Parex Resources Inc. — Audit Report / Information 2021

Mar 4, 2021

MANAGEMENT'S REPORT

Management is responsible for the reliability and integrity of the consolidated financial statements, the notes to the consolidated financial statements, and other financial information presented elsewhere in this annual report.

The consolidated financial statements were prepared by management in accordance with International Financial Reporting Standards. Since a precise determination of many assets and liabilities is dependent on future events, the timely preparation of financial statements requires that management make estimates and assumptions and use judgment. When alternative accounting methods exist, management has chosen those that it deems most appropriate in the circumstances.

PricewaterhouseCoopers LLP were appointed by the Company's shareholders to express an audit opinion on the consolidated financial statements. Their examination included such tests and procedures as they considered necessary to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

The Board of Directors is responsible for overseeing that management fulfills its responsibilities for financial reporting and internal control. The Board exercises this responsibility through the Finance & Audit Committee. The Finance & Audit Committee recommends appointment of the external auditors to the Board, evaluates their independence and approves their fees. The Finance & Audit Committee meets regularly with management and the external auditors to oversee that management's responsibilities are properly discharged, to review the consolidated financial statements and recommend that the consolidated financial statements be presented to the Board for approval. The external auditors have full and unrestricted access to the Finance & Audit Committee to discuss their audit and their findings.

"signed"	"signed"
Imad Mohsen	Kenneth G. Pinsky
President and Chief Executive Officer	Chief Financial Officer

March 3, 2021

Independent auditor's report

To the Shareholders of Parex Resources Inc.

Our opinion

In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of Parex Resources Inc. and its subsidiaries (together, the Company) as at December 31, 2020 and 2019, and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (IFRS).

What we have audited

The Company's consolidated financial statements comprise:

• the consolidated balance sheets as at December 31, 2020 and 2019;
• the consolidated statements of comprehensive income for the years then ended;
• the consolidated statements of changes in equity for the years then ended;
• the consolidated statements of cash flows for the years then ended; and
• the notes to the consolidated financial statements, which include significant accounting policies and other explanatory information.

Basis for opinion

We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the Auditor's responsibilities for the audit of the consolidated financial statements section of our report.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Independence

We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada. We have fulfilled our other ethical responsibilities in accordance with these requirements.

Key audit matters

Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the consolidated financial statements for the year ended December 31, 2020. These matters were

PricewaterhouseCoopers LLP 111-5th Avenue SW, Suite 3100, Calgary, Alberta, Canada T2P 5L3 T: +1 403 509 7500, F: +1 403 781 1825

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addressed in the context of our audit of the consolidated financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.

Key audit matter	How our audit addressed the key audit matter
The impact of oil and natural gas reserves onnet property, plant and equipment (PP&E)	Our approach to addressing the matter included thefollowing procedures, among others:
Refer to note 2 – Basis of preparation, significantaccounting estimates and judgments, note 3 –Summary of significant accounting policies, note 4– Determination of fair values and note 8 –	Tested how management determined therecoverable amount for each of the Company'sCGUs and DD&A expense, which included thefollowing:
Property, plant and equipment to the consolidatedfinancial statements.	Evaluated the appropriateness of themethods used by management in makingthese estimates;
The Company has $902.9 million of net PP&E as atDecember 31, 2020. Depletion, depreciation andamortization (DD&A) expense was $114.2 million	Tested the data used in determining theseestimates;
for the year then ended.Costs accumulated within each cash generating	Evaluated the reasonableness of significantassumptions used in developing theunderlying estimates:
unit (CGU) are depleted using the unit-ofproduction method based on proved plus probablereserves incorporating estimated future prices andcosts. Costs subject to depletion include estimatedfuture costs to be incurred in developing provedplus probable reserves. Costs of majordevelopment projects are excluded from the costssubject to depletion until they are available for use.	oProved plus probable reserves, futuredevelopment costs and operating costsby considering the past performance ofeach significant CGU, and whetherthese assumptions were consistentwith evidence obtained in other areasof the audit.
For the purpose of impairment testing, assets aregrouped into the smallest group of assets that	oFuture commodity prices by comparingthose forecasts with other reputablethird party industry forecasts.
generates cash inflows from continuing use that arelargely independent of the cash inflows of otherassets or groups of assets. The carrying amountsof the Company's long-term assets are reviewed at	oThe discount rate by determiningwhether it is consistent with evidenceobtained.
each reporting date to determine whether there isany indication of impairment. If an indication ofimpairment exists, management estimates the	Recalculated the unit-of-production ratesused to calculate DD&A expense for eachof the Company's CGUs.
asset's recoverable amount. Impairment loss isrecognized if the carrying amount of an asset or itsCGU exceeds its estimated recoverable amount.	The work of management's experts was usedin performing the procedures to evaluate thereasonableness of the proved plus probable oil

and natural gas reserves used to determine

The fair value less cost of disposal (FVLCD) is based on available market information, where

applicable. In the absence of such information, FVLCD is determined using discounted future after tax net cash flows of proved plus probable reserves using forecast prices and costs prepared by the Company's independent qualified reserve evaluators (management's experts).

An indication of impairment was identified for all CGUs at March 31, 2020 and impairment tests were performed. The Company determined that the carrying amount for the Boranda CGU exceeded its recoverable amount and an impairment of $7.0 million was recorded. The recoverable amount was determined using fair value less cost of disposal.

At December 31, 2020, there were no indicators of impairment noted, or indicators requiring a reversal of previously recorded impairments.

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. Changes in reserve estimates impact the financial results of the Company as reserves and estimated future development costs are used to calculate depletion and are also used in measuring fair value less costs of disposal of property, plant and equipment for impairment calculations.

We determined that this is a key audit matter due to (i) the significant judgment made by management, including the use of management's experts, when developing the expected future after tax net cash flows to determine the recoverable amount and the proved plus probable oil and natural gas reserves; and (ii) a high degree of auditor judgment, subjectivity and effort in performing procedures relating to the significant assumptions.

Key audit matter How our audit addressed the key audit matter

DD&A expense and the recoverable amount of the Company's PP&E for each CGU. As a basis for using this work, management's experts' competence, capability and objectivity were evaluated, their work performed was understood and the appropriateness of their work as audit evidence was evaluated by considering the relevance and reasonableness of the assumptions, methods and findings.

Other information

Management is responsible for the other information. The other information comprises the Management's Discussion and Analysis and the information, other than the consolidated financial statements and our auditor's report thereon, included in the annual report.

Our opinion on the consolidated financial statements does not cover the other information and we do not express any form of assurance conclusion thereon.

In connection with our audit of the consolidated financial statements, our responsibility is to read the other information identified above and, in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit, or otherwise appears to be materially misstated.

If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

Responsibilities of management and those charged with governance for the consolidated financial statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with IFRS, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the consolidated financial statements, management is responsible for assessing the Company's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so.

Those charged with governance are responsible for overseeing the Company's financial reporting process.

Auditor's responsibilities for the audit of the consolidated financial statements

Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian generally accepted auditing standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated financial statements.

As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and maintain professional skepticism throughout the audit. We also:

• Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control.
• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.
• Conclude on the appropriateness of management's use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor's report to the related disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor's report. However, future events or conditions may cause the Company to cease to continue as a going concern.
• Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation.
• Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Company to express an opinion on the consolidated financial statements. We are responsible for the direction, supervision and performance of the group audit. We remain solely responsible for our audit opinion.

We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.

From the matters communicated with those charged with governance, we determine those matters that were of most significance in the audit of the consolidated financial statements of the current period and

are therefore the key audit matters. We describe these matters in our auditor's report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

The engagement partner on the audit resulting in this independent auditor's report is John Williamson.

/s/PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Alberta March 3, 2021

CONSOLIDATED FINANCIAL STATEMENTS Consolidated Balance Sheets

As at(thousands of United States dollars)	NOTE	December 31,2020	December 31,2019
ASSETS
Current assets
Cash and cash equivalents		$330,564	$396,839
Accounts receivable	5	80,166	149,510
Prepaids and other current assets		13,457	8,363
Derivative financial instruments	22	—	511
Current income tax receivable	17	16,534	—
Crude oil inventory	6	1,915	653
		$442,636	$555,876
Deferred tax asset	17	42,729	89,254
Goodwill	10	73,452	73,452
Exploration and evaluation	7	79,365	142,916
Property, plant and equipment	8	902,899	823,083
		$1,541,081	$1,684,581
LIABILITIES AND SHAREHOLDERS' EQUITYCurrent liabilities
Accounts payable and accrued liabilities		$115,427	$141,716
Current income tax payable	17	—	61,763
Current portion of decommissioning and environmental liabilities	14	7,054	8,366
		122,481	211,845
Lease obligation	9	1,820	770
Cash settled share-based compensation liabilities	13	11,843	12,379
Decommissioning and environmental liabilities	14	44,057	43,569
Deferred tax liability	17	20,402	13,573
		200,603	282,136
Shareholders' equity
Share capital	15	763,372	812,684
Contributed surplus		43,228	48,573
Retained earnings		533,878	541,188
		1,340,478	1,402,445
		$1,541,081	$1,684,581

Commitments and Contingencies (note 24)

See accompanying Notes to the Consolidated Financial Statements Approved by the Board:

"signed"	"signed"
Paul Wright	Bob MacDougall
Director	Director

Consolidated Statements of Comprehensive Income

For the year ended December 31,
(thousands of United States dollars, except per share amounts)	NOTE	2020	2019
Oil and natural gas sales	11	$587,520	$1,113,622
Royalties		(55,655)	(136,068)
Revenue		531,865	977,554
Commodity risk management contracts (loss)	22	(3,940)	—
		527,925	977,554
Expenses
Production		87,272	111,061
Transportation		59,147	88,974
Purchased oil		28,241	52,791
General and administrative		36,058	34,214
Impairment of property, plant and equipment assets	8	7,000	—
Impairment of exploration and evaluation assets	7	6,166	22,767
Equity settled share-based compensation expense	15	4,235	7,603
Cash settled share-based compensation expense	16	5,275	20,081
Depletion, depreciation and amortization	8	113,758	125,899
Foreign exchange loss	22	409	6,924
		347,561	470,314
Finance (income)	12	(2,129)	(7,382)
Finance expense	12	9,142	10,958
Net finance expense		7,013	3,576
Income before income taxes		173,351	503,664
Income tax expense
Current tax expense	17	20,674	120,163
Deferred tax expense	17	53,355	55,507
		74,029	175,670
Net income and comprehensive income for the year		$99,322	$327,994
Basic net income per common share	18	$0.72	$2.24
Diluted net income per common share	18	$0.71	$2.20

See accompanying Notes to the Consolidated Financial Statements

Consolidated Statements of Changes in Equity

For the year ended December 31,
(thousands of United States dollars)	2020	2019
Share Capital
Balance, beginning of year	$812,684	$848,946
Issuance of common shares under share-based compensation plans	15,570	31,509
Repurchase of shares	(64,882)	(67,771)
Balance, end of year	$763,372	$812,684
Contributed Surplus
Balance, beginning of year	$48,573	$54,742
Share-based compensation	4,235	7,603
Options, RSUs and PSUs exercised	(9,580)	(13,772)
Balance, end of year	$43,228	$48,573
Retained earnings
Balance, beginning of year	$541,188	$369,344
Net income for the year	99,322	327,994
Repurchase of shares	(106,632)	(156,150)
Balance, end of year	533,878	541,188
	$1,340,478	$1,402,445

See accompanying Notes to the Consolidated Financial Statements

Consolidated Statements of Cash Flows

For the year ended December 31,

(thousands of United States dollars)	NOTE	2020	2019
Operating activities
Net income		$99,322	$327,994
Add non-cash items
Depletion, depreciation and amortization	8	113,758	125,899
Non-cash finance expense	12	5,655	6,853
Equity settled share-based compensation expense	15	4,235	7,603
Cash settled share-based compensation expense	16	5,275	20,081
Deferred tax expense	17	53,355	55,507
Impairment of property, plant and equipment assets	8	7,000	—
Impairment of exploration and evaluation assets	7	6,166	22,767
Unrealized foreign exchange loss	22	1,472	3,417
Loss on settlement of decommissioning liabilities	14	803	359
Net change in non-cash working capital	19	(7,023)	(205,413)
Cash provided by operating activities		290,018	365,067
Investing activities
Property, plant and equipment expenditures	8	(116,915)	(148,519)
Exploration and evaluation expenditures	7	(24,349)	(59,677)
Net change in non-cash working capital	19	(38,534)	(10,796)
Cash (used in) investing activities		(179,798)	(218,992)
Financing activities
Issuance of common shares under share-based compensation plans	15	5,990	17,737
Common shares repurchased	15	(171,514)	(223,921)
Payments on lease obligation	9	(872)	(592)
Net change in non-cash working capital	19	(2,046)	(3,793)
Cash (used in) financing activities		(168,442)	(210,569)
Decrease in cash for the year		(58,222)	(64,494)
Impact of foreign exchange on foreign currency-denominated cash balances		(8,053)	(1,558)
Cash, beginning of year		396,839	462,891
Cash, end of year		$330,564	$396,839

Supplemental Disclosure of Cash Flow Information (note 19) See accompanying Notes to the Consolidated Financial Statements

Notes to the Consolidated Financial Statements

For the year ended December 31, 2020

(Tabular amounts in thousands of United States dollars, unless otherwise stated. Amounts in text are in United States dollars, unless otherwise stated.)

1. Corporate Information

Parex Resources Inc. and its subsidiaries ("Parex" or "the Company") are in the business of the exploration, development, production and marketing of oil and natural gas in Colombia.

Parex Resources Inc. is a publicly traded Company, incorporated and domiciled in Canada. Its registered office is at 2400, 525-8th Avenue S.W., Calgary, Alberta T2P 1G1. The Company was incorporated on August 17, 2009, pursuant to the Business Corporations Act (Alberta).

The consolidated financial statements were approved and authorized for issuance by the Board of Directors on March 3, 2021.

2. Basis of Preparation, Significant Accounting Estimates and Judgements

a) Statement of compliance

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standard Boards ("IASB").

The policies applied in these consolidated financial statements are based on IFRS issued and outstanding as of March 3, 2021, the date the Board of Directors approved the consolidated financial statements.

b) Basis of measurement

The consolidated financial statements have been prepared under the historical cost convention except for derivative financial instruments and share-based compensation transactions which are measured at fair value. The methods used to measure fair values are discussed in note 4 - Determination of Fair Values.

c) Use of management estimates, judgments and measurement uncertainty

The timely preparation of the consolidated financial statements requires that management make estimates and use judgment regarding the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as at the date of the consolidated financial statements. Accordingly, actual results could differ from estimated amounts as future confirming events occur.

In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel strain of the coronavirus ("COVID-19"). The outbreak and subsequent measures intended to limit the pandemic contributed to significant declines and volatility in financial markets. The pandemic has adversely impacted global commercial activity, including significantly reducing worldwide demand for crude oil. As a result of declining commodity prices and financial markets, the Company's share price and market capitalization declined from December 31, 2019.

The full extent of the impact of COVID-19 on the Company's operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of COVID-19, its continued impact on capital and financial markets on a macro-scale and any new information that may emerge concerning the severity of the virus. These uncertainties may persist beyond when it is determined how to contain the virus or treat its impact. The outbreak presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by Management in the preparation of its financial results.

Determining the recoverable amount of a cash-generating unit ("CGU") or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. Significant estimates and judgments made by management in the preparation of these consolidated financial statements are outlined below:

(i) Depletion, depreciation and reserves

Depletion is based on the proved plus probable reserves as evaluated in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and incorporating the estimated future cost of developing and extracting those. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates are based on current production forecasts, prices and economic conditions. As circumstances change and additional data becomes available, reserve estimates may also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions of reserve estimates are often required due to changes in well performance, prices, economic conditions and governmental regulations.

Although every reasonable effort is made to determine that reserve estimates are accurate, reserve estimation is an inferential science. As a result, subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices and reservoir performance. Such revisions can be either positive or negative. Changes in reserve estimates impact the financial results of the Company as reserves and estimated future development costs are used to calculate depletion and are also used in measuring fair value less costs of disposal of property, plant and equipment for impairment calculations (see note 8 - Property, Plant and Equipment).

(ii) Determination of cash-generating units ("CGUs")

The determination of CGUs requires judgment in defining a group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or groups of assets. CGUs are determined by similar geological structure, shared infrastructure, geographical proximity, commodity type, similar exposure to market risks and materiality.

(iii) Exploration and evaluation ("E&E")

The decision to transfer assets from E&E to property, plant and equipment ("PP&E") is primarily based on the estimated proved plus probable reserves used in the determination of an area's technical feasibility and commercial viability (see note 7 – Exploration and Evaluation Assets).

(iv) Decommissioning and environmental liabilities

Decommissioning and restoration costs will be incurred by the Company at the end of the operating life of certain of its assets. The ultimate decommissioning and restoration costs are uncertain and cost estimates can vary in response to many factors including changes to relevant legal and regulatory requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing and amount of expenditure can also change in response to changes in reserves, laws and regulations or their interpretation, the timing and likelihood of the settlement of the obligation, discount rates, and future interest rates. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The Company uses a risk-free discount rate based on forecasted Colombia interest rates.

Liabilities for environmental costs are recognized in the period in which they are incurred, normally when the asset is developed and the associated costs can be estimated. These liabilities are in addition to the decommissioning liabilities due to government regulations that require the Company to perform additional mitigation against the environmental issues attributed to water usage and deforestation from oil and gas activities performed. In addition, the timing of expected settlement of the environmental liabilities differs from the timing of expected settlement of the decommissioning liabilities. Refer to note 14 – Decommissioning and Environmental Liabilities.

(v) Impairment indicators and discount rate

The recoverable amounts of CGUs and individual assets have been determined as the greater of either an asset's or CGU's value in use or fair value less costs of disposal. These calculations require the use of estimates and assumptions and are subject to changes as new information becomes available including information on future commodity prices, quantity of reserves and discount rates as well as future development and operating costs. It is reasonably possible that the commodity price assumptions may change, which may impact the estimated life of the oil and natural gas reserves and the recoverable economical reserves and may require a material adjustment to the carrying value of oil and natural gas assets. The Company monitors internal and external indicators of impairment relating to its property, plant and equipment, and exploration and evaluation assets. Refer to note 7 – Exploration and Evaluation Assets, note 8 – Property, Plant and Equipment and note 10 – Goodwill.

(vi) Share-based compensation

Compensation costs accrued for under the Company's Stock Option plan and Share Appreciation Right ("SAR") plan are subject to the estimation of what the ultimate payout will be using the Black-Scholes pricing model which is based on significant assumptions such as the future volatility of the market price of Parex shares and expected term of the issued stock option or SAR. Compensation costs accrued for under the Company's Restricted Share Unit ("RSU") plan pursuant to which RSUs and Performance Share Units ("PSUs") may be issued, Deferred Share Unit ("DSU") plan, Cash Settled Restricted Share Units ("CRSU") plan and Cash or share settled Restricted Share Units ("CosRSU") and Performance Share Units ("CosPSU") plan pursuant to which CosRSUs and CosPSUs are measured at fair value based on the market price of Parex shares on the date of issuance. Refer to note 15 - Share Capital and note 16 - Cash Settled Incentive Plans.

(vii) Derivative financial asset/liability

The estimated fair value of derivative instruments and resulting derivative assets and liabilities depends on estimated forward prices and volatility in those prices and by their nature are subject to measurement uncertainty.

(viii) Income taxes

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and interpretation. As such, income taxes are subject to measurement uncertainty. The Company follows the liability method for calculating deferred taxes. Assessing the recoverability of deferred tax assets requires the Company to make significant estimates related to the expectations of future cash flows from operations and the application of existing tax laws. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Company to realize the deferred tax assets and liabilities recorded at the balance sheet date could be impacted. Additionally, changes in tax laws could limit the ability of the Company to obtain tax deductions in the future.

(ix) Business combinations, corporate and property acquisitions

Business combinations, corporate and property acquisitions are accounted for using the acquisition method of accounting whereby the assets acquired and the liabilities assumed are recorded at fair values. The determination of fair value often requires management to make assumptions and estimates about future events. The fair value of property, plant and equipment recognized in a business combination, corporate or property acquisition is based on market values. The market value of property, plant and equipment is the estimated amount for which PP&E could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm's length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in PP&E) are estimated with reference to the discounted cash flows expected to be derived from oil and natural gas production based on externally prepared reserve reports. The market value of E&E assets are estimated with reference to the market values of current arm's length transactions in comparable locations. Assumptions are also required to determine the fair value of decommissioning obligations associated with the properties. Changes in any of these assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill (or gain from a bargain purchase) in the acquisition equation. Future net earnings can be affected as a result of changes in future depletion and depreciation, asset impairment or goodwill impairment.

3. Summary of Significant Accounting Policies

The accounting policies set out below have been applied consistently to all years presented in these consolidated financial statements, and have been applied consistently by the Company and its subsidiaries.

a) Consolidation

The consolidated financial statements include the accounts of the Company and all of its subsidiaries at December 31, 2020. The principal operating subsidiaries and their activities are:

Entity	Country ofincorporation	Country ofprinciplebusiness activity		Ownership % Principle business activity
Parex Resources (Colombia) Ltd.	Barbados	Colombia	100	Oil and natural gas exploration and development
Verano Energy Limited	Bermuda	Colombia	100	Oil and natural gas exploration and development

The above listing does not include the wholly-owned holding company subsidiaries or inactive operating company subsidiaries of Parex. All companies in the Parex group are wholly-owned subsidiaries.

Inter-company balances and transactions are eliminated on consolidation. Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company recognizes its share of assets, liabilities, revenues and expenses of a joint operation. A significant portion of the Company's operating cash flows is derived through joint operations which are involved in the development and production of crude oil in Colombia. Joint ventures arise when the Company has rights to the net assets of the arrangement. Joint ventures are accounted for under the equity method.

b) Foreign currency translation

(i) Functional and presentation currency

Items included in the consolidated financial statements are measured using the currency of the primary economic environment in which the Company operates (the "functional currency"). The consolidated financial statements are presented in United States dollars, which is the functional currency of Parex.

(ii) Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the date of the transaction. Generally, foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at periodend exchange rates of monetary assets and liabilities denominated in currencies other than an operation's functional currency are recognized in the statement of comprehensive income.

c) Financial instruments

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously.

The Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:

• Level 1 inputs are quoted prices in active markets for identical assets and liabilities;
• Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly; and
• Level 3 inputs are unobservable inputs for the asset or liability.

Classification and Measurement of Financial Assets

The initial classification of a financial asset depends upon the Company's business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Company classified its financial assets:

• Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest;
• Fair Value through Other Comprehensive Income ("FVOCI"): Includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest; or
• Fair Value Through Profit or Loss ("FVTPL"): Includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial instruments.

On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial recognition of an equity investment that is not held-fortrading, the Company may irrevocably elect to present subsequent changes in the investment's fair value in OCI. There is no subsequent reclassification of fair value changes to earnings following the derecognition of the investment. However, dividends that reflect a return on investment continue to be recognized in net earnings. This election is made on an investment-by-investment basis.

At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings.

Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period following the change in the business model. A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership.

Impairment of Financial Assets

The Company recognizes loss allowances for Expected Credit Losses ("ECLs") on its financial assets measured at amortized cost. Due to the nature of its financial assets, the Company measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component.

As at December 31, 2020, all of the Company's receivables were outstanding for less than 90 days. The average expected credit loss on the Company's trade accounts receivable was 1.3% at December 31, 2020.

Classification and Measurement of Financial Liabilities

A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The classification of a financial liability is irrevocable.

Financial liabilities at FVTPL are measured at fair value with changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are initially measured at fair value less directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings.

A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability is modified in a non-substantial way, the amortized cost of the liability is remeasured based on the new cash flows and a gain or loss is recorded in net earnings.

Derivative Financial Instruments

Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.

Risk management assets and liabilities are derivative financial instruments classified as measured at FVTPL. Derivatives financial instruments are recorded using mark-to-market accounting whereby instruments are recorded in the consolidated balance sheets as either an asset or liability with changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.

d) Capital assets

(i) Exploration and evaluation

All costs directly associated with the exploration and evaluation of oil and natural gas reserves are initially capitalized. E&E costs are those expenditures for an area where technical feasibility and commercial viability have not yet been determined. These costs include unproved property acquisition costs, exploration costs, geological and geophysical costs, decommissioning costs, E&E drilling, sampling and appraisals. Costs incurred prior to acquiring the legal rights to explore an area are charged directly to comprehensive income as E&E expenses.

When an area is determined to be technically feasible and commercially viable the accumulated costs are transferred to PP&E, where they are depleted. When an area is determined not to be technically feasible and commercially viable or the Company decides not to continue with its activity, the unrecoverable costs are charged to comprehensive income as impairment of exploration and evaluation assets. Net proceeds from any disposal of an intangible exploration asset are recorded as a reduction in intangible assets.

(ii) Property, plant and equipment

All costs directly associated with the development of oil and natural gas reserves are capitalized on an area-by-area basis. Development costs include expenditures for areas where technical feasibility and commercial viability have been determined. These costs include proved property acquisitions, development drilling, completion of wells, gathering facilities and infrastructure, decommissioning and restoration costs and transfers of E&E assets.

Costs accumulated within each CGU are depleted using the unit-of-production method based on proved plus probable reserves incorporating estimated future prices and costs. Costs subject to depletion include estimated forecast costs to be incurred in developing proved plus probable reserves. Costs of major development projects are excluded from the costs subject to depletion until they are available for use.

Costs associated with office furniture, fixtures and leasehold improvements are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 1 to 5 years.

e) Impairment of long-term assets

The carrying amounts of the Company's long-term assets, other than deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. E&E assets are also assessed for impairment when they are reclassified to PP&E, and, if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. E&E assets are allocated to related CGUs where they are assessed for impairment upon their eventual reclassification to PP&E. E&E assets not reclassified to PP&E are assessed for impairment on a block by block basis. If an indication of impairment exists, management estimates the asset's recoverable amount.

For the purpose of impairment testing, assets are grouped into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs of disposal ("FVLCD").

The value in use is determined by estimating the present value of the pre-tax future net cash flows expected to be derived from the continued use of the asset or CGU. The FVLCD is based on available market information, where applicable. In the absence of such information, FVLCD is determined using discounted future after tax net cash flows of proved plus probable reserves using forecast prices and costs prepared by the Company's independent qualified reserve evaluators.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in comprehensive income.

The recoverable amount of goodwill is determined as the fair value less costs of disposal using a discounted cash flow method. Goodwill is evaluated at the Colombia segment level as business combinations giving rise to goodwill do not have specifically identifiable benefits to any one CGU.

Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

f) Crude oil inventory and overlift oil volumes

Crude oil inventory consists of crude oil in transit at the balance sheet date and is valued at the lower of cost, using the weighted average cost method, and net realizable value. Costs include direct and indirect expenditures incurred in bringing the crude oil to its existing condition and location. The liability for overlift oil volumes is valued based on the Brent oil price at the balance sheet date. Sales revenue is subsequently recorded at the Brent oil price once the overlifted pipeline volumes are returned. A gain/loss on overlifted oil volumes is recorded on the difference between the original liability and the revenue recorded on the returned barrels.

g) Purchased oil

Purchased oil includes costs to buy third party oil and accruals for overlifted oil volumes. The costs for third party oil are initially recorded in inventory until the crude oil title is transferred. The costs for overlifted oil volumes are originally recorded as an accrued liability until the volumes are returned.

h) Goodwill

Goodwill is recorded on a business acquisition when the purchase price is in excess of the fair values assigned to assets acquired and liabilities assumed. Goodwill is not amortized and an impairment test is performed annually or as events occur that could indicate impairment. To test for impairment, goodwill is allocated to each of the Company's CGUs, groups of CGUs, or an operating segment expected to benefit from the acquisition. Goodwill is tested by combining the carrying amounts of property, plant and equipment and exploration and evaluation assets and goodwill and comparing this to the recoverable amount. Fair value less costs of disposal, is derived by estimating the discounted after-tax future net cash flows as described in the property, plant and equipment impairment test, plus the fair market value of undeveloped land, seismic and inventory. Value in use is assessed using the present value of the expected future cash flows. Any excess of the carrying amount over the recoverable amount is recorded as impairment. Impairment charges, which are not tax affected, are recognized in comprehensive income and are not reversed. Goodwill is reported at cost less any impairment.

i) Revenue recognition

Parex principally generates revenue from the sale of commodities, which include crude oil and natural gas. Revenue associated with the sale of commodities is recognized when control is transferred from Parex to its customers. The Company's commodity sale contracts represent a series of distinct transactions. The Company considers its performance obligations to be satisfied and control to be transferred when all the following conditions are satisfied:

• Parex has transferred title and physical possession of the commodity to the buyer;
• Parex has transferred the significant risks and rewards of ownership of the commodity to the buyer; and
• Parex has the present right to payment.

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. The Company sells its production of crude oil and natural gas pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized in the same period. The Company does not have any contracts where the period between the transfer of the promised goods or services to the customer and payment by the customer exceeds one year. As a result, Parex does not adjust its revenue transactions for the time value of money.

Parex enters into contracts with customers that can have performance obligations that are unsatisfied (or partially unsatisfied) at the reporting date. The Company applies a practical expedient of IFRS 15 and does not disclose information about remaining performance obligations that have original expected durations of one year or less, or for performance obligations where the Company has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the Company's performance completed to date. The Company also applies a practical expedient of IFRS 15 that allows any incremental costs of obtaining contracts with customers to be recognized as an expense when incurred rather than being capitalized.

Contract modifications with the Company's customers could change the scope of the contract, the price of the contract, or both. A contract modification exists when the parties to the contract approve the modification either in writing, orally, or based on the parties' customary business practices. Contract modifications are accounted for either as a separate contract when there is an additional product at a stand-alone selling price, or as part of the existing contract, through either a cumulative catch-up adjustment or prospectively over the remaining term of the contract, depending on the nature of the modification and whether the remaining products are distinct.

The Company's revenue transactions do not contain significant financing components.

j) Equity settled share-based compensation

The Company has an incentive stock option plan and a restricted unit plan pursuant to which the Company may issue Restricted Share Units ("RSUs") and Performance Share Units ("PSUs") for certain employees, officers and directors as described in note 15 - Share Capital. The Company records share-based compensation expense using the fair value method. The fair value of an option granted is calculated at the grant date using the Black-Scholes pricing model, and expensed over the vesting period of the option. The fair value of each RSU and PSU granted is calculated using the market price of Parex shares on the date of issuance, and expensed over the vesting period of the RSU and PSU. The Company determines an appropriate forfeiture rate by examining the history of its forfeitures. The Company records the cumulative share-based compensation as contributed surplus. When options, RSUs or PSUs are exercised, contributed surplus is reduced and share capital is increased by the amount of accumulated share-based compensation for the exercised security. Any consideration received on the exercise of stock options, RSUs or PSUs is credited to share capital.

PSUs may be granted with certain performance measures, specified at the grant date as determined by the Company's Board of Directors. Based upon the achievement of the performance measures, a pre-determined adjustment factor of between 0-2x is applied to PSUs eligible to vest at the end of the performance period. The expense recognized over the vesting period of PSUs is the fair value of the PSUs with an estimated adjustment factor. If the actual final adjustment factor is higher than estimated at grant, additional expense is recognized on vesting for the incremental fair value. Upon the exercise of the options, RSUs and PSUs consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase to share capital.

k) Cash settled share-based compensation

The Company has a share appreciation rights plan for certain employees of Parex Colombia as described in note 16 - Cash Settled Incentive Plans. Obligations for payments of cash under the foreign subsidiaries' SARs plan are accrued as compensation expense over the vesting period based on the fair value of SARs, subject to appreciation limits specified in the plan. The fair value of SARs is measured using the Black-Scholes pricing model. In accordance with the fair value method, increases or decreases in the fair value of the SARs result in a corresponding change in the recorded liability. The accrued compensation for a right that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture.

The Company has a Cash Settled Restricted Share Unit ("CRSUs") plan which allows the Company to issue CRSUs to certain employees of Parex Colombia as described in note 16 - Cash Settled Incentive Plans. Obligations for payments of cash under the foreign subsidiaries' CRSUs plan are accrued as compensation expense over the vesting period based on the fair value of CRSUs. The fair value of CRSUs is equal to the market price of the Company's common shares at the valuation date. In accordance with the fair value method, increases or decreases in the fair value of the CRSUs result in a corresponding change in the recorded liability. The accrued compensation for a right that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture. The CRSUs liability cannot be settled by the issuance of common shares.

The Company has a Deferred Share Unit ("DSU") plan which allows the Company to issue DSUs to all non-employee directors of Parex Resources Inc, as described in note 16 - Cash Settled Incentive Plans. As DSUs vest immediately on issuance, obligations for payments of cash under the DSUs plan are accrued as compensation expense immediately on issuance based on the fair value of the DSUs. The fair value of DSUs at each reporting period is equal to the market price of the Company's common shares at the valuation date. In accordance with the fair value method, increases or decreases in the fair value of the DSUs result in a corresponding change in the recorded liability. The accrued compensation for a unit that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture.

During 2019 the Company put in place a Cash or Share Settled Restricted Share Unit/Performance Share Unit ("CosRSU/CosPSU") incentive plan to issue CosRSUs and CosPSUs to certain employees of Parex Canada as described in note 16 - Cash Settled Incentive Plans. This new plan will replace the equity settled RSU/PSU plan. Obligations for payments of cash or settlement of shares under the CosRSUs and CosPSUs plan are accrued as compensation expense over the vesting period based on the fair value of the CosRSUs and CosPSUs. The fair value of CosRSUs and CosPSUs is equal the market price of the Company's common shares at the valuation date. In accordance with the fair value method, increases or decreases in the fair value of the CosRSUs and CosPSUs result in a corresponding change in the recorded liability. The accrued compensation for a right that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture. The CosRSUs and CosPSUs liability can be settled in cash or by the issuance of common shares at the election of the employee.

l) Provisions

A provision is recognized if, as a result of a past event, the Company has a current legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

m) Decommissioning and environmental liabilities

The Company's activities give rise to dismantling, decommissioning, environmental, abandonment and site disturbance remediation activities. Provisions are made for the estimated cost of the future site restoration and capitalized in the relevant asset category.

Decommissioning and environmental liabilities are measured at the present value of management's best estimate of the cost and future timing of the expenditure required to settle the present obligation at the balance sheet date using a risk-free discount rate. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as a finance expense whereas increases (decreases) due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning and environmental liabilities are charged against the provision to the extent the provision was established.

n) Operating Segments

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by the Company's chief operating decision makers. The operating segments are Canada and Colombia. The Company evaluates the financial performance of its operating segments primarily based on operating cash flow.

o) Finance income and expense

Finance expense comprises standby fees related to the undrawn credit facility, bank taxes, accretion on provisions, loss (gain) on settlement of provisions, loss on disposition of tangible assets and expected credit loss provision (recovery). Finance income comprises interest earned on cash and other income and gains on property acquisitions.

p) Cash

Cash is comprised of cash and other short-term highly liquid investments with maturities less than 3 months held in chartered banks in Canada and recognized financial institutions in Colombia and the Caribbean with BBB+ credit ratings or higher.

q) Income taxes

Income tax expense comprises current and deferred tax. Income tax expense is recognized in comprehensive income.

Current tax is the expected tax payable on taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

In general, deferred tax is recognized in respect of temporary differences arising between the tax basis of assets and liabilities and their carrying amounts in the consolidated financial statements. Deferred tax is determined on a non-discounted basis using tax rates, currency exchange rates and laws enacted or substantively enacted by the balance sheet date and expected to apply when the deferred tax asset or liability is settled. Deferred tax assets are recognized to the extent that it is probable that the assets can be recovered. Deferred tax is not provided on temporary differences arising on investments in subsidiaries except, in the case of subsidiaries, where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not be reversed in the foreseeable future. Deferred tax assets and liabilities are presented as non-current.

r) Per share information

Basic net income per share is calculated by dividing the income or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted net income per share is determined by adjusting the income or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options granted to employees, except when the effect would be anti-dilutive.

s) Leases

The Company adopted IFRS 16 on January 1, 2019 using the modified retrospective approach, whereby the cumulative effect of initially applying the standard was recognized as a $2.2 million increase to right-of-use assets (included in "Property, Plant and Equipment") with a corresponding increase to lease obligations (the non-current portion of $1.5 million is recorded in "Lease Obligation" and the current portion of $0.7 million is recorded in "accounts payable and accrued liabilities"). On adoption of IFRS 16, the Company's lease liabilities related to contracts classified as a lease are measured at the discounted present value of the remaining minimum lease payments, excluding short-term and low-value leases. The right-of-use assets recognized were measured at amounts equal to the present value of the lease obligations. The weighted average incremental borrowing rate used to determine the lease obligation at adoption was approximately 5.0%. The right-of-use asset and lease obligation recognized relate to the Company's head office lease in Calgary, Alberta. The Company elected to not apply lease accounting to certain leases for which the lease term ends within 12 months of the date of initial application. The measurement of lease obligations are subject to management's judgment and the application of the incremental borrowing rate.

Of the $9.5 million operating lease commitments as at December 31, 2018, $2.2 million related to lease obligations recognized as at January 1, 2019. Non-lease components were $6.5 million and $0.8 million related to short-term and low-value leases.

4. Determination of Fair Values

A number of the Company's accounting policies and disclosures require the determination of fair value for financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the methods below. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

a) PP&E and intangible exploration assets

The fair value of PP&E and intangible exploration assets are determined if there are indicators of impairment. The fair value of PP&E is the estimated amount for which PP&E could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm's-length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The fair value of oil and natural gas assets (included in PP&E) is estimated with reference to the discounted cash flows expected to be derived from oil and natural gas production based on the reserve reports prepared by the Company's independent qualified reserve evaluators. The risk-adjusted discount rate is specific to the asset with reference to general market conditions.

b) Cash, accounts receivable, and accounts payable and accrued liabilities

The fair value of cash, accounts receivable and accounts payable and accrued liabilities is estimated as the present value of future cash flows, discounted at the market rate of interest at the reporting date. At December 31, 2020 and 2019 the fair value of these balances approximated their carrying value due to their short-term to maturity.

c) Stock options

The fair value of stock options is measured using the Black-Scholes pricing model. Measurement inputs include the share price on measurement date, exercise price of the option, expected future share price volatility, weighted average expected life of the instruments (based on historical experience and general option-holder behavior), expected dividends and the risk-free interest rate (based on Government of Canada Bonds) for the relevant expected life as described in note 15 - Share Capital.

d) Share appreciation rights

The fair value of SARs is measured using the Black-Scholes pricing model. Measurement inputs include the share price on each balance sheet date, expected future share price volatility, weighted average expected life of the instruments (based on historical experience and general SARholder behavior), expected dividends and the risk-free interest rate (based on Government of Canada Bonds) for the relevant expected life as described in note 16 - Cash Settled Incentive Plans.

e) Restricted share units, performance share units, cash settled restricted share units, cash or share settled restricted share units and performance share units and deferred share units

The fair value of stock RSUs, PSUs, CRSUs, DSUs, CosRSU and CosPSU are measured based on the market price of Parex shares on each balance sheet date. Refer to note 15 - Share Capital and note 16 - Cash Settled Incentive Plans.

f) Derivative financial asset /liability

Risk management contracts are initially recognized at fair value on the date a derivative contract is entered into and are remeasured at their fair value at each subsequent reporting date. The fair value of the risk management contract on initial recognition is normally the transaction price. Subsequent to initial recognition, the fair values are based on quoted market prices where available from active markets, otherwise fair values are estimated based on market prices at the reporting date for similar assets or liabilities with similar terms and conditions.

5. Accounts Receivable

	December 31, 2020	December 31, 2019
Trade receivables	$80,166	$143,577
Value added taxes (VAT)	—	5,933
	$80,166	$149,510

Trade receivables consist primarily of oil sale receivables related to the Company's oil sales. VAT receivable is $nil as at December 31, 2020 (December 31, 2019 - $5.9 million). All accounts receivable are expected to be received within twelve months and are thus recognized as current assets.

6. Inventory

	December 31, 2020		December 31, 2019
Crude oil inventory	$	1,915	$653

Crude oil inventory consists of crude oil in transit at the balance sheet date and is valued at the lower of cost, using the weighted average cost method, and net realizable value. Costs include direct and indirect expenditures incurred in bringing the crude oil to its existing condition and location. During 2020 $0.7 million (year ended December 31, 2019 - $1.4 million) of produced crude oil inventory cost was expensed to the consolidated statements of comprehensive income. Purchased crude oil is sold immediately. The cost associated with purchased oil is shown in the consolidated statements of comprehensive income as purchased oil expense.

7. Exploration and Evaluation Assets

Cost

Balance at December 31, 2018	$127,800
Additions	59,677
Transfers to PP&E	(25,590)
Changes in decommissioning liability	3,796
Exploration and evaluation impairment	(22,767)
Balance at December 31, 2019	$142,916
Additions	24,349
Transfers to PP&E	(82,110)
Changes in decommissioning liability	376
Exploration and evaluation impairment	(6,166)
Balance at December 31, 2020	$79,365

Additions and Transfers

E&E assets consist of the Company's exploration projects which are pending either the determination of proved or probable reserves or impairment. During the year ended December 31, 2020 additions of $24.3 million (year ended December 31, 2019 - $59.7 million) represent the Company's share of costs incurred on E&E assets during the period. During the year ended December 31, 2020 $82.1 million of E&E assets were transferred to PP&E related to the VIM-1 and Fortuna Blocks. During the year ended December 31, 2019 - $25.6 million of E&E assets were transferred to PP&E related to the Boranda Block.

2020 Impairments

During 2020, the Company completed impairment reviews of its E&E assets. It was determined that the carrying amount of certain E&E assets, primarily associated with the costs in blocks which are in the process of being relinquished, won't be recovered. The impairment review compared the carrying value of the assets to the recoverable amount which was determined to be $nil for these assets. It was determined that the impairment was $6.2 million which is recorded in the consolidated statements of comprehensive income for the year ended December 31, 2020.

2019 Impairments

During 2019, the Company completed impairment reviews of its E&E assets. It was determined that the carrying amount of certain E&E assets primarily associated with the LLA-10 block and the Morpho block wouldn't be recovered as the Company had plans to relinquish or had already relinquished the block, respectively. The impairment review compared the carrying value of the assets to the recoverable amount which was determined to be $nil for these assets. It was determined that the impairment was $22.8 million which is recorded in the consolidated statements of comprehensive income for the year ended December 31, 2019.

At December 31, 2020 and December 31, 2019 the Company did not have any E&E assets in Canada.

8. Property, Plant and Equipment

	Canada	Colombia	Total
Cost
Balance at December 31, 2018	$3,867	$2,064,880	$2,068,747
Additions	121	148,398	148,519
Right-of-use asset addition (non-cash)	2,227	—	2,227
Transfers from E&E assets	—	25,590	25,590
Changes in decommissioning and environmental liability	—	(3,077)	(3,077)
Balance at December 31, 2019	6,215	2,235,791	2,242,006
Additions	145	116,770	116,915
Right-of-use asset addition (non-cash)	1,805	—	1,805
Transfers from E&E assets	—	82,110	82,110
Changes in decommissioning and environmental liability	—	229	229
Balance at December 31, 2020	$8,165	$2,434,900	$2,443,065
Accumulated Depreciation, Depletion and AmortizationBalance at December 31, 2018	$3,678	$1,289,538	$1,293,216
Depletion and depreciation for the year	136	124,996	125,132
Depreciation - Right-of-use asset	767	—	767
DD&A included in crude oil inventory costing	—	(192)	(192)
Balance at December 31, 2019	4,581	1,414,342	1,418,923
Depletion and depreciation for the year	110	112,889	112,999
Depreciation - Right-of-use asset	759	—	759
DD&A included in crude oil inventory costing	—	485	485
Property, plant and equipment impairment	—	7,000	7,000
Balance at December 31, 2020	$5,450	$1,534,716	$1,540,166
Net book value:
As at December 31, 2018	$189	$775,342	$775,531
As at December 31, 2019	$1,634	$821,449	$823,083
As at December 31, 2020	$2,715	$900,184	$902,899

Additions and Transfers

During 2020, property, plant and equipment ("PPE") additions of $116.9 million mainly relate to drilling costs in Colombia at Blocks LLA-34, Cabrestero and Aguas Blancas and facility costs at Blocks LLA-34 and Capachos. During the year ended December 31, 2019, additions of $148.5 million mainly related to drilling costs in Colombia at Blocks LLA-34, Capachos and Aguas Blancas. For the year ended December 31, 2020, $82.1 million of E&E assets were transferred to PP&E related to the VIM-1 and Fortuna Blocks (year ended December 31, 2019 - $25.6 million E&E assets were transferred to PP&E related to the Boranda Block).

For the year ended December 31, 2020 future development costs of $422.7 million (year ended December 31, 2019 - $453.1 million) were included in the depletion calculation for development and production assets. For the year ended December 31, 2020 $7.2 million of general and administrative costs (year ended December 31, 2019 - $10.2 million) have been capitalized in respect of development and production activities during the current period.

Impairments

The carrying amounts of the Company's PP&E assets are reviewed at each reporting date to determine whether there is any indication of impairment. As a result of the COVID-19 pandemic and the drastic decrease in forecast global crude oil prices compared to those at December 31, 2019, an indication of impairment was identified for all CGUs at March 31, 2020 and impairment tests were performed. The Company determined that the carrying amount of the Boranda CGU in the Magdalena Basin exceeded its recoverable amount and an impairment of $7.0 million was recorded in the consolidated statements of comprehensive for the three month period ended March 31, 2020. All other CGU's were found to have recoverable amounts greater than carrying amounts. The recoverable amount was determined using fair value less cost of disposal. Future cash flows for the CGU's declined due to lower crude oil prices.

The fair value as determined for the Company's producing properties was consistent with the Company's independent qualified reserve evaluators reserve estimate at December 31, 2019, updated for forecast crude oil prices at March 31, 2020 and adjusting for the first quarter production and future development capital expenditures. There are no E&E assets associated with this CGU. Future cash flows were discounted using a rate of 11%. As at March 31, 2020, the recoverable amount of the CGU was estimated to be $16.5 million. A 1% change to the assumed discount rate or a 5% change in forward price estimates over the life of the reserves would have an immaterial impact on the impairment.

The fair value estimation approach used, requires assumptions about revenue, future oil prices, tax rate and discount rates, all of which are level 3 inputs. The future oil prices used in the model are based on a forecast of crude oil prices by Parex' independent reserve evaluators.

Prices used at March 31, 2020 are as follows:

	2020	2021	2022	2023	2024	Thereafter
Brent ($US/bbl)	38.64	45.50	52.50	57.50	62.50	2% increase per year
Prices used at December 31, 2019 are as follows:
	2020	2021	2022	2023	2024	Thereafter
Brent ($US/bbl)	67.00	68.00	71.00	73.00	75.00	2% increase per year

At December 31, 2020 and 2019 there were no indicators of impairment noted, or indicators requiring a reversal of previously recorded impairments.

9. Lease Obligation

The Company has the following future commitments associated with its office lease obligation:

	December 31, 2020	December 31, 2019
Balance beginning of year	$1,637$	—
Additions	—	2,227
Interest expense	54	99
Lease payments	(926)	(689)
Modifications	1,805	—
Balance end of year	2,570	1,637
Current portion of lease obligations	(750)	(867)
Non-current portion of lease obligations	$1,820$	770

During the year ended December 31, 2020, the Company has included the extension for the office lease where the Company has the right to extend the lease at its discretion and is reasonably certain to exercise the extension period.

The consolidated statements of comprehensive income for the year ended December 31, 2020 includes expenses related to leases as follows: $0.1 million (year ended December 31, 2019 - $0.1 million) of interest expense related to the lease obligation, $0.8 million (year ended December 31, 2019 - $0.8 million) of depreciation for right-of-use assets, $0.6 million (year ended December 31, 2019 - $0.6 million) of nonlease components associated with the office lease obligation and $1.7 million (year ended December 31, 2019 - $0.8 million) related to shortterm and low value leases.

Total cash outflows related to the office lease obligation were $2.2 million for the year ended December 31, 2020 (year ended December 31, 2019 - $2.1 million).

10. Goodwill

	December 31, 2020	December 31, 2019
Goodwill	$73,452	$73,452

Impairment test of goodwill

The Company performed its annual test for goodwill impairment at the balance sheet date in accordance with its policy described in note 3 - Summary of Significant Accounting Policies. The Company has allocated goodwill to the Colombia operating segment.

The estimated fair value less costs of disposal of the Colombia operating segment exceeded the carrying value. As a result, no goodwill impairment was recorded.

Valuation Techniques

The recoverable amount of the group of CGUs to which the goodwill was assigned is based on fair value less costs of disposal. The technique used in determining the recoverable amount is based on the net present value of the after-tax cash flows from oil and gas reserves of the group of CGU's based on reserves estimated by Parex' independent reserve evaluator and the fair value of undeveloped land based on estimates with consideration given to acquisition metrics of recent transactions completed on similar assets to those contained within the relevant group of CGU's. The discounting process uses a rate of return that is commensurate with the risk associated with the assets and the time value of money. This approach requires assumptions about revenue, future oil prices, tax rates and discount rates, all of which are level 3 inputs.

Significant Assumptions

Oil Reserves

Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated.

Future Oil Prices

Oil forward price estimates are used in the cash flow model. Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors. The future oil prices used in the model are based on a forecast of crude oil prices by Parex' independent reserve evaluator.

Prices used at December 31, 2020 are as follows:

	2021	2022	2023	2024	2025	Thereafter
Brent ($US/bbl)	50.75	55.00	58.50	61.79	62.95	2% increase per year
Prices used at December 31, 2019 are as follows:

2020 2021 2022 2023 2024 Thereafter Brent ($US/bbl) 67.00 68.00 71.00 73.00 75.00 2% increase per year

Discount Rate

The Company assumed a discount rate in order to calculate the present value of its projected cash flows. The discount rate represented a weighted average cost of capital ("WACC") for comparable companies operating in similar industries, based on publicly available information. The WACC is an estimate of the overall required rate of return on an investment for both debt and equity owners and serves as the basis for developing an appropriate discount rate. Its determination requires separate analysis of the cost of equity and debt, and considers a risk premium based on an assessment of risks related to the projected cash flows of the group of Colombia based CGUs whose revenues are denominated in USD. The after tax discount rate used in performing the impairment test was 12% (year ended December 31, 2019 - 11%).

The fair value of the group of Colombian CGUs was in excess of its carrying value. Based on sensitivity analysis, no reasonably possible change in discount rate assumptions would cause the carrying amount of the group of Colombia CGUs to exceed its recoverable amount.

11. Revenue

The Company's oil and natural gas production revenue is determined pursuant to the terms of the revenue agreements. The transaction price for crude oil and natural gas is based on the commodity price in the month of production, adjusted for quality, location, allowable deductions, if any, or other factors. Commodity prices are based on market indices that are determined on a monthly or daily basis.

The Company's oil and natural gas revenues by product are as follows:

For the year ended December 31,	2020	2019
Crude oil	$570,187	$1,101,060
Natural gas	17,333	12,562
Oil and natural gas sales	$587,520	$1,113,622

At December 31, 2020, receivables from contracts with customers, which are included in accounts receivable, were $80.2 million (December 31, 2019 - $143.6 million).

12. Net Finance Expense

For the year ended December 31,	2020	2019
Bank charges and credit facility fees	$2,630$	3,647
Accretion on decommissioning and environmental liabilities	4,125	4,592
Interest and other income	(2,129)	(7,382)
Right of use asset interest	54	99
Loss on settlement of decommissioning liabilities	803	359
Loss on disposition of tangible assets	1,345	235
Expected credit loss provision	1,006	—
Other	(821)	2,026
Net finance expense	$7,013$	3,576
For the year ended December 31,	2020	2019
Non-cash finance expense	$6,458$	7,212
Cash finance expense (income)	555	(3,636)
Net finance expense	$7,013$	3,576

13. Cash Settled Share-Based Compensation Liabilities

Cash settled share-based compensation liabilities are comprised of the following:

	December 31, 2020	December 31, 2019
Long-term DSUs payable	$2,988	$4,496
Long-term CRSUs payable	2,570	4,004
Long-term CosRSUs and CosPSUs payable	6,285	3,879
Total cash settled-share based compensation payable	$11,843	$12,379

14. Decommissioning and Environmental Liabilities

	Decommissioning	Environmental	Total
Balance, December 31, 2018	$42,052	$15,549	$57,601
Additions	10,524	1,355	11,879
Settlements of obligations during the year	(10,536)	(1,229)	(11,765)
Loss on settlement of obligations	359	—	359
Accretion expense	3,166	1,426	4,592
Change in estimate - inflation and discount rates	1,455	170	1,625
Change in estimate - costs	(10,253)	(2,532)	(12,785)
Foreign exchange loss (gain)	477	(48)	429
Balance, December 31, 2019	$37,244	$14,691	$51,935
Additions	2,554	480	3,034
Settlements of obligations during the year	(3,560)	(1,070)	(4,630)
Loss on settlement of obligations	803	—	803
Accretion expense	2,286	1,839	4,125
Change in estimate - inflation and discount rates	360	(2,062)	(1,702)
Change in estimate - costs	(441)	(286)	(727)
Foreign exchange (gain)	(1,036)	(691)	(1,727)
Balance, December 31, 2020	38,210	12,901	51,111
Current obligation	(3,629)	(3,425)	(7,054)
Long-term obligation	$34,581	$9,476	$44,057

The total environmental, decommissioning and restoration obligations were determined by management based on the estimated costs to settle environmental impact obligations incurred and to reclaim and abandon the wells and well sites based on contractual requirements. The obligations are expected to be funded from the Company's internal resources available at the time of settlement.

The total decommissioning and environmental liability is estimated based on the Company's net ownership in wells drilled as at December 31, 2020, the estimated costs to abandon and reclaim the wells and well sites and the estimated timing of the costs to be paid in future periods. The total undiscounted amount of cash flows required to settle the Company's decommissioning liability is approximately $60.4 million as at December 31, 2020 (December 31, 2019 – $63.3 million) with the majority of these costs anticipated to occur in 2033 or later. A risk-free discount rate of 5.25% and an inflation rate of 2.0% were used in the valuation of the liabilities (December 31, 2019 – 6.74% risk-free discount rate and a 3.1% inflation rate). The risk-free discount rate and the inflation rate used in 2020 are based on forecast Colombia rates.

Included in the decommissioning liability is $3.6 million (December 31, 2019 – $4.3 million) that is classified as a current obligation.

The total undiscounted amount of cash flows required to settle the Company's environmental liability is approximately $20.5 million as at December 31, 2020 (December 31, 2019 – $21.5 million) with the majority of these costs anticipated to occur in 2033 or later in Colombia. A risk-free discount rate of 5.25% and an inflation rate of 2.0% were used in the valuation of the liabilities (December 31, 2019 – 6.74% risk-free discount rate and a 3.1% inflation rate). The risk-free discount rate and the inflation rate used in 2020 are based on forecast Colombia rates.

Included in the environmental liability is $3.4 million (December 31, 2019 – $4.1 million) that is classified as a current obligation.

15. Share Capital

a) Issued and outstanding common shares

	Number of shares	Amount
Balance, December 31, 2018	155,013,908$	848,946
Issued for cash – exercise of options and RSUs	2,960,620	17,737
Allocation of contributed surplus – exercise of options and RSUs	—	13,772
Repurchase of shares	(14,679,474) $	(67,771)
Balance, December 31, 2019	143,295,054	812,684
Issued for cash – exercise of options, RSUs and PSUs	1,429,616	5,990
Allocation of contributed surplus – exercise of options, RSUs and PSUs	—	9,580
Repurchase of shares	(13,851,994)	(64,882)
Balance, December 31, 2020	130,872,676$	763,372

The Company has authorized an unlimited number of voting common shares without nominal or par value.

In 2020, a total of 1,429,616 options, RSUs and PSUs were exercised for proceeds of $6.0 million (year ended December 31, 2019 - 2,960,620 options and RSUs were exercised for $17.7 million).

In 2020, the Company repurchased 13,851,994 common shares pursuant to its Normal Course Issuer Bid for $171.5 million at an average cost per share of Cdn$16.62 (year ended December 31, 2019 - 14,679,474 common shares repurchased for $223.9 million at an average cost per share of Cdn$20.41). The cost to repurchase common shares at a price in excess of their average book value has been charged to retained earnings.

b) Stock options

The Company has a stock option plan which provides for the issuance of options to the Company's officers and certain employees to acquire common shares. The maximum number of options reserved for issuance under the stock option plan may not exceed 5% of the number of common shares issued and outstanding. The stock options vest over a three-year period and expire five years from the date of grant.

		Weighted average
	Number of options	exercise price Cdn$/option
Balance, December 31, 2018	4,341,747	13.14
Granted	228,300	19.23
Exercised	(2,104,304)	11.12
Balance, December 31, 2019	2,465,743	15.42
Granted	265,788	21.83
Exercised	(624,270)	12.62
Forfeited	(44,800)	11.75
Balance, December 31, 2020	2,062,461	17.17

Stock options outstanding and the weighted average remaining life of the stock options at December 31, 2020 are as follows:

		Options outstanding			Options vested
Exercise price Cdn$	Number ofoptions	Weighted averageremaining life(years)	Weightedaverageexercise priceCdn$/option	Number ofoptions	Weighted averageremaining life(years)	Weightedaverageexercise priceCdn$/option
$14.74 - $15.41	41,850	1.37	14.87	41,850	1.37	14.87
$15.42 - $15.84	861,352	0.87	15.66	861,352	0.87	15.66
$15.85 - $17.13	480,937	1.19	16.02	480,937	1.19	16.02
$17.14 - $19.81	368,172	2.64	18.63	180,776	2.44	18.60
$19.82 - $22.18	310,150	4.00	21.75	16,583	3.34	20.95
	2,062,461	1.74	17.17	1,581,498	1.18	16.14

The fair value of each option granted is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions:

For the year ended December 31,	2020	2019
Risk-free interest rate (%)	1.31	1.75
Expected life (years)	4	4
Expected volatility (%)	37	40
Forfeiture rate (%)	3	3
Expected dividends	—	—

The weighted average fair value at the grant date for the year ended December 31, 2020 was Cdn$6.67 per option (year ended December 31, 2019 – Cdn$6.42 per option). The weighted average share price on the exercise date for options exercised in 2020 was Cdn$19.23 (year ended December 31, 2019 – Cdn$21.62).

c) Restricted and performance share units

The Company has in place a restricted share unit plan pursuant to which the Company may grant restricted shares to certain employees. The restricted shares vest at 33% on each of the first, second and third anniversaries of the grant date and expire five years from date of grant.

In 2019 the Company put in place a new Cash or Share settled RSU/PSU plan ("CosRSU") which will replace this equity settled RSU/PSU plan.

	Number of RSU's	Weighted averageexercise price Cdn$/RSU
Balance, December 31, 2018	2,527,068	0.01
Exercised	(856,316)	0.01
Forfeited	(7,434)	0.01
Balance, December 31, 2019	1,663,318	0.01
Exercised	(600,416)	0.01
Forfeited	(37,543)	0.01
Balance, December 31, 2020	1,025,359	0.01

RSUs outstanding and the weighted average remaining life of the RSUs at December 31, 2020 are as follows:

	RSUs outstanding			RSUs vested
Exercise price Cdn$	Number of RSUs	Weighted averageremaining life (years)	Number of RSUs	Weighted average remaininglife (years)
0.01	1,025,359	1.43	859,199	1.30

The fair value of each RSU granted is based on the market price of Parex shares on the date of issuance. For the year ended December 31, 2020 and 2019 a weighted average forfeiture rate of 3% was applied.

Pursuant to the restricted share unit plan, the Company may grant performance share units to certain employees. The performance share units vest three years after the grant date and expire one month after the performance multiplier has been determined. PSUs may be granted with certain performance measures, specified at the grant date as determined by the Company's Board of Directors. Based upon the achievement of the performance measures, a pre-determined adjustment factor of between 0-2x is applied to PSUs eligible to vest at the end of the performance period. In March 2020 the board of directors approved a multiplier of 1.98X be applied to the 2017 PSU grant resulting in 101,430 PSU's issued.

	Number of PSU's	Weighted averageexercise price Cdn$/PSU
Balance, December 31, 2018	320,500	0.01
Balance, December 31, 2019	320,500	0.01
Granted by performance factor	101,430	0.01
Exercised	(204,930)	0.01
Balance, December 31, 2020	217,000	0.01

The fair value of each PSU granted is based on the share price at which the common shares of the Company traded for on the grant date. The weighted average fair value at the grant date for the year ended December 31, 2020 was Cdn$16.01 per PSU.

d) Equity settled share-based compensation

For the year ended December 31,	2020	2019
Option expense	$1,219$	1,867
Restricted and performance share units expense	3,016	5,736
Total equity settled share-based compensation expense	$4,235$	7,603

16. Cash Settled Incentive Plans

a) Share appreciation rights ("SARs")

Parex Colombia has a SARs plan that provides for the issuance of SARs to certain employees of Parex Colombia. The plan entitles the holders to receive a cash payment equal to the excess of the market price of the Company's common shares at the time of exercise over the grant price. At any time, if the current market price of the Company's common shares exceeds four times the grant price, Parex has the option to require the holders to exercise all vested SARs. SARs typically vest over a three-year period and expire five years from the date of grant. The SARs liability cannot be settled by the issuance of common shares.

	Number of SARs	Weighted averageexercise price Cdn$/SAR
Balance, December 31, 2018	1,591,866	13.90
Exercised	(989,225)	13.33
Forfeited	(33,869)	15.42
Balance, December 31, 2019	568,772	14.80
Exercised	(224,711)	13.33
Forfeited	(5,771)	11.22
Balance, December 31, 2020	338,290	15.84

As at December 31, 2020 338,290 SARs were vested (December 31, 2019 – 531,844 SARs were vested).

Obligations for payments of cash under the SARs plan are accrued as compensation expense over the vesting period based on the fair value of SARs, subject to appreciation limits specified in the plan. The fair value of SARs is measured using the Black-Scholes pricing model at each reporting date based on weighted average pricing assumptions noted below:

For the year ended December 31,	2020	2019
Risk-free interest rate (%)	0.20	1.71
Expected life (years)	1	1
Expected volatility (%)	55	34
Forfeiture rate (%)	3	—
Share price ($/Cdn)	17.52	24.15
Expected dividends	—	—

As at December 31, 2020, the total SARs liability accrued is $1.2 million (December 31, 2019 - $4.6 million) all of which is classified as current in accordance with the three-year vesting period.

b) Deferred share units ("DSUs")

The Company has in place a deferred share unit plan pursuant to which the Company may grant deferred shares to all non-employee directors. The deferred share units vest immediately and are settled in cash upon the retirement of the non-employee director from the Parex Board. The value of the DSUs at the exercise date is equivalent to the five day weighted average share price at which the common shares of the Company traded for immediately preceding the exercise date. DSUs can only be redeemed following retirement from the Board of Directors of the Company in accordance with the terms of the DSU Plan. The DSUs liability cannot be settled by the issuance of common shares.

	Number of DSU's	Weighted averageexercise price Cdn$/DSU
Balance, December 31, 2018	219,350	—
Granted	26,435	—
Balance, December 31, 2019	245,785	—
Granted	35,320	—
Exercised on board retirement	(63,960)	—
Balance, December 31, 2020	217,145	—

The fair value at the grant date is equivalent to the five day weighted average share price at which the common shares of the Company traded for immediately preceding the grant date. The weighted average fair value at the grant date for the year ended December 31, 2020 was Cdn$15.41 per DSU (year ended December 31, 2019 - Cdn$21.47 per DSU).

Given the DSUs vest immediately, obligations for payments of cash under the DSUs plan are accrued as compensation expense immediately based on the fair value of the DSU. As at December 31, 2020 the total DSUs liability accrued is $3.0 million (December 31, 2019 - $4.5 million) all of which is classified as long-term in accordance with the terms of the DSU plan.

c) Cash settled restricted share units ("CRSUs")

Parex Colombia has a CRSUs plan that provides for the issuance of CRSUs to certain employees of Parex Colombia. The plan entitles the holders to receive a cash payment equal to the market price of the Company's common shares at the time of exercise. CRSUs vest over a three-year period and are exercised at the vest date. The CRSUs liability cannot be settled by the issuance of common shares.

	Number of CRSUs	Weighted averageexercise price Cdn$/CRSU
Balance, December 31, 2018	785,075	—
Granted	551,020	—
Exercised	(306,251)	—
Forfeited	(38,174)	—
Balance, December 31, 2019	991,670	—
Granted	381,278	—
Exercised	(476,705)	—
Forfeited	(20,542)	—
Balance, December 31, 2020	875,701	—

The weighted average fair value at the grant date for the year ended December 31, 2020 was Cdn$21.03 per CRSU (year ended December 31, 2019 - Cdn$19.19 per CRSU).

Obligations for payments of cash under the CRSUs plan are accrued as compensation expense over the vesting period based on the fair value of CRSUs. The fair value of CRSUs is equivalent to the trading value of a common share of the Company on the valuation date. As at December 31, 2020, the total CRSUs liability accrued is $8.2 million (December 31, 2019 - $11.8 million) of which $2.6 million (December 31, 2019 - $4.0 million) is classified as long-term in accordance with the three-year vesting period.

d) Cash or share settled Restricted Share Units and Performance Share Units ("CosRSU and CosPSU")

In 2019 Parex put in place a new Cash or share settled RSU/PSU incentive plan. This new plan will replace the equity settled RSU/PSU plan. This plan provides for the issuance of RSUs and PSUs to certain employees of Parex Canada. The plan entitles the holders to receive a cash payment equal to the market price of the Company's common shares at the time of exercise or the employee can elect to receive the award in Parex common shares. CosRSUs and CosPSUs vest over a three-year period and are exercised at the vest date.

CosRSU:

	Number of CosRSUs
Balance, December 31, 2018	—
Granted	655,185
Forfeited	(6,000)
Balance, December 31, 2019	649,185
Granted	618,649
Exercised	(221,813)
Balance, December 31, 2020	1,046,021

CosPSU:

	Number of CosPSUs
Balance, December 31, 2018	—
Granted	222,100
Balance, December 31, 2019	222,100
Granted	211,600
Balance, December 31, 2020	433,700

As at December 31, 2020, no CosRSUs and CosPSUs were vested.

The weighted average fair value at the grant date for the year ended December 31, 2020 was Cdn$21.31 per CosRSU and CosPSU (year ended December 31, 2019 - Cdn $19.50 per CosRSU and CosPSU).

Obligations for payments of cash under the CosRSUs and CosPSUs plans are accrued as compensation expense over the vesting period based on the fair value of RSUs and PSUs. The fair value of CosRSUs and CosPSUs is equivalent to the trading value of a common share of the Company on the valuation date. As at December 31, 2020, the total CosRSUs and CosPSUs liability accrued is $11.3 million (December 31, 2019 - $7.1 million) of which $6.3 million (December 31, 2019 - $3.9 million) is classified as long-term in accordance with the three-year vesting period.

e) Cash settled share-based compensation

For the year ended December 31,	2020	2019
SARs (recovery) expense	$(2,149) $	1,784
CRSUs expense	813	9,460
DSUs (recovery) expense	(811)	1,748
CosRSUs and CosPSUs expense	7,422	7,089
Total cash settled-share based compensation expense	$5,275$	20,081
Cash payments made upon exercise	$12,119$	9,173

17. Income Tax

The components of tax expense for 2020 and 2019 were as follows:

For the year ended December 31,	2020	2019
Current tax expense	$20,703$	120,987
Adjustments in respect of prior period	(29)	(824)
Total current tax expense	$20,674$	120,163
Deferred tax	53,355	55,507
Total tax expense	$74,029$	175,670

Factors affecting tax expense for the year

The standard Colombian corporate income tax rate for 2020 was 32% (year ended December 31, 2019 – 33%). The following is a reconciliation of income taxes calculated at the Colombian corporate tax rate to the tax expense for 2020 and 2019:

For the year ended December 31,	2020	2019
Income before tax	$173,351$	503,664
Income before tax multiplied by the standard rate of Colombian corporate tax of 32% (2019 – 33%)	55,472	166,209
Effects of:
Income taxes recorded at rates different from the Colombian tax rate	(16,161)	(1,082)
Impact of Colombian tax rate changes	(257)	(134)
Impact of deferred tax rate changes	3,526	860
Non-deductible expense and other permanent differences	25,140	9,059
Share-based compensation	1,016	4,110
Adjustment in respect of prior period	(7,016)	(1,178)
Foreign exchange impact on tax pools denominated in foreign currency	15,130	(2,187)
Change in unrecognized deferred tax assets	(2,821)	13
Total tax expense	$74,029$	175,670

Colombian current tax rates are as follows: 32% for 2020; 31% in 2021, and 30% thereafter.

The analysis of deferred income tax assets as follows:

	December 31, 2020	December 31, 2019
Deferred tax assets to be settled within 12 months	$1,068	$1,092
Deferred tax assets to be settled after more than 12 months	41,661	88,162
Deferred income tax assets	$42,729	$89,254

The analysis of deferred income tax liabilities as follows:

	December 31, 2020	December 31, 2019
Deferred tax liabilities to be settled within 12 months	$(8,182) $	(9,556)
Deferred tax liabilities to be settled after more than 12 months	28,584	23,129
Deferred income tax liability	$20,402	$13,573
Net deferred tax liability (asset)	$(22,327) $	(75,681)

The deferred income tax liabilities and assets to be settled (recovered) within 12 months represents management's estimate of the timing of the reversal of temporary differences and does not correlate to the current income tax expense of the subsequent year.

The movement during the year in the deferred income tax (liabilities) assets and the net components is as follows:

Deferred Tax (Liability)	December 31, 2020	Charged (credited)to the statement ofcomprehensiveincome /(loss)	December 31, 2019	Charged (credited)to the statement ofcomprehensiveincome /(loss)
PP&E	$(36,457) $	(4,707) $	(31,750) $	(9,525)
Decommissioning liability	9,961	(188)	10,149	(1,399)
Cash-settled equity based compensation	2,822	(2,086)	4,908	1,510
Other	3,272	152	3,120	(2,641)
Balance, end of period	$(20,402) $	(6,829) $	(13,573) $	(12,055)

The movement during the year in the deferred income tax assets and the net components is as follows:

Deferred Tax Asset	December 31, 2020	Charged (credited)to the statement ofcomprehensiveincome /(loss)	December 31, 2019	Charged (credited)to the statement ofcomprehensiveincome /(loss)
PP&E	$33,410	$(43,840) $	77,250	$(36,307)
Loss carry forwards	3,696	(2,143)	5,839	(7,336)
Decommissioning liability	5,513	(170)	5,683	(341)
Other	110	(372)	482	532
Balance, end of period	$42,729	$(46,525) $	89,254	$(43,452)

The Company has losses as well as other cumulative tax deductions in excess of book value in Canada available to reduce future taxable income in future years. At December 31, 2020 the deferred tax asset amount recorded in Canada is $7.0 million. The Company did not recognize deferred income tax assets on capital losses and other items in Canada of $150.4 million. Non-capital losses in Canada expire in 20 years and capital losses carry-forward indefinitely. The Company does not have losses available in Colombia. Amounts denominated in foreign currency have been translated at the December 31, 2020 exchange rate. At December 31, 2020 the Company had the following losses carryforward:

	Canada
Year of expiry
2033	$3,554
2034	2,365
2035	9,344
2036	808
Indefinitely	167,116
	$183,187

Earnings retained by subsidiaries amounted to $706.7 million at December 31, 2020 (December 31, 2019 - $772.3 million). No provision has been made for withholding and other taxes that would become payable on the distribution of these earnings as it is not expected that they will be remitted in the foreseeable future.

18. Net income per Share

a) Basic net income per share

For the year ended December 31,	2020	2019
Net income
Net income for the purpose of basic net income per share	$99,322	$327,994
Weighted average number of shares for the purposes of basic net income per share (000's)	138,356	146,380
Basic net income per share	$0.72	$2.24
b) Diluted net income per shareFor the year ended December 31,	2020	2019
Net income
Net income used to calculate diluted net income per share	$99,322	$327,994
Weighted average number of shares for the purposes of basic net income per share (000's)Dilutive effect of share options and RSUs on potential common shares	138,3561,263	146,3802,645
Weighted average number of shares for the purposes of diluted net income per share	139,619	149,025
Diluted net income per share	$0.71	$2.20

For the year ended December 31, 2020, 678,322 stock options (December 31, 2019 - 228,300) were excluded from the diluted weighted average shares calculation as they were anti-dilutive.

19. Supplemental Disclosure of Cash Flow Information

a) Net change in non-cash working capital

For the year ended December 31,	2020	2019
Accounts receivable	$69,344	$(86,151)
Prepaids and other current assets	(5,094)	(3,428)
Crude oil inventory	(1,262)	793
Accounts payable and accrued liabilities	(106,446)	(119,259)
Depletion related to crude oil inventory	485	(192)
Decommissioning and environmental liabilities	(4,630)	(11,765)
Net change in non-cash working capital	$(47,603) $	(220,002)
OperatingInvestingFinancing	$(7,023) $(38,534)(2,046)	(205,413)(10,796)(3,793)
Net change in non-cash working capital	$(47,603) $	(220,002)

b) Interest and taxes paid

For the year ended December 31,	2020	2019
Cash interest paid	$—	$—
Cash income taxes paid	$45,008	$136,251

20. Employee Salaries and Benefit Expenses

For the year ended December 31,	2020	2019
Salaries, bonuses and other short-term benefits	$29,709	$30,961
Equity settled share-based compensation	4,235	7,603
Cash settled share-based compensation	5,275	20,081
	$39,219	$58,645

Employee salaries, bonuses and short-term benefits are included in general and administrative expenses in the consolidated statement of comprehensive income. Stock option, SARs, RSUs, PSUs, CosRSUs, CosPSUs and DSUs expense are included in share-based compensation expense in the consolidated statements of comprehensive income.

21. Capital Management

The Company's strategy is to maintain a strong capital base in order to provide flexibility in the future development of the business and maintain the confidence of investors and capital markets.

Parex has a senior secured credit facility which at December 31, 2020 had a borrowing base in the amount of $200.0 million (December 31, 2019 - $200.0 million). The credit facility is intended to serve as means to increase liquidity and fund cash or letter of credit needs as they arise. As at December 31, 2020, $nil (December 31, 2019 - $nil) was drawn on the credit facility.

The Company has also provided a general security agreement to Export Development Canada ("EDC") in connection with the performance security guarantees that support letters of credit provided to the Colombian National Hydrocarbon Agency ("ANH") related to the exploration work commitments on its Colombian concessions (see note 24 - Commitments). This performance guarantee facility has a limit of $150.0 million (December 31, 2019 - limit of $150.0 million) of which $21.9 million (December 31, 2019 - $25.4 million) is utilized at December 31, 2020. At December 31, 2020, there is an additional $24.5 million (December 31, 2019 - $22.5 million) of letters of credit that are provided by a Latin American bank on an unsecured basis.

As at December 31, 2020 the Company's net working capital surplus was $320.2 million (December 31, 2019 - $344.0 million), of which $330.6 million is cash.

On December 21, 2020, the Toronto Stock Exchange ("TSX") approved the Company's NCIB application to purchase up to 12,868,562 of the Company's common shares for cancellation between the periods of December 23, 2020 and December 22, 2021.

On December 19, 2019 the Toronto Stock Exchange ("TSX") approved the Company's NCIB application to purchase up to 13,986,994 of the Company's common shares for cancellation and the Company repurchased the maximum amount of shares in the period between December 23, 2019 and December 22, 2020.

Parex has the ability to adjust its capital structure by issuing new equity or debt and making adjustments to its capital expenditure and share buy-back programs to the extent the capital expenditures are not committed. The Company considers its capital structure at this time to include shareholders' equity, the credit facility and its working capital. As at December 31, 2020 shareholders' equity was $1,340.5 million (December 31, 2019 - $1,402.4 million).

22. Financial Instruments and Risk Management

The Company's non-derivative financial instruments recognized on the consolidated balance sheet consist of cash, accounts receivable, accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair value. The fair values of the current financial instruments approximate their carrying value due to their short-term maturity. The fair value of the revolving credit facility is equal to its carrying amount as the facility bears interest at floating rates and the credit spreads within the facility are indicative of market rates.

Long-term financial instruments of the Company carried on the consolidated balance sheet are carried at amortized cost. Financial derivative instruments, specifically fixed price contracts, are carried at fair value. There are no significant differences between the carrying amount of derivative financial instruments and their estimated fair values as at December 31, 2020.

The fair value of the Company's financial derivative instruments are quoted in active markets. The Company classifies the fair value of these transactions according to the following hierarchy.

Level 1 – quoted prices in active markets for identical financial instruments.

Level 2 – quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 3 – valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.

The Company's financial derivative instruments have been classified as level 2 based on the fair value hierarchy described above. The Company used the following techniques to determine the fair value measurements: Crude oil and foreign currency contracts are recorded at their estimated fair value based on the difference between the contracted price and the period end forward price for the same commodity and foreign currency, using quoted market prices or the period end forward price for the same commodity and foreign currency, extrapolated to the end of the contract term.

a) Credit risk

Credit risk is the risk of loss associated with the inability of a third party to fulfill its payment obligations. The Company is exposed to the risk that third parties that owe it money do not meet their obligations. The Company assesses the financial strength of its joint venture partners and oil marketing counterparties in its management of credit exposure.

The Company for the year ended December 31, 2020 had the majority of its oil sales to 10 counterparties. Accounts receivable balance as at December 31, 2020 are substantially made up of receivables with customers in the oil and gas industry and are subject to normal industry credit risks. The Company historically has not experienced any collection issues with its crude oil customers. At December 31, 2020 there are no accounts receivable past due (December 31, 2019 - $nil).

As at December 31, 2020 and 2019 the Company's accounts receivable are aged as follows:

For the year ended December 31,	2020	2019
Current (less than 90 days)	$80,166	$149,510
Past due (more than 90 days)	—	—
Total	$80,166	$149,510

None of the Company's receivables are impaired at December 31, 2020. The maximum credit risk exposure associated with accounts receivable is the total carrying value.

b) Liquidity risk

The Company's approach to managing liquidity risk is to have sufficient cash and/or credit facilities to meet its obligations when due. Management typically forecasts cash flows for a period of 12 to 36 months to identify any financing requirements. Liquidity is managed through daily and longer-term cash, debt and equity management strategies. These include estimating future cash generated from operations based on reasonable production and pricing assumptions, estimating future discretionary and non-discretionary capital expenditures and assessing the amount of equity or debt financing available. The Company is committed to maintaining a strong balance sheet and has the ability to change its capital program based on expected operating cash flows. The balance drawn on the Company's $200.0 million credit facility at December 31, 2020 was $nil.

The following are the contractual maturities of financial liabilities at December 31, 2020:

	Less than 1year	2-3 Years	4-5 Years	Thereafter	Total
Accounts payable and accrued liabilities	$102,815	—	—	—	$102,815
Lease obligation	750	1,820	—	—	2,570
Cash settled equity plans payable	11,862	11,843	—	—	23,705
Total	$ 115,427	13,663	—	—	$ 129,090

The following are the contractual maturities of financial liabilities at December 31, 2019:

	Less than 1year	2-3 Years	4-5 Years	Thereafter	Total
Accounts payable and accrued liabilities	$125,282	—	—	—$	125,282
Current income tax payable	61,763	—	—	—	61,763
Lease obligation	867	770	—	—	1,637
Cash settled equity plans payable	15,567	12,379	—	—	27,946
Total	$203,479	13,149	—	—$	216,628

c) Commodity price risk

The Company is exposed to commodity price movements as part of its operations, particularly in relation to the prices received for its oil production. Crude oil is sensitive to numerous worldwide factors, many of which are beyond the Company's control. Changes in global supply and demand fundamentals in the crude oil market and geopolitical events can significantly affect crude oil prices. Consequently, these changes could also affect the value of the Company's properties, the level of spending for exploration and development and the ability to meet obligations as they come due. The Company's oil production is sold under short-term contracts, exposing it to the risk of near-term price movements.

As at December 31, 2020 the Company had no outstanding commodity price risk management contracts.

The table below summarizes the loss on the commodity risk management contracts that were in place during the year ended December 31, 2020 and 2019:

For the year ended December 31,	2020	2019
Realized loss on commodity risk management contracts	$3,940$	—
Total	$3,940$	—

d) Foreign currency risk

The Company is exposed to foreign currency risk as various portions of its cash balances are held in Canadian dollars (Cdn$) and Colombian pesos (COP$) while its committed capital expenditures are expected to be primarily denominated in US dollars.

As at December 31, 2020 the Company had no outstanding foreign currency risk management contracts.

The table below summarizes the loss (gain) on the foreign currency risk management contracts that were in place during the year ended December 31, 2020 and 2019:

For the year ended December 31,	2020	2019
Premiums paid on foreign currency risk management contracts	$—	$389
Unrealized (gain) on foreign currency risk management contracts	—	(8,591)
Realized loss on foreign currency risk management contracts	511	4,469
Total	$511	$(3,733)

The Company recorded a realized $0.5 million loss on these contracts in the year ended December 31, 2020 which is recorded in the financial statement line item "Foreign exchange (gain) loss in the consolidated statements of comprehensive income. The Company recorded an $8.6 million unrealized gain and $4.9 million loss realized on these contracts in the year ended December 31, 2019 which is recorded in the financial statement line item "Foreign exchange (gain) loss".

23. Segmented Information

The Company has foreign subsidiaries and the following segmented information is provided:

For the year ended December 31, 2020	Canada	Colombia	Total
Oil and natural gas sales	$—	$587,520	$587,520
Royalties	—	(55,655)	(55,655)
Revenue	—	531,865	531,865
Commodity risk management contracts (loss)	—	(3,940)	(3,940)
	—	527,925	527,925
Expenses
Production	—	87,272	87,272
Transportation	—	59,147	59,147
Purchased oil	—	28,241	28,241
General and administrative	17,496	18,562	36,058
Impairment of property, plant and equipment assets	—	7,000	7,000
Impairment of exploration and evaluation assets	—	6,166	6,166
Equity settled share-based compensation expense	4,235	—	4,235
Cash settled share-based compensation expense (recovery)	6,611	(1,336)	5,275
Depletion, depreciation and amortization	869	112,889	113,758
Foreign exchange loss (gain)	957	(548)	409
	30,168	317,393	347,561
Finance (income)	(544)	(1,585)	(2,129)
Finance expense	1,499	7,643	9,142
Net finance expense	955	6,058	7,013
Income (loss) before taxes	(31,123)	204,474	173,351
Current tax expense	2	20,672	20,674
Deferred tax expense (recovery)	(552)	53,907	53,355
Net income (loss)	$(30,573) $	129,895	$99,322
Capital assets (end of year)	$2,715	$979,549	$982,264
Capital expenditures	$145	$141,119	$141,264
Total assets (end of year)	$167,415	$1,373,666	$1,541,081

For the year ended December 31, 2019	Canada	Colombia	Total
Oil and natural gas sales	$—	$1,113,622	$1,113,622
Royalties	—	(136,068)	(136,068)
Revenue	—	977,554	977,554
Expenses
Production	—	111,061	111,061
Transportation	—	88,974	88,974
Purchased oil	—	52,791	52,791
General and administrative	18,706	15,508	34,214
Impairment of exploration and evaluation assets	—	22,767	22,767
Equity settled share-based compensation expense	7,603	—	7,603
Cash settled share-based compensation expense	8,837	11,244	20,081
Depletion, depreciation and amortization	903	124,996	125,899
Foreign exchange loss (gain)	(290)	7,214	6,924
	35,759	434,555	470,314
Finance (income)	(4,228)	(3,154)	(7,382)
Finance expense	1,699	9,259	10,958
Net finance expense (income)	(2,529)	6,105	3,576
Income (loss) before taxes	(33,230)	536,894	503,664
Current tax expense	2,397	117,766	120,163
Deferred tax expense	5,139	50,368	55,507
Net income (loss)	$(40,766) $	368,760	$327,994
Capital assets (end of year)	$1,634	$964,365	$965,999
Capital expenditures	$121	$208,075	$208,196
Total assets (end of year)	$151,514	$1,533,067	$1,684,581

In Colombia in the year 2020 the majority of oil sales were with ten counterparties (year ended December 31, 2019 – ten counterparties) in the oil and gas industry and are subject to normal industry credit risks.

24. Commitments and Contingencies

a) Colombia

At December 31, 2020 performance guarantees are in place with the ANH for certain blocks. The guarantees are in the form of issued letters of credit totaling $46.4 million (December 31, 2019 - $47.9 million) to support the exploration work commitments in respect of the 24 blocks in Colombia.

At December 31, 2020 EDC has provided the Company's bank with performance security guarantees to support approximately $21.9 million (December 31, 2019 - $25.4 million) of the letters of credit issued on behalf of Parex. The EDC guarantees have been secured by a general security agreement issued by Parex in favour of EDC. The letters of credit issued to the ANH are reduced from time to time to reflect completed work on an ongoing basis. At December 31, 2020, there are an additional $24.5 million (December 31, 2019 - $22.5 million) letters of credit that are provided by a Latin American bank on an unsecured basis.

The value of the Company's exploration commitments as at December 31, 2020 in respect of the Colombia blocks are estimated to be as follows:

(000s)
2021	$37,507
2022	5,425
2023	37,385
Thereafter	89,091
	$169,408

b) Operating leases

In the normal course of business, Parex has entered into arrangements and incurred obligations that will impact the Company's future operations and liquidity. These commitments include leases for office space and accommodations.

The existing minimum lease payments for office space and accommodations at December 31, 2020 are as follows:

(000s)	Total	2021	2022	2023	2024	Thereafter
Office and accommodations	$7,512	2,750	1,613	1,629	1,520	—

25. Related Party Disclosures

a) Significant Subsidiaries

The consolidated financial statements include the financial statements of Parex Resources Inc. at December 31, 2020 and 2019. Transactions between subsidiaries are eliminated upon consolidation.

b) Compensation of Key Management Personnel

Key management personnel compensation, including directors, is as follows:

For the year ended December 31,	2020	2019
Salaries, directors' fees and other benefits	$4,515$	4,241
Equity settled share-based compensation	1,613	3,714
Cash settled share-based compensation	1,451	4,934
	$7,579$	12,889

At December 31, 2020 key management personnel are comprised of the Company's directors and eight executives. As at December 31, 2020, there is a Cdn$9.1 million commitment relating to change of control or termination of employment of the eight executives (December 31, 2019 - Cdn$8.9 million for the seven executives).

c) Other transactions

The Company did not have any related party transactions with entities outside the consolidated group for the years ended December 31, 2020 and 2019.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of Parex Resources Inc. ("Parex" or the "Company") for the three months and year ended December 31, 2020 and 2019 is dated March 3, 2021 and should be read in conjunction with the audited consolidated financial statements for the years ended December 31, 2020 and 2019. The audited consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS" or "GAAP") as issued by the International Accounting Standards Board.

Additional information related to Parex and factors that could affect the Company's operations and financial results, including disclosure of production and sales volumes by product type, are included in reports on file with Canadian securities regulatory authorities, including the Company's Annual Information Form dated March 3, 2021 (the "AIF"), and may be accessed through the SEDAR website at www.sedar.com.

All financial amounts are in United States (US) dollars unless otherwise stated.

Company Profile

Parex is an oil and gas company actively engaged in crude oil exploration, development and production in Colombia. Headquartered in Calgary, Canada, Parex, through its foreign subsidiaries, holds interests in onshore exploration and production blocks. The common shares of the Company trade on the Toronto Stock Exchange ("TSX") under the symbol PXT.

Abbreviations

Refer to the final page of the MD&A for commonly used abbreviations in the document. Refer to the Advisory on Forward-Looking Statements and Non-GAAP Terms used.

2020 Highlights

• Annual oil and natural gas production in 2020 averaged 46,518 barrels of oil equivalent per day ("boe/d") (97% crude oil), a decrease of 12% over 2019 average production of 52,687 boe/d (98% crude oil)) or 6% on a production per basic share basis as a result of the Company reducing production volumes in the low oil price environment. Refer to "Consolidated Results of Operations" for annual production by product type;
• Recognized net income of $99.3 million ($0.72 per share basic) for the year ended December 31, 2020 compared to net income of $328.0 million ($2.24 per share basic) for the year ended December 31, 2019;
• Generated an operating netback of $20.84/boe (2019 $37.51/boe) and funds flow provided by operations ("FFO") netback of $17.52/boe (2019 - $29.61/boe) from an average Brent price of $43.30/bbl (2019 - $64.21/bbl);
• Funds flow provided by operations was $297.0 million ($2.15 per share basic), a 48% decrease from the year ended December 31, 2019 of $570.5 million ($3.90 per share basic); FFO was lower in 2020 due to lower sales volumes and lower Brent oil prices compared to 2019;
• Utilized free funds flow of $155.8 million to purchase and cancel 13,851,994 of the Company's common shares for a total cost of $171.5 million at an average price of CAD $16.62 pursuant to the Company's normal course issuer bid program ("NCIB");
• Capital expenditures for the year ended December 31, 2020 were $141.3 million compared to $208.2 million for the year ended December 31, 2019. Capital expenditures were fully funded from FFO;
• Working capital was $320.2 million at December 31, 2020 compared to $344.0 million at December 31, 2019. In addition, the Company has an undrawn syndicated bank credit facility of $200.0 million; and
• Participated in drilling 30 gross (19.45 net) wells in Colombia resulting in 25 oil wells, 2 abandoned wells, 2 wells under test and 1 pressure maintenance well, for a success rate of 93%, compared to 43 gross (26.95 net) wells in the comparative period of 2019.

Three Months Ended December 31, 2020 ("fourth quarter" or "Q4") Highlights

• Fourth quarter oil and natural gas production was 46,642 boe/d (96% crude oil), a decrease of 14% over the fourth quarter of 2019 (8% decrease on a per basic share basis), a 5% increase over the previous quarter ended September 30, 2020 (9% increase on a per basic share basis), and comparable to the 2020 average oil and natural gas production. Refer to "Consolidated Results of Operations" for annual production by product type;
• Recognized net income of $56.2 million ($0.42 per share basic) compared to net income of $27.6 million in the previous quarter ended September 30, 2020 and net income of $87.2 million ($0.61 per share basic) in Q4 2019.
• Generated an operating netback of $24.76/boe (2019 $36.43/boe) and a funds flow provided by operations ("FFO") netback of $19.06/boe (2019 - $27.89/boe) from an average Brent price of $45.26/bbl (2019 - $62.49/bbl);
• Funds flow provided by operations was $81.6 million ($0.61 per share basic) a 43% decrease compared to $143.3 million ($1.00 per share basic) in Q4 2019; FFO was reduced due to lower sales volumes and lower Brent oil prices;
• Utilized free funds flow of $34.6 million to purchase and cancel 6,606,994 of the Company's common shares for a total cost of $77.2 million (average price of CAD $15.77) pursuant to the Company's NCIB;
• Capital expenditures were $46.9 million in the period compared to $58.3 million in the comparative period of 2019. The fourth quarter capital expenditure program included $41.1 million for drilling and completion;
• Working capital was $320.2 million at December 31, 2020 compared to $370.7 million at September 30, 2020 and $344.0 million at December 31, 2019; and
• Participated in drilling 8 gross (4.85 net) wells in Colombia resulting in 8 oil wells, for a success rate of 100% in Q4 2020 compared to 22 gross (14.60 net) wells in the preceding nine months of 2020 and 15 gross (9.25 net) wells in the fourth quarter of 2019.

Financial Summary

	For the three months endedDecember 31,		For the year ended
(Financial figures in $000s except per share amounts)	2020	2019	2020	2019	2018
Light Crude and Medium Crude Oil (bbl/d)	6,637	8,346	6,021	7,214	4,668
Heavy Crude Oil (bbl/d)	38,332	44,740	39,197	44,494	39,120
Average daily oil production (bbl/d)(1)	44,969	53,086	45,218	51,708	43,788
Average daily conventional natural gas production (mcf/d)(1)	10,038	6,810	7,800	5,874	3,720
Average oil and natural gas production (boe/d)	46,642	54,221	46,518	52,687	44,408
Production split (% crude oil)	96	98	97	98	99
Realized sales price ($/boe)	36.95	53.00	32.55	54.70	58.64
Operating netback ($/boe)(2)	24.76	36.43	20.84	37.51	41.44
Oil and natural gas sales	167,264	289,585	587,520	1,113,622	965,723
Funds flow provided by operations(2)(5)	81,567	143,269	297,041	570,480	400,627
Per share – basic	0.61	1.00	2.15	3.90	2.58
Per share – diluted(2)	0.60	0.98	2.13	3.83	2.51
Net income	56,192	87,218	99,322	327,994	402,904
Per share – basic	0.42	0.61	0.72	2.24	2.59
Per share – diluted	0.42	0.60	0.71	2.20	2.53
Capital expenditures	46,932	58,321	141,264	208,196	302,343
Free funds flow (2)	34,635	84,948	155,777	362,284	98,284
Total assets (end of period)	1,541,081	1,684,581	1,541,081	1,684,581	1,642,120
Working capital surplus (end of period)(3)	320,155	344,031	320,155	344,031	218,526
Bank debt (end of period)(4)	—	—	—	—	—
Weighted average shares outstanding (000s)
Basic	133,812	142,967	138,356	146,380	155,417
Diluted	135,184	145,565	139,619	149,025	159,562
Outstanding shares (end of period) (000s)	130,873	143,295	130,873	143,295	155,014

(1) Reference to crude oil or natural gas production in the above table and elsewhere in this MD&A refer to the light and medium crude oil and heavy crude oil and conventional natural gas, respectively, product types as defined in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities.

(2) Non-GAAP terms. Refer to "Non-GAAP Terms".

(3) Working capital calculation does not take into consideration the undrawn amount available under the syndicated bank credit facility.

(4) Syndicated bank credit facility borrowing base of $200.0 million as at December 31, 2020, $200.0 million at December 31, 2019.

(5) In the second quarter of 2019, Parex changed the way it calculates and presents funds flow from operations. For further details refer to the "Non-GAAP Terms". Comparative periods have also been adjusted for this change. For the year ended December 31, 2018, funds flow provided by operations includes a $137.5 million ($0.88 per share basic) charge for a voluntary tax restructuring.

Guidance

The table below is a summary of Parex' 2020 actual results and 2021 guidance:

		2020 Actuals 2021 Guidance(5)
Brent crude average ($/bbl)(2)	43	45
Production (average for period) (boe/d)	46,518	47,000-49,000
Total Capex ($ millions)	141	165-185
Funds flow provided by operations (FFO)(1) ($ millions)	297	320-340
Free funds flow (FFO less total capex mid-points)(1) ($ millions)	156	155
Share buy-back program(3)(5) ($ millions)	172	150
Outstanding shares (end of period)(3) (millions)	131	118-120
Production per share growth %	(6)%	14%
Estimated working capital (end of period) ($ millions)	320	335
Bank debt outstanding (end of period) ($ millions)	—	—
Operating netback ($/boe)(1)(2)	21	23
Funds Flow provided by Operations (FFO) netback(1)(2) ($/boe)	18	19
Current tax effective rate on FFO (%)(4)	7%	8%

(1) The table above contains Non-GAAP measures. Refer to "Non-GAAP Terms".

(2) 2021 Guidance assumes Brent/Vasconia crude differential less than $3.75/bbl under $45/bbl Brent pricing scenario.

(3) It is expected free funds flow will be used to fund purchases under the Company's 2021 NCIB and assumes an average share price of CAD $15/share under $45/

bbl Brent pricing scenario.

(4) Effective tax rate is the expected tax rate on funds flow provided by operations.

(5) 2021 Guidance is as released November 2020 and is using USD-CAD exchange rate of 1.31.

Parex' 2020 financial and operational results were below guidance released in November 2019, as a result of the Company voluntarily curtailing production in late first quarter of 2020 in response to the significant decline in world oil prices, reducing the 2020 capital expenditure program by 37%, and the ongoing uncertainty in market conditions resulting from the COVID-19 pandemic. In the third quarter of 2020 the Company began bringing back additional production from previously shut-in or curtailed fields.

The Company expects Q1 2021 average production to be approximately 46,500-47,500 boe/d.

Parex is entering 2021 in a strong operational and financial position. In 2021, the Company expects to purchase the maximum number of shares under its NCIB and fund its planned capital expenditures with funds flow provided by operations, and if appropriate potentially utilizing a portion of cash reserves. Parex does not currently have any commodity price hedging positions active for 2021.

Financial and Operational Results

Consolidated Results of Operations

Parex' oil and gas operations are conducted in Colombia with head office functions conducted in Canada.

	For the three months endedDecember 31,			For the year endedDecember 31,
	2020		2019	2020	2019
Average daily production
Light Crude and Medium Crude Oil (bbl/d)	6,637		8,346	6,021	7,214
Heavy Crude Oil (bbl/d)	38,332		44,740	39,197	44,494
Crude oil (bbl/d)	44,969		53,086	45,218	51,708
Conventional Natural Gas (mcf/d)	10,038		6,810	7,800	5,874
Total (boe/d)	46,642		54,221	46,518	52,687
Production split (% crude oil production)	96		98	97	98
Average daily sales of oil and natural gas
Produced crude oil (bbl/d)	44,845		54,696	45,022	51,799
Purchased crude oil (bbl/d)	2,688		3,561	3,000	2,991
Produced natural gas (mcf/d)	10,038		6,810	7,800	5,874
Total (boe/d)	49,206		59,392	49,322	55,769
Operating netback (000s)(1)
Oil and natural gas sales	$167,264	$	289,585	$587,520	$1,113,622
Royalties	(13,642)		(36,717)	(55,655)	(136,068)
Net revenue	153,622		252,868	531,865	977,554
Production expense	(22,499)		(29,183)	(87,272)	(111,061)
Transportation expense	(16,938)		(20,462)	(59,147)	(88,974)
Purchased oil expense	(7,536)		(16,154)	(28,241)	(52,791)
Operating netback	$106,649	$	187,069	$357,205	$724,728
Operating netback (per boe) (1)
Oil and natural gas sales	$36.95	$	53.00	$32.55	$54.70
Royalties	(3.19)		(7.15)	(3.28)	(7.06)
Net revenue	33.76		45.85	29.27	47.64
Production expense	(5.26)		(5.68)	(5.15)	(5.76)
Transportation expense	(3.74)		(3.74)	(3.28)	(4.37)
Operating netback	$24.76	$	36.43	$20.84	$37.51

(1) Refer to "Non-GAAP Terms" for a description and details of the operating netback calculation.

Overall, the Company's benchmark Brent price decreased by $17.23/bbl, while revenue decreased by $16.05/boe in the fourth quarter of 2020 as compared to the fourth quarter of 2019. The price improvement relative to the Brent crude benchmark decrease is mainly a result of stronger Vasconia pricing (narrowing differential to Brent oil price), partially offset by an increase in wellhead sales as compared to the comparative period. Royalties decreased by $3.96/boe as a result of lower crude prices in the quarter. Production costs decreased by $0.42/ boe mainly as a result of the depreciation of the Colombian peso and the shut-in of higher cost smaller oil fields in Q2 2020.

Overall, the operating netback decreased by $11.67/boe vs a Brent benchmark crude decrease of $17.23/bbl.

Change in Operating Netback by Component Q3/20 vs. Q4/20

Overall, the Company's benchmark Brent price increased by $1.92/bbl, while revenue increased by $3.07/boe in the fourth quarter of 2020 as compared to the third quarter of 2020. The increase in revenue relative to the Brent crude benchmark increase is mainly a result of stronger Vasconia pricing and decreased wellhead sales in the quarter as compared to the comparative period. Royalties increased by $0.22/boe as a result of higher crude oil benchmark prices in the quarter. Production costs increased by $0.26/boe related to the appreciation of the Colombian peso compared to the comparative period. Transportation costs increased by $0.93/boe as a result of decreased wellhead sales in the quarter and the additional direct export oil cargo sales.

Overall, the operating netback increased by $1.66/boe vs a Brent benchmark crude increase of $1.92/bbl.

Oil and Natural gas Sales

a) Average Daily Production and Sales Volumes (boe/d)

	For the three monthsended December 31,	For the year endedDecember 31,
	2020	2019	2020	2019
Block LLA-34 (Tigana, Jacana and Tua fields)	31,483	40,186	33,917	38,549
Block Cabrestero (Bacano and Akira fields)	6,158	5,739	4,902	6,032
Capachos block (Capachos and Andina fields)	3,654	2,947	3,274	2,440
Block LLA-26 (Rumba field)	1,258	1,468	1,132	1,626
Block LLA-32 (Kananaskis, Calona, Carmentea and Azogue fields)	1,097	1,093	1,142	1,389
Other blocks	1,319	1,653	851	1,672
Total Crude Oil Production	44,969	53,086	45,218	51,708
Natural gas production	1,673	1,135	1,300	979
Total crude oil and natural gas production	46,642	54,221	46,518	52,687
Crude oil inventory (build) draw	(124)	1,610	(196)	91
Average daily sales of produced oil and natural gas	46,518	55,831	46,322	52,778
Purchased oil	2,688	3,561	3,000	2,991
Sales Volumes	49,206	59,392	49,322	55,769

Oil and natural gas production for the fourth quarter of 2020 averaged 46,642 boe/d, a 14% decrease from the fourth quarter of 2019 and an increase of approximately 5% from the third quarter of 2020 as development drilling was commenced in late Q2 and Q3. Further, in the third quarter of 2020 the Company began bringing back additional production from previously shut-in or curtailed fields.

Oil and natural gas sales in the fourth quarter 2020 were 49,206 boe/d compared to 59,392 boe/d for the fourth quarter of 2019. The decrease in oil sales volumes was a result of the decrease in oil production and purchased oil purchases/sales over the comparative period.

Production

Production By Area (Three Months ended December 31,2020)

b) Crude Oil Reference and Realized Prices

	For the three months endedDecember 31,	For the year endedDecember 31,
	2020	2019	2020	2019
Reference Prices
Brent ($/bbl)	45.26	62.49	43.30	64.21
Vasconia ($/bbl)	42.69	58.50	38.90	60.89
WTI ($/bbl)	42.63	56.94	39.44	57.05
Average Realized Prices
Realized sales price ($/boe)	36.95	53.00	32.55	54.70
Realized price (differential) to Brent crude ($/boe)	(8.31)	(9.49)	(10.75)	(9.51)

During Q4 2020, the differential between Brent reference pricing and the Company's realized sale price was $8.31/boe. The differential to Brent crude during Q4 2020 decreased by $1.15/boe compared to the third quarter of 2020 where the differential was $9.46/boe (see below).

The table below provides a quarter-by-quarter view of Parex' historical pricing in Colombia:

Average price for the period	Q4 2020	Q3 2020	Q2 2020	Q1 2020	Q4 2019
Brent ($/bbl)	45.26	43.34	33.39	51.05	62.49
Vasconia ($/bbl)	42.69	40.35	26.70	45.97	58.50
Brent/Vasconia crude (differential) ($/bbl)	(2.57)	(2.99)	(6.69)	(5.08)	(3.99)
Parex quality differential ($/bbl)	(0.15)	(0.35)	(0.44)	(0.18)	(0.72)
Parex wellhead and cargo export sales discount ($/bbl)	(5.59)	(6.12)	(7.01)	(7.32)	(4.78)
Parex realized sales price ($/boe)	36.95		33.88 52.33 19.25		38.47 59.92 53.00
Parex realized price (differential) to Brent crude ($/boe)	(8.31)	(9.46)	(14.14)	(12.58)	(9.49)
Parex transportation expense ($/boe)(1)	(3.74)	(2.81)	(2.33)	(4.04)	(3.74)
Parex price differential and transportation expense ($/boe)	(12.05)	(12.27)	(16.47)	(16.62)	(13.23)

(1) See Transportation section below.

Differences between Parex' realized price and Vasconia crude price is mainly related to quality adjustments, wellhead sale marketing contracts, and timing of oil sales compared to quarter averages. The differential between Vasconia crude pricing and Brent crude pricing also affects Parex' realized sales price and is set in liquid global markets and therefore attributed to factors that are beyond the Company's control. The significant decrease in global crude oil prices beginning in March 2020 widened the Brent/Vasconia differential to as high as $10/bbl in April and May 2020. In the fourth quarter of 2020 the Vasconia differential improved to $2.57/bbl average for Q4 2020 vs $6.69 in Q2 2020. Parex' Colombian oil production is fully exposed to swings in the Vasconia differential to Brent.

Parex realized price differential to Brent and Vasconia crudes can fluctuate period over period due to, among other factors, the type of sales contract and the accounting treatment for oil sold at the wellhead versus a direct export sales contract.

In 2019 the combined price differential and transportation expense had trended downward due to the shrinking of Vasconia crude differential and the depreciation of the Colombian peso, however in the fourth quarter of 2019 this differential began to widen. In the second quarter of 2020, this differential widened further by approximately $2.70/boe compared to the fourth quarter of 2019 and the price differential plus transportation expense increased by $3.24/boe mainly as a result the dramatic decrease in world oil prices beginning in March 2020 as a result of the COVID-19 pandemic. During the third and fourth quarters of 2020, the differential improved dramatically compared to the first two quarters of 2020. This improvement was due to a reduction of global heavy crude differentials which the Company realized through the sale of its Vasconia blended crude.

Parex' combined transportation costs plus Brent price differential has been trending lower since 2019, except for the period of the COVID-19 pandemic oil price shock in Q1 & Q2 2020. This improvement is primarily the result of an improvement of global heavy crude differentials and Colombia's location allowing Parex crude oil access to all the major global crude oil buying markets.

Brent Realized Price Differential & Transportation Expense

c) Natural Gas Revenue and Realized Prices

	For the three monthsended December 31,		For the year endedDecember 31,
	2020	2019	2020	2019
Natural gas revenue ($000s)	$ 5,392	3,361	$ 17,333	12,562
Realized sales price ($/Mcf)	5.84	5.36	6.07	5.86

Parex natural gas revenues were $5.4 million and $17.3 million for the three months and year ended 2020 compared to $3.4 million and $12.6 million in the same period of 2019. The increase in natural gas sales from the prior periods is related to increased natural gas volumes sold from Block LLA-32 and the Capachos block. At the Capachos block, Parex completed a gas processing facility and a related natural gas in-field flowline.

d) Oil and Natural Gas Revenue

2020 oil and natural gas revenue decreased by $526.1 million or 47% as reconciled in the table below to 2019:

($000s)
Oil and natural gas revenue, year ended December 31, 2019	$1,113,622
Sales volume of produced oil, a decrease of 13% (6,777 bbl/d)	(135,254)
Sales volume of purchased oil, an increase of 0.3% (9 bbl/d)	352
Sales price decrease of 41%	(395,971)
Sales volume and price change of produced natural gas	4,771
Oil and natural gas revenue, year ended December 31, 2020	$587,520

Oil and natural gas revenue decreased year over year mainly due to the decrease in world oil prices and decreased sales volumes of produced oil.

e) Crude Oil Inventory in Transit

($000s)For the years ended December 31,	2020	2019
Crude oil in transit	$1,915$	653

At December 31, 2020, the Company had 99.5 mbbls (December 31, 2019 - 27.7 mbbls) of crude oil inventory in transit, which was injected into Colombian pipelines. The inventory was valued based on direct and indirect expenditures (including production costs, transportation costs, depletion expense and royalty expense) at approximately $19/bbl ($24/bbl - 2019) incurred in bringing the crude oil to its existing condition and location.

A reconciliation of quarter to quarter crude oil inventory movements is provided below:

(mbbls)For the periods ended	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020
Crude oil inventory in transit - beginning of the period	88.0	75.9	250.5	27.7
Oil production	4,118.9	3,940.2	3,615.2	4,830.4
Oil sales	(4,354.7)	(4,179.9)	(4,073.5)	(4,922.8)
Purchased oil	247.3	251.8	283.7	315.2
Crude oil inventory in transit - end of the period	99.5	88.0	75.9	250.5
% of period production	2.4	2.2	2.1	5.2

Crude oil inventory build and (draw) from period to period are subject to factors that the Company does not control such as timing of the number of shipments from storage to export. Crude oil inventory as a percentage of quarterly production at December 31, 2020 was 2.4%. Parex expects crude oil inventory in future periods to be in line with normal historic levels of below 5% of period production.

f) Purchased Oil

	For the three monthsended December 31,	For the year endedDecember 31,
		2019	2020		2019
Purchased oil expense ($000s)	$	7,536	$ 16,154	$ 28,241	$	52,791

Purchased oil expense for the three months and year ended December 31, 2020 was $7.5 million and $28.2 million as compared to $7.1 million in the preceding quarter and $16.2 million and $52.8 million for the three months and year ended December 31, 2019. Purchased oil expense has decreased as a result of a decrease in oil blending operations and a decrease in purchases of partner crude at certain fields, primarily at the Capachos field. Transportation costs are incurred by the Company to transport purchased oil to sale delivery points.

Royalties

	For the three months endedDecember 31,				For the year endedDecember 31,
	2020		2019		2020		2019
Royalties ($000s)	$13,642	$	36,717	$	55,655	$	136,068
Per unit ($/boe)(1)	3.19		7.15		3.28		7.06
Percentage of sales(1)	8.6		13.5		10.1		12.9

(1) Calculated based on Company working interest sales volumes excluding purchased oil volumes sold.

For the three months and year ended December 31, 2020 royalties as a percentage of sales were 8.6% and 10.1%, a decrease from 13.5% and 12.9% in the three months and year ended December 31, 2019. The third quarter of 2020 royalty as a percentage of sales was 8.8%. The decrease in royalties as a percentage of oil sales compared to the prior year is a result of lower benchmark WTI prices which are used in the high price share royalty ("HPR") calculation. Benchmark WTI prices for the three months and year ended December 31, 2020 were $42.63 and $39.44 compared to $40.88 in the third quarter of 2020, and $56.94 and $57.05 for the 2019 comparative periods.

The decrease in royalty expense to $13.6 million and $55.7 million in the three months and year ended December 31, 2020 compared to $36.7 million and $136.1 million for the 2019 comparative prior year periods is a result of lower benchmark WTI prices used in the calculation of royalties and decreased oil production and sales over the prior period. As realized oil prices increase royalties as % of oil sales will also increase to historic levels.

The HPR comes into effect when accumulated production of any production area, inclusive of royalty volumes, exceeds 5 million barrels, and in the event international reference prices exceed pricing determined in the contract. The calculation is described as a "High Price Share" in the Company's AIF, which may be accessed through the SEDAR website at www.sedar.com.

Production Expense

	For the three months endedDecember 31,				For the year endedDecember 31,
		2020		2019		2020		2019
Production expense ($000s)	$	22,499	$	29,183	$	87,272	$	111,061
Per unit ($/boe)(1)		5.26		5.68		5.15		5.76

(1) Calculated based on Company working interest sales volumes excluding purchased oil volumes sold.

A breakdown of the production expense on a per boe basis between operated and non-operated fields are provided below:

	For the three months endedDecember 31,		For the year endedDecember 31,
	2020	2019	2020	2019
Per unit ($/boe) – based on sales volumes – operated(1)	7.38	8.88	7.34	8.66
Per unit ($/boe) – based on sales volumes – non-operated(1)	4.27	4.45	4.33	4.68

(1) Calculated based on Company working interest sales volumes excluding purchased oil volumes sold.

Production expense includes the cost of activities in the field to operate wells and facilities, lift to surface, gather, process, treat and store production.

Production expense for the three months and year ended December 31, 2020 was $5.26/boe and $5.15/boe compared to $5.68/boe and $5.76/boe for the three months and year ended December 31, 2019. Production expense for the third quarter of 2020 was $5.00/boe.

Operated properties production expense in the fourth quarter of 2020 was $7.38/boe compared to $6.09/boe for the third quarter of 2020 and non-operated properties production expense was $4.27/boe for the fourth quarter of 2020 compared to $4.62/boe for the third quarter of 2020.

The decrease in operated production expense for the year ended December 31, 2020 is mainly the result of the depreciation of the Colombian peso, additional production from the Capachos field and the voluntary shut-in of higher operating cost fields compared to the prior period.

The decrease in non-operated production expense for the year ended December 31, 2020 is mainly the result of the depreciation of the Colombian peso comparative to the prior period.

Production Expense

Transportation Expense

	For the three months endedDecember 31,				For the year endedDecember 31,
		2020		2019		2020		2019
Transportation expense ($000s)	$	16,938	$	20,462	$	59,147	$	88,974
Per unit ($/boe)		3.74		3.74		3.28		4.37

Transportation expense includes trucking costs incurred to transport production to several offloading stations for sale and in some instances an oil transportation tariff from the in-basin delivery point to the buyer's facility and national pipeline tariffs for transportation of Parex crude oil to the tide water crude oil export facility.

For the three months ended December 31, 2020, the cost of transportation of $3.74/boe has increased compared to the third quarter of 2020 cost of $2.81/boe and was comparable to the comparative period in 2019. Transportation expense will fluctuate period over period due the mix of sales contracts types in force during the period. The increase from the third quarter of 2020 is mainly due to an increase in oil sale cargo exports where Parex records the full cost of transportation to the point of export.

The combined transportation expense and price differential from Brent, on a per boe basis, has decreased from the fourth quarter of 2019 and third quarter of 2020. See "Crude Oil Reference and Realized Prices".

On a year to date basis transportation expense has decreased to $3.28/boe from $4.37/boe in the comparative period in 2019 mainly as a result of decreased crude cargo exports where Parex records the full cost of transport to the export point and a higher percentage of in-basin wellhead sales where Parex only records the price received at the field.

General and Administrative Expense ("G&A")

	For the three months endedDecember 31,					For the year endedDecember 31,
($000s)		2020		2019		2020		2019
Gross G&A	$	12,643	$	13,227	$	44,343	$	46,067
G&A recoveries		(544)		(496)		(1,129)		(1,649)
Capitalized G&A		(2,151)		(1,820)		(7,156)		(10,204)
Net G&A expense	$	9,948	$	10,911	$	36,058	$	34,214
Per unit ($/boe) (1)		2.32		2.19		2.12		1.78

(1) Calculated based on Company working interest production volumes.

Net G&A was $9.9 million and $36.1 million for the three months and year ended December 31, 2020 compared to $10.9 million and $34.2 million for the same periods in 2019. Net G&A has increased for the year as a result of decreased capitalized G&A and G&A recoveries as a result of less capital activity compared to the prior year. Gross G&A was $12.6 million and $44.3 million for the three months and year ended December 31, 2020 (three months and year ended December 31, 2019 - $13.2 million and $46.1 million). On a per boe basis net G&A for the year has increased 19% from the comparative year as a result of voluntarily curtailment of production during the year in response to the significant decline in world oil prices and ongoing uncertainty in market conditions resulting from the COVID-19 pandemic.

The Company's G&A expense is mainly denominated in local currencies of COP and Cdn dollar which as they appreciate/depreciate have an impact on G&A expense. Refer to the "Foreign Exchange Sensitivity Analysis" for further information.

Net General and Administrative Expenses

Share-Based Compensation

	For the three months endedDecember 31,	For the year endedDecember 31,
($000s)	2020	2019	2020		2019
Equity settled share-based compensation expense	$1,608	$1,785	$4,235	$	7,603
Cash settled share-based compensation expense	8,687	8,202	5,275		20,081
Total net expense	$10,295	$9,987	$9,510	$	27,684

Share-based compensation expense was $9.5 million for the year ended December 31, 2020 compared to $27.7 million for the same period in 2019. The decrease is primarily due to the decrease in the Company's share price and its impact on cash settled share-based compensation expense as explained below.

Equity settled share-based compensation expense was $1.6 million and $4.2 million for the three months and year ended December 31, 2020 compared to $1.8 million and $7.6 million for the same periods in 2019. Equity settled share-based compensation includes the Company's stock option plan and the restricted share unit ("RSU") plan pursuant to which RSUs and performance based RSUs ("PSUs") were awarded. The decrease in the equity settled plan expense from the prior year is mainly related to the decrease in the awards remaining to be amortized under these plans as compared to the prior year.

Cash settled share-based compensation relates to the Company's cash settled incentive plans and includes share appreciation rights ("SARs"), cash settled restricted share units ("CRSUs"), cash or share settled restricted share units ("CosRSUs"), cash or share settled performance share units ("CosPSUs") and deferred share units ("DSUs"). The CRSU plan is replacing the current SAR plan for the Colombian employees as granted SAR's vest, and are exercised. There will be no SAR grants going forward. For the three months and year ended December 31, 2020 there was an expense of $8.7 million and $5.3 million related to cash settled incentive plans compared to a $8.2 million expense and expense of $20.1 million for the same periods in 2019. The decrease in expense is attributable to the decrease in Parex share price to Cdn$17.52 at December 31, 2020 from Cdn$24.15 at December 31, 2019, partially offset by the issuance of cash settled compensation. Obligations for payments of cash under the Company's cash settled incentive plans are accrued as expense over the vesting period based on the fair value of the units as described in note 16 - Cash Settled Incentive Plans of the consolidated financial statements for the year ended December 31, 2020. As at December 31, 2020, the total cash settled incentive plans liability accrued is $23.7 million (December 31, 2019 - $27.9 million).

Cash payments to settle cash settled share-based compensation in the three months and year ended December 31, 2020 were $0.5 million and $12.1 million respectively (three months and year ended December 31, 2019 - $0.6 million and $9.2 million).

Depletion, Depreciation and Amortization Expense ("DD&A")

	For the three months endedDecember 31,						For the year endedDecember 31,
	2020		2019		2020		2019
DD&A ($000s) total	$32,554	$	32,636	$	113,758	$	125,899
Per unit ($/boe)(1)	7.59		6.54		6.68		6.55

(1) DDA per unit ($/bbl) is calculated using Company working interest production volumes and does not include inventory adjustments.

Fourth quarter 2020 DD&A was $32.6 million ($7.59/boe) compared to $32.6 million ($6.54/boe) for the same period in 2019. For the year ended December 31, 2020 DD&A was $113.8 million ($6.68/boe) as compared to $125.9 million ($6.55/boe) for the prior year.

For the fourth quarter of 2020, future development costs of $422.7 million (three months ended December 31, 2019 - $453.1 million) were included in the depletion calculation. Fourth quarter 2020 DD&A of $7.59/boe increased from the comparative period of $6.54/boe due to a small decrease in proved and probable reserves and oil and gas production from the prior comparative period.

Foreign Exchange

	For the three months endedDecember 31,	For the year endedDecember 31,
($000s)	2020	2019	2020	2019
Foreign exchange (gain) loss	$10,222	$5,733$	(102) $	10,657
Foreign currency risk management contracts loss (gain)	—	(245)	511 —	(3,733)
Total foreign exchange loss	$10,222	$5,488$	409$	6,924
Average foreign exchange rates
USD$/CAD$	1.30	1.32	1.34	1.33
USD$/Colombian peso	3,662	3,404	3,693	3,281

The Company's main exposure to foreign currency risk relates to the pricing of foreign currency denominated in Canadian dollars and Colombian pesos ("COP"), as the Company's functional currency is the US dollar. The Company has exposure in Colombia and Canada on costs, such as capital expenditures, local wages, royalties and income taxes, all of which may be denominated in local currencies. The main drivers of foreign exchange loss and gain recorded on the consolidated statements of comprehensive income is the COP denominated tax withholdings receivable and income tax payable balances in Colombia. The timing of payment settlements, accruals and their adjustments have impacts on foreign exchange gains/losses.

For the three months and year ended December 31, 2020, a total foreign exchange loss of $10.2 million and $0.4 million was recorded compared to a loss of $5.5 million and $6.9 million in the respective prior year periods. Unrealized foreign exchange gains and losses may be reversed in the future as a result of fluctuations in exchange rates and are recorded in the Company's consolidated statement of comprehensive income.

The Company reviews its exposure to foreign currency variations on an ongoing basis and maintains cash deposits primarily in USD denominated deposits in Canada, Barbados, Bermuda and Colombia.

Foreign Exchange Sensitivity Analysis

Cost component		$/boe Impact of change in local currency/$USD exchange rate
	Estimated percent ofcost denominated inlocal currency	10% appreciation oflocal currency	10% depreciation oflocal currency
Production expense	80 % $	0.42 $	(0.42)
Transportation expense	80 % $	0.30 $	(0.30)
G&A expense	100 % $	0.23 $	(0.23)

The table above displays the estimated per boe impact of a change in Parex' local currencies and the effect on Parex' key cost components. The component impact in $/boe terms uses Q4 2020 per boe costs. This analysis ignores all other factors impacting cost structure including efficiencies, cost reduction strategies, etc.

Net Finance Expense

	For the three months endedDecember 31,	For the year endedDecember 31,
	2020	2019	2020		2019
Bank charges and credit facility fees	$514	$784	$2,630	$	3,647
Accretion on decommissioning and environmental liabilities	925	1,269	4,125		4,592
Interest and other income	(250)	(1,062)	(2,129)		(7,382)
Right of use asset interest	4	22	54		99
Loss (gain) on settlement of decommissioning liabilities	442	(1,301)	803		359
Loss on disposition of tangible assets	1	3	1,345		235
Expected credit loss provision (recovery)	(428)	—	1,006		—
Other	(174)	1,983	(821)		2,026
Net finance expense	$1,034	$1,698	$7,013	$	3,576
	For the three months endedDecember 31,		For the year endedDecember 31,
	2020	2019	2020		2019
Non-cash finance expense	$766	$1,954	$6,458	$	7,212
Cash finance expense (income)	268	(256)	555		(3,636)
Net finance expense	$1,034	$1,698	$7,013	$	3,576

Bank taxes and credit facility fees relate to bank taxes paid in Colombia and the standby fees related to the undrawn credit facility. The noncash components of net finance expense include the accretion on decommissioning and environmental liabilities, loss (gain) on settlement of decommissioning liabilities, loss on disposition of tangible assets, other and the expected credit loss provision (recovery) which has increased due to the COVID-19 pandemic and it's impact on credit markets and ratings.

Risk Management

Management of cash flow variability is an integral component of Parex' business strategy. Changing business conditions are monitored regularly and, where material, reviewed with the Board of Directors to establish risk management guidelines to be used by management. The risk exposure inherent in movements in the price of crude oil, fluctuations in the US/COP exchange rate and interest rate movements are all proactively reviewed by Parex and as considered appropriate may be managed through the use of derivatives. The Company considers these derivative contracts to be an effective means to manage and forecast cash flow.

Parex has elected not to apply IFRS prescribed "hedge accounting" rules and, accordingly, pursuant to IFRS the fair value of the financial contracts is recorded at each period-end. The fair value may change substantially from period to period depending on commodity and foreign exchange forward strip prices for the financial contracts outstanding at the balance sheet date. The change in fair value from period-end to period-end is reflected in the earnings for that period. As a result, earnings may fluctuate considerably based on the period-ending commodity and foreign exchange forward strip prices.

a) Risk Management Contracts – Brent Crude

At December 31, 2020 the Company had no crude oil risk management contracts in place and still has no crude oil risk management obligations at the time of writing this MD&A. Parex has no outstanding draw on its credit facility or significant commitments due in the next 12 months and as such it is considered appropriate not to have any commodity derivative contracts in place at this time and thereby avoid the costs associated with these types of contracts.

The table below summarizes the loss on the commodity risk management contracts that were in place during the three months and years ended December 31, 2020 and 2019:

	For the three months endedDecember 31,		For the year endedDecember 31,
($000s)	2020	2019	2020	2019
Realized loss on commodity risk management contracts	$—$	$—	3,940	—
Total	$—$	—$	3,940$	—

The Company has no commodity risk management contracts in place for 2021 and so is fully exposed to fluctuations in oil prices.

b) Risk Management Contracts – Foreign Exchange

The Company is exposed to foreign currency risk as various portions of its cash balances are held in Colombian pesos (COP) and Canadian dollars (Cdn$) while its committed capital expenditures are expected to be primarily denominated in US dollars.

At December 31, 2020 the Company had no foreign currency risk management contracts in place.

The table below summarizes the loss (gain) on the foreign currency risk management contracts that were in place during the three months and years ended December 31, 2020 and 2019:

	For the three months endedDecember 31,	For the year endedDecember 31,
($000s)	2020	2019	2020	2019
Premiums paid on foreign currency risk management contracts	$—$	178$	—$	389
Unrealized (gain) on foreign currency risk management contracts	—	(213)	—	(8,591)
Realized loss (gain) on foreign currency risk management contracts	—	(210)	511	4,469
Total	$—$	(245) $	511$	(3,733)

The Company recorded a realized $0.5 million loss on these contracts in the year ended December 31, 2020 which is recorded in the financial statement line item "Foreign exchange (gain) loss" in the consolidated statements of comprehensive income. The Company recorded an $8.6 million unrealized gain and $4.9 million loss realized on these contracts in the year ended December 31, 2019 which is recorded in the financial statement line item "Foreign exchange (gain) loss".

Income Tax

The components of tax expense (recovery) for the three months and year ended December 31, 2020 and 2019 were as follows:

($000s)	For the three months ended	For the year endedDecember 31,
		2020		2019	2020	2019
Current tax expense	$	10,885	$	32,763$	20,674	$120,163
Deferred tax expense (recovery)		(30,647)		(10,855)	53,355	55,507
Total tax expense (recovery)	$	(19,762) $		21,908$	74,029	$175,670

Current tax expense in the fourth quarter of 2020 was $10.9 million as compared to $32.8 million in the comparative three month period. In the current quarter tax expense as a percentage of consolidated cash flows before tax was 11.8%. For the full year 2020 the Company recorded $20.7 million of current tax expense as compared to $120.2 million in 2019. This decrease is mainly a result of a decrease in cash flows from the prior period primarily as a result of the reduction in Brent oil prices in 2020.

Deferred tax in the fourth quarter of 2020 was a recovery of $30.6 million and an expense of $53.4 million for the year ended December 31, 2020 ($10.9 million recovery and $55.5 million expense for the three months and year ended December 31, 2019). The deferred tax recovery in the quarter is a result of the appreciation of the Colombian peso at the period end date compared to the prior year and its effect on the Colombian tax basis.

Capital Expenditures and Acquisitions

($000s)	Colombia			Canada			Total
For the year ended December 31,	2020	2019	2020		2019	2020		2019
Acquisition of unproved properties	$1,474	$1,476	$—	$	—	$1,474	$	1,476
Geological and geophysical	1,466	12,366	—		—	1,466		12,366
Drilling and completion	125,096	175,502	—		—	125,096		175,502
Well equipment and facilities	12,616	18,600	—		—	12,616		18,600
Other	467	130	145		122	612		252
Total capital expenditures and acquisitions	$ 141,119	$ 208,074	$145	$	122	$ 141,264		$ 208,196
($000s)	Colombia			Canada			Total
For the three months ended December 31,	2020	2019	2020		2019	2020		2019
Acquisition of unproved properties	$986	$52	$—	$	—	$986	$	52
Geological and geophysical	542	4,349	—		—	542		4,349
Drilling and completion	41,075	52,676	—		—	41,075		52,676
Well equipment and facilities	3,991	1,126	—		—	3,991		1,126
Other	337	75	1		43	338		118

Capital Expenditures Summary

During the year ended December 31, 2020 the Company incurred $141.3 million of capital expenditures compared to $208.2 million in the same period of 2019. During 2020 the Company drilled 30 gross (19.45 net) wells, compared to 43 gross (26.95 net) wells in 2019.

During the year ended December 31, 2020 capital expenditures of $141.3 million were self-funded from funds flow from operations of $297.0 million. The Company has maintained its ability to fund growth from cash flow since 2012, excluding the cost of a corporate acquisition completed in 2014.

In the fourth quarter of 2020 the Company drilled 8 gross (4.85 net) wells in Colombia compared to 15 gross (9.25 net) wells in the comparative period. Drilling and completion costs during the fourth quarter of 2020 totaled $41.1 million mainly related to drilling and completion costs in Colombia at Blocks LLA-34 and Fortuna.

Non-cash Impairment Charges

	For the three months endedDecember 31,		For the year endedDecember 31,
($000s)	2020		2019	2020		2019
Impairment of E&E assets	$6,166	$	17,223	$6,166	$	22,767
Impairment of PP&E related to Boranda CGU	—		—	7,000		—
Total non-cash impairment charges before deferred income taxrecoveries	$6,166	$	17,223	$13,166	$	22,767

2020 Impairments

The impairment of E&E assets during the three months and year ended December 31, 2020 of $6.2 million is primarily associated with the costs in blocks in the process to relinquish that will not be recovered. The net book value of costs on these block has been impaired to $nil.

As a result of the COVID-19 pandemic and the significant decrease in forecast global crude oil prices compared to those at December 31, 2019, an indication of impairment was identified for all CGUs at March 31, 2020 and impairment tests were performed. The Company determined that the carrying amount of the Boranda CGU in the Magdalena Basin exceeded its recoverable amount and an impairment of $7.0 million was recorded in the consolidated statements of comprehensive income (loss) for the three month period ended March 31, 2020. All other CGU's were found to have recoverable amounts greater than carrying amounts. The recoverable amount for this testing was determined using fair value less cost of disposal. Future cash flows for the CGU's declined due to lower crude oil prices.

The fair value as determined for the Company's producing properties was consistent with the Company's independent qualified reserve evaluators reserve estimate at December 31, 2019, updated for forecast oil prices at March 31, 2020 and adjusting for first quarter production and future development capital expenditures. There are no E&E assets associated with this CGU. Future cash flows were discounted using a rate of 11%. As at March 31, 2020, the recoverable amount of the CGU was estimated to be $16.5 million. The impairment of $7.0 million was due to the lower crude oil price forecast at March 31, 2020 assumed in the fair value calculation compared to the prior year. A 1% change to the assumed discount rate or a 5% change in forward price estimates over the life of the reserves would have an immaterial impact on the impairment.

The future oil prices used in the model are based on a forecast of crude oil prices by Parex' independent reserve evaluators.

Prices used at March 31, 2020 are as follows:

	2020	2021	2022	2023	2024	Thereafter
Brent ($US/bbl)	38.64	45.50	52.50	57.50	62.50	2% increase per year

At December 31, 2020 Parex tested its CGU's for PP&E impairment where it was determined that the recoverable amount of the CGU's exceeded their carrying amounts, and therefore the Company's CGU's were not impaired. The recoverable amount was determined using estimated fair value less costs of disposal. Future cash flows were discounted using an after tax discount rate of 12% with the following prices being used by Parex' independent reserve evaluator at December 31, 2020:

	2021	2022	2023	2024	2025	Thereafter
Brent ($US/bbl)	50.75	55.00	58.50	61.79	62.95	2% increase per year

At December 31, 2020 and 2019 there were no indicators of impairment noted for PP&E, or indicators requiring a reversal of previously recorded impairments.

2019 Impairments

The impairment of E&E assets during the three months and year ended December 31, 2019 of $17.2 million and $22.8 million was primarily associated with the LLA-10 block exploration costs that would not be recovered as the Company had plans to relinquish the block, post drilling of the Tautaco dry hole. 2019 impairments include Morpho block costs that would not be recovered as the Company had relinquished the LLA-10 block. The net book value of costs on this block has been impaired to $nil.

At December 31, 2019 Parex tested its CGU's for PP&E impairment where it was determined that the recoverable amount of the CGU's exceeded their carrying amounts, and therefore the Company's CGU's were not impaired. The recoverable amount was determined using estimated fair value less costs of disposal. Future cash flows were discounted using an after tax rate of 11% with the following prices being used by Parex' independent reserve evaluator at December 31, 2019:

	2020	2021	2022	2023	2024	Thereafter
Brent ($US/bbl)	67.00	68.00	71.00	73.00	75.00	2% increase per year

For further information regarding the impairment charges for the years ended December 31, 2020 and 2019, refer to note 7 - Exploration and Evaluation Assets and note 8 - Property, Plant and Equipment in the audited consolidated financial statements.

Impairment Test of Goodwill

The Company performed its annual test for goodwill impairment at the balance sheet date in accordance with its policy described in note 3 - Summary of Significant Accounting Policies of the audited consolidated financial statements for the years ended December 31, 2020 and 2019. The Company has allocated goodwill to the Colombia operating segment. The estimated fair value less costs of disposal of the Colombia operating segment exceeded the carrying value. As a result, no goodwill impairment was recorded. For additional information refer to note 10 - Goodwill in the audited consolidated financial statements.

Summary of Quarterly Results

Three months ended ($000s) (except per share amounts)	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020
Average daily oil and natural gas production (boe/d)	46,642	44,305	40,858	54,295
Realized sales price ($/boe)	36.95	33.88	19.25	38.47
Financial
Oil and natural gas sales	$167,264	$146,231	$80,407	$193,618
Funds flow provided by operations(1)	$81,567	$79,384	$38,777	$97,313
Per share – basic	0.61	0.57	0.28	0.69
Per share – diluted(1)	0.60	0.57	0.27	0.68
Net income (loss)	$56,192	$27,619	$19,290	$(3,779)
Per share – basic	0.42	0.20	0.14	(0.03)
Per share – diluted	0.42	0.20	0.14	(0.03)
Capital Expenditures, excluding corporate acquisitions	$46,932	$17,756	$5,310	$71,266
Total assets (end of period)	$1,541,081	$1,548,484	$1,533,377	$1,610,341
Working capital surplus (end of period)(2)	$320,155	$370,722	$339,310	$330,356
(1) Non-GAAP term. See "Non-GAAP Terms" below.(2) Working capital does not include the undrawn amount available on the credit facility.
Three months ended ($000s) (except per share amounts)	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019
Average daily oil and natural gas production (boe/d)	54,221	53,045	52,252	51,208
Realized sales price ($/boe)	53.00	53.59	59.92	52.33
Financial
Oil and natural gas sales	$289,585	$275,693	$301,750	$246,594
Funds flow provided by operations(1)	$143,269	$142,733	$150,973	$133,505
Per share – basic	1.00	0.99	1.03	0.88
Per share – diluted(1)	0.98	0.97	1.00	0.86
Net income	$87,218	$57,257	$101,505	$82,014
Per share – basic	0.61	0.40	0.69	0.54
Per share – diluted	0.60	0.39	0.67	0.53
Capital Expenditures, excluding corporate acquisitions	$58,321	$48,600	$48,742	$52,533
Total assets (end of period)	$1,684,581	$1,593,802	$1,574,528	$1,657,956

(1) Non-GAAP term. See "Non-GAAP Terms" below. In the second quarter of 2019, Parex changed the way it calculates and presents funds flow from operations. Comparative periods have also been adjusted for this change.

(2) Working capital does not include the undrawn amount available on the credit facility.

Factors that Caused Variations Quarter Over Quarter

During the fourth quarter of 2020, production of 46,642 boe/d was in excess of production compared to the previous quarter ended September 30, 2020. Revenue and funds flow provided by operations were higher than the previous quarter due to an increase in volumes sold and realized prices. Working capital decreased to $320.2 million from $370.7 million at September 30, 2020 primarily due to buying back 6.6 million shares pursuant to the Company's NCIB.

During the third quarter of 2020, production of 44,305 boe/d (consisting of 4,626 bbls/d light crude oil and medium crude oil, 38,309 bbls/d of heavy crude oil and 8,220 mcf/d of conventional natural gas) was in excess of production for the previous quarter ended June 30, 2020. Revenue and funds flow provided by operations were higher than the previous quarter due to an increase in realized prices and volumes sold. Working capital increased to $370.7 million from $339.3 million at June 30, 2020.

During the second quarter of 2020, production of 40,858 boe/d (consisting of 4,186 bbls/d light crude oil and medium crude oil, 35,478 bbls/d of heavy crude oil and 7,164 mcf/d of conventional natural gas) was lower than production for the previous quarter ended March 31, 2020. Revenue and funds flow provided by operations were lower than the previous quarter mainly due to decrease in realized prices and volumes sold. Working capital increased to $339.3 million from $330.4 million at March 31, 2020.

During the first quarter of 2020, production of 54,295 boe/d (consisting of 8,380 bbls/d light crude oil and medium crude oil, 44,657 bbls/d of heavy crude oil and 7,548 mcf/d of conventional natural gas) was in excess of production for the previous quarter ended December 31, 2019. Revenue and funds flow provided by operations were lower than the previous quarter mainly due to a decrease in realized prices and volumes sold. Working capital decreased to $330.4 million from $344.0 million at December 31, 2019.

During the fourth quarter of 2019, production of 54,221 boe/d (consisting of 8,346 bbls/d light crude oil and medium crude oil, 44,740 bbls/d of heavy crude oil and 6,810 mcf/d of conventional natural gas) was in excess of production from the previous quarter ended September 30, 2019. Revenue and funds flow provided by operations were higher than the previous quarter due to an increase in volumes sold, partially offset by a decrease in realized prices. Working capital increased to $344.0 million from $279.9 million at September 30, 2018.

Please refer to "Financial and Operating Results" for detailed discussions on variations during the comparative quarters and to Parex' previously issued annual and interim MD&As for further information regarding changes in prior quarters.

Fourth Quarter Results

Consolidated Statements of Comprehensive Income for the three months ended December 31, 2020 and 2019:

($000s) For the three month period ended December 31,	2020	2019
Oil and natural gas sales	$167,264	$289,585
Royalties	(13,642)	(36,717)
Revenue	153,622	252,868
Expenses
Production	22,499	29,183
Transportation	16,938	20,462
Purchased oil	7,536	16,154
General and administrative	9,948	10,911
Impairment of exploration and evaluation assets	6,166	17,223
Equity settled share-based compensation expense	1,608	1,785
Cash settled share-based compensation expense	8,687	8,202
Depletion, depreciation and amortization	32,554	32,636
Foreign exchange loss	10,222	5,488
	116,158	142,044
Finance (income)	(250)	(1,062)
Finance expense	1,284	2,760
Net finance expense	1,034	1,698
Income before income taxes	36,430	109,126
Income tax (recovery) expense
Current tax expense	10,885	32,763
Deferred tax (recovery)	(30,647)	(10,855)
	(19,762)	21,908
Net income and comprehensive income for the period	$56,192	$87,218

Liquidity and Capital Resources

As at December 31, 2020 the Company had a working capital surplus of $320.2 million, excluding amounts available under the credit facility, as compared to working capital surplus of $344.0 million at December 31, 2019. Bank debt was $nil at December 31, 2020 and December 31, 2019. The credit facility has a current borrowing base of $200.0 million and is subject to a borrowing base redetermination to be completed by the end of May 2021. At December 31, 2020 Parex held $330.6 million of cash, compared to $353.3 million at September 30, 2020 and $396.8 million at December 31, 2019. The Company's cash balances reside primarily in current accounts with chartered financial institutions, the majority of which are held on account in Canada, Barbados, Bermuda and Colombia in USD.

Parex' senior secured credit facility ("credit facility") with a syndicate of banks has a current borrowing base of $200.0 million. Key covenants include a rolling four quarters total funded debt to adjusted EBITDA test of 3:50:1, and other standard business operating covenants. Given there is $nil balance drawn on the facility as at December 31, 2020, the Company is in compliance with all covenants. The next annual review is scheduled to occur at the end of May 2021. As the Company currently has $nil bank debt and no plans in 2021 to utilize the credit facility, the next re-determination is not expected to impact the Company's current or future operations or reduce the 2021 outlook.

On December 19, 2019 the Toronto Stock Exchange ("TSX") approved the Company's NCIB application to purchase up to 13,986,994 of the Company's common shares for cancellation. The NCIB commended on December 23, 2019 and the maximum number of shares were repurchased by December 17, 2020 at an average price of Cdn$16.69.

On December 21, 2020, the Toronto Stock Exchange ("TSX") approved the Company's NCIB application to purchase up to 12,868,562 of the Company's common shares for cancellation. The NCIB commenced on December 23, 2020 and will terminate on December 22, 2021 or such earlier time as the NCIB is completed or terminated by Parex. The Company also entered into an automatic share purchase plan with a broker to facilitate repurchases of Common Shares pursuant to the Company's NCIB. Under the Company's automatic share purchase plan, the Company's broker may repurchase Common Shares under the NCIB during the Company's self-imposed blackout periods.

Refer to note 24 - Commitments and Contingencies of the audited financial statements for the year ended December 31, 2020 for a description of the performance guarantee facility with Export Development Canada as well as the unsecured letters of credit.

Outstanding Share Data

Parex is authorized to issue an unlimited number of voting common shares without nominal or par value. As at December 31, 2020 the Company had 130,872,676 common shares outstanding compared to 143,295,054 at December 31, 2019, a decrease of 9%. At March 3, 2021 the common shares outstanding has been reduced to 129,430,548 due to the NCIB.

The Company has a stock option plan and RSU (which includes PSUs) plan. The plans provide for the issuance of stock options, RSUs and PSUs to the Company's officers, executive and certain employees to acquire common shares. In 2019, Parex created a new cash or share settled RSU and PSU plan. Under this new plan any employee who chooses share settlement will receive common shares of the Company purchased on the open market, hence there will be no new issuance of common shares from treasury under this new plan. Going forward, it is expected that only the grants under the Company's stock option plan and the exercise of previously issued RSUs and PSUs will result in common shares issued from treasury.

As at March 3, 2021 Parex has the following securities outstanding:

	Number	%
Common shares	129,430,548	98
Stock options	1,630,840	1
Restricted and performance share units	717,178	1
	131,778,566	100

As of the date of this MD&A, total stock options, RSUs and PSUs outstanding represent approximately 2% of the total issued and outstanding common shares.

Contractual Obligations, Commitments and Guarantees

In the normal course of business, Parex has entered into arrangements and incurred obligations that will affect the Company's future operations and liquidity. These commitments primarily relate to exploration work commitments including seismic and drilling activities. The Company has discretion regarding the timing of capital spending for exploration work commitments, provided that the work is completed by the end of the exploration periods specified in the contracts or the Company can negotiate extensions of the exploration periods. The Company's exploration commitments are described in the Company's AIF under "Description of Business - Principal Properties". These obligations and commitments are considered in assessing cash requirements in the discussion of future liquidity.

In Colombia, the Company has provided guarantees to the ANH which on December 31, 2020 were $46.4 million (December 31, 2019 - $47.9 million) to support the exploration work commitments on its blocks. The guarantees have been provided in the form of letters of credit for varying terms. Export Development Canada has provided performance security guarantees under the Company's $150.0 million (December 31, 2019 - $150.0 million) performance guarantee facility to support approximately $21.9 million (December 31, 2019 - $25.4 million) of the letters of credit issued on behalf of Parex. The letters of credit issued to the ANH are reduced from time to time to reflect the work performed on the various blocks. At December 31, 2020, there are an additional $24.5 million (December 31, 2019 - $22.5 million) letters of credit that are provided by a Latin American bank on an unsecured basis.

The following table summarizes the Company's estimated undiscounted commitments as at December 31, 2020:

($000s)	Total	<1 year	1 – 3 years	3 – 5 years	>5 years
Exploration	$169,408	$37,507	$42,810	$89,091	$—
Office and accommodations(1)	7,512	2,750	3,242	1,520	—
Decommissioning and Environmental Obligations	80,962	7,054	—	—	73,908
Total	$ 257,882	$47,311	$46,052	$90,611	$73,908

(1) Includes minimum lease payment obligations associated with leases for office space and accommodations.

Decommissioning and Environmental Liabilities

	Decommissioning	Environmental	Total
Balance, December 31, 2018	$42,052	$15,549	$57,601
Additions	10,524	1,355	11,879
Settlements of obligations during the year	(10,536)	(1,229)	(11,765)
Loss on settlement of obligations	359	—	359
Accretion expense	3,166	1,426	4,592
Change in estimate - inflation and discount rates	1,455	170	1,625
Change in estimate - costs	(10,253)	(2,532)	(12,785)
Foreign exchange loss (gain)	477	(48)	429
Balance, December 31, 2019	$37,244	$14,691	$51,935
Additions	2,554	480	3,034
Settlements of obligations during the year	(3,560)	(1,070)	(4,630)
Loss on settlement of obligations	803	—	803
Accretion expense	2,286	1,839	4,125
Change in estimate - inflation and discount rates	360	(2,062)	(1,702)
Change in estimate - costs	(441)	(286)	(727)
Foreign exchange (gain)	(1,036)	(691)	(1,727)
Balance, December 31, 2020	38,210	12,901	51,111
Current obligation	(3,629)	(3,425)	(7,054)
Long-term obligation	$34,581	$9,476	$44,057

The total environmental, decommissioning and restoration obligations were determined by management based on the estimated costs to settle environmental impact obligations incurred and to reclaim and abandon the wells and well sites based on contractual requirements. The obligations are expected to be funded from the Company's internal resources available at the time of settlement.

The total decommissioning and environmental liability is estimated based on the Company's net ownership in wells drilled as at December 31, 2020, the estimated costs to abandon and reclaim the wells and well sites and the estimated timing of the costs to be paid in future periods. The total undiscounted amount of cash flows required to settle the Company's decommissioning liability is approximately $60.4 million as at December 31, 2020 (December 31, 2019 - $63.3 million) with the majority of these costs anticipated to occur in 2033 or later. A risk-free discount rate of 5.25% and an inflation rate of 2.0% were used in the valuation of the liabilities (December 31, 2019 - 6.74% risk-free discount rate and a 3.1% inflation rate). The risk-free discount rate and the inflation rate used in 2020 are based on forecast Colombia rates.

Included in the decommissioning liability is $3.6 million (December 31, 2019 - $4.3 million) that is classified as a current obligation.

The total undiscounted amount of cash flows required to settle the Company's environmental liability is approximately $20.5 million as at December 31, 2020 (December 31, 2019 - $21.5 million) with the majority of these costs anticipated to occur in 2033 or later in Colombia. A risk-free discount rate of 5.25% and an inflation rate of 2.0% were used in the valuation of the liabilities (December 31, 2019 - 6.74% risk-free discount rate and a 3.1% inflation rate). The risk-free discount rate and the inflation rate used in 2020 are based on forecast Colombia rates.

Included in the environmental liability is $3.4 million (December 31, 2019 - $4.1 million) that is classified as a current obligation.

Decommissioning and environmental liabilities are considered critical accounting estimates. There are significant uncertainties related to decommissioning and environmental expenditures and the impact on the financial statements could be material. The eventual timing of and costs for these expenditures could differ from current estimates. The main factors that can cause expected estimated cash flows in respect of decommissioning and environmental liabilities to change are:

• Changes in laws, legislation and regulations;
• Construction of new facilities;
• Change in commodity price;
• Change in the estimate of oil reserves and the resulting amendment to the life of reserves;
• Changes in technology; and
• Execution of decommissioning and environmental liabilities.

Advisory on Forward-Looking Statements

Certain information regarding Parex set forth in this MD&A, including assessments by the Company's management of the Company's plans and future operations, contains forward-looking statements that involve substantial known and unknown risks and uncertainties. The use of any of the words "plan", "expect", "forecast", "project", "intend", "believe", "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 the Company's internal projections, estimates or beliefs concerning, among other things, future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, 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 the Company's 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 MD&A include, but are not limited to, statements with respect to:

• the Company's operational strategy, plans, priorities and focus;
• 2021 guidance for Brent crude average price, average production, total capital expenditures, funds flow provided by operations, free funds flow, amount spent on the Company's share buy-back program, outstanding shares at end of the applicable period, production per share growth, estimated working capital at end of the applicable period, bank debt outstanding at end of applicable period, operating netback, FFO netback and current tax effective rate on FFO and assumptions underlying such estimates and guidance;
• expectation that Parex will purchase the maximum allowable shares under its normal course issuer bid and assumptions as to average share price;
• Parex' 2021 NCIB and the sources of funding;
• Expected Q1 2021 average production;
• Parex' strong financial position and the benefits to be derived thereunder;
• fluctuation in Brent/Vasconia crude differential;
• expectation that crude oil inventory in future periods to be in line with normal historic levels;
• the timing of payment of total decommissioning and environmental liability cost and the internal resources available at the time of settlement;
• the Company's expectations regarding the per boe and G&A expense impact caused by appreciation and depreciation of the Colombian peso;
• the effect of the Colombian peso/US$ exchange rate on the variability of general and administrative, transportation costs and production costs;
• foreign currency risk and the ability to reverse unrealized foreign exchange gains and losses in the future;
• the Company's risk management strategy and the fluctuation of earnings based on strip prices;
• terms of the Company's credit facility including the timing of the next borrowing base redetermination;
• no plans to utilize the credit facility in 2021;
• terms of certain contractual obligations;
• the Company's expectation that only the grants under the Company's stock option plan and exercise of previously issued RSUs and PSUs will result in common shares issued from treasury;
• the Company's expectation that the next redetermination of its credit facility will not impact its current or future operations or reduce the 2021 outlook;
• estimated amounts, timing and the anticipated sources of funding for the Company's exploration, office and accommodations, environmental, decommissioning and restoration obligations.
• the statements set forth under "Accounting Policies and Estimates" in this MD&A.

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; impact of the COVID-19 pandemic and the ability of the Company carry on its operations as currently contemplated in light of the COVID-19 pandemic; determination by OPEC and other country as to production levels; 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; continued volatility in market prices for oil; the impact of significant declines in market prices for oil; competition; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; partner approval of capital work programs and other matters requiring approval; imprecision in reserve and resource estimates; the production and growth potential of Parex' assets; obtaining required approvals of regulatory authorities in Canada and Colombia; risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities; fluctuations in foreign exchange or interest rates; environmental risks; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and natural gas industry; ability to access sufficient capital from internal and external sources; risk that the Company will not 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; risk of failure to achieve the anticipated benefits associated with acquisitions; risk of failure to achieve perceived benefits from voluntary tax restructuring; failure of counterparties to perform under the terms of their contracts; changes to pipeline capacity; risk that Parex' evaluation of its existing portfolio of development and exploration opportunities is not consistent with its expectations; failure to meet expected production targets; the risks discussed under "Risk Factors" in the Company's AIF and under "Decommissioning and Environmental Liabilities" in this MD&A, 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 affect the Company's 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 MD&A 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 forwardlooking statements contained in this MD&A, Parex has made assumptions regarding, among other things: current and future commodity prices and royalty regimes; the impact (and the duration thereof) that the COVID-19 pandemic will have on the demand for crude oil and natural gas, Parex' supply chain and Parex' ability to produce, transport and sell Parex crude oil and natural gas; availability of skilled labour; timing and amount of capital expenditures; uninterrupted access to areas of the Company's operations and infrastructure; future exchange rates; the price of oil; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; recoverability of reserves and future production rates; timing and number of dry hole write-offs permitted for Colombian tax purposes; royalty rates; future operating costs; foreign exchange rates; the status of litigation; timing of drilling and completion of wells; that the Company 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 the Company's conduct and results of operations will be consistent with its expectations; that the Company will have the ability to develop the Company'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 the Company's reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; that the Company 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; on-stream timing of production from successful exploration wells; operational performance of non-operated producing fields; pipeline capacity; and other matters. The ability of the Company to carry out its business plan is primarily dependent upon the continued support of its shareholders, the discovery of economically recoverable reserves and the ability of the Company to obtain financing or generate sufficient cash flow to develop such reserves.

Forward-looking statements and other information contained in this MD&A concerning the oil and natural gas industry in the countries in which it operates and the Company's general expectations concerning this industry are based on estimates prepared by Management using data from publicly available industry sources as well as from resource reports, market research and industry analysis and on assumptions based on data and knowledge of this industry which the Company believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While the Company is not aware of any material misstatements regarding any industry data presented herein, the oil and natural gas industry involves numerous risks and uncertainties and is subject to change based on various factors.

Management has included forward looking information and the above summary of assumptions and risks related to forward-looking information in this MD&A in order to provide shareholders with a more complete perspective on the Company's current and future operations and such information may not be appropriate for other purposes. The Company's 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 there from. These forward-looking statements are made as of the date of this MD&A and Parex disclaims any intent or obligation to update publicly any forwardlooking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

This MD&A may contain future oriented financial information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by management to provide an outlook of the Company's activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions including the assumptions discussed above. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments. FOFI contained in this MD&A was made as of the date of this MD&A and the Company disclaims any intention or obligations to update or revise any FOFI contained in this MD&A, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

Non-GAAP Terms

This report contains financial terms that are not considered measures under GAAP such as operating netback, operating netback per boe, funds flow provided by operations, funds flow provided by operations per boe, funds flow netback per boe, free funds flow and diluted funds flow per share that do not have any standardized meaning under IFRS and may not be comparable to similar measures presented by other companies. Management uses these non-GAAP measures for its own performance measurement and to provide shareholders and investors with additional measurements of the Company's efficiency and its ability to fund a portion of its future capital expenditures.

Adoption of IFRS 16 Leases had an immaterial impact on netbacks, funds flow provided by operations and EBITDA non-GAAP measures.

Funds flow provided by operations, is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. In Q2 2019, the Company changed how it presents funds flow provided by operations to present on a comparable basis to peer presentation. Amounts have been restated for prior periods. A reconciliation from cash provided by operating activities to funds flow provided by operations is as follows:

	For the three monthsended December 31,			For the year endedDecember 31,
($000s)	2020	2019	2020	2019
Cash provided by operating activities	$86,988	$	83,766	$290,018	$365,067
Net change in non-cash working capital	(5,421)		59,503	7,023	205,413
Funds flow provided by operations	81,567		143,269	297,041	570,480

Funds flow provided by operations per boe or funds flow netback per boe, is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital, divided by produced oil and natural gas sales volumes. The Company considers funds flow netback to be a key measure as it demonstrates Parex' profitability after all cash costs relative to current commodity prices and is calculated as follows:

	For the three months endedDecember 31,		For the year endedDecember 31,
($000s)	2020	2020	2019
Funds flow provided by operations	$81,567	$	143,269	$297,041	$	570,480
Company produced oil and natural gas sales in period	4,279,656		5,136,452	16,954,264		19,265,365
Funds flow provided by operations per boe	19.06		27.89	17.52		29.61

Free funds flow, is a non-GAAP measure that is determined by funds flow provided by operations less capital expenditures. The Company considers free funds flow or free cash flow to be a key measure as it demonstrates Parex' ability to fund return of capital, such as the NCIB, without accessing outside funds and is calculated as follows:

	For the three months endedDecember 31,		For the year endedDecember 31,
($000s)	2020		2019	2020	2019
Funds flow provided by operations	$81,567	$	143,269	$297,041	$570,480
Capital expenditures, excluding corporate acquisitions	46,932		58,321	141,264	208,196
Free funds flow	$34,635	$	84,948	$155,777	$362,284

Diluted funds flow per share is calculated by dividing funds flow provided by operations by the weighted average number of shares outstanding. Parex presents diluted funds flow provided by operations per share whereby per share amounts are calculated using weightedaverage shares outstanding, consistent with the calculation of earnings per share. The following table shows the variables used in the calculation of diluted funds flow per share:

	For the three months endedDecember 31,			For the year endedDecember 31,
($000s)	2020	2019		2020		2019
Funds flow provided by operations	$81,567	$143,269	$	297,041	$	570,480
Weighted average number of shares for the purposes of basic funds flow	133,812	142,967		138,356		146,380
Dilutive effect of share options on potential common shares	1,372	2,598		1,263		2,645
Weighted average number of shares for the purposes of dilutedfunds flow	135,184	145,565		139,619		149,025

Adjusted EBITDA is defined as net income (loss) before interest, taxes, depletion and depreciation and adjusted for other non-cash items, transaction costs and extraordinary and non-recurring items. Adjusted EBITDA is solely used in the calculation of the bank covenant and is not considered a key performance measure by Management.

Operating netback per boe

The Company considers operating netbacks to be a key measure as they demonstrate Parex' profitability relative to current commodity prices. Below is a description of each component of the Company's operating netback and how it is determined.

Oil and natural gas sales per boe is determined by sales revenue excluding risk management contracts divided by total equivalent sales volume including purchased oil volumes. A reconciliation of the calculation of oil and natural gas sales per boe is provided below:

	For the three months endedDecember 31,			For the year endedDecember 31,
($000s)		2020			2020		2019
Oil and natural gas revenue excluding risk management contracts	$	167,264	$	289,585	$	587,520	$	1,113,622
Oil revenue for purposes of sales price per boe	$	167,264	$	289,585	$	587,520	$	1,113,622
Denominator (BOEs)
Company produced oil and natural gas sales in period		4,279,656		5,136,452		16,954,264		19,265,365
Purchased oil volumes sold		247,296		327,612		1,097,971		1,091,580
Total oil and natural gas sales volumes		4,526,952		5,464,064		18,052,235		20,356,945

Sales price per boe	$36.95	$53.00	$32.55	$54.70

Royalties per boe is determined by dividing royalty expense by the total equivalent sales volume and excludes purchased oil volumes. A reconciliation of royalties per boe is provided below:

	For the three months endedDecember 31,			For the year endedDecember 31,
($000s)		2020		2019	2020	2019
Royalty expense	$	13,642	$	36,717	$55,655	$136,068
Denominator (BOEs)
Company produced oil and natural gas sales in period		4,279,656		5,136,452	16,954,264	19,265,365
Royalty expense per boe	$	3.19	$	7.15	$3.28	$7.06

Production expense per boe is determined by dividing production expense by the total equivalent sales volume and excludes purchased oil volumes. A reconciliation of production expense per boe is provided below:

	For the three months endedDecember 31,					For the year endedDecember 31,
($000s)		2020		2019		2020		2019
Production Expense	$	22,499	$	29,183	$	87,272	$	111,061
Denominator (BOEs)
Company produced oil and natural gas sales in period		4,279,656		5,136,452		16,954,264		19,265,365
Production expense per boe	$	5.26	$	5.68	$	5.15	$	5.76

Transportation expense per boe is determined by dividing the transportation expense by the total equivalent sales volumes including purchased oil volumes. A reconciliation of transportation expense per boe is provided below:

	For the three months endedDecember 31,				For the year endedDecember 31,
($000s)		2020		2019	2020		2019
Transportation Expense	$	16,938	$	20,462	$59,147	$	88,974
Denominator (BOEs)
Company produced oil and natural gas sales in period		4,279,656		5,136,452	16,954,264		19,265,365
Purchased oil volumes sold		247,296		327,612	1,097,971		1,091,580
Total oil and natural gas sales volumes		4,526,952		5,464,064	18,052,235		20,356,945
Transportation expense per boe	$	3.74	$	3.74	$3.28	$	4.37

Environmental Initiatives Impacting Parex

In Colombia there is currently no specific regulation that obliges companies to specifically monitor and report GHG emissions. However in 2017, the Colombian government submitted a bill which sets guidelines to manage climate change, although very little specifics were provided. Although at the present time there is no specific regulations related to climate change or GHG emissions in Colombia, Parex has a plan in place to monitor and disclose key metrics surrounding the environmental impacts of Parex' operations. Climate change regulation in Colombia has the potential to significantly affect the regulatory environment of the crude oil and natural gas industry in Colombia. Such regulations impose certain costs and risks on the industry, and there remains some uncertainty with regard to the impact of climate change and environmental laws and regulations on Parex, as Parex is unable to predict additional legislation or amendments that the Colombian government may enact in the future. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material impact on the Company's operations and cash flow.

Business Environment and Risks

Overall

Parex is exposed to a variety of risks including but not limited to operational, financial, competitive, political and environmental risks. As a participant in the oil and natural gas industry, Parex is exposed to operational risks such as: unsuccessful exploration and exploitation activities, the inability to find new reserves that are commercially and economically feasible, premature declines of reservoirs, well blow-outs and other operating hazards, and lack of infrastructure or transportation to access markets and monetize reserves. The Company works to mitigate these risks by employing highly skilled personnel and utilizing available technology. The Company also maintains a corporate insurance program consistent with industry practices to protect against insurable losses.

The Company is exposed to normal financial risks inherent in the oil and natural gas industry including: commodity price risk, exchange rate risk, interest rate risk and credit risk. The Company continuously monitors opportunities to use financial instruments to manage exposure to fluctuations in commodity prices, foreign currency rates and interest rates. Parex operates the majority of its properties and, therefore, has significant control over the timing, direction and costs related to exploration commitments and development opportunities.

COVID-19

The COVID-19 pandemic has resulted in emergency actions taken by governments worldwide which has had an effect in all of the Company's operating jurisdictions. The actions taken by these governments have typically included, but is not limited to travel bans, mandatory and selfimposed quarantines and isolations, social distancing, and the closing of non-essential businesses which has had significant negative effects on economies, including a substantial decline in crude oil and natural gas demand. Additionally, such actions have resulted in volatility and disruptions in regular business operations, supply chains and financial markets as well as declining trade and market sentiment. COVID-19 as well as other factors have resulted in the deepest drop in crude oil prices that global markets have seen since 1991. With the rapid spread of COVID-19, oil prices and the global equity markets deteriorated significantly in 2020. Despite the approval of certain vaccines by the regulatory bodies in Canada and the U.S., the ongoing evolution of the development and distribution of an effective vaccine also continues to raise uncertainty and global equity markets could remain under pressure. The supply/demand imbalance is anticipated to cause a reduction in industry spending in 2021. These events and conditions caused a significant decrease in the valuation of oil and natural gas companies in 2020 and a decrease in confidence in the oil and natural gas industry. COVID-19 also poses a risk on the financial capacity of Parex' contract counterparties and potentially their ability to perform contractual obligations.

The full extent of the risks surrounding the COVID-19 pandemic is continually evolving in light of an effective distribution of the vaccine and also through subsequent waves, or it additional variants of COVID-19 continue to emerge which are more transmissible or cause more severe disease. The following risks disclosed in the Company's Annual Information Form for the year ended December 31, 2020 may be exacerbated as a result of the COVID-19 pandemic: market risks related to the volatility of oil and gas prices, volatility of foreign exchange rates, volatility of the market price of common shares, and hedging arrangements; operational risks related to increasing operating costs or declines in production levels, operator performance and payment delays, and government regulations, ability to obtain additional financing, and variations in foreign exchange rates; and other risks related to cyber-security as the Company's workforce moves to remote connections, accounting adjustments, effectiveness of internal controls, and reliance on key personnel, management, and labour.

Changing Investor Sentiment

A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, the impact of oil and gas operations on the environment, environmental damage relating to spills of petroleum products during transportation and indigenous rights, have affected certain investors' sentiments towards investing in the oil and gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Board, management and employees of the Company. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in the Company or not investing in the Company at all. Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, the Company, may result in limiting the Company's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares even if the Company's operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause a decrease in the value of the Company's assets which may result in an impairment change.

The Company's workforce may be exposed to widespread pandemic

Parex' operations are located in areas relatively remote from local towns and villages and represent a concentration of personnel working and residing in close proximity to one another. Should an employee or visitor become infected with a serious illness that has the potential to spread rapidly, this could place Parex' workforce at risk. The 2020 outbreak of the novel coronavirus (COVID-19) in China and other countries around the world is one example of such an illness. The Company takes every precaution to strictly follow industrial hygiene and occupational health guidelines. There can be no assurance that this virus, virus variants or another infectious illness will not impact Parex' personnel and ultimately its operations.

Foreign Jurisdiction Political Risk

Parex is focused on international oil and natural gas exploration and production activities in Colombia. As such, the Company is subject to potential political risks such as: changes in polices and regulation related to changes in government, price controls, renegotiation of land tenure agreements, nationalization, changes in tax and royalty regulations, amendments or changes to legal systems, and complex regulatory regimes. The Company focuses its foreign operations in countries where management has prior experience and/or engages local in-country staff as soon as possible. The Company engages local, Canadian and international advisors. The Company may also, from time to time, arrange for insurance to mitigate specific risks. The Company is also exposed to potential delay of its operations due to waiting on permits or obtaining surface access to drilling locations.

Venezuela Presidential Crisis

A crisis concerning who is the legitimate President of Venezuela has been underway since January 10th, 2019, when the opposition-majority National Assembly declared that incumbent Nicolás Maduro's 2018 re-election was invalid and the body declared its president, Juan Guaidó, to be acting president of the nation. As of February 2019, Guaidó is recognized as the interim president of Venezuela by more than 50 countries including the United States and most Latin American and European countries. Maduro's government states that the crisis is a "coup d'état" led by the United States to topple him and control the country's oil reserves." Guaidó denies the coup allegations, saying peaceful volunteers back his movement.

The crisis has had a profound impact on the people of Venezuela and its neighboring countries including Colombia. At this time, it is unknown what the impact will be on the regions oil markets, and Colombia foreign relations and politics.

The Capachos block, which the Company operates is 75 km from the Venezuelan border to Colombia in the department of Arauca. The Company is monitoring the situation closely but to date has not seen any material impacts of the crises on the operations of the Company however, it cannot be foreseen whether this will change in the future.

Security in Colombia

A 50-year armed conflict between government forces and anti-government insurgent groups and illegal paramilitary groups, both thought to be funded by the drug trade, continues in Colombia. Insurgents continue to attack civilians and violent guerrilla activity continues in certain parts of the country. Regions that border Venezuela and Ecuador have historically been areas of high security risk and there continues to be guerrilla activity.

Continuing attempts to reduce or prevent guerrilla activity may not be successful and guerrilla activity may disrupt Parex Colombia operations in the future. The Company may not be able to establish or maintain the safety of its operations and personnel in Colombia and this violence may affect its operations in the future. Continued or heightened security concerns in Colombia could also result in a significant loss to Parex and/or costs exceeding current expectations.

Reserves Estimates

Parex has retained an independent engineering consulting firm that assists the Company in evaluating oil and natural gas reserves on an annual basis. Reserve values are based on a number of variables and assumptions such as future commodity prices, projected production, future production costs and governmental regulations. Reserve estimates are prepared in accordance with standards and procedures set out in the COGE and NI 51-101. The reserves and recovery information contained in the independent reserve report is an estimate. The actual production and ultimate reserves from the properties may be greater or less than the estimates prepared by the independent reserve engineers.

Volatility of Commodity Prices and Foreign Exchange Rates

The Company's operational results and financial condition depend on the prices received for petroleum production. Commodity prices are determined by economic and, in some circumstances, political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions, also influence prices. Parex is exposed to commodity price risk whereby the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum are affected by the global economic events that dictate the levels of supply and demand. As at the date of this MD&A, Parex has no active crude oil hedges in place (see "Risk Management Contracts – Brent Crude").

Foreign currency risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate as a result of changes in foreign currency exchange rates. The Company is exposed to foreign currency fluctuations as various portions of its cash balances and future expenses and revenues are denominated in Colombian pesos (COP) and Canadian dollars (Cdn$). As at the date of this MD&A, Parex does not have active foreign exchange hedges in place (see "Risk Management Contracts – Foreign Exchange").

Counterparty Risk

Credit risk is the risk of a counterparty failing to meet its obligations in accordance with the agreed upon terms. The Company may be exposed to third-party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its commodities and other parties. Parex has established credit policies and controls designed to mitigate the risk of default or non-payment with respect to oil and natural gas sales, financial hedging transactions and joint venture participants. The Company makes every effort to sell its commodities to major companies with excellent credit ratings and/or managing its crude production on a portfolio basis.

Access to Capital

From time to time, the Company may have to raise additional funds to finance business development activities. Parex' ability to raise additional capital will depend on a number of factors such as general economic and market conditions that are beyond the Company's control. Internally generated funds will also fluctuate with changing commodity prices. Parex currently has a $200.0 million syndicated credit facility with three banks. The Company is required to comply with covenants under this facility and in the event it does not comply, access to capital could be restricted or repayment may be required. At the date of this MD&A bank debt was $nil. Parex routinely reviews the covenants based on actual and forecasted results and has the ability to make changes to development and exploration plans to comply with the covenants under the credit facility. Parex is committed to maintaining a strong balance sheet, which at current has available working capital, along with an adaptable capital expenditure program that can be adjusted to capitalize on, or reflect acquisition opportunities and, if necessary a tightening of liquidity sources. From the company's founding to the date of this MD&A, Parex has had no defaults or breaches on its bank debt or any of its financial liabilities.

Operational Matters

The oil and natural gas industry is intensely competitive, with Parex competing against companies that may have greater technical and financial resources. There is competition for new exploration and development properties, for infrastructure and sales contracts, for drilling and other specialized technical equipment and for experienced key human resources. As appropriate, Parex seeks to enter into joint venture arrangements with large and/or experienced industry players.

There are also extensive and varying environmental regulations imposed by the governments in the countries in which Parex operates. The Company adopts prudent and industry-recommended field operating procedures in all of its operations, as well as maintaining a health, safety and environment program.

Exploration

The Company is exposed to a high level of exploration risk. The Company's current and future (to the extent discovered or acquired) proved reserves will decline as reserves are produced from its properties unless the Company is able to acquire or develop new reserves. The business of exploring for, developing or acquiring reserves is capital-intensive and is subject to numerous estimates and interpretations of geological and geophysical data. There can be no assurance that the Company's future exploration, development and acquisition activities will result in material additions of proved reserves. To manage this risk, to the extent possible, Parex employs highly experienced geologists and geophysicists, uses technology such as 3D seismic as a primary exploration tool and focuses exploration efforts in known hydrocarbonproducing basins. In addition, the Company takes a portfolio approach to exploration by dispersing drilling locations among different exploration blocks and geological basins and by targeting multiple play-types. The Company may also choose to mitigate exploration risk through acquisitions that may require raising funds.

Cyber-Security

The Company is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Company's information technology systems by third parties or insiders. Although the Company has security measures and controls in place that are designed to mitigate these risks, a breach of its security measures and/or a loss of information could occur and result in a loss of material and confidential information and reputation, breach of privacy laws and a disruption to its business activities. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Company's business, financial condition and results of operations. Parex relies on information technology, such as computer hardware and software systems, in order to properly operate its business. In the event the Company is unable to regularly deploy software and hardware, effectively upgrade systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data. In addition, information systems could be damaged or interrupted by natural disasters, force majeure events, telecommunications failures, power loss, acts of war or terrorism, computer viruses, malicious code, physical or electronic security breaches, intentional or inadvertent user misuse or error, or similar events or disruptions. Any of these or other events could cause interruptions, delays, loss of critical or sensitive data or similar effects, which could have a material adverse impact on the protection of intellectual property, and confidential and proprietary information, and on Parex' business, financial condition, results of operations and funds flow from operations.

Internal Controls over Financial Reporting

Disclosure controls and procedures ("DC&P"), as defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, are designed to provide reasonable assurance that information required to be disclosed in annual filings, interim filings or other reports filed, or submitted by the Company under securities legislation authorities is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the Company's management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Chief Executive Officer and the Chief Financial Officer of Parex evaluated the effectiveness of the design and operation of the Company's DC&P. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded Parex DC&P were effective as at December 31, 2020.

Internal control over financial reporting ("ICFR"), as defined in National Instrument 52-109, includes those policies and procedures that:

• 1. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of Parex;
• 1. Are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of Parex are being made in accordance with authorizations of management and Directors of Parex; and
• 1. Are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the annual financial statements or interim financial reports.

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining ICFR for Parex. They have, as at the financial year ended December 31, 2020, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control framework Parex officers used to design the Company's ICFR is the 2013 Internal Control - Integrated Framework ("COSO Framework") published by The Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Under the supervision of the Chief Executive Officer and the Chief Financial Officer, Parex conducted an evaluation of the effectiveness of the Company's ICFR as at December 31, 2020 based on the COSO Framework. Based on this evaluation, the officers concluded that as of December 31, 2020, Parex maintained effective ICFR. It should be noted that while Parex officers believe that the Company's controls provide a reasonable level of assurance with regard to their effectiveness, they do not expect that the DC&P and ICFR will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system are met.

There were no changes in Parex' ICFR during the year ended December 31, 2020 that materially affected, or are reasonably likely to materially affect, the Company's ICFR.

Off-Balance-Sheet Arrangements

The Company did not enter into any off-balance-sheet arrangements during the twelve months ended December 31, 2020.

Financial Instruments and Other Instruments

The Company's non-derivative financial instruments recognized in the consolidated balance sheet consist of cash, accounts receivable, accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair value. The fair values of the current financial instruments approximate their carrying value due to their short-term maturity.

Related Party Transactions

Compensation of Key Management Personnel

Key management personnel compensation, including directors, is as follows:

	2020	2019
Salaries, directors' fees and other benefits	$4,515$	4,241
Equity settled share-based compensation	1,613	3,714
Cash settled share-based compensation	1,451	4,934
	$7,579$	12,889

At December 31, 2020 key management personnel are comprised of the Company's directors and eight executives. As at December 31, 2020, there is a Cdn$9.1 million commitment relating to change of control or termination of employment of the eight executives (December 31, 2019 - Cdn$8.9 million for the seven executives).

Other related party transactions

The Company did not have any related party transactions with entities outside the consolidated group for the years ended December 31, 2020 and 2019.

Significant Accounting Policies

Refer to note 3 - Summary of Significant Accounting Policies of the December 31, 2020 consolidated financial statements for a summary of significant accounting policies applied by the Company.

Significant Accounting Estimates

The preparation of consolidated financial statements in accordance with IFRS requires management to make significant judgments, assumptions and estimates that affect the financial results of the Company. The following discussion outlines the accounting policies and practices involving the use of estimates that the Company believes are critical in determining Parex' financial results.

Oil and natural gas reserves

The Company retains qualified independent reserves evaluators to evaluate the Company's proved and probable oil and natural gas reserves. As at December 31, 2020 and in prior periods, Parex' reserves were evaluated by GLJ Ltd., who are a firm of qualified independent reserves evaluators. The evaluation was conducted in accordance with the COGE handbook and NI 51-101. The Operations and Reserves Committee of the Company's Board of Directors is comprised of independent directors whose mandate is to steward the reserves evaluation process.

The estimation of reserves involves the exercise of judgment. Forecasts are based on engineering data, expected rates of production and the timing of future capital expenditures, all of which are subject to major uncertainties and interpretations. The Company expects that over time its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels. Reserve estimates can have a significant impact on net income, as they are a key component in the calculation of DD&A and for determining potential asset impairment. A downward revision in reserves estimates or an increase in estimated future development costs could result in the recognition of a higher DD&A charge to net income.

Oil and natural gas assets (development and producing costs) are aggregated into CGUs based on their ability to generate largely independent cash flows. If the carrying value of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income. The recoverable amount of an asset or CGU is the greater of its fair value less costs to sell and its value in use. Fair value less costs to sell may be determined using discounted future net cash flows of proved plus probable reserves using forecast prices and costs. A downward revision in reserves estimates could result in the recognition of impairments charged to net income.

Reversals of impairments are recognized when there has been a subsequent increase in the recoverable amount. In this event, the carrying amount of the asset or CGU is increased to its revised recoverable amount with an impairment reversal recognized in net income.

Decommissioning and environmental liabilities

The Company is required to recognize a liability for future dismantling, decommissioning, environmental, abandoning and site disturbance remediation costs associated with the Company's oil and natural gas properties in accordance with existing laws, contracts or other policies. The fair value of the estimated decommissioning and environmental liability is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related long-lived asset, which is depleted on a unit-of-production basis over the life of the reserves. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to net income, and for revisions to the estimated future cash flows. Actual costs incurred upon settlement of the obligations are charged against the liability.

Decommissioning and environmental liabilities are determined by using management's best estimate of costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances, industry practices and the possible use of the site. Since these estimates are specific to the sites involved, there are many individual assumptions underlying the Company's total decommissioning and environmental liability. These individual assumptions can be subject to change based on experience. Restoration technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. The Company estimates future decommissioning and environmental costs based on current estimates adjusted for inflation. This estimate for inflation is also subject to management uncertainty.

Current and Deferred tax

The Company follows the liability method of accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using substantially enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect of a change in income tax rates on deferred tax liabilities and assets is recognized in net income in the period that the change occurs. Deferred tax assets are only recognized to the extent that it is probable that sufficient future taxable income will be available in the applicable jurisdiction to allow the deferred tax assets to be realized.

The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations from multiple jurisdictions. Rates are also affected by legislative changes. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded in the financial statements. Estimates of current income tax for interim periods are also subject to additional uncertainty. A variety of factors cannot be known until year-end and, therefore, estimates are used for interim period current tax provisions.

Share-based compensation

The Company records stock-based compensation expense using the fair value method. The fair value of an option is calculated at the grant date, and expensed equally over the vesting term of the option. The Company records the cumulative stock-based compensation as contributed surplus. When options are exercised, contributed surplus is reduced and share capital is increased by the amount of accumulated stock-based compensation for the exercised option. Any consideration received on the exercise of stock options is credited to share capital.

The determination of stock-based compensation expense is based on assumptions regarding stock volatility, risk-free interest rates and the expected life of the options. These assumptions, by their nature, are subject to measurement uncertainty.

Obligations for payments of cash under the subsidiaries' SARs plan are accrued as compensation expense over the vesting period based on the fair value of SARs, subject to appreciation limits specified in the plan. The fair value of SARs is measured using the Black-Scholes pricing model. In accordance with the fair value method, increases or decreases in the fair value of the SARs result in a corresponding change in the recorded liability. The accrued compensation for a right that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture.

The determination of SARs expense is based on assumptions regarding stock volatility, risk-free interest rates and the expected life of the SAR. These assumptions, by their nature, are subject to measurement uncertainty.

The fair value of an RSU, PSU and CRSU is calculated using the market price of Parex shares on the date of issuance, and expensed over the vesting period of the RSU, PSU or CRSU.

In accordance with the fair value method, increases or decreases in the fair value of the CRSUs result in a corresponding change in the recorded liability. The accrued compensation for a right that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture.

PSUs may be granted with certain performance measures, specified at the grant date as determined by the Company's Board of Directors. Based upon the achievement of the performance measures, a pre-determined adjustment factor of between 0-2x is applied to PSUs eligible to vest at the end of the performance period. The expense recognized over the vesting period of PSUs is the fair value of the PSUs with an estimated adjustment factor.

The fair value of a DSU is calculated using the market price of Parex shares on the date of issuance, and expensed immediately. In accordance with the fair value method, increases or decreases in the fair value of the DSUs result in a corresponding change in the recorded liability. The accrued compensation for a right that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture.

Obligations for payments of cash under the CosRSUs and CosPSUs plans are accrued as compensation expense over the vesting period based on the fair value of CosRSUs and CosPSUs. The fair value of CosRSUs and CosPSUs is equivalent to the trading value of a common share of the Company on the valuation date.

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired, and is assessed for impairment annually at December 31 of each year. To test for impairment, goodwill is allocated to each of the Company's CGUs, or groups of CGUs, that are expected to benefit from the acquisition and is tested as described in the Company's impairment policy. The recoverable amount of an asset or a CGU is the greater of its value in use and its FVLCD.

Value in use is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or CGU. FVLCD is based on available market information, where applicable. In the absence of such information, FVLCD is determined using discounted future net cash flows of proved plus probable reserves using forecast prices and costs. A downward revision in reserves estimates could result in the recognition of a goodwill impairment charge to net earnings.

These calculations require the use of estimates and assumptions and are subject to changes as new information becomes available including information on future commodity prices, expected production volumes, quantity of reserves and discount rates as well as future development and operating costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs.

Derivative liabilities

Risk management contracts are initially recognized at fair value on the date a derivative contract is entered into and are remeasured at their fair value at each subsequent reporting date. The fair value of the risk management contract on initial recognition is normally the transaction price. Subsequent to initial recognition, the fair value are based on quoted market price where available from active markets, otherwise fair values are estimated based on market prices at the reporting date for similar assets or liabilities with similar terms and conditions.

Legal, environmental remediation and other contingent matters

In respect of these matters, the Company is required to determine both whether a loss is probable based on judgment and interpretation of laws and regulations and if such a loss can reasonably be estimated. When any such loss is determined, it is charged to net income. Management continually monitors known and potential contingent matters and makes appropriate provisions by charges to net income when warranted by circumstances.

DIRECTORS	CORPORATE HEADQUARTERS	AUDITORS
Wayne FooChairman of the Board	Parex Resources Inc.2700, Eighth Avenue Place, West Tower	PricewaterhouseCoopers LLPCalgary, Alberta
Lisa Colnett	585 8 Avenue S.W.,Calgary, Alberta, Canada T2P 1G1	LEGAL COUNSEL
Sigmund Cornelius	Tel: 403-265-4800	Burnet, Duckworth & Palmer LLP
Robert Engbloom	Fax: 403-265-8216E-mail: info@parexresources.com	Calgary, Alberta
Bob MacDougall	OPERATING OFFICES	TRANSFER AGENTAND REGISTRAR
Glenn McNamara	Parex Resources Colombia Ltd. Sucursal	Computershare Trust Company of
Imad Mohsen	Calle 113 No. 7-21, Of. 611,Edificio Teleport, Torre A,	CanadaCalgary, Alberta
Carmen Sylvain	Bogotá, Colombia	RESERVES EVALUATORS
Paul Wright	Tel: 571-629-1716Fax: 571-629-1786	GLJ Ltd.Calgary, Alberta
OFFICERS & SENIOR EXECUTIVES		INVESTOR RELATIONS
Imad MohsenPresident and Chief Executive Officer		Michael KruchtenSr. Vice President, Capital Markets &Corporate Planning
Eric FurlanChief Operating Officer		Tel: 403-517-1733Fax: 403-265-8216
Kenneth G. PinskyChief Financial Officer & Corporate Secretary		E-mail:
Daniel FerreiroPresident, Parex Colombia & Country Manager		Investor.Relations@parexresources.comWebsite: www.parexresources.com
Ryan FowlerSr. Vice President, Exploration & BusinessDevelopment
Michael KruchtenSr. Vice President, Capital Markets &Corporate Planning
Jeff MeunierVice President, New Ventures
Joshua ShareSr. Vice President, Corporate Services

ABBREVIATIONS

Oil and Natural Gas Liquids

bbl(s)mbblsbbl(s)/dBOE or boeboe/dmcfmcf/d	barrel(s)one thousand barrelsbarrels of oil per daybarrel of oil equivalent, using the conversion factor of 6 Mcf: 1 bblbarrels of oil equivalent per daythousand cubic feetthousand cubic feet per day
Other
WTIBrent	West Texas IntermediateBrent Ice
Vasconia	Vasconia Crude
FFO	Funds flow provided by operations

"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.