jacamar B-4 11 JS-2

LLA-34

B-5

9

Curucucu

13 10 12 17

TSO-1 TSO-7 TSO-3 TSO-2 T-1

Field (Parex’ WI) GLJ 3P Reserves (MMBO) GLJ 2P Reserves (MMBO) YEAR END 2016 2017 2016 2017 Tigana Guadalupe 51 71 34 52 Jacana Guadalupe 45 76 30 50 Tigana-Jacana Mirador 19 36 12 21 Other LLA-34 14 19 11 12 LLA-34 TOTAL 129 202 87 135 Cabrestero 18 18 11 13

TSO-5 TSO-4 J20

21 22

Tigui Sur 1 TSO-8 B-7 Tigui 1 TSO-6 T-2 T-4 T-3 B-6

Tigana

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LLANOS-34 BRIDGING JACANA & TIGANA FIELDS

• Tigana-Norte 1 has produced ~3.5

mmbbls(1) since June 2014

• Expanding Tigana North area
• Focus is Guadalupe with Mirador upside
• Drilled 4 wells in 2017
• 2018 Plan: 4 development wells

(1) As at March 31, 2018

Tigana

TSO-1 TS6 TS1 TS2 TN4 TN1 TN2 TN3 T2 T3 TS5 TS4 TSO-3 TSO-7 T4 TS3 TS7 Jacana-10

Jacana

As per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective Dec. 31/17

Appraisal/Dev GLJ 3P (2017YE) Faults

Tua

TSO-2 TN5 TN6 TN7 TN9 TSO-5 TSO-4 TN8 TSO-8

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Corporate Presentation | July 2018 14

ANDINA CAPACHOS-2 CAPACHOS SUR-2 NORESTE-1 EXPLORATION

GUADALUPE DEPTH STRUCTURE

NEXT STEPS

• Drilled 2 wells to earn 50% in the block.
• Capachos-2 drilled, restricted production.
• Capachos Sur-2 drilled as water disposal well.
• Drilling Andina exploration well.
• Targeting ~34-39 API Oil in the Guadalupe Formation.
• Construction of gas processing facility by 4Q18.

CAPACHOS DEVELOPMENT AND EXPLORATION POTENTIAL

Future exploration Development well Legacy wells Parex wells

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MAGDALENA BASIN: NEXT GROWTH PLATFORM

De MARES(1)

• Tested Coyote-1, produced oil
• Evaluate follow-up drilling

locations

• 5-6 wells planned in 2018

VIM-1

• Identifying prospects from 3D

Seismic data

• Drill 2 exploration wells

AGUAS BLANCAS(1)

• Light oil opportunity
• Drill 10 wells

VMM-9 & VMM-11

• Acquire 400 km2 of 3D Seismic

PLAYON(1)

• Drill follow-up to Boranda-1

(1) Farm-in on Ecopetrol

Barranquilla Cartagena Barrancabermeja Vasconia Monterrey Terminal Covenas Hidrocasanare Cusiana

Trucking Parex Blocks Pipeline River

Ayacucho Jaguey Guaduas Lerida

VIM-1 PLAYON DE MARES VMM-9 VMM-11 AGUAS BLANCAS

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Corporate Presentation | July 2018 16

TIGHT OIL – NEXT GROWTH AREA?

Size of the Provincia Sub Basin

WCSB Unconventional & Tight Oil Plays Provincia Sub-Basin

Existing oil wells PXT appraisal

Coyote 1/2/3 Aguas Blancas De Mares Block

Potentially material plays for Parex

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Corporate Presentation | July 2018 17

SUMMARY OF THE AGUAS BLANCAS OPPORTUNITY

• 1. Drill 6 development wells: extend

water flood pattern

• 2. Drill 4 appraisal wells: test southern

extent & identify oil in place

• 3. Stimulate 2 wells to increase

productivity

• 4. Sanction Phase 2 (contingent): drill

10-15 development wells

2 . 2

West Area (FW) East Area (HW) Phase II Dev. Area

D/E Compartment Appraisal Existing Injector Existing Producer New Water Injector New Producer Future Pad Existing Standing Well Waterflood Pattern

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Corporate Presentation | July 2018 18

VIM-1: APURE PROSPECT

• Multiple structural & stratigraphic

plays on block

• Main target is a carbonate

reservoir draped over a basement high

• Analogue fields at Cicuco, Boquete

and El Dificil

• Currently drilling

El Dificil Field

Discovered: 1943 Cum Production = 12 MMBO, 352 BCF

Boquete Field

Discovered: 1961 Cum Production = 18.5 MMBO, 41 BCF

Cicuco Field

Discovered: 1956 Cum Production = 48 MMBO, 194 BCF

VIM 1

Apure Prospect

Lower Magdalena Basin

Calizas Member carbonate fairway

Data Source: IHS

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2018 SUMMARY

• 1. Self-funded industry leading

production growth

• 2. Grow & develop Southern

Casanare blocks

• 3. Prove play concepts in

Middle/Lower Magdalena Basins

• 4. Expand portfolio through

Business Development

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Corporate Presentation | July 2018 20

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 10,057 Llanos 3 LLA-26 Operated 100% N/A 93,376 Llanos 4 LLA-29 Operated 100% N/A 69,915 Llanos 5 LLA-30 Operated 100% N/A 117,322 Llanos 6 LLA-32(2) Operated 87.5% Geopark 57,040 Llanos 7 LLA-34 Non-operated 55% Geopark 68,382 Llanos 8 LLA-40(2) Operated 100% N/A 82,422 Llanos 9 Balay Non-operated 10% Perenco 4,500 Llanos 10 Cabrestero Operated 100% N/A 7,605 Llanos 11 Capachos(2) Operated 50% Ecopetrol 64,073 Llanos 12 Los Ocarros Operated 100% N/A 31,066 Llanos 13 VIM-1 Operated 100% N/A 223,651 Lower Magdalena 14 Aguas Blancas(2) Operated 50% Ecopetrol 13,386 Middle Magdalena 15 De Mares(2) Operated 50% Ecopetrol 174,387 Middle Magdalena 16 Morpho(3) Operated 100% N/A 51,420 Middle Magdalena 17 Playon(2) Operated 50% Ecopetrol 43,200 Middle Magdalena 18 Sogamoso Operated 100% N/A 3,695 Middle Magdalena 19 VMM-9 Operated 100% N/A 152,412 Middle Magdalena 20 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 are round up or down to the nearest dollar figure
• Net Debt is defined as Bank Debt - Working Capital
• 2017 transportation expense on a gross dollar and per boe basis were restated as a result of the Company adopting IFRS 15

(Unaudited Results)

2018 2017 2016 Q1 FY Q4 Q3 Q2 Q1 FY Q4 Q3 Q2 Q1

OPERATING

Production (thousands of boe/d) 40.6 35.5 39.0 36.2 34.3 32.6 29.7 31.1 29.8 29.1 28.9 Brent Price ($/bbl) 67 55 62 52 51 55 45 51 47 47 35 Average realized prices, prior to hedging ($/boe) 56 43 50 41 40 42 38 45 40 40 27 Royalty ($/boe) 7 5 6 4 4 4 3 4 3 3 2 Opex ($/boe) 5 5 5 6 5 5 5 6 5 5 5 Transportation ($/boe) 4 4 4 4 4 5 12 11 12 12 12 Operating Netback ($/boe) 39 29 35 28 27 28 18 24 21 20 8 Funds Flow Netback ($/boe) 28 22 26 20 17 23 13 19 16 13 5

FINANCIAL

(millions of USD, except per share amounts) Funds flow from operations 101 280 94 66 52 68 144 52 45 32 16 Net income (loss) 72 155 56 56 4 40 (46) (45) 6.8 (0.2) (8) EBITDA* 123 314 113 73 59 71 134 56 43 30 6 Cash and cash equivalents 295 235 235 196 203 185 149 149 132 94 92 Working Capital 206 163 163 140 128 131 93 93 118 98 80 Net Debt (Surplus) (206) (163) (163) (140) (128) (131) (93) (93) (118) (98) (80) Capital Expenditures 58 212 66 51 59 36 112 67 26 14 5 Bank Credit Facility 100 100 100 100 100 175 175 175 175 175 200 Weighted average shares outstanding 155 154 155 155 154 153 152 153 153 152 152

TRADING STATISTICS (CAD) – PXT

(based on intra-day trading) Share Price High 19.87 18.46 18.46 16.14 18.19 17.73 18.22 18.22 17.40 14.61 11.96 Low 16.82 12.19 14.64 12.19 13.59 14.64 7.74 14.86 12.00 10.50 7.74 Close (end of period) 18.12 18.16 18.16 15.05 14.75 16.95 16.90 16.90 16.65 12.51 10.95 Average daily volume (thousands) 983 762 790 847 606 808 693 679 547 678 970

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COLOMBIA – CURRENT LAND BASE

Source: Divestco - 2017 LLA-16

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ADVISORIES HOW TO REACH US

This presentation is provided for informational purposes only as of July 18, 2018 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 2018 capital budgets, including the expected allocation

• f

such budget to the number

• f

wells and capital expenditures for each

• f

development/appraisal in existing fields, exploration, appraisal and maintenance;

PAREX RESOURCES INC. 2700 Eighth Avenue Place, West Tower 585 8th Avenue 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, Capital Markets & Corporate Planning

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Corporate Presentation | July 2018 24

ADVISORIES

the Company's forecasted 2018 average production range; the Company's estimated average daily production for full year 2018 & full year 2019; 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 2018; the Company's exploration, development and appraisal program for 2018 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 2018; 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

• utlook; 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; 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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Corporate Presentation | July 2018 25

ADVISORIES

• This document also contains a financial outlook, in particular the information set forth on slides 2-5 & 7. 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, 2017 reserves set forth in this presentation have been prepared by GLJ Petroleum Consultants Ltd. ("GLJ") as of December 31, 2017 with a preparation date of February

2, 2018 (the "GLJ 2017 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, 2018. The estimates of Parex' December 31, 2016 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2016 with a preparation date of February 6, 2017 in accordance with NI 51-101 and 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.

• 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 2017 Report and account for drilling locations that have associated proved and/or probable and/or possible reserves, as applicable. Of the 191 drilling locations identified herein, 115 are proved locations, 43 are probable locations and 33 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

• 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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