ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2014

April 22, 2015

TABLE OF CONTENTS

SELECTED DEFINITIONS ......................................................................................................................................... 1 ABBREVIATIONS ....................................................................................................................................................... 4 CONVERSION ............................................................................................................................................................. 4 PRESENTATION OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION .................................... 4 MARKET AND INDUSTRY DATA ............................................................................................................................ 8 SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS ................................................................ 8 EXCHANGE RATE INFORMATION ....................................................................................................................... 12 PRESENTATION OF INFORMATION ..................................................................................................................... 12 CORPORATE STRUCTURE ..................................................................................................................................... 13 GENERAL DEVELOPMENT OF THE BUSINESS .................................................................................................. 14 BUSINESS OF THE CORPORATION ...................................................................................................................... 17 INDUSTRY CONDITIONS ........................................................................................................................................ 28 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION ........................................ 33 RISK FACTORS ......................................................................................................................................................... 43 DESCRIPTION OF CAPITAL STRUCTURE ........................................................................................................... 59 DIVIDENDS ............................................................................................................................................................... 61 MARKET FOR SECURITIES .................................................................................................................................... 61 PRIOR SALES ............................................................................................................................................................ 61 DIRECTORS AND EXECUTIVE OFFICERS........................................................................................................... 62 LEGAL PROCEEDINGS AND REGULATORY ACTIONS .................................................................................... 64 INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS ........................................ 65 AUDITORS, TRANSFER AGENT AND REGISTRAR ............................................................................................ 65 MATERIAL CONTRACTS ........................................................................................................................................ 65 INTERESTS OF EXPERTS ........................................................................................................................................ 65 ADDITIONAL INFORMATION................................................................................................................................ 66

APPENDIX A – FORM 51-101F2 – REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED

RESERVES EVALUATOR

APPENDIX B – FORM 51-101F3 – REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS

DISCLOSURE

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SELECTED DEFINITIONS

In this Annual Information Form, the capitalized terms set forth below have the following meanings:

“2012 Financing” has the meaning set forth under the heading “General Development of the Business ‒ Three Year

History of the Corporation – Year Ended December 31, 2012”;

“ABCA” means the Business Corporations Act (Alberta) and the regulations thereunder, as amended;

“ACIPET” means Asociación Colombiana de Ingenieros Petróleos, the Colombian Society of Petroleum Engineers;

“ANH” means the Agencia Nacional de Hidrocarburos, or the National Hydrocarbons Agency, an agency of the

Colombian government and the Colombian hydrocarbons regulator;

“ANLA” means the National Agency of Environmental Licences of Colombia, an agency of MADT;

“Annual Information Form” means this annual information form of PetroNova dated April 22, 2015;

“Board of Directors” means the board of directors of the Corporation, as constituted from time to time;

“Caguan-Putumayo Basin” means the Caguan-Putumayo Basin located in southern Colombia;

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of

Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy and Petroleum;

“Colombia” means the Republic of Colombia;

“Colombian Blocks” means, collectively, the PUT 2 Block, the Tinigua Block and the Llanos Blocks as described

under the heading “Business of the Corporation – The Corporation’s Oil and Gas Properties”;

“Common Shares” means common shares in the capital of the Corporation as presently constituted;

“Contractor” has the meaning set forth under the heading “Industry Conditions – E&P Contracts”;

“Corporation” or “PetroNova” means PetroNova Inc., a corporation incorporated under the laws of Alberta and

includes, except where the context otherwise requires, the Corporation’s subsidiaries;

“CPO 6 Block” means the CPO 6 Block located in the Llanos Basin;

“CPO 7 Block” means the CPO 7 Block located in the Llanos Basin;

“CPO 7 E&P Contract” means the E&P Contract relating to the CPO 7 Block dated January 14, 2009 between the

ANH, Tecpetrol and Inepetrol S.A., which was subsequently assigned to PetroNova Colombia - Branch in March

2010;

“CPO 13 Block” means the CPO 13 Block located in the Llanos Basin;

“CPO 13 E&P Contract” means the E&P Contract relating to the CPO 13 Block dated January 14, 2009 between

the ANH, Tecpetrol and Inepetrol S.A., which was subsequently assigned to PetroNova Colombia - Branch in March

2010;

“CSA Notice 51-324” means Canadian Securities Administrators Staff Notice 51-324 – Glossary to NI 51-101

Standards of Disclosure for Oil and Gas Activities;

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“E&P Contract” means an exploration and production contract used in Colombia established by the ANH, as more

particularly described under the heading “Industry Conditions – E&P Contracts”;

“Ecopetrol” means Ecopetrol S.A., formerly known as Empresa Colombiana de Petróleos S.A.;

“EIA” means an environmental impact assessment;

“EMP” means an environmental management plan;

“Exploratory A-2 Well” means an exploratory well that is drilled in a structural or stratigraphic feature where oil or

natural gas have been previously discovered (new reservoir exploratory well);

“Exploratory A-3 Well” means an exploratory well that is drilled in a structural or stratigraphic feature where no oil

or natural gas have been previously discovered (new field wildcat);

“IFC” means International Finance Corporation;

“IFC ALAC Fund” means the IFC African, Latin American and Caribbean Fund, LP;

“IFC ALAC Subscription Agreement” means the equity, warrant and note subscription agreement dated September

7, 2012 between the Corporation and the IFC ALAC Fund;

“IFC Subscription Agreement” means the equity, warrant and note subscription agreement dated September 7, 2012

between the Corporation and IFC;

“Inelectra” means Inelectra S.A.C.A., a body corporate incorporated under the laws of Venezuela, and where the

context requires, its affiliates;

“Inepetrol Corporation A.B.” means a body corporate incorporated under the laws of Sweden;

“Inepetrol S.A.” means a body corporate incorporated under the laws of Venezuela and a wholly owned subsidiary

of Inepetrol Corporation A.B.;

“Llanos Basin” means the Llanos Basin located in the eastern region of Colombia;

“Llanos Blocks” means, collectively, the CPO 7 Block and the CPO 13 Block;

“Llanos Contractors” has the meaning set forth under the heading “Business of the Corporation – The Corporation’s

Oil and Gas Properties – Llanos Basin – CPO 7 Block”;

“MADT” means the Ministry of Environment and Territorial Development of Colombia, formerly known as the

Minister of Environment, Housing and Territorial Development of Colombia;

“NI 51-101” means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities of the Canadian

Securities Administrators;

“NI 51-102” means National Instrument 51-102 – Continuous Disclosure Obligations of the Canadian Securities

Administrators;

“Notes” means the non-interest bearing convertible promissory notes of the Corporation that were due August 15,

2013;

“Option Plan” means the stock option plan of the Corporation;

“Options” means stock options of the Corporation;

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“Participating Interest” means with respect to any party to an E&P Contract, the undivided ownership interest of

such party (expressed as a percentage of the total ownership interests of all parties in such contract) in the rights and

obligations derived from such contract, which ownership interest has been recognized by the ANH and the Colombian

Ministry of Energy and Mines;

“PetroNova International Inc.” means a body corporate incorporated under the laws of the Cayman Islands and a

wholly owned subsidiary of the Corporation;

“PetroNova Colombia Inc.” means a body corporate incorporated under the laws of the Cayman Islands and a wholly

owned subsidiary of PetroNova International Inc.;

“PetroNova Colombia - Branch” means the Colombian branch of PetroNova Colombia Inc.;

“Petrotech” means Petrotech Engineering Ltd., an independent petroleum engineering firm;

“Petrotech Report” means the report prepared by Petrotech dated March 20, 2015 and effective as of December 31,

2014 entitled “Evaluation of the Interests of PetroNova Inc. in CPO 7 and 13 Blocks in the Eastern Llanos Basin,

Colombia”;

“PRE Agreement” means the farm-out agreement dated February 27, 2014 between the Corporation’s wholly owned

subsidiary PetroNova Colombia Inc. and a wholly owned subsidiary of Pacific Rubiales Energy Corp. (“PRE”) in

respect of the Tinigua Block;

“Private Working Interest” means with respect to any person, the undivided interest of such person (expressed as a

percentage of the total interests of all parties) in the rights and obligations derived from an E&P Contract pursuant to

a private agreement, which interest has not been recognized as a Participating Interest by the ANH;

“PUT 2 Block” means the PUT 2 Block located in the Caguan-Putumayo Basin;

“PUT 2 E&P Contract” means the E&P Contract relating to the PUT 2 Block dated February 18, 2009 between the

ANH and Inepetrol S.A., which was subsequently assigned to PetroNova Colombia - Branch in March 2010;

“Reserves Data” has the meaning set forth under the heading “Statement of Reserves Data and Other Oil and Gas

Information – Disclosure of Reserves Data”;

“Series A Preferred Share” means the one (1) Series A preferred share of the Corporation;

“Series A Warrants” means the Series A Common Share purchase warrants of the Corporation;

“Series B Warrants” means the Series B Common Share purchase warrants of the Corporation;

“Suroco Agreement” means the definitive agreement dated July 19, 2013 between the Corporation, PetroNova

Colombia Inc., Suroco Energy Inc. and Suroco Energy SLU (“Suroco SLU”) in respect of the PUT 2 Block;

“Tecpetrol” means Tecpetrol Colombia S.A.S. (formerly Tecpecol S.A.), a body corporate incorporated under the

laws of Colombia, and an affiliate of Tecpetrol S.A.;

“Tinigua Block” means the Tinigua Block located in the Caguan-Putumayo Basin;

“Tinigua E&P Contract” means the E&P Contract relating to the Tinigua Block dated January 23, 2009 between the

ANH and Inepetrol S.A., which was subsequently assigned to PetroNova Colombia - Branch in March 2010;

“Tinigua Participation Agreement” means the agreement dated May 10, 2010 between PetroNova Colombia Inc.

and an independent third party, pursuant to which PetroNova Colombia Inc. has agreed to assign 10% of its

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Participating Interest in the Tinigua E&P Contract, as more particularly described under the heading “Business of the

Corporation – The Corporation’s Oil and Gas Properties – Caguan Putumayo Basin – Tinigua Block”;

“TSXV” means the TSX Venture Exchange;

“United States” or “U.S.” means the United States of America, its territories and possessions, any state of the United

States and the District of Columbia; and

Certain terms used in this Annual Information Form in describing reserves and other oil and natural gas information

are defined under the heading “Presentation of Reserves Data and Other Oil and Gas Information”. Certain other

terms and abbreviations used in this Annual Information Form, but not defined or described, are defined in NI 51-101,

CSA Notice 51-324 or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings

herein as in NI 51-101, CSA Notice 51-324 or the COGE Handbook.

ABBREVIATIONS

In this Annual Information Form, the abbreviations set forth below have the following meanings:

API the American Petroleum Institute m3 cubic metres

API° a degree of gravity that provides a relative measure of

crude oil density

Mcf thousand cubic feet

Bbl barrel of oil Mbbl thousand barrels of oil

Bbl/d barrels of oil per day MMbbl million barrels of oil

BOE barrel of oil equivalent MMBTU million British thermal units

BOE/d barrel of oil equivalent per day WTI West Texas Intermediate

km kilometres $/Bbl U.S. Dollars per barrel

km2 square kilometres 2D two dimensional

m metres 3D three dimensional

M$ thousand U.S Dollars

CONVERSION

To Convert From To Multiply By

cubic metres cubic feet 35.494

Bbls cubic metres 0.159

cubic metres Bbls 6.290

litre Bbls 0.0063

miles km 1.609

km miles 0.621

feet metres 0.305

metres feet 3.281

acres hectares 0.405

hectares acres 2.471

PRESENTATION OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Caution Respecting Reserves Information

The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of

associated uncertainty. Categories of proved and probable reserves have been established to reflect the level of these

uncertainties and to provide an indication of the probability of recovery. The estimation and classification of reserves

requires the application of professional judgment combined with geological and engineering knowledge to assess

whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including

uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to

properly use and apply reserves definitions.

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With respect to the disclosure of reserves contained herein relating to portions of the Corporation’s properties, the

estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as

estimates of reserves and future net revenue for all properties due to the effects of aggregation.

The recovery and reserve estimates of reserves provided herein are estimates only. Actual reserves may be

greater than or less than the estimates provided herein. The estimated future net revenue from the production

of PetroNova’s petroleum reserves does not represent the fair market value of PetroNova’s reserves. See

“Statement of Reserves Data and Other Oil and Gas Information”.

Caution Respecting BOE

The Corporation has adopted the standard of 6 Mcf:1 Bbl when converting natural gas to BOEs. BOEs may be

misleading, particularly if used in isolation. A BOE conversion ratio of 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.

Caution Respecting Test Results

Test results are not necessarily indicative of long-term performance or of ultimate recovery.

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable

from known accumulations, as of a given date, based on:

analysis of drilling, geological, geophysical and engineering data;

the use of established technology; and

specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.

Reserves are classified according to the degree of certainty associated with the estimates.

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable.

It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves.

It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of

the estimated proved plus probable reserves.

Development and Production Status

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories.

Developed reserves are those reserves that are expected to be recovered from existing wells and installed

facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when

compared to the cost of drilling a well) to put the reserves on production. The developed category may

be subdivided into producing and non-producing.

o Developed producing reserves are those reserves that are expected to be recovered from completion

intervals open at the time of the estimate. These reserves may be currently producing or, if shut in,

they must have previously been on production, and the date of resumption of production must be

known with reasonable certainty.

o Developed non-producing reserves are those reserves that either have not been on production, or

have previously been on production, but are shut in, and the date of resumption of production is

unknown.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a

significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them

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capable of production. They must fully meet the requirements of the reserves category (proved, probable)

to which they are assigned.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and

undeveloped categories or to subdivide the developed reserves for the pool between developed producing

and developed non-producing. This allocation should be based on the evaluator’s assessment as to the

reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and

their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to “individual reserve entities”, which

refers to the lowest level at which reserves calculations are performed, and to “reported reserves”, which refers to the

highest level sum of individual entity estimates for which reserve estimates are presented. Reported reserves should

target the following levels of certainty under a specific set of economic conditions:

at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated

proved reserves; and

at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the

estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is

desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserve

estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative measure

of probability. In principle, there should be no difference between estimates prepared using probabilistic or

deterministic methods.

Forecast Prices and Costs

“Forecast prices and costs” means future prices and costs that are:

(a) generally accepted as being a reasonable outlook of the future; and

(b) if, and only to the extent that, there are fixed or presently determinable future prices or costs to

which the Corporation is legally bound by a contractual or other obligation to supply a physical

product, including those for an extension period of a contract that is likely to be extended, those

prices or costs rather than the prices or costs referred to in paragraph (a).

Interests in Reserves, Production, Wells and Properties

“gross” means:

(a) in relation to the Corporation’s interest in production or reserves, its “company gross reserves”,

which are the Corporation’s working interest (operating or non-operating) share before deduction

of royalties and without including any royalty interests of the Corporation;

(b) in relation to wells, the total number of wells in which the Corporation has an interest; and

(c) in relation to properties, the total area of properties in which the Corporation has an interest.

“net” means:

(a) in relation to the Corporation’s interest in production or reserves, the Corporation’s working interest

(operating or non-operating) share after deduction of royalty obligations, plus the Corporation’s

royalty interests in production or reserves;

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(b) in relation to the Corporation’s interest in wells, the number of wells obtained by aggregating the

Corporation’s working interest in each of its gross wells; and

(c) in relation to the Corporation’s interest in a property, the total area in which the Corporation has an

interest multiplied by the working interest owned by the Corporation.

Exploration and Development Wells and Costs

“Development costs” mean costs incurred to obtain access to reserves and to provide facilities for extracting, treating,

gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable

operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a) gain access to and prepare well locations for drilling, including surveying well locations for the

purpose of determining specific development drilling sites, clearing ground, draining, road building,

and relocating public roads, gas lines and power lines, to the extent necessary in developing the

reserves;

(b) drill and equip development wells, development type stratigraphic test wells and service wells,

including the costs of platforms and of well equipment such as casing, tubing, pumping equipment

and the wellhead assembly;

(c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters,

manifolds, measuring devices and production storage tanks, natural gas cycling and processing

plants, and central utility and waste disposal systems; and

(d) provide improved recovery systems.

“Exploration costs” mean costs incurred in identifying areas that may warrant examination and in examining specific

areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory

wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related

property (sometimes referred to in part as “prospecting costs”) and after acquiring the property. Exploration costs,

which include applicable operating costs of support equipment and facilities and other costs of exploration activities,

are:

(a) costs of topographical, geochemical, geological and geophysical studies, rights of access to

properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews

and others conducting those studies (collectively sometimes referred to as “geological and

geophysical costs”);

(b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income

and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease

records;

(c) dry hole contributions and bottom hole contributions;

(d) costs of drilling and equipping exploratory wells; and

(e) costs of drilling exploratory type stratigraphic test wells.

“Development well” means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity

to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

“Exploratory well” means a well that is not a development well, a service well or a stratigraphic test well.

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“Service well” means a well drilled or completed for the purpose of supporting production in an existing field. Wells

in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas),

water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection

for combustion.

“Stratigraphic test well” means a drilling effort, geologically directed, to obtain information pertaining to a specific

geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon

production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon

exploration. Stratigraphic test wells are classified as:

(a) “exploratory type” if not drilled into a proved property; or

(b) “development type”, if drilled into a proved property. Development type stratigraphic wells are also

referred to as “evaluation wells”.

MARKET AND INDUSTRY DATA

This Annual Information Form contains certain statistical, market, corporate and industry data that is based upon

information from the Government of Colombia and certain industry publications and reports (including the Monthly

Statistical Bulletin of ACIPET and statistical reports of the Colombian Central Bank (Banco de la República), the

ANH and the Government of Colombia), published information released by third parties or is based on estimates

derived from same and management’s knowledge of, and experience in, the markets in which the Corporation operates.

Government and industry publications and reports generally indicate that they have obtained their information from

sources believed to be reliable, but do not guarantee the accuracy and completeness of their information. Certain of

ACIPET, the Colombian Central Bank, the ANH, the Government of Colombia or any industry third party in respect

of which published information has been referenced are advisors to participants in the oil and natural gas industry,

and they may present information in a manner that is more favourable to the industry than would be presented by an

independent source. Actual outcomes may vary materially from those forecast in such reports or publications, and the

prospect for material variation can be expected to increase as the length of the forecast period increases. While the

Corporation believes this data to be reliable, market and industry data are subject to variations and cannot be verified

with complete certainty due to limits on the availability and reliability of raw data, the voluntary nature of the data

gathering process and other limitations and uncertainties inherent in any statistical survey. The Corporation has not

independently verified any of the data from third party sources referred to in this Annual Information Form or

ascertained the underlying assumptions relied upon by such sources.

NON-GAAP MEASURES

This Annual Information Form uses “netback” which does not have standardized meanings prescribed by generally

accepted accounting principles and therefore may not be comparable measures to other companies where similar

terminology is used. Netback denotes petroleum and natural gas revenue less royalties, less operating expenses and

less transportation and marketing expenses.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this Annual Information Form constitute forward-looking statements. These

statements relate to future events or the Corporation’s future performance. All statements other than statements of

historical fact are forward-looking statements. The use of any of the words “anticipate”, “plan”, “continue”,

“estimate”, “expect”, “may”, “will”, “project”, “should”, “believe”, “predict” and “potential” and similar expressions

are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties

and other factors that may cause actual results or events to differ materially from those anticipated in such forward-

looking statements. No assurance can be given that these expectations will prove to be correct and such forward-

looking statements included in this Annual Information Form should not be unduly relied upon. These statements

speak only as of the date of this Annual Information Form. In addition, this Annual Information Form may contain

forward-looking statements and forward-looking information attributed to third party industry sources.

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In particular, this Annual Information Form contains forward-looking statements including, among other places, under

the headings “General Development of the Business”, “Business of the Corporation”, “Industry Conditions”,

“Statement of Reserves Data and Other Oil and Gas Information” and “Risk Factors”. This forward-looking

information includes, but is not limited to, statements pertaining to the following:

the Corporation’s business objectives and strategies;

the Corporation’s intention to participate in future bid rounds in Colombia and elsewhere to acquire

additional exploration acreage;

the Corporation’s plans to consider strategic acquisitions and business combination and to look at

partnerships in respect of the development of its properties;

the Corporation’s expected operational, capital and exploration expenditures;

the Corporation’s ability to operate as a going concern;

the Corporation’s seismic acquisition and drilling plans;

the Corporation’s plans for, and anticipated results of, exploration and development activities;

the timing of commencement of certain of the Corporation’s operations and projects;

the results of various projects of the Corporation

the performance characteristics of the Corporation’s oil and natural gas properties;

the estimated quantity and value of the Corporation’s reserves;

expected abandonment and reclamation costs;

the Corporation´s oil and gas production levels and production estimates;

the price to be received by the Corporation upon the sale of its oil;

the timing of development of unproved reserves;

the Corporation’s tax horizon;

the Corporation’s plans to fund future development costs;

the Corporation’s ability to satisfy its minimum exploration programs in respect of its properties;

the Corporation’s access to and ability to raise capital;

the Corporation’s dependence on personnel;

the Corporation’s expectations regarding commodity prices and costs;

expectations regarding the Corporation´s ability to raise capital and to continually add to reserves

through acquisitions, exploration and development;

general economic and financial market conditions;

the receipt of government approval of contracts entered into with industry partners in relation to

properties and operations;

the Corporation’s plans to conduct testing on wells and the results of such testing;

supply and demand fundamentals for crude oil and natural gas; and

the Corporation’s treatment under governmental regulatory regimes and tax laws.

With respect to forward-looking statements and forward-looking information contained in this Annual Information

Form, assumptions have been made regarding, among other things:

future crude oil and natural gas prices;

the Corporation’s ability to operate as a going concern;

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the state of the economy and the exploration and development business in Colombia;

currency exchange rates;

interest and inflation rates;

the Corporation’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient

manner;

the Corporation’s ability to carry out its exploration program as contemplated and to obtain all necessary

licences, permits and approvals;

the regulatory framework governing royalties, taxes and environmental matters in Colombia and any

other jurisdictions in which the Corporation may conduct its business in the future;

the applicability of technologies for recovery and production of the Corporation’s oil and natural gas

resources;

reserve volumes;

the recoverability of the Corporation’s oil and gas reserves and resources;

the Corporation’s future production levels;

the Corporation’s ability to market oil and gas;

future operational, capital and exploration expenditures to be made by the Corporation and the timing

thereof;

the sufficiency of budgeted capital expenditures to carry out planned expenditures;

future sources of funding for the Corporation’s exploration program;

the Corporation’s future debt levels;

operating and general administrative costs;

the performance of existing and future wells and well production rates;

success rates for future drilling;

the geography of the areas in which the Corporation is exploring;

the impact of increasing competition on the Corporation

the availability and demand for labour, services and materials; and

the Corporation’s ability to obtain financing on acceptable terms.

Undue reliance should not be placed on forward-looking information, as there can be no assurance that the plans,

intentions, expectations or assumptions upon which they are based will occur. Although the Corporation believes that

the expectations and assumptions reflected in the forward-looking information are reasonable, there can be no

assurance that such expectations will prove to be correct. As a consequence, actual results may differ materially from

those anticipated.

Forward-looking information necessarily involves both known and unknown risks and uncertainties that could cause

actual results to differ materially from those anticipated including risks associated with:

general economic, market and business conditions;

volatility in market prices for crude oil and natural gas;

risks related to the exploration, development and production of oil and natural gas;

risks inherent in the Corporation’s international operations, including security and legal risks in

Colombia;

risks related to the timing of completion of the Corporation’s projects;

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risks associated with the production, transportation and marketing of oil and natural gas;

competition for, among other things, capital, the acquisition of resources and skilled personnel;

actions by governmental authorities, including changes in government regulation and taxation;

environmental risks and hazards;

risks inherent in the exploration, development and production of oil and natural gas which may create

liabilities to the Corporation in excess of the Corporation’s insurance coverage, if any;

failure to accurately estimate and to establish adequate cash reserves for abandonment and reclamation

costs;

failure of third parties’ reviews, reports and projections to be accurate;

the availability of capital on acceptable terms;

political risks;

the failure of the Corporation or the holder of certain licenses or leases to meet specific requirements of

such licenses or leases;

adverse claims made in respect of the Corporation’s properties or assets;

failure to engage or retain key personnel;

potential losses which would stem from any disruptions in production, including work stoppages or other

labour difficulties, or disruptions in the transportation network on which the Corporation is reliant;

uncertainties inherent in estimating quantities of oil and natural gas reserves and resources;

failure to acquire or develop oil and natural gas resources and reserves;

geological, technical, drilling and processing problems, including the availability of equipment and

access to properties;

failure by counterparties to make payments or perform their operational or other obligations to the

Corporation in compliance with the terms of contractual arrangements between the Corporation and such

counterparties;

current global financial conditions, including fluctuations in interest rates, foreign exchange rates and

stock market volatility;

the other factors discussed under “Risk Factors” in this Annual Information Form.

In addition, information and statements in this Annual Information Form relating to “resources” and “reserves” are

deemed to be forward-looking information and statements, as they involve the implied assessment, based on certain

estimates and assumptions, that the resources and reserves described exist in the quantities predicted or estimated, and

that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the

foregoing list of risk factors should not be construed as exhaustive.

The forward-looking statements included in this Annual Information Form are expressly qualified by this cautionary

statement and are made as of the date of this Annual Information Form. The Corporation does not undertake any

obligation to publicly update or revise any forward-looking statements except as required by applicable securities

laws.

Any “financial outlook” contained in this Annual Information Form, as such term is defined by applicable securities

laws, is provided for the purpose of providing information about management’s current expectations and plans relating

to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

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EXCHANGE RATE INFORMATION

United States Dollars

The following table sets forth, for the periods indicated, the high, low, average and period-end noon spot rates of

exchange for one U.S. dollar, expressed in Canadian dollars, published by the Bank of Canada.

Year Ended December 31,

2014 2013 2012

CDN$ CDN$ CDN$

Highest rate during the period 1.1643 1.0697 1.0418

Lowest rate during the period 1.0614 0.9839 0.9710

Average noon spot rate for period(1) 1.1045 1.0299 0.9983

Rate at the end of the period 1.1601 1.0636 0.9949

Note:

(1) Determined by averaging the noon spot rates on the last business day of each month during the respective period.

On April 22, 2015, the noon spot rate of exchange posted by the Bank of Canada for the conversion of U.S. dollars

into Canadian dollars was $1.00 equals CDN$1.2250.

Colombian Pesos

The following table sets forth, for the periods indicated, the high, low, average and period-end closing spot rates of

exchange for one Colombian peso (COL$), expressed in Canadian dollars, published by the Bank of Canada.

Year Ended December 31,

2014 2013 2012

CDN$ CDN$ CDN$

Highest rate during the period 0.000586 0.000571 0.000582

Lowest rate during the period 0.000476 0.000532 0.000538

Average closing spot rate for period(1) 0.000553 0.000551 0.000557

Rate at the end of the period 0.000486 0.000551 0.000563

Note:

(1) Determined by averaging the closing spot rates on the last business day of each month during the respective period.

On April 22, 2014, the closing spot rate of exchange posted by the Bank of Canada for the conversion of Colombian

pesos into Canadian dollars was COL$1.00 equals CDN$0.000493.

PRESENTATION OF INFORMATION

The information contained in this Annual Information Form is presented as at December 31, 2014 unless otherwise

noted. The Corporation presents its financial statements in U.S. dollars. In this Annual Information Form, references

to “CDN$” and “Canadian dollars” are to Canadian dollars and references to “$”, “US$” and “U.S. dollars” are to

United States dollars. Amounts are stated in United States dollars unless otherwise indicated. Words importing the

singular number only include the plural, and vice versa, and words importing any gender include all genders. Certain

terms used herein are defined in NI 51-101 and CSA Notice 51-324 and, unless the context otherwise requires, shall

have the same meanings in this Annual Information Form as in NI 51-101 or CSA Notice 51-324, as the case may be.

13

CORPORATE STRUCTURE

Name, Address and Incorporation

PetroNova was incorporated as “Inepetrol Inc.” under the ABCA on September 17, 2009, as a wholly owned

subsidiary of Inepetrol Corporation A.B. On May 12, 2010, the Corporation amended its articles to change its name

to “PetroNova Inc.” On June 22, 2010, the Corporation amended its articles to: (i) change the authorized share capital

of the Corporation from an unlimited number of Class “A” common voting shares, Class “B” common voting shares,

Class “C” common non-voting shares and preferred shares to an unlimited number of Common Shares and preferred

shares; (ii) convert the issued and outstanding Class “A” common voting shares into Common Shares; and (iii) change

the minimum number of directors from one to three. On June 28, 2010, the Corporation amended its articles to remove

the restrictions on share transfers. On September 28, 2012, the Corporation amended its articles to create the Series A

Preferred Share that was issued in connection with the 2012 Financing. See “General Development of the Business –

Three Year History of the Corporation – Year Ended December 31, 2012” and “Description of Capital Structure”.

The Corporation’s registered office is located at 1900, 520 – 3rd Avenue S.W., Calgary, Alberta T2P 0R3. The

Corporation conducts substantially all of its operations through PetroNova Colombia - Branch’s office located at Calle

99, No. 9A – 45, piso 6, Bogotá, Colombia.

Intercorporate Relationships

The corporate ownership structure of the Corporation and its subsidiaries is set forth in the diagram below. The

jurisdiction of incorporation of each of the Corporation and its subsidiaries is indicated below its name:

PetroNova Colombia Inc. ( Cayman Islands )

PetroNova Inc. ( Alberta )

PetroNova International Inc. ( Cayman Islands )

PetroNova Colombia –

Branch

(Colombia))

Colombian Assets

100 %

100 %

14

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History of the Corporation

Year Ended December 31, 2012

On February 1, 2012, the Corporation announced an oil discovery at its Puerto Gaitán 1 exploratory well on the CPO

6 Block. In addition, the Corporation commenced an extended well test in the Puerto Gaitán well. On February 29,

2012, the Corporation announced results at its Cusumbo 1 exploratory well and on April 4, 2012, PetroNova

announced results at its Camaleon 1 exploratory well, both located on the CPO 6 Block. The Cusumbo 1 and Camaleon

1 wells were subsequently abandoned.

On May 9, 2012, the Corporation announced an oil discovery at its Atarraya-1 exploratory well located on the CPO 7

Block and the Corporation commenced an extended well test in the Atarraya-1 well which is currently ongoing.

On June 18, 2012, the Corporation announced results at its Pilón-1 exploratory well located on the CPO 7 Block,

which was subsequently abandoned.

On July 25, 2012, the Corporation announced an oil discovery at its Pendare-1 exploratory well located on the CPO

13 Block. The well reached a total depth of 3,265 feet on June 26, 2012 without incident. The well produced an

average of 166 barrels of fluid per day with an average of 15% basic sediment and water.

On September 28, 2012, PetroNova completed a non-brokered private placement (the “2012 Financing”) of

46,153,845 units at a purchase price of CDN$0.65 per unit for aggregate gross proceeds of approximately

CDN$30,000,000. Pursuant to the IFC Subscription Agreement and the IFC ALAC Subscription Agreement, IFC

purchased 23,076,923 units for gross proceeds to the Corporation of approximately CDN$15,000,000 and the IFC

ALAC Fund purchased 18,461,538 units for gross proceeds to the Corporation of approximately CDN$12,000,000,

respectively. In addition, PetroNova issued 4,615,384 units to additional investors on substantially the same terms as

the units issued to IFC and the IFC ALAC Fund for additional gross proceeds to the Corporation of approximately

CDN$3,000,000. Each unit consisted of one Common Share, ½ of one Series A Warrant, ½ of one Series B Warrant

and a pro rata portion of the Notes in the aggregate principal amount of CDN$4,5000,000. In accordance with their

terms, the Notes were subsequently converted into an aggregate of 14,516,130 Common Shares on August 15, 2013.

In addition, the IFC ALAC Fund acquired the Series A Preferred Share for CDN$0.01. The IFC and the IFC ALAC

Fund also received a pre-emptive right on future equity issuances of PetroNova for so long as the IFC and IFC ALAC

Fund hold any securities of the Corporation. The net proceeds from the 2012 Financing were used by the Corporation

to fund its drilling program in the Llanos and Caguan-Putumayo Basins, to further delineate its assets and for general

corporate purposes. For a description of the rights attaching to the Series A Warrants, the Series B Warrants and the

Series A Preferred Share, see “Description of Capital Structure” in this Annual Information Form.

On November 1, 2012, the Corporation resumed its drilling campaign in the Llanos Blocks by drilling the Matamata-

1 exploratory well in the CPO 7 Block. Petrophysical interpretation results showed a low resistivity and high water

saturation in C5 and C7 intervals of the Carbonera formation and the operator decided to abandon the well.

On November 30, 2012, the Corporation provided results on its Arowana-1 exploratory well in the CPO 13 Block.

Petrophysical interpretation results in a low resistivity and high water saturation for the objective C7 sand of the

Carbonera formation and the operator decided to abandon the well.

On December 18, 2012, the Corporation provided an update on the Tornado-1 exploratory well in the CPO 13 Block.

Despite some oil was shown in the Mirador sand sequence, wireline logs acquired after drilling measured low

resistivity in the Carbonera and Eocene Mirador formations and the identified reservoirs were interpreted as water

bearing. The operator decided to abandon the well.

On December 20, 2012, the Corporation obtained the environmental license from ANLA required to commence

drilling in the Canelo-Nogal area of the PUT 2 Block. In the Canelo-Norte area of the same block, agreements with

indigenous communities were reached and signed in November 2012 and the Corporation submitted an application to

15

ANLA to allow the Corporation to commence drilling. The environmental license was subsequently granted on

January 31, 2013.

During the year ended December 31, 2012, the Corporation completed the acquisition, processing and interpretation

of 109 km2 of 3D seismic in the Tinigua Block. All Phase 1 exploration commitments were completed and the

Corporation moved into Phase 2 of the exploration program. An EIA was concluded and submitted to ANLA to request

an environmental license in order to drill exploration wells. Environmental authorities started the analysis of the EIA

submitted and conducted a verification visit to site. PetroNova selected an area to drill the exploration well and

conducted a site survey to determine the first well location. An agreement with the Uribe municipality was reached in

order to work together to repair the existing roads and allow the transportation of the rig loads when required.

During the year ended December 31 2012, the Corporation produced 20,491 Bbls (gross) of crude oil from its extended

production testing and sold 14,000 Bbls. Sales of crude oil obtained during tests have been applied by the Corporation

against its exploration and evaluation assets until the commercialization phase is achieved.

Year Ended December 31, 2013

On January 31, 2013, the Corporation obtained the environmental license from ANLA to drill exploratory wells in the

PUT 2 Block. Subsequently, on October 29, 2013, the Corporation announced that it had spud its first exploratory

well on the PUT 2 Block, namely the Canelo Sur-2 well.

On July 19, 2013, the Corporation, PetroNova Colombia Inc., Suroco Energy Inc. and Suroco SLU entered into the

Suroco Agreement whereby Suroco SLU acquired a 25% Private Working Interest in the PUT 2 Block. Under the

terms of the Suroco Agreement, Suroco SLU acquired an interest in the block in exchange for payment of $3.2 million,

associated with the acquisition of the 2D and 3D seismic and its share of back costs incurred to date on the first well

of the block. Suroco SLU also agreed to pay the first $6 million in costs for the first exploration well drilled on the

block. PetroNova Colombia Inc. paid the next $3 million in costs of said well, with additional costs funded by the

parties based on their respective interests in the block. Suroco SLU’s 25% Private Working Interest will convert into

a full 25% undivided Participating Interest in the block upon approval by the ANH, and an application has been made

to the ANH for such approval. The ANH approval was received in July 2014.

On July 4, 2013, the Corporation entered into an agreement with Tecpetrol, the current operator of the CPO 6 Block,

to relinquish its 20% non-operating interest in the CPO 6 Block to Tecpetrol effective March 31, 2013. The

relinquishment of the CPO 6 Block by PetroNova to Tecpetrol was subsequently approved by the ANH on February

24, 2014. Due to such relinquishment, the Corporation does not have any further commitments in connection with this

block.

In the Llanos Blocks, the Corporation drilled five wells during the year ended December 31, 2013, resulting in two

successful wells (Pendare-2 and Atarraya-4), two unsuccessful wells (Guasco-1 and Cayabana-1) and one well to be

used as a water disposal well (Atarraya-3). In addition, the Corporation moved the CPO 7 Block into Phase 2 of the

exploration program which expires in 2016 and includes additional commitments to drill exploratory wells and

additional seismic. The Corporation completed the acquisition of additional 2D seismic data and has drilled the

Cayabana-1 well as part of these commitments.

During the year ended December 31, 2013, the Corporation produced 93,960 Bbls (gross) of crude oil from its

extended production testing and has sold 87,186 Bbls. Sales of crude oil obtained during tests have been applied

against its exploration and evaluation assets until the commercialization phase is achieved.

Year Ended December 31, 2014

On January 8, 2014, the Corporation announced that it had been granted an environmental license for the Tinigua

Block permitting PetroNova to drill a maximum of 20 exploratory wells from five different platforms, and install

surface facilities for extended testing as required.

16

On February 27, 2014, the Corporation, through its wholly-owned subsidiary PetroNova Colombia Inc., and PRE

entered into the PRE Agreement whereby PRE acquired a 50% Private Working Interest in the Tinigua

Block. Pursuant to the terms of the PRE Agreement, PRE paid PetroNova cash consideration of $12.5 million for

back-costs associated with the Tinigua Block and agreed to carry the cost of drilling, completing, and testing of up to

four wells, up to $33 million, to earn a 50% Participating Interest in the Tinigua E&P Contract. PRE will assume up

to $19 million of PRE’s and PetroNova Colombia Inc.’s share of the capital and operational expenditures for the first

and second exploratory wells to be drilled in the Tinigua E&P Contract area, of up to $12 million and up to $7 million,

respectively. Should PRE refrain from exercising its right of withdrawal after the first exploratory well, PRE will

assume up to $7 million of PRE’s and PetroNova Colombia Inc.’s share of the capital and operational expenditures

for each of the third and fourth exploratory wells to be drilled in the Tinigua E&P Contract area (the “Additional

Carry Obligation”). PetroNova Colombia Inc.’s share of the Additional Carry Obligation will be repaid to PRE by

PetroNova Colombia Inc. out of 50% of PetroNova Colombia Inc.’s corresponding production share from the Tinigua

E&P Contract. During the last phase of the exploration period of the Tinigua E&P Contract, PRE shall have, at its

sole discretion, the option to be designated the operator of the Tinigua E&P Contract. If PRE elects to become the

operator, PRE will pay PetroNova Colombia Inc. an additional one-time consideration of $4 million. PRE’s 50%

Private Working Interest will convert into a full 50% undivided Participating Interest in the block upon approval by

the ANH and an application has been made to the ANH for such approval. The ANH approval was received in

December 2014.

On March 14, 2014, the Corporation announced that it had temporarily suspended operations at the Canelo Sur-2

exploratory well located in the PUT 2 Block pending resolution of a community-related dispute in the region. The

well had reached the programmed total depth of 9,970 feet; however, a community-related issue arose that prevented

personnel and supplies from reaching the drilling site. The well was drilled to evaluate multiple reservoir targets in

the Villeta formation with the principal targets being the Lower “U” and the “T” sands. Well log data and mud-gas

log data acquired indicate a gross reservoir thickness of approximately 45 feet with fair quality oil shows and natural

fluorescence over the Lower “U” sand and a gross reservoir thickness of approximately 69 feet with poor oil shows

over the “T” sand. The Villeta upper “U” sand, over which a full suite of well logs was acquired, indicates the zone

to be wet. Due to adverse hole conditions, a porosity log was not acquired over both of the lower “U” and “T” sands,

which has hampered the interpretation. The Corporation resumed activities in relation to the Canelo Sur-2 well on

March 2014, upon the resolution of the community-related dispute, and the well was cased. Based on the interpreted

potential oil pay indicated by oil shows during drilling, as well as by the open hole and cased hole well log information,

a 44 foot interval in the Villeta lower 'U' sand was perforated and tested. Production testing with a hydraulic pump

yielded primarily formation water with intermittent volumes of light oil (up to 3% of the fluid rate) over approximately

48 hours of evaluation. Based on the testing results, the Corporation announced on May 13, 2014, that the Canelo Sur-

2 well was going to be abandoned after obtaining inconclusive results from the testing of the lower “U” sand of the

Villeta formation.

On July 25, 2014, the Corporation closed a non-brokered private placement of 28,571,428 Common Shares at a

purchase price of CDN$0.28 per Common Share for total gross proceeds of CDN$8 million. The Common Shares

were acquired by Alentar Holdings Inc., an international investment company with assets and experience in the oil

and gas industry in Colombia and South America, and Inepetrol Investments Ltd., a company related to the original

founders of the Corporation. A.V. Securities Inc. acted as a finder in connection with the private placement and was

paid a cash fee of CDN$285,000.

On August 12, 2014, the Corporation appointed Mr. Marcel Apeloig to serve as a director of the Corporation.

In respect of the Corporation’s drilling campaign in the CPO 13 Block, the Corporation drilled the following wells in

2014:

The Pendare-4 well was spud on November 15, 2014 and drilled to 3,348 feet. The mud and electric

logs indicated high water saturation in the targeted Basal Carbonera Sands. The well was temporarily

plugged allowing its eventual conversion into a water disposal well to be used, if necessary.

The Pendare-6 well was spud on December 1, 2014 and directionally drilled to a total depth of 3,642 feet.

The electrical logs indicated approximately 68 feet of net oil pay in two main sand sections: 25 feet

17

corresponding to the targeted top of the Basal Carbonera sands (the producing sand in the Pendare-1 and 2

wells) and 43 feet corresponding to a new sand not seen in the previous Pendare wells. A total of 405 Bbls

was produced during 40 hours of the jet pump tests. The well was equipped with an electric submersible

pump and the Corporation plans to conduct an extended test after the ANH approval is obtained.

The Tillavá Este-1 well was spud on November 30, 2014 and drilled to a total depth of 2,966 feet. The

electrical logs, confirmed by side wall cores, indicated approximately 23 feet of net oil pay over a gross

interval of approximately 49 feet in the Carbonera Basal sands, however large washouts were detected at the

pay area. A 41 foot window was milled, under-reamed, gravel-packed and tested with a jet pump recovering

mostly water with 1 to 2% of heavy crude, typical of the wells in adjoining block.

For further information regarding the Corporation’s exploration programs in respect of the Colombian Blocks, please

see “Business of the Corporation – The Corporation’s Oil and Gas Properties”.

Subsequent Events

In respect of the Corporation’s drilling campaign in the CPO 13 Block, the Corporation drilled the following wells in

2015:

The Pendare-3H, a horizontal well, was spud on January 2, 2015 to optimize the production flow rates of the

Pendare discovery. A total of 417 Bbls was produced during 46 hours of the jet pump tests. The well has

been equipped with an electric submersible pump and based on the estimated productivity index is expected

to produce at rates in excess of those attained during the short hydraulic pump test.

The Tillavá Sur -1 well was spud on January 7, 2015 and drilled to 2,903 feet. Good quality oil-bearing

Carbonera Basal sand was found between 2,671 and 2,683 feet. Casing was cemented and the well was tested

with a jet pump through a seven foot milled and gravel packed window. The test yielded an unexpectedly

low flow rate with only approximately 4% crude and the jet pump was found to be jam-packed with viscous

heavy crude. Several alternatives are being considered to test the well again upon release of the drilling rig.

The Corporation has conducted a throughout review of its current level of general and administrative expenses and

capital expenditures plan in response to the significant decline in prices of crude oil that started in late 2014. In that

sense, the Corporation has renegotiated or significantly reduced some of its administrative commitments and is

currently negotiating capital expenditures with partners.

For further information regarding the Corporation’s exploration programs in respect of the Colombian Blocks, please

see “Business of the Corporation – The Corporation’s Oil and Gas Properties”.

Significant Acquisitions

The Corporation did not complete any acquisitions during the year ended December 31, 2014 for which disclosure is

required under Part 8 of NI 51-102.

BUSINESS OF THE CORPORATION

Overview

The Corporation, through its subsidiaries, is engaged in the exploration for, and the acquisition and development of,

oil and natural gas resources in South America, specifically in Colombia. The Corporation’s assets currently include

the Corporation’s various Participating Interests in the Colombian Blocks, two of which are operated by the

Corporation. The Colombian Blocks consist of the PUT 2 and the Tinigua Blocks located in the Caguan-Putumayo

Basin, both of which are operated by the Corporation, and the non-operated Llanos Blocks located in the Llanos Basin.

See “– The Corporation’s Oil and Gas Properties”.

18

Business Objectives and Strategy

PetroNova’s business objective is to build a diversified oil and gas exploration and production company in South

America, initially focused on Colombia, with a view to expanding into additional countries in the future. The

Corporation’s strategy is to develop its existing portfolio of assets and to pursue further exploration opportunities in

areas with proven hydrocarbon systems that the Corporation considers to be cost-effective and of low to moderate

risk. In addition, the Corporation will continue to evaluate strategic acquisition or business combination opportunities

of oil and natural gas companies or properties from time to time where it views further exploration and development

opportunities exist. To this effect, the Corporation may participate in future bid rounds in Colombia and elsewhere to

acquire additional exploration acreage. The Corporation hopes to generate returns for its shareholders principally

through capital growth and intends to take advantage of opportunities to acquire acreage and prospects suitable for

exploration and development.

The Corporation has established the following fundamental guidelines pursuant to which the Corporation evaluates

the selection and participation in new areas in an attempt to mitigate the geological risk inherent to high potential

exploration:

the presence of a proven hydrocarbon system in the area is known;

the existence and availability of technical information allows preliminary evaluations;

the proximity to existing or underdeveloped infrastructure will allow the shipment of oil; and

the economics are attractive under conservative price forecasts.

The Corporation’s short term goals are to complete the seismic acquisition, processing and interpretation process and

to continue the ongoing drilling campaign. The Corporation will implement its growth strategies through organic

growth by drilling identified prospects and generating new exploratory opportunities in its current acreage via farm-

in and farm-out opportunities and by participation in bid rounds when attractive.

The Corporation’s Oil and Gas Properties

PetroNova has Participating Interests in two different geological basins in Colombia, each offering their own risk and

reward profile with significant resource potential. All of the Corporation’s assets are located nearby or on trend with

existing major oil fields or discoveries. The properties are located in the Caguan-Putumayo and Llanos Basins and

cover approximately 1,296,824 gross (333,624 net) acres of exploration and production acreage on a combined basis.

19

The interests of the Corporation in its properties in Colombia are summarized in the following table:

Basin Block

Participating

Interest

ANH

Participation

Factor(1)

Net

Acres(2) Gross Acres

Designated

Operator

Caguan-Putumayo PUT 2 75%(3) 1% 72,499(3) 96,665 PetroNova

Caguan-Putumayo Tinigua 40%(4) – 42,188(4) 105,471 PetroNova

Llanos CPO 7 20% 47% 125,558 627,792 Tecpetrol

Llanos CPO 13 20% 32% 93,379 466,896 Tecpetrol

Total 333,624 1,296,824

Notes:

(1) In addition to the participation factor payable to the ANH, all properties are subject to the sliding scale royalty. See “Industry Conditions

– E&P Contracts – Royalties”.

(2) Net acres consists of the gross acres multiplied by the Corporation’s Participating Interest and excludes adjustments for royalties and the participation factor payable to the ANH.

(3) During 2014, the ANH approved the conversion of Suroco SLU’s 25% Private Working Interest into a full 25% Participating Interest.

See “General Development of the Business – Three Year History of the Corporation – Year Ended December 31, 2014” and “Business of the Corporation – Caguan-Putumayo Basin – PUT 2 Block”.

(4) During 2014, the ANH approved the conversion of PRE’s 50% Private Working Interest into a full 50% Participating Interest. Pursuant

to the Tinigua Participation Agreement, the Corporation has agreed, subject to the fulfillment of certain conditions, including the approval of ANH, to assign 10% of its rights to the Tinigua E&P Contract to an independent third party. Under the terms of the Tinigua

Participation Agreement, the Corporation is required to pay all costs and expenses associated with Phase 1 of the exploration program.

After such time, the third party may elect to participate in the Tinigua Block. With respect to the Tinigua Block, net acres has been calculated on the basis of the Corporation’s Participating Interest after giving effect to the 10% Private Working Interest which has been

granted to a third party pursuant to the Tinigua Participation Agreement. See “Caguan-Putumayo Basin – Tinigua Block”.

The following is a brief description of the Corporation’s oil and gas properties.

20

Caguan-Putumayo Basin

The Caguan-Putumayo Basin is located in southern Colombia and is the northern extension of the Oriente basin of

Ecuador. The limit of the Caguan-Putumayo Basin to the northeast is the Caguan sub-basin. To the north and west are

the Upper Magdalena Valley and the Eastern Cordillera. To the south is the continuation of the basin into Ecuador.

The basin is approximately 104,000 km2. The Corporation currently participates in two exploration blocks in the

Caguan-Putumayo Basin: the PUT 2 Block and the Tinigua Block. The PUT 2 Block is located in the south-west

portion of the basin and the Tinigua Block is located in the northern portion of the basin.

PUT 2 Block

The Corporation has a 75% Participating Interest in the PUT 2 Block which is 96,665 gross (72,499 net) acres in size,

after giving effect to the 25% interest granted to Suroco SLU pursuant to the Suroco Agreement. See “General

Development of the Business – Three Year History of the Corporation – Year Ended December 31, 2013”.

The Corporation’s Participating Interest in the PUT 2 Block was granted by the ANH on February 18, 2009 and

PetroNova Colombia - Branch has been designated by the ANH as operator of the block. The PUT 2 E&P Contract

sets out the terms of the Corporation’s Participating Interest in the PUT 2 Block and provides for a sliding scale royalty

rate on oil and gas production plus an additional 1% participation factor payable to the ANH. See “Industry Conditions

– E&P Contracts”.

The Corporation’s exploration program under the PUT 2 E&P Contract is as follows:

Phase

Duration(1)

Exploration Program

Status

Estimated

Amount

($)(2)(3)

1 49 months Acquire, process and interpret 79 km of 2D seismic

Completed 1,975,000

Drill one (1) Exploratory A-3 Well

Completed 4,000,000

26 months Acquire, process and interpret 12 km of 2D seismic

Completed 300,000

2(4) 36 months Drill two (2) Exploratory A-3 Wells

Pending 8,000,000

13 months Acquire, process and interpret 10 km2 of 3D seismic

Completed 400,000

Total Exploration Program 14,675,000

Notes:

(1) Indicates the duration in months following the expiry of the 6 month pre-exploration phase. (2) Represents the Corporation’s minimum financial obligation in respect of the work to be completed under Phase 1 of the PUT 2 E&P

Contract and is based on management’s cost estimate for such work at the time the PUT 2 E&P Contract was granted. The actual cost

of such work may be more or less than the amounts prescribed in the PUT 2 E&P Contract and such variances could be material. See

“Risk Factors”. (3) As at December 31, 2014, the Corporation had incurred expenditures in the amount of approximately $41,840,320 in respect of the

Corporation’s obligations under Phase 1 and 2 of the exploration program required under the PUT 2 E&P Contract. See “– Exploration

Program – General”. (4) On July 2014, the Corporation moved into Phase 2 of the exploration program with an initial term of 36 months since commencement.

The Corporation is currently in Phase 2 of the exploration program required under the PUT 2 E&P Contract. Pursuant

to the PUT 2 E&P Contract, the Corporation is required to acquire, process and interpret a minimum of 10 km2 of

seismic data during Phase 2, which the Corporation satisfied through the completion of the acquisition, processing

and interpretation of approximately 110 km2 of 3D seismic in the Canelo-Sur and Canelo-Nogal prospects and

surrounding areas. Additionally, the Corporation is committed to drill two (2) Exploratory A-3 wells.

In addition, the Corporation has obtained the required environmental licenses from ANLA authorizing the Corporation

to drill a total of 27 exploratory wells in the Canelo-Nogal and the Canelo-Norte areas.

21

On May 13, 2014, the Corporation announced that the Canelo Sur-2 well located in its PUT-2 Block was going to be

abandoned after obtaining inconclusive results from the testing lower “U” sand of the Villeta formation. See “General

Development of the Business – Three Years History of the Corporation”.

Tinigua Block

The Corporation has a 40% Participating Interest in the Tinigua Block which is 105,471 gross (42,188 net) acres in

size, after giving effect to the 10% Private Working Interest granted to a third party pursuant to the Tinigua

Participation Agreement and after giving effect to the 50% Participating Interest granted to PRE pursuant to the PRE

Agreement. See “General Development of the Business – Three Years History of the Corporation”.

The Corporation’s Participating Interest in the Tinigua Block was granted by the ANH on January 23, 2009 and

PetroNova Colombia - Branch has been designated by the ANH as operator of the block. The Tinigua E&P Contract

sets out the terms of the Corporation’s Participating Interest in the Tinigua Block and provides for a sliding scale

royalty rate on oil and gas production. There is no additional participation factor payable to the ANH under the Tinigua

E&P Contract. See “Industry Conditions – E&P Contracts”.

Pursuant to the terms of the Tinigua Participation Agreement, the Corporation has agreed, subject to the fulfillment

of certain conditions, including the approval of ANH, to assign 10% of its rights to the Tinigua E&P Contract to an

independent third party. Under the terms of the Tinigua Participation Agreement, the Corporation is required to pay

all costs and expenses associated with Phase 1 of the exploration program outlined below. After such time, the third

party may elect to participate in the Tinigua Block. Should the third party elect to participate, it: (i) is responsible for

10% of all future costs; (ii) is obligated to repay the Corporation its share of incurred costs and expenses; and (iii) is

entitled, subject to receipt of ANH approval, to the formal assignment to it of a 10% Participating Interest in the

Tinigua E&P Contract. Should the third party elect not to participate, the Corporation will retain the 10% Participating

Interest without further obligation to or from the third party.

The Corporation’s exploration program under the Tinigua E&P Contract is as follows:

Phase Duration(1) Exploration Program Status

Estimated

Amount

($)(2)(3)

1 33 months

and 66

days

Conduct surface geological study in 50 km2 area of interest

including sampling of stratigraphic column and structure data

Completed 150,000

Conduct bio-stratigraphy from samples of surface geology of

pre-existing wells

Completed 50,000

Conduct satellite image of the area of environmental interests

relating to facilities and areas to be conducted by seismic

Completed 62,000

Reprocess 2D seismic data

Completed 100,000

Conduct surface geochemical survey of 100 sample points for

rock and fluid analyses and identify geochemical anomalies of

interest

Completed 150,000

Acquire, process and interpret 55.4 km2 3D seismic

Completed 3,000,000

Study interpretation of geological and geophysical data

Completed

200,000

2(4) 19 months Drill one (1) Exploratory A-3 Well

Pending 4,500,000

3 12 months Drill one (1) Exploratory A-2 Well

N/A 4,500,000

4 8 months Re-interpretation and study

N/A 350,000

5 12 months Acquire, process and interpret 25 km2 3D seismic

N/A 2,500,000

22

Phase Duration(1) Exploration Program Status

Estimated

Amount

($)(2)(3)

6 10 months Drill one (1) Exploratory A-2 Well N/A 4,500,000

Total Exploration Program 20,062,000

Notes:

(1) Indicates the duration in months following the expiry of the 6 month pre-exploration phase. (2) Represents the Corporation’s minimum financial obligation in respect of the work to be completed under Phase 1 and Phase 2 of the

Tinigua E&P Contract and is based on management’s cost estimate for such work at the time the Tinigua E&P Contract was granted.

The actual cost of such work may be more or less than the amounts prescribed in the Tinigua E&P Contract and such variances could

be material. See “Risk Factors”. As the Corporation is in Phase 2 of the exploration program, Phases 3 to 6 do not currently represent a financial obligation to the Corporation.

(3) As at December 31, 2014, the Corporation had incurred expenditures in the amount of approximately $21,882,876 in respect of the

Corporation’s obligations under Phase 1 and 2 of the exploration program required under the Tinigua E&P Contract. See “– Exploration Program – General”.

(4) On March 19, 2013, the Corporation requested that the ANH extend Phase 2 of the exploration program from 12 months to 19 months

On February 14, 2014, the Corporation received approval for an extension of Phase 2 until June 17, 2014 and on September 5, 2014, the

ANH suspended the term of the Phase 2 (effective December 9, 2013) until proper security conditions are in place to operate.

The Corporation is currently in Phase 2 of the exploration program required under the Tinigua E&P Contract and has

completed all Phase 1 commitments. Pursuant to Tinigua E&P Contract, the Corporation is required to drill one (1)

Exploratory A-3 Well during Phase 2. On January 8, 2014, the Corporation was granted an environmental license for

the Tinigua Block which will allow PetroNova to drill a maximum of 20 exploratory wells from five different

platforms and install surface facilities for extended testing as required. Preliminary works in the Uribe municipality,

to repair existing roads to allow transportation of rig loads, have been completed in preparation for drilling the first

Exploratory A-3 Well.

In May 2014, the Corporation requested a time restitution period of five months of the phase 2 exploration program

on its Tinigua block and the ANH temporarily suspended the duration of the phase 2 exploration program (effectively

from December 9, 2013) until military support is secured. The Corporation continues to work with communities and

local authorities during the socialization process of its environmental license, as well as the Environmental

Management Plan (PMA), right of ways, contractor surveys and bid packages.

Llanos Basin

The Llanos Basin is located in the Eastern region of Colombia. Geomorphologic boundaries are the Colombian-

Venezuela border to the north, Macarena High and Vaupés Arch to the south, Guaicaramo fault system to the west

and Guyana Shield to the east. The Corporation currently participates in two exploration blocks in the Llanos Basin:

the CPO 7 Block and the CPO 13 Block, each of which is located in the southern portion of the basin.

CPO 7 Block

The Corporation has a 20% Participating Interest in the CPO 7 Block which is 627,792 gross (125,558 net) acres in

size. The Participating Interest was granted by the ANH on January 14, 2009 and Tecpetrol, the owner of the remaining

80% Participating Interest, has been designated by the ANH as operator of the block. The CPO 7 E&P Contract sets

out the terms of the Corporation’s Participating Interest in the CPO 7 Block and provides for a sliding scale royalty

rate on oil and gas production plus an additional 47% participation factor payable to the ANH. See “Industry

Conditions – E&P Contracts”.

The exploration program of the Corporation and Tecpetrol (collectively, the “Llanos Contractors”) under the CPO

7 E&P Contract is as follows:

23

Phase Duration(1) Exploration Program Status

Estimated

Amount

($)(2)

PetroNova’s

Obligation(3)

1 48 months Acquire, process and interpret 650 km of 2D

seismic

Completed 13,000,000 2,600,000

Drill two (2) Exploratory A-3 Wells to 5,570 feet

Completed 2,560,000 512,000

48 months Drill one (1) Exploratory A-3 Wells to 6,880 feet

Completed 1,600,000 320,000

2(4) 36 months Drill two (2) Exploratory A-3 Wells to 5,577 feet

Acquire, process and interpret 100 km of 2D

seismic

Pending

Completed

2,560,000

2,000,000

512,000

400,000

Total Exploration Program 21,720,000 4,344,000

Notes:

(1) Indicates the duration in months following the expiry of the 6 month pre-exploration phase. (2) Represents the Llanos Contractors’ minimum financial obligation in respect of the work to be completed under Phase 1 and Phase 2 of

the CPO 7 E&P Contract and is based on the Llanos Contractors’ cost estimate for such work at the time the CPO 7 E&P Contract was

granted. The actual cost of such work may be more or less than the amounts prescribed in the CPO 7 E&P Contract and such variances could be material. See “Risk Factors”.

(3) The Corporation has a 20% Participating Interest in the CPO 7 E&P Contract. Accordingly, PetroNova is responsible for 20% of the

financial obligation associated with the minimum exploration commitment. As at December 31, 2014, the Corporation had incurred expenditures in the amount of approximately $13 million in respect of the Corporation’s obligations under Phase 1 and 2 of the minimum

exploration program required under the CPO 7 E&P Contract. See “– Exploration Program – General”. (4) Pursuant to the CPO 7 E&P Contract, the Llanos Contractors were originally required to drill three (3) Exploratory A-3 Wells during

Phase 2. On July 12, 2013, the ANH approved a change in the exploration program to replace one exploratory well in exchange for the

acquisition, processing and interpretation of 100 km of 2D seismic.

The Llanos Contractors are currently in Phase 2 of the exploration program required under the CPO 7 E&P Contract

and have completed all Phase 1 commitments. Pursuant to the CPO 7 E& P Contract, the Llanos Contractors are

required to complete the acquisition, processing and interpretation of 100 km of 2D seismic during Phase 2. During

the financial year ended December 31, 2014, the Llanos Contractors completed the acquisition, processing and

interpretation of 100 km 2D of new seismic, which resulted in the identification and mapping of additional prospects

and leads.

Likewise, pursuant to the CPO 7 E&P Contract, the Llanos Contractors are also required to drill two (2) Exploratory

A-3 Wells during Phase 2. On September 12, 2012, the ANH approved that any additional exploratory well drilled in

the CPO 7 Block during Phase 1 of the exploration program will be considered as a fulfilment of those wells required

during the Phase 2. Based on this change, the Corporation has a commitment to drill only one (1) additional exploratory

well during Phase 2 prior to July 2016.

During 2014, the Corporation completed acquisition of additional 2D and 3D seismic and is currently interpreting the

results obtained. The ANH extended the duration of the evaluation program in respect of the Atarraya field located on

the CPO 7 Block to March 26, 2015. A production license for this discovery has been approved by ANLA, however

the operator of the CPO 7 Block rejected such license and some additional clarifications have been requested.

CPO 13 Block

The Corporation has a 20% Participating Interest in the CPO 13 Block which is 466,896 gross (93,379 net) acres in

size. The Participating Interest was granted by the ANH on January 14, 2009 and Tecpetrol, the owner of the remaining

80% Participating Interest, has been designated by the ANH as operator of the block. The CPO 13 E&P Contract sets

out the terms of the Corporation’s Participating Interest in the CPO 13 Block and provides for a sliding scale royalty

rate on oil and gas production plus an additional 32% participation factor payable to the ANH. See “Industry

Conditions – E&P Contracts”.

The Llanos Contactors’ exploration program under the CPO 13 E&P Contract is as follows:

24

Phase Duration(1) Exploration Program Status

Estimated

Amount

($)(2)

PetroNova’s

Obligation(3)

1 60 months Acquire, process and interpret 775 km of 2D seismic

Completed 15,500,000 3,100,000

Drill three (3) Exploratory A-3 Wells to 2,953 feet

Completed 2,880,000 576,000

60 months Acquire, process and interpret 15 km of 2D seismic

Completed 300,000 60,000

2 36 months Drill three (3) Exploratory A-3 Wells to 2,953 feet

Completed 2,880,000 576,000

Total Exploration Program 21,560,000 4,312,000

Notes:

(1) Indicates the duration in months following the expiry of the 6 month pre-exploration phase. (2) Represents the Llanos Contractors’ minimum financial obligation in respect of the work to be completed under the exploration program

of the CPO 13 E&P Contract and is based on the Llanos Contractors’ cost estimate for such work at the time the CPO 13 E&P Contract

was granted. The actual cost of such work may be more or less than the amounts prescribed in the CPO 13 E&P Contract and such variances could be material. See “Risk Factors”. As the Llanos Contractors are in Phase 1 of the exploration program, Phase 2 does

not currently represent a financial obligation to the Llanos Contractors.

(3) The Corporation has a 20% Participating Interest in the CPO 13 E&P Contract. Accordingly, PetroNova is responsible for 20% of the financial obligation associated with the minimum exploration commitment. As at December 31, 2014, the Corporation had incurred

expenditures in the amount of approximately $19.7 million in respect of the Corporation’s obligations under Phase 1 and 2 of the

minimum exploration program required under the CPO 13 E&P Contract. See “– Exploration Program – General”.

The Llanos Contractors are currently in Phase 2 of the exploration program required under the CPO 13 E&P Contract,

which includes commitments to drill three exploratory wells within the next three years. One of these wells was drilled

during Phase 1 and considered by the ANH as fulfillment of its Phase 2 commitments. On November 15, 2014 the

Company initiated a drilling campaign in the CPO 13 Block to appraise the Pendare discovery and to drill exploration

wells in the “El Tigre” area. Three wells were drilled in the Pendare evaluation area (Pendare-4, Pendare-6 and Pendare

3H) and the results obtained significantly increased the proved and probable reserves associated to the Pendare

discovery. In the “El Tigre” area, two wells were drilled (Tillavá Este-1 and Tillavá Sur-1) and preliminary results

suggest the presence of a trapping mechanism similar to those observed in nearby fields. See “General Development

of the Business – Subsequent Events”. The Company has fulfilled all its phase 2 commitments at CPO-13 and there

are no remaining commitments of the exploration program in the CPO 13 Block.

On September 12, 2014, the Corporation obtained the environmental production license for the Pendare discovery.

This license will allow the Corporation to initiate the development and production phase of the discovery.

Exploration Program – General

As at December 31, 2014, the Corporation has expended approximately $99 million on its Colombian exploration

program. The Corporation plans to fund its remaining exploration program expenditures through a combination of

cash on hand, internally generated cash flow, potential farm-outs, and debt and/or equity financing, if such financing

is available on favourable terms. See “Risk Factors – Financial Resources and Additional Funding Requirements”.

The estimates contained herein with respect to the Corporation’s expenditures represent forward-looking information

and reflect management’s current expectations regarding its business plans. The Corporation’s actual expenditures

may vary depending on a variety of factors, including general economic conditions, the availability of equipment and

personnel and the success of the Corporation’s business development activities. See “Special Note Regarding

Forward-Looking Statements” and “Risk Factors”.

Employees and Specialized Skill and Knowledge

As at December 31, 2014, the Corporation, including its subsidiaries, had 34 employees. As of the date hereof, the

Corporation´s personnel have been reduced to 18 employees according to the Corporation´s efforts to reduce its

general and administrative expense and safeguard its current cash flow.

25

PetroNova’s oil and gas exploration and development activities in Colombia require specialized skills and knowledge

in the areas of petroleum engineering, geology, geophysics and drilling. In addition, specific knowledge and expertise

relating to local laws in Colombia (including regulations relating to land tenure, exploration, development, production,

marketing, transportation, the environment, royalties and taxation) and market conditions are required to compete with

other oil and gas entities operating in Colombia. In order to source the specialized skills and knowledge required to

successfully carry out the Corporation’s operations, the Corporation offers what it believes to be a competitive

compensation package and has been actively hiring employees and consultants with specialized skills required by the

industry and has experienced limited rotation in its personnel. However, the number of persons skilled in the

acquisition, exploration, development and operation of oil and gas properties in Colombia is limited and competition

for such persons is intense. See “Risk Factors – Ability to Attract and Retain Qualified Personnel”.

Royalties and Taxes

All of the properties described above are subject to the standard ANH royalties, high price sharing and corporate taxes.

See “Industry Conditions – E&P Contracts”.

Environmental Impact

The Corporation carries out its activities and operations in compliance with all relevant and applicable environmental

regulations and best industry practices. At present, the Corporation believes that it meets all applicable environmental

standards and regulations and has included appropriate amounts in its capital expenditure budget to continue to meet

its continuing environmental obligations. The costs incurred by the Corporation in respect of continued environmental

compliance amounted to less than 1% of the total capital expenditures incurred by the Corporation to date. See “Risk

Factors – Environmental Regulation and Risks”.

Social and Environmental Policies

The vision of the Corporation is to be recognized by communities, authorities, suppliers and employees as a positive

social reference within the oil and gas industry supported by its performance and contribution to the social

development of those areas where it operates. A Social Responsibility Policy has been adopted and implemented by

the Corporation to clearly set out the Corporation’s goals, guidelines and procedures when interacting with

communities, authorities, suppliers, employees and other interest groups to ensure the Corporation and such groups

work together in harmony to contribute to the development and improvement of quality of life in those areas where

the Corporation operates. The policy establishes governing principles which are based on the fundamental principles

of commitment, responsibility, respect for human dignity, transparency, solidarity, participation and respect.

The Corporation is also committed to setting and meeting high environmental and safety standards. The Corporation

has adopted and implemented a Health, Industrial Safety and Environmental Policy to ensure that: (i) environmental

quality, precaution, prevention and protection standards are met; and (ii) the personal safety of all persons working

directly or indirectly with the Corporation or who are under the Corporation’s area of influence, is safeguarded, while

the Corporation is operating and developing its properties. The policy sets out the goals of the Corporation in respect

of these matters and sets out procedures to follow to achieve such goals.

Further, MADT requires environmental licences for all new activities in accordance with strict national standards and

closely monitors activities by reviewing reports and making onsite inspections. The environmental licences are very

detailed plans, including contingency plans which the Corporation complies with. In addition, the Corporation may

be required to obtain, from time to time, the approvals of regional authorities that are autonomous from MADT in

respect of environmental matters such as waste disposal and water pollution. See “Industry Conditions –

Environmental Regulatory Framework”.

The Corporation has an environmental team based in Bogotá, Colombia who is responsible for obtaining

environmental licences and filing environmental reports. This team works closely with field-based operating personnel

and sub-contractors who are responsible for implementing the environmental plans.

26

Pursuant to the IFC Subscription Agreement and the IFC ALAC Subscription Agreement, the Corporation has agreed

to comply with: (i) the IFC’s Performance Standards on Social & Environmental Sustainability, dated January 1, 2012,

which are available on IFC’s website at www.ifc.org (the “Performance Standards”); (ii) all applicable laws and

regulations of Canada, Colombia and any other jurisdictions where the Corporation may have projects; and (iii) the

World Bank Group Environmental, Health and Safety General Guidelines (April 2007) and Environmental, Health

and Safety General Guidelines for Onshore Oil and Gas Development (April 2007), which are also available on IFC

website at www.ifc.org.

The Corporation has also agreed with IFC and IFC ALAC on an Environmental and Social Action Plan which sets

out specific social and environmental measures to be undertaken by the Corporation to enable the Corporation’s

projects to be explored and developed in compliance with the Performance Standards, and has covenanted to IFC and

IFC ALAC Fund that it will undertake its operations in compliance with such plan.

In addition, the Corporation has agreed with IFC and IFC ALAC Fund as follows:

(a) in connection with any exploration or development activities in which the Corporation is the

operator, to prepare (and continue to use reasonable efforts to procure the Corporation’s joint

operation partners to prepare) a stakeholder engagement plan to ensure proper stakeholder

relationships, monitor community support and identify needs and priorities for sustainable

development in each area of activity and with any exploration or developments;

(b) prior to making an investment in any project, to undertake due diligence in a manner consistent with

good international industry practice and in compliance with the Performance Standards and the

Corporation’s health, safety, environment and social policies. If the results of the due diligence

determine that the proposed project can attain substantial compliance through commercially

reasonable corrective measures, the Corporation will implement, and require, to the extent possible,

any joint operating partners to implement, a plan, agreed to with IFC and the IFC ALAC Fund which

specifies actions and target completion dates for the project to be compliant with the Performance

Standards. If the proposed project materially contravenes the Performance Standards in a manner

that cannot be remediated through such a plan, the Corporation will not enter into the project;

(c) to not conduct or be associated with any exploration or operations that will affect “Indigenous

Peoples” without having gone through the process of “Free, Prior, Informed Consent” and have

achieved “Consent” for the proposed activities, each as defined in the Performance Standards;

(d) to conduct a screening of target exploration sites to identify potential high biodiversity values

associated with those sites and if based on the results of the screening, high biodiversity values are

associated with such exploration sites, identify and implement appropriate mitigation measures in

line with the requirements of the Performance Standards, such exercise to be designed and

conducted with a well-regarded biodiversity specialist with regional experience in Colombia; and

(e) to perform a rapid biodiversity study to determine the presence of “Critical Habitats” (as defined in

the Performance Standards) and not conduct or be associated with any on-ground exploration or

operations which would result in destruction or significant degradation of a Critical Habitat as

defined through application of the Performance Standards.

Community Relations

The Corporation has an internal commitment to community relationships in the areas where the Corporation has

operations. This commitment is demonstrated by making community relationships a key responsibility in each area in

which the Corporation operates and assigning staff to ensure the community’s needs and the Corporation’s impact on

the community are addressed. Local employment is promoted by identifying, providing and supporting job

opportunities.

27

If the oil and gas exploration or exploitation activities of the Corporation will directly affect indigenous communities,

the Corporation is required to undergo an extensive consultation process with such communities and prepare a plan

which seeks to mitigate the impact of such activities. The Corporation is also required to compensate affected

indigenous communities in respect of the impact of the Corporation’s exploration and exploitation activities. The

Corporation has undertaken an extensive consultation process with the indigenous communities that reside within the

Colombian Blocks over the past year. There are no consultation processes currently ongoing. See “Industry

Conditions – Environmental Regulatory Framework”.

In addition, the Corporation has adopted a Social Responsibility Policy which addresses, among other things,

community relations and has agreed with IFC and IFC ALAC Fund to abide by certain standards, guidelines and

policies and to follow certain procedures which affect and govern community relations. Please see “Business of the

Corporation – Social and Environmental Policies”.

Security

Although there are certain security risks associated with operating in Colombia, the security environment in Colombia

has improved since 2002 and the Corporation believes many of the risks can be effectively managed. Working with

local communities promotes an atmosphere of mutual respect, benefit and trust, and thereby decreases the risk of

serious security issues. Within Bogotá and in field operating areas, the Corporation maintains contact with appropriate

local, regional and national bodies to monitor any local security situations and mitigate risk. Since the Corporation

commenced operations, the Corporation has experienced some disruptions to its operations as a result of community-

related incidents, including a disruption which arose in March 2014 which resulted in operations being suspended at

the Canelo Sur-2 well located on the PUT 2 Block. See “General Development of the Business – Three Year History

of the Corporation – Year Ended December 31, 2014”, “Risk Factors – Security and Guerrilla Activity in Colombia”

and “Risk Factors – Social Disruptions and Instability in Colombia”.

Competitive Conditions

There is considerable competition in the world-wide oil and natural gas industry, including in Colombia where the

Corporation’ assets and activities are located. Operators more established than the Corporation, with access to broader

technical skills, larger amounts of capital and other resources, are active in the industry in Colombia. This represents

a significant risk for the Corporation, which must rely on modest resources and access to capital markets for funding

of its activities. See “Risk Factors – Competition”.

Foreign Operations

All of the Corporation’s assets and operations are currently located in Colombia. Operations in Colombia are subject

to political, economic and other uncertainties, including, but not limited to, risk of terrorist activities, revolution,

border disputes, expropriation, renegotiations or modification of existing contracts, import, export and transportation

regulations and tariffs, taxation policies, including royalty and tax increases and retroactive tax claims, exchange

controls, currency fluctuations, labour disputes and other uncertainties arising out of foreign government sovereignty

over the Corporation’s Colombian operations. The Corporation’s operations may also be adversely affected by

applicable laws in Colombia the effect of which could have a negative impact on the Corporation. See “Risk Factors”

in this Annual Information Form for a further description of the risk factors affecting the Corporation’s operations.

Seasonal Factors

Seasonal conditions in Colombia may interfere with the Corporation’s ability to explore and develop its properties.

During the rainy season in Colombia, the Corporation’s properties in the Llanos Basin have only seasonal access due

to heavy rains during the wet season from April through to October, unless all-weather roads are available. In the

Caguan-Putumayo Basin, operations may be affected by adverse conditions during rainy season due to floods and

damages to access roads. The Corporation attempts to mitigate this by constructing all-weather road access and

locations constructed for year-round operation; however, unusually severe rains could affect access to producing

properties.

28

INDUSTRY CONDITIONS

Colombia – General

There are eight commercial oil producing basins in Colombia – the Upper, Middle and Lower Magdalena Valley;

Llanos; Caguan-Putumayo; Catatumbo; Eastern Cordillera and the Guajira basins. Oil extracted from fields in these

basins is transported through Colombia’s five oil pipelines, four of which (the Oleoducto Central S.A (OCENSA)

Pipeline, which transports oil from the Cusiana-Cupiagua complex, the 490 mile Caño Limon pipeline, and the Alto

Magdalena and Colombia Oil pipelines) connect production fields to the Caribbean port town of Coveñas through the

Caño Limon – Coveñas pipeline. The fifth pipeline, the Transandino or Trans Andean pipeline, transports crude oil

from the Orito field in the Caguan-Putumayo Basin to Colombia’s Pacific port of Tumaco.

Historically, all oil production in Colombia was undertaken directly and through Ecopetrol in contracts of association

with foreign companies that allowed Ecopetrol to back into exploration discoveries for up to 50% working interest.

Ecopetrol is the majority state-owned company responsible for the exploration, extraction, production, transportation

and marketing of oil for export. At the start of the 21st century, Colombia was considered to be at risk of becoming a

net oil importer and, as a result, the regulatory regime in Colombia underwent a significant change effective January

1, 2004, with the formation of the ANH, which was given the responsibility of regulating the Colombian oil industry.

Under these policies, the ANH took over the role of regulating the Colombian oil industry and Ecopetrol took on the

role of a domestic producer that competes directly with foreign and domestic companies.

The ANH

The regulatory regime in Colombia underwent a significant change in 2004 with the creation of the ANH by Decree

1760 of 2003. According to this decree, the role of the ANH is: (i) to act as the administrator of hydrocarbon resources;

(ii) to award exploration and production areas; and (iii) to design, promote, execute and act as administrator of E&P

Contracts, which are more fully described below. Pursuant to Decree 4137 on November 3, 2011, the ANH was

granted additional administrative and financial tools to allow the ANH to fulfill its roles as hydrocarbons administrator.

Previously, the ANH dealt with exploration acreage on a “first-come, first-served” basis, but has since adopted a

system of competitive bidding rounds, whereby the ANH allows any company that meets specified criteria to submit

a bid for a block of land. Previous bids were evaluated on two criteria: additional government participation (“X Factor”

or “additional royalty”) and additional work program (investment),” but current bids also consider elements related to

environmental and social responsibility.

The ANH developed two different contracts for the development of exploration and production activities in Colombia:

(i) E&P Contracts, which replaced the former association contracts; and (ii) technical evaluation agreements, which

are short-term contracts between an exploration company and the ANH to analyze existing data and acquire new

information to evaluate an area of interest. Under the earlier association contracts, Ecopetrol had an immediate right

to back into production. In the opinion of management, the current E&P Contracts provide full risk/reward benefits

for exploration and production companies in Colombia.

E&P Contracts

An E&P Contract is the principal contract used by the ANH to grant exploration and production rights. Under the

terms of an E&P Contract, an exploration and production company (known as the “Contractor”) retains the exclusive:

(i) rights from the ANH to explore and produce conventional hydrocarbons within a delineated contract area; (ii) rights

to the income from any production area or commercial field discovered within the contract area, subject to royalties

and other fees payable to the ANH; and (iii) rights for the use of subsoil to conduct exploration and development

operations. E&P Contracts also include a provision for a “high price share” if a cumulative production from a field of

5 MMbbls is reached. An E&P Contract is a long-term contract divided into the following stages: exploration period,

evaluation period and production period, each as described below.

29

Exploration Period

An exploration period has a six year exploration term comprised of a number of exploration phases ranging from

between one and three years each. Each exploration phase may be extended for six additional months if the Contractor

complies with the conditions contained in the E&P Contract to obtain such extensions.

During the exploration period, the Contractor is required to carry out a mandatory exploration program for each phase

as prescribed in the specific E&P Contract. During the first phase of the exploration period, the mandatory exploration

program typically consists of the completion of a prescribed seismic acquisition program and the drilling of an

Exploratory A-3 Well. Each subsequent phase of the exploration period also contains specific seismic acquisition and

drilling obligations. The Contractor is required to submit to the ANH an exploration plan for each phase setting out

its plan for fulfilling the required exploration operations. The E&P Contract allows for amendments to the exploration

plan and the substitution of an exploratory well for seismic acquisition obligations, all with the prior approval of the

ANH. Prior to the commencement of operations for each phase within the exploration period, the Contractor is

required to deliver to the ANH a performance guarantee from an acceptable banking institution for a specified amount

(typically 50%) of the budgeted value of the operations to be performed. Provided the Corporation has satisfied its

obligations, the Corporation has the right at the end of each phase to withdraw and not to proceed to the next phase of

the exploration period. In those circumstances, the Corporation forfeits its Participating Interest but is not obligated to

make any further payments. The Corporation may also terminate its obligations under the E&P Contract during a

phase. In those circumstances, the Corporation is obligated to pay the ANH 50% of the uncompleted commitments

for the terminated phase plus the entire amount of the additional exploration program of such phase set out in the E&P

Contract.

If, during any phase of the exploration period, the Contractor makes a discovery that it considers to have commercial

potential, it is required to notify the ANH in writing of the discovery and shall thereupon be entitled to undertake an

evaluation program as described below.

Provided that there is a discovery and the Contractor undertakes an evaluation program, the Contractor is entitled,

upon the expiry of the exploration period, to withhold 50% of the contract area prescribed in the E&P Contract

(excluding the areas set out in the evaluation program or any production areas) to conduct a subsequent exploration

program. Notification of the Contractor’s intention to conduct a subsequent or additional exploration program must

be provided to the ANH prior to the expiry of the last phase of the exploration period. The subsequent exploration

program shall be for a maximum of two phases, eighteen (18) months each, and must include, at a minimum, the

drilling of one (1) exploratory well in each of the two phases. Provided that the Contractor meets its contractual work

obligations in the first phase of the subsequent exploration period, it may elect to continue to the second phase. In

such case, the Contractor is entitled to retain 50% of the contract area for second phase operations, with the balance

of the contract area (excluding the areas set out in the evaluation program or any production areas) being relinquished

to the ANH. Should the Contractor elect not to proceed to the second phase of a subsequent exploration program, the

Contractor must relinquish the entirety of the remaining contract area (excluding the areas set out in the evaluation

program or any production areas) to the ANH.

At any time during the exploration period, a Contractor may voluntarily relinquish part of the contract area by

demonstrating to the ANH that, despite the relinquishment, the Contractor will be able to comply with its mandatory

exploration program obligations on the remaining part of the contract area.

Nothing in the E&P Contract limits the right of the Contractor to perform exploration and seismic operations in excess

of the minimum obligations set out in the mandatory exploration program, provided that all operations require the

ANH to provide its approval in advance. Excess operations conducted in one phase may be credited towards work

obligations in future phases with prior approval from the ANH.

Evaluation Period

In the event a Contractor makes a discovery which it considers to have commercial potential, it has the right, upon the

submission of an application to the ANH, to determine the commercial viability of the discovery by conducting an

evaluation program for a period of up to two years duration on a defined evaluation area encompassing the discovery.

The evaluation program submitted to the ANH must set forth the operations to be conducted and may be extended for

30

one additional year (two years in the case of heavy oil or gas) where certain criteria are met, including notification of

additional time necessary to drill an additional well or wells.

Upon the completion of the evaluation program and prior to the expiry of the evaluation period, the Contractor is

required to declare whether or not the discovery is a commercial discovery. Where the discovery is declared to be a

commercial discovery, the discovery is considered a commercial field on the date of such declaration at which time

the production period is deemed to commence. If the Contractor does not declare the discovery to be a commercial

discovery, in the manner or within the time specified in the E&P Contract, the discovery is deemed not to be a

commercial discovery. In that case, the Contractor will lose any and all rights to the discovery and the evaluation area

must be returned to the ANH without further compensation.

Production Period

Upon the declaration of field commerciality during an evaluation period, the Contractor is required to submit to the

ANH, for its approval, the proposed areal extent of the discovered field plus a surrounding area of not more than one

(1) kilometre, which area is designated as the production area. The production area may be extended at a later date in

certain limited circumstances with the approval of the ANH. In addition, within ninety (90) days of the declaration of

field commerciality, the Contractor is required to submit to the ANH, for its approval, a detailed development plan

which includes a description of the drilling program for development wells, the required facilities and infrastructure

and the proposed delivery point for future production. The Contractor is also obligated to establish an appropriate

abandonment fund in accordance with the formulas established in the E&P Contract.

The production period has a duration of twenty-four (24) years per productive field commencing from the declaration

of field commerciality and can be extended in successive periods of up to ten (10) years each until the end of the

economic life of the field, subject to certain requirements established in the E&P Contract, including: (i) continuous

production in the field during the five (5) years preceding the extension request; (ii) demonstration by the Contractor

that during the previous four (4) years it has drilled one exploratory well in each calendar year; and (iii) payment of

5% to 10% of the remaining projected field value to the ANH.

ANH Participation in Production

Pursuant to the terms of the E&P Contracts, the ANH is entitled to a participation factor, after royalties, in all future

production from a commercial field. The high price sharing formula and the fees for use of subsoil, described in more

detail below, do not apply to the ANH participation factor. The ANH participating share of production for each of the

Corporation’s properties is set out below:

Block ANH Participation Factor Contractor Share

Tinigua Nil 100%

PUT 2 1% 99%

CPO 7 47% 53%

CPO 13 32% 68%

Royalties

Royalties payable over production are calculated on a field-by-field basis using a sliding scale (s/s) that ranges from

a minimum of 8% (for incremental production up to 5,000 Bbl/d) up to a maximum of 25% (for incremental production

above 600,000 Bbl/d) as illustrated below:

31

Royalty Rate (%)

Production Rate (BOE/d) per field Light Crude Gas Onshore Heavy Crude Gas Offshore

0 to 5,000 8 6.4 6 4.8

5,001 to 125,000 s/s 8 – 20 s/s 6.4 – 16 s/s 6 – 15 s/s 4.8 – 12

125,001 to 400,000 20 16 15 12

400,001 to 600,000 s/s 20 – 25 s/s 16 – 20 s/s 15 – 18.75 s/s 12 – 15

> 600,000 25 20 18.75 15

Production of oil with gravity equal to or less than 15° API attract 75% of the royalties applicable to light crude. For

the purposes of royalty calculations for natural gas, the conversion factor of 1 Bbl = 5.700 cubic feet is utilized.

All of the Corporation’s E&P Contracts are subject to this sliding scale royalty.

High Price Share

The high price sharing formula is applicable in circumstances where aggregate production from an oil field exceeds a

prescribed minimum number of barrels and where the price per barrel received is in excess of a prescribed reference

price. High price sharing for liquids is triggered when gross cumulative production per field exceeds 5 MMbbls and

oil sales price (WTI) exceeds prescribed benchmarks, according to the following formula:

ANH Payment = Price of Hydrocarbons at Delivery Point x Contractor Net Volume x Q, where:

Q = [(P - Po) / P] x S

P = WTI price

Po = Reference price

S = Participation percentage

Reference base price (Po)

API gravity of the liquid hydrocarbons

Po

($/Bbl)

(Year

2013)

Po

($/Bbl)

(Year

2014)

Po

($/Bbl)

(Year

2015)

>29°API

....................................................................................................................

34.55 35.22 35.66

> 22° API and ≤ 29° API

....................................................................................................................

35.89 36.59 37.04

> 15° API and ≤ 22° API

....................................................................................................................

37.23 37.95 38.42

Discoveries located in water depths > 300 m

....................................................................................................................

42.54 43.37 43.91

> 10° API and ≤ 15° API

....................................................................................................................

53.17 54.20 54.87

Liquid hydrocarbons associated to non-conventional reservoirs

....................................................................................................................

- 87.48 88.56

Exported Natural Gas Distance in straight line from the

delivery point and receipt point in country of destination

Po

$/MMBTU

(Year 2013)

Po

$/MMBTU

(Year 2014)

Po

$/MMBTU

(Year 2015)

Lower than or equal to 500 km

........................................................................................................

$7.99 $8.15 $8.25

Higher than 500 km and lower than or equal to 1,000 km

........................................................................................................

$9.31 $9.49 $9.61

More than 1,000 km or LNG Plan

........................................................................................................

$10.64 $10.85 $10.98

S Factor:

32

WTI price (P)

Participation

Percentage

(S)

Po ≤ P < 2Po

......................................................................................................................................................

30%

2Po ≤ P <3Po

......................................................................................................................................................

35%

3Po ≤ P <4Po

......................................................................................................................................................

40%

4Po ≤ P <5Po

......................................................................................................................................................

45%

5Po ≤P

......................................................................................................................................................

50%

Economic rights for the use of subsoil

Fees for subsoil access and use are determined based upon whether the Contractor is in an exploration period, an

evaluation period or production period. For each phase during an exploration period, the Contractor is required to pay

a fee to the ANH for access to the subsoil. No fee is payable for the first phase of an exploration period where the first

phase is less than one (1) year in duration. The fee is payable per hectare on a sliding scale basis depending upon the

duration of the phase of the exploration period and the size of the contract area. The fee is indexed on an annual basis

using the U.S. inflation index. The following table sets out the subsoil access fee payable by the Contractor for the

contract area (excluding evaluation and production areas) in 2015:

Size of Area First 100,000 hectares Additional hectares (above 100,000 hectares)

Phase duration ≤18 months >18 months ≤18 months >18 months

Fee Range inside polygon

A and B:

2015

2014

2013

$2.71

$2.68

$2.63

$3.61

$3.57

$3.50

$3.61

$3.57

$3.50

$5.41

$5.34

$5.24

Outside polygon A and B:

2015

2014

2013

$1.81

$1.79

$1.76

$2.71

$2.68

$2.63

$2.71

$2.68

$2.63

$3.61

$3.57

$3.50

Evaluation and Production Areas

A separate subsoil access fee is applicable to evaluation and production areas and is tied to production. For liquid

hydrocarbons, the fee (2015) is $0.1372/bbl. For natural gas, the fee (2015) is $0.1372/Mcf of the Contractor´s share

of production. The fee is indexed annually using the U.S. Inflation index.

Environmental Regulatory Framework

The environmental regulatory framework in Colombia, including occupational health, industrial safety, environmental

protection and social responsibility, which governs the oil and gas industry is divided into two parts: planning and

compliance.

Planning

MADT, through ANLA, requires that EIAs and EMPs be submitted as the principal planning tools for all new projects,

ensuring local and specific environmental and social variables are included in project planning. Exploratory drilling

projects require the submission of an EIA and EMP at least five months prior to beginning project activities. Following

approval, ANLA awards an environmental license. When a discovery is made, the environmental license typically

allows for a maximum one year of production testing while the company prepares a new EIA and EMP for the

development of a permanent oil and gas production field and development drilling.

33

Field pipeline design and construction is subject to a two part environmental licensing process. First, the company and

the government environmental authority review options to agree on an environmentally friendly pipeline design and

layout. Once an agreement is reached, the company can apply for the pipeline environmental license through a

comprehensive EIA and EMP.

Once a production field’s environmental license is in place, development drilling, flowlines, batteries and other

production infrastructure can be added by preparing specific EMPs.

Social responsibility in project planning includes consultation with local communities through regulatory procedures,

which procedures depend upon the type of community to be consulted (i.e.: settlers, farmers, indigenous, Afro-

Colombians). In addition, each EIA and EMP should include a comprehensive plan with respect to occupational health

and industrial safety, based on national regulations and international standards with respect to health and safety.

Compliance

The second essential area in occupational health, industrial safety, environmental protection and social responsibility

is maintaining optimal regulation compliance standards. In Colombia, these regulations include specific standards for

water and air quality, wastewater and solid waste treatment and disposal, air emission control and industrial hygiene.

The Corporation’s operations are subject to strict monitoring by MADT as well as the regional environmental

corporations (Corpoamazonia in Putumayo, Cormacarena in Meta and Corpocauca in Cauca). These regional

authorities belong to the Colombian National Environmental System.

PetroNova has contracted third party health, safety, environment and community specialists in all of the Corporation’s

areas of operations. The ANH ensures that both the Corporation’s employees and contractors comply with

environmental legislation, the requirements set by the regional environmental corporations and adhere to approved

environmental management plans.

At the end of each operation, an environmental compliance report is prepared, against which the environmental

authorities do their final evaluation. A yearly follow-up to this report is also completed.

Taxes

The Corporation’s pre-tax income from Colombian sources, as defined under Colombian law, is subject to Colombian

income tax at a statutory rate of 33%, although a “presumptive” minimum income tax based on net productive assets

may apply in years of little or no net income which may be carried forward as a deduction for five years and recovered

against future cash taxes otherwise payable. Tax losses may be carried forward indefinitely without limitation.

A new tax reform in Colombia, issued in December 2012, established a reduction in the income tax rate from 33% to

25% and the creation of an income tax for equity (the “CREE”) with a 9% rate for 2013 to 2015 and 8% from 2016.

The CREE cannot be offset using tax operating losses and payers will be exempted from paying some employment

contributions. The remittance of earnings abroad could be subject to income tax withholding on the portion that has

not been subject to income tax at a 25% rate.

In December 2014, the Colombian Congress enacted new corporate tax rates increasing to 39% in 2015, 40% in 2016,

42% in 2017, and 43% in 2018. As at January 1, 2019, the corporate tax rate will reduce back to 34%. In addition, the

Congress introduced a new wealth tax which accrues on net worth as at January 1, 2015, 2016, and 2017; 1.15%,

1.00% and 0.40% respectively.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of reserves data and other oil and gas information set forth below is dated April 22, 2015 with an

effective date of December 31, 2014 and a preparation date of March 20, 2015.

34

The Report on Reserves Data by Independent Qualified Reserves Evaluator in Form 51-101F2 and the Report of

Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached as Appendix A and Appendix

B, respectively, to this Annual Information Form.

Disclosure of Reserves Data

The reserves data set forth below (the “Reserves Data”) is based upon an independent evaluation by Petrotech with

an effective date of December 31, 2014 contained in the Petrotech Report. The Reserves Data summarizes the crude

oil reserves of the Corporation attributable to the Llanos Blocks and the net present values of future net revenue for

such reserves using forecast prices and costs. Petrotech has confirmed to the Reserves Committee of the Corporation’s

Board of Directors that the Petrotech Report has been prepared in accordance with the standards contained in the

COGE Handbook and the reserves definitions contained in NI 51-101 and CSA Notice 51-324. The Corporation

engaged Petrotech to provide an evaluation of proved and proved plus probable reserves and no request was made to

evaluate possible reserves.

All of the Corporation’s reserves are located onshore in Colombia and are attributable to the Llanos Blocks, of which

the Corporation has a 20% interest. As at December 31, 2014, no reserves were attributable to the PUT 2 Block

or the Tinigua Block and accordingly there was no future net revenue related to the PUT 2 or Tinigua Blocks.

In preparing its report, Petrotech obtained basic information from the Corporation, which included land data, well and

accounting information, reservoir and geological studies, contract information, budget forecasts and financial data.

Other engineering, geological or economic data required to conduct the evaluation, and upon which the Petrotech

Report is based, were obtained from public records, other operators and from Petrotech’s non-confidential files. The

extent and character of ownership and all factual data supplied to Petrotech by the Corporation were accepted by

Petrotech as presented.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the

fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be

attained and variances could be material. The recovery and reserve estimates of the Corporation’s crude oil

reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be

recovered. Actual crude oil reserves may be greater than or less than the estimates provided herein. Readers

should review the definitions and information contained under the heading “Presentation of Reserves Data and

Other Oil and Gas Information” in conjunction with the following tables and notes. For more information as to

the risks involved, see “Risk Factors – Reserves Estimates”.

Estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as

estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Certain columns may

not add due to rounding.

SUMMARY OF OIL AND GAS RESERVES

as of December 31, 2014

FORECAST PRICES AND COSTS

Light and

Medium Oil Heavy Oil

Reserves Category

Gross

(Mbbl)

Net

(Mbbl)

Gross

(Mbbl)

Net

(Mbbl)

PROVED

Developed Producing 139 68 86 53

Developed Non-Producing - - 183 112

Undeveloped 484 232 2,280 1,321

TOTAL PROVED 622 300 2,549 1,485

TOTAL PROBABLE 466 218 2,707 1,520

TOTAL PROVED PLUS PROBABLE 1,088 517 5,256 3,006

35

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE(1)

as of December 31, 2014

FORECAST PRICES AND COSTS

Before Income Taxes

Discounted At (%/year)

After Income Taxes

Discounted At (%/year)(2)

Unit Value(3)

Before Income

Tax Discounted

at 10%/year

($/Bbl)

Reserves

Category

0

(M$)

5

(M$)

10

(M$)

15

(M$)

20

(M$)

0

(M$)

5

(M$)

10

(M$)

15

(M$)

20

(M$)

PROVED Developed

Producing 3,286 3,090 2,920 2,770 2,637 2,746 2,592 2,457 2,336 2,228 13.02

Developed Non-Producing 3,052 2,825 2,633 2,470 2,328 3,033 2,808 2,618 2,455 2,315 14.38

Undeveloped 45,163 38,509 33,254 29,033 25,589 39,798 34,085 29,554 25,900 22,907 12.03

TOTAL PROVED 51,500 44,424 38,807 34,273 30,554 45,576 39,485 34,628 30,692 27,450 12.24 PROBABLE 47,059 35,870 28,402 23,144 19,276 37,316 28,175 22,097 17,835 14,714 8.95

TOTAL PROVED

PLUS

PROBABLE 98,559 80,294 67,209 57,417 49,831 82,892 67,661 56,726 48,527 42,165 10.59

Note:

(1) Estimates of future net revenue, whether discounted or not, do not represent fair market value. (2) For more information, please see “Industry Conditions – Taxes”.

(3) Unit amounts are derived using net reserves volumes.

TOTAL FUTURE NET REVENUE(1)

(UNDISCOUNTED)

as of December 31, 2014

FORECAST PRICES AND COSTS

Reserves Category

Revenue

(M$)

Royalties(2)

(M$)

Operating

Costs

(M$)

Development

Costs

(M$)

Abandonment

and

Reclamation

Costs

(M$)

Future Net

Revenue

Before

Income

Taxes

(M$)

Income

Taxes(3)

(M$)

Future Net

Revenue

After Income

Taxes

(M$)

PROVED 144,955 211 83,368 8,833 1,253 51,500 5,924 45,576

PROVED PLUS PROBABLE 297,204 417 176,238 19,115 3,292 98,559 15,667 82,892

Notes:

(1) Estimates of future net revenue, whether discounted or not, do not represent fair market value. (2) Oil royalties are paid in kind. For more information, please see “Industry Conditions – E&P Contracts – Royalties”.

(3) For more information, please see “Industry Conditions – Taxes”.

36

FUTURE NET REVENUE(1)

BY PRODUCTION GROUP

as of December 31, 2014

FORECAST PRICES AND COSTS

Reserves Category Production Group

Future Net Revenue

Before Income Taxes

(Discounted at

10%/Year)

(M$)

Unit Value(2)

($/Bbl)

PROVED RESERVES Light and Medium Crude Oil (including solution gas and other by-products) 8,168 13.12

Heavy Oil (including solution gas and other by-

products) 30,639 12.02

Total 38,807 12.24

PROVED PLUS

PROBABLE RESERVES

Light and Medium Crude Oil (including solution gas

and other by-products) 13,830 12.71

Heavy Oil (including solution gas and other by-

products) 53,379 10.16

Total 67,209 10.59

Notes:

(1) Estimates of future net revenue, whether discounted or not, do not represent fair market value. (2) Unit amounts are derived using net reserves volumes.

Pricing Assumptions – Forecast Prices and Costs

Petrotech employed the following pricing and inflation rate assumptions in estimating the Reserves Data using forecast

prices and costs as of December 31, 2014, being the NYMEX futures and the forecast oil prices of each block:

Year

Sproule Brent

(US$/Bbl)

GLJ Brent

(US$/Bbl)

McDaniel Brent

(US$/Bbl)

Average Brent

(US$/Bbl)

Vasconia

(US$/Bbl)

PetroNova

(US$/Bbl)

2015 68.00 67.50 70.00 68.50 64.33 60.97

2016 83.00 82.50 77.60 81.03 76.86 72.12

2017 93.00 87.50 82.60 87.70 83.54 78.05

2018 94.40 90.00 87.60 90.67 87.30 80.69

2019 95.81 95.00 92.00 94.27 90.90 83.90

2020 97.25 100.00 96.60 97.95 94.54 87.17

Thereafter Escalate at 2% per year after 2020

The December 31, 2014 oil price for West Texas Intermediate (WTI) closed at $53.27 per barrel, Brent closed at

$57.33 per barrel and the Vasconia oil closed at $51.89 per barrel (from Platts Latin American Posted Prices).

Vasconia oil is the Colombian posted export oil price in the Eastern Llanos Basin. The Atarraya and Pendare oil is

mixed to make into an oil blend of approximately 19o API and sold at an 11% discount to the Brent price. For this

evaluation, the average Brent oil price is used from the forecasts of Sproule, GLJ and McDaniel and then adjusted to

the PetroNova price. All future commodity prices of crude oil prices were taken from NYMEX (www.cmegroup.com)

on the last day of trading in 2014.

The Corporation’s weighted average historical prices for the most recent financial year were $93.23 per barrel for

light and medium oil and $92.20 per barrel for heavy oil.

37

Reconciliation of Changes in Reserves

RECONCILIATION OF GROSS RESERVES

BY PRODUCT TYPE

FORECAST PRICES AND COSTS

Light and Medium Oil Heavy Oil

Factors

Gross

Proved

(Mbbl)

Gross

Probable

(Mbbl)

Gross

Proved

Plus

Probable

(Mbbl)

Gross

Proved

(Mbbl)

Gross

Probable

(Mbbl)

Gross

Proved

Plus

Probable

(Mbbl)

December 31, 2013 825.6 355.7 1,181.4 1,209.9 483.7 1,693.6

Extensions and Improved Recovery(1) - - - 1,346.4 1,954.2 3,300.6

Technical Revisions(2) (92.1) 109.8 17.7 - - -

Discoveries - - - - 268.7 268.7

Acquisitions - - - - - -

Dispositions - - - - - -

Economic Factors (92.1) - (92.1) - - -

Production (19.0) - (19.0) (7.2) - (7.2)

December 31, 2014 622.4 465.5 1,087.9 2,549.1 2,706.6 5,255.7

Notes:

(1) The Pendare-6 well has delineated the heavy oil field which added additional well locations to increase proved and probable reserve. The

Pendare-6 well also discovered an additional layer of heavy oil in the Basal Carbonera but has not been tested. (2) The Atarraya producing wells have experienced a faster decline rate resulting in less proved reserve.

Additional Information Relating to Reserves Data

Undeveloped Reserves

Undeveloped reserves are attributed by Petrotech in accordance with the standards and procedures contained in the

COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of

certainty and are expected to be recovered from known accumulations where a significant expenditure is required to

render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be

recovered than proved reserves and are expected to be recovered from known accumulations where a significant

expenditure is required to render them capable of production. Proved and probable undeveloped reserves have been

assigned in accordance with engineering and geological practices as defined under NI 51-101. See “Presentation of

Reserves Information and Other Oil and Gas Information”.

As at December 31, 2014, proved undeveloped reserves accounted for 87% of PetroNova’s total proved reserves and

44% of PetroNova’s total proved plus probable reserves. As at December 31, 2014, probable undeveloped reserves

accounted for 50% of PetroNova’s total proved plus probable reserves.

Approximately all of the Corporation’s proved and probable undeveloped reserves relate to appraisal and development

drilling locations.

The Corporation currently plans to pursue the development of its proved undeveloped reserves within the next two

years and its probable undeveloped reserves within the next three years through ordinary course capital expenditures.

Management plans to assign resources to develop undeveloped reserves in priority, focusing initially on developing

its proved undeveloped reserves and then developing its probable undeveloped reserves. The Corporation may choose

to delay development depending on a number of circumstances, including the existence of higher priority expenditures

and prevailing commodity prices and cash flow. Further details about the Corporation’s specific exploration and

drilling plans are set forth under the heading “Business of the Corporation”.

38

Proved Undeveloped Reserves

The following table sets forth the volumes of proved undeveloped reserves that have been attributed for each of the

Corporation’s product types using forecast prices and costs. The Corporation’s proved undeveloped reserves were

first attributed to the Corporation in 2012.

Year

Gross Light and Medium Oil

(Mbbl)

Gross Heavy Oil

(Mbbl)

First

Attributed

Cumulative

at Year End

First

Attributed

Cumulative

at Year End

2012 and prior 442 442 128 128

2013 - 526 925 1,053

2014 - 484 1,227 2,280

Proved undeveloped reserves are assigned using offset locations surrounding currently producing wells. The

Corporation plans to develop proved undeveloped reserves by drilling delineation wells within the next two years.

Probable Undeveloped Reserves

The following table sets forth the volumes of probable undeveloped reserves that have been attributed for each of the

Corporation’s product types using forecast prices and costs. The Corporation’s probable undeveloped reserves were

first attributed to the Corporation in 2012.

Year

Gross Light and Medium Oil

(Mbbl)

Gross Heavy Oil

(Mbbl)

First

Attributed

Cumulative

at Year End

First

Attributed

Cumulative

at Year End

2012 and prior 687 687 233 233

2013 - 255 251 484

2014 - 466 2,223 2,707

Probable undeveloped reserves are assigned using offset surrounding proved undeveloped locations. The Corporation

plans to develop proved undeveloped reserves by drilling delineation wells within the next two to three years.

Significant Factors or Uncertainties

The process of estimating reserves is inherently 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 natural gas prices and costs change. The reserve estimates contained herein are based on

current production forecasts, prices and economic conditions and other factors and assumptions that may affect the

reserve estimates and the present worth of the future net revenue therefrom. These factors and assumptions include,

among others: (i) historical production in the area compared with production rates from analogous producing areas;

(ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of reserves; (v) success of future

development activities; (vi) marketability of production; (vii) effects of government regulations; and (viii) other

government levies imposed over the life of the reserves. Although every reasonable effort is made to ensure 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.

As circumstances change and additional data becomes available, reserve estimates also change. Estimates are reviewed

and revised, either upward or downward, as warranted by the new information. Revisions are often required due to

changes in well performance, prices, economic conditions and government restrictions. Revisions to reserve estimates

can arise from changes in year-end prices, reservoir performance and geologic conditions or production. These

revisions can be either positive or negative and may be material. See “Risk Factors”.

39

As discussed above, the Corporation has a large inventory of development opportunities in its portfolio. At the forecast

prices and cost used in the Petrotech Price Forecast, the development activities discussed under the heading “–

Undeveloped Reserves” are expected to be economic. However, should oil and natural gas prices continue to fall

materially, these activities may not be economic and the Corporation could defer their implementation.

Future Development Costs

The following table sets forth development costs deducted in the estimation of the future net revenue attributable to

the reserve categories noted below, using forecast prices and costs.

Year

Proved Reserves

(M$)

Proved Plus

Probable Reserves

(M$)

2015 - -

2016 6,743 4,675

2017 2,090 5,549

2018 - 3,503

2019

Remaining - -

Total (Undiscounted) 8,833 13,728

PetroNova currently anticipates that future development costs will be funded through a combination of cash on hand,

internally generated cash flow, debt and/or equity financing, if such financing is available on favourable terms, and

farm-outs. The interest and other costs of external funding are not included in the future net revenue estimates set forth

herein and would reduce the future net revenue to some degree depending on the funding sources utilized. PetroNova

does not currently anticipate that interest or other funding costs would make further development of any of its

properties to which reserves have been attributed uneconomic.

There can be no guarantee that funds will be available or that the Board of Directors will allocate funding to develop

all of the reserves. Failure to develop those reserves could have a negative impact on PetroNova’s future cash flow.

There can be no guarantee that funds will be available or that the Board of Directors will allocate funding to develop

all of the reserves. Failure to develop those reserves could have a negative impact on PetroNova’s future cash flow.

Further, the Corporation may choose to delay development depending upon a number of circumstances including the

existence of higher priority expenditures and available cash flow. See “Risk Factors”.

Other Oil and Gas Information

Oil and Gas Properties

All of the Corporation’s properties are located in Colombia and are onshore. For a description of the Corporation’s

principal properties and the relinquishments, surrenders, back-ins and changes in ownership applicable to the

Corporation’s E&P Contracts, see “Business of the Corporation – The Corporation’s Oil and Gas Properties” and

“Industry Conditions – E&P Contracts”.

Oil and Gas Wells

The following table sets forth the number and status of oil wells as at December 31, 2014 in which PetroNova has an

interest, all of which are located on the Llanos Blocks.

Producing Oil Wells Non-Producing Oil Wells Total Oil Wells

Location Gross Net Gross Net Gross Net

Colombia 4 0.8 - - 4 0.8

As at December 31, 2014, the Corporation did not have an interest in any gas wells.

40

Properties with no Attributed Reserves

The following table sets forth, as at December 31, 2014, the gross and net acres of unproved properties held by

PetroNova and the net area of unproved property for which PetroNova expects its rights to explore, develop and exploit

to expire during the next year.

Unproved Properties

(acres)

Location Gross Net

Net Area Expected to

Expire by December 31,

2015

PUT 2 Block 96,665 72,499 -

Tinigua Block 105,471 94,924 -

Total 202,136 167,423 -

For a description of the existence, nature, timing and cost of the work commitments associated with the PUT 2 Block

and the Tinigua Block, see “Business of the Corporation – The Corporation’s Oil and Gas Properties – Caguan-

Putumayo Basin”. The Corporation does not have any properties with no attributed reserves on its Llanos Blocks.

Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves

The most significant factor affecting the uncertainty relevant to properties with no attributed reserves is the current

level of crude prices and the completion of drilling of the first exploratory wells in the Tinigua Blocks. For more

information, please see “Business of the Corporation – The Corporation’s Oil and Gas Properties – Caguan-

Putumayo Basin” and “Risk Factors”.

Forward Contracts

PetroNova currently does not have any forward contracts.

Additional Information Concerning Abandonment and Reclamation Costs

The following table discloses PetroNova’s abandonment and reclamation costs deducted in the estimation of

PetroNova’s future net revenue.

Year

Proved Reserves

(M$)

Proved Plus Probable Reserves

(M$)

2015 120 -

2016 - -

2017 -

All years 1,101.8 2,574.2

Discounted at 10% 520.2 822.1

Gross wells 22 48

Net wells 4.4 9.6

PetroNova will be liable for its share of ongoing environmental obligations and for the ultimate reclamation of the

properties held by it upon abandonment. PetroNova estimates the costs to abandon and reclaim all wells. The

Corporation’s model for estimating the amount and timing of future abandonment and reclamation expenditures is

done on an operating area level. Estimated expenditures for each operating area are based on management’s prior

experience in the areas. Abandonment and reclamation costs have been estimated over an approximate 10 year period

with the majority of the costs estimated to be incurred after 5 years. Facility reclamation costs are scheduled to be

incurred in the year following the end of the reserve life of the associated reserves. At December 31, 2014, the

Corporation expects to incur reclamation and abandonment costs in respect of 0.8 net wells.

41

Tax Horizon

In Colombia, the Corporation’s tax pools have sheltered it from paying current cash income taxes. The Corporation is

subject to presumptive income tax, equity tax and the CREE tax in Colombia. See “Industry Conditions – Taxes”.

Based on the Corporation’s current exploration and development plans, the Corporation does not expect to pay income

tax in Colombia until 2016.

Costs Incurred

The following table summarizes property acquisition costs, exploration costs and development costs incurred by the

Corporation during the year ended December 31, 2014.

Nature of Cost

Amount

(M$)

Colombia

Property Acquisition Costs

Proved Properties -

Unproved Properties -

Exploration Costs 24,487

Development Costs -

Total 24,487

Exploration and Development Activities

The following table sets forth the gross and net wells in which PetroNova participated during the year ended December

31, 2014:

Exploratory Wells Development Wells Total Wells

Gross Net Gross Net Gross Net

Colombia

Oil wells 2 0.4 - - 2 0.4

Gas wells - - - - - -

Service wells - - - - - -

Stratigraphic test

wells

-

-

-

-

-

-

Dry holes 2 0.95 - - 2 0.95

Total 4 1.35 - - 4 1.35

For a description of the Corporation’s current and likely exploration and development activities, see “Business of the

Corporation”.

Production Estimates

The following table discloses by product type the volume of production estimated by Petrotech in the Petrotech Report

for the year ended December 31, 2015 reflected in the estimates of gross proved and gross probable reserves disclosed

in the tables above under the heading “– Disclosure of Reserves Data”. All estimated production is in respect of the

Llanos Blocks.

42

Light and Medium Oil Heavy Oil

(Mbbl) (Mbbl)

Total Proved 56 76

Total Probable 3 31

Production History

The following table summarizes certain information in respect of production, prices received, royalties paid, operating

expenses and resulting netback associated with the Llanos Blocks for the periods indicated below:

Period Light and Medium Oil Heavy Oil

Q1 2014

Average Gross Daily Production (Bbl/d) 243.83 66.21

Average price received ($/Bbl) 100.45 96.49

Royalties paid (Bbl)(1) 1,755.57 357.54

Opex ($/Bbl) 32.33 83.10

Netback ($/Bbl) 68.13 13.39

Q2 2014

Average Gross Daily Production (Bbl/d) 246.22 131.35

Average price received ($/Bbl) 102.29 100.01

Royalties paid (Bbl)(1) 1,772.81 709.30

Opex ($/Bbl) 33.01 42.93

Netback ($/Bbl) 69.28 57.07

Q3 2014

Average Gross Daily Production (Bbl/d) 254.52 101.23

Average price received ($/Bbl) 95.85 93.55

Royalties paid (Bbl)(1) 1,832.57 546.63

Opex ($/Bbl) 25.91 51.43

Netback ($/Bbl) 69.95 42.12

Q4 2014

Average Gross Daily Production (Bbl/d) 203.10 87.35

Average price received ($/Bbl) 70.30 75.66

Royalties paid (Bbl)(1) 1,462.34 471.70

Opex ($/Bbl) 28.09 51.31

Netback ($/Bbl) 42.21 25.08

Note:

(1) Oil royalties are paid in kind. For more information, please see “Industry Conditions – E&P Contracts – Royalties”.

The following table discloses for each important field, and in total, the Corporation’s production volumes for the

year ended December 31, 2014 by product type.

Field

Light and

Medium Oil

(Bbl/d)

Heavy Oil

(Bbl/d)

Atarraya 52.1 -

Pendare - 19.6

Total 52.1 19.6

43

RISK FACTORS

The business and operations of the Corporation are subject to a number of risks and uncertainties. The risks and

uncertainties discussed below are not the only ones facing the Corporation. Additional risks and uncertainties not

presently known to the Corporation or which the Corporation currently considers immaterial may also impair the

business and operations of the Corporation and cause the value of the securities of the Corporation to decline. If any

of the following risks actually occur, the Corporation’s business may be harmed and the financial condition and results

of operations of the Corporation may suffer significantly. In that event, the trading price of the Common Shares could

decline and shareholders may lose all or part of their investment. Prospective investors should review the risks with

their legal and financial advisors and should consider, in addition to the matters set forth elsewhere in this Annual

Information Form, the following risks. An investment in the securities of the Corporation is suitable only for

purchasers who are aware of such risks and who have the ability and willingness to accept the risk of total loss of their

invested capital.

Investors should carefully consider the risk factors set out below and consider all other information contained

herein and in the Corporation’s other public filings before making an investment decision.

Availability of Funding and Ability to Continue as Going Concern

The Corporation has no producing properties for which revenue has been attributed and no history of earnings, and

there is no assurance that any of the Corporation’s properties will commence production, generate earnings, operate

profitably or provide a return on investment in the future. These conditions, along with other factors noted below,

create material uncertainty that casts doubt on the Corporation's ability to continue as a going concern.

The Corporation’s consolidated financial statements for the years ended December 31, 2014 and 2013 have been

prepared on a going concern basis, which contemplates the Corporation’s continued operation for the foreseeable

future and the Corporation’s ability to realize assets and discharge liabilities and commitments in the normal course

of business. If the going concern assumption is not appropriate, adjustments may be necessary to the carrying amounts

and

classification of the Corporation’s assets and liabilities. The consolidated financial statements do not include any

adjustments that may result if the Corporation is unable to continue as a going concern, and, such adjustments could

be material.

For the year ended December 31, 2014, PetroNova reported a net loss of $46,230,137 and currently, the Corporation's

cash flow is not sufficient to fund its ongoing activities. The Corporation will require additional financing in order

to carry out its oil and gas acquisition, exploration and development activities. The lack of availability of existing

financing or the failure to obtain additional financing on a timely basis could cause the Corporation to forfeit its

interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations, and may

affect the Corporation's ability to expend the capital required to replace its reserves or to maintain its interests in the

Colombian Properties. There can be no assurance that additional debt or equity financing will be available to meet

these requirements or, if available, on terms acceptable to the Corporation. This may be complicated by the limited

market liquidity for the shares of smaller companies, restricting access to some institutional investors. Continued

uncertainty in domestic and international credit markets could also materially affect the Corporation's ability to access

sufficient capital for its capital expenditures and acquisitions. Furthermore, if additional financing is raised through

the issuance of equity, control of the Corporation may change and the shareholders may suffer dilution. The

Corporation may also consider asset dispositions or farm-out or joint venture arrangements in order to fund or

implement its exploration and development activities; however, there can be no assurance that the Corporation will

be able to secure such dispositions or arrangements on acceptable terms or at all. The inability of the Corporation to

access sufficient capital for its operations and/or to secure acceptable alternative arrangements may have a material

adverse effect on the Corporation's ability to execute its business strategy and on its business, financial condition,

results of operations and prospects.

These uncertainties cast significant doubt about the Corporation’s ability to continue as a going concern, which is

dependent upon achieving cash flow from operating activities and receiving additional support from its creditors and

investors.

44

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful

evaluation may not be able to overcome. The long-term commercial success of the Corporation depends on its ability

to find, acquire, develop and commercially produce oil and natural gas reserves. As at December 31, 2014, only limited

reserves have been assigned to the Corporation’s oil and gas properties. The future value of the Corporation is therefore

dependent on the success of the Corporation’s activities, which are directed toward the exploration, appraisal and

development of its properties in Colombia. Exploration, appraisal and development of oil and natural gas properties

is highly speculative and involves a significant degree of risk.

The Corporation has plans to explore its interests in the Colombian Blocks as outlined in this Annual Information

Form. The Corporation must fulfill certain minimum work commitments on the Colombian Blocks as required by the

E&P Contracts. There is no assurance that all of the required commitments will be fulfilled within the time frames

provided or that the Corporation will be able to carry out or complete its exploration programs as currently

contemplated. Accordingly, the Corporation may lose certain exploration rights on its Colombian Blocks and may be

subject to certain financial penalties that would be levied by the ANH or other governmental authority. Further, the

Corporation’s future is contingent on the initial success of its exploration programs and there is no certainty of the

initial success of the Corporation’s exploration programs.

There is no guarantee that exploration or appraisal of the properties the Corporation may have from time to time will

lead to a commercial discovery or, if there is commercial discovery, that the Corporation will be able to realize such

reserves as intended. Few properties that are explored are ultimately developed into new reserves. There is no

assurance that commercial quantities of oil and natural gas will be discovered or acquired by the Corporation. If at

any stage the Corporation is precluded from pursuing its exploration programs, or such programs are otherwise not

continued, the Corporation’s business, financial condition, results of operations and the value of the Common Shares

could be materially adversely affected. Without the continual addition of new reserves, the Corporation’s existing

reserves and the production therefrom will decline over time as such existing reserves are exploited. It is impossible

to guarantee that the exploration programs on the Corporation’s properties will generate economically recoverable

reserves. The commercial viability of a new hydrocarbon pool is dependent upon a number of factors which are

inherent to reserves, such as hydrocarbon composition, associated non-hydrocarbon fluids and proximity of

infrastructure, as well as crude oil prices which are subject to considerable volatility, regulatory issues such as price

regulation, taxes, royalties, land tax, import and export of crude oil, and environmental protection issues. The

individual impact generated by these factors cannot be predicted with any certainty but, once combined, may result in

non-economical reserves. A future increase in the Corporation’s reserves will depend not only on its ability to explore

and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing

properties or prospects. No assurance can be given that the Corporation will be able to continue to locate satisfactory

properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, the

Corporation may determine that current markets, terms of acquisition and participation or pricing conditions make

such acquisitions or participations uneconomical.

Oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are

productive but do not produce sufficient petroleum substances to return a profit after drilling, completing, operating

and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion

and operating costs.

It is difficult to project the costs of implementing any exploratory drilling program due to the inherent uncertainties

of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over-

pressured zones and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic

data and interpretations thereof.

Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of

operations and adversely affect the production from successful wells. Field operating conditions include, but are not

limited to, delays in obtaining governmental and other approvals or consents, insufficient storage or transportation

capacity or other geological and mechanical conditions.

45

While diligent well supervision and effective maintenance operations can contribute to maximizing production rates

over time, production delays and declines from normal field operating conditions cannot be eliminated and can be

expected to adversely affect revenue and cash flow levels to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards

typically associated with such operations, including, but not limited to: encountering unexpected formations or

pressures; premature declines of reservoirs; the invasion of water into producing formations; fires; explosions; blow-

outs; cratering; sour gas releases; spills; pollution; earthquakes and other natural disasters. These typical risks and

hazards could result in work stoppages and also result in substantial damage to oil and natural gas wells, production

facilities, other property, the environment and personal injury.

Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Corporation’s

business, financial condition, results of operations and prospects. As is standard industry practice, the Corporation is

not fully insured against all risks, nor are all risks insurable. Although the Corporation maintains liability insurance in

an amount that it considers consistent with industry practice, liabilities associated with certain risks could exceed

policy limits or not be covered. In either event, the Corporation could incur significant costs which could have a

material adverse effect upon its financial condition.

Limited Operating and Earnings History

The Corporation only recently commenced operations in Colombia and has no earnings history. Accordingly, the

Corporation has no significant operating history in the oil and gas industry in Colombia and has limited historical

financial information or record of performance. The Corporation’s business plan requires significant expenditure,

particularly capital expenditure, in its oil and gas exploration phase. The Corporation will be subject to all the risks

associated with establishing new oil and gas operations in a foreign country, including the timing and cost of the

construction of infrastructure and facilities, the availability and cost of skilled labour and equipment, the need to obtain

necessary environmental or other governmental approvals and permits, and the availability of funds to finance

construction and development activities. The Corporation's current capital may not be sufficient to cover the costs of

the Corporation’s drilling and exploration program and, accordingly, additional financing or joint venture partners

would be required to conduct these activities. The inability to obtain future financing or find future joint venture

partners could materially affect the Corporation’s business, financial condition, results of operations, and the value of

the Common Shares.

Any future profitability from the Corporation’s business will be dependent upon the successful exploration and

development of the Corporation’s petroleum properties, and there can be no assurance that the Corporation will

achieve profitability in the future. The timing and extent of such revenues is variable and uncertain and accordingly

the Corporation is unable to predict when, if at all, profitability will be achieved. Significant revenues may not occur

for some time, if at all. The timing and extent of any revenues is variable and uncertain and, accordingly, the

Corporation is unable to predict when, if at all, profitability will be achieved. An investment in the Common Shares

is highly speculative and should only be made by persons who can afford a significant or total loss of their investment.

Commodity Price Fluctuations

Crude oil prices are unstable and are subject to fluctuation. The Corporation’s revenues, profitability and rate of growth

are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Prices for oil and natural

gas are subject to wide fluctuations in response to changes in the supply of and demand for oil and natural gas, market

uncertainty and a variety of additional factors that are beyond the control of the Corporation. These factors include,

but are not limited to:

global energy policy, including (without limitation) the ability of OPEC to set and maintain production levels

and influence prices for crude oil;

political instability and hostilities;

domestic and foreign supplies of crude oil;

46

the overall level of energy demand;

weather conditions;

government regulations;

taxes;

currency exchange rates;

the availability of refining capacity and transportation infrastructure;

the effect of worldwide environmental and/or energy conservation measures;

the price and availability of alternative energy supplies; and

the overall economic environment.

Declines in oil and natural gas prices will adversely affect the Corporation’s financial condition, liquidity and results

of operations.

Oil and natural gas prices have decreased significantly since mid-2014. Any prolonged period of low crude oil or

natural gas prices could result in a decision by the Corporation to suspend or slow exploration and development

activities or reduce production levels. Any of such actions could have a material adverse effect on the Corporation’s

business, financial condition, results of operations and prospects and ultimately on the market price of the Common

Shares. In addition, bank borrowings available to the Corporation will be in part determined by the borrowing base

of the Corporation. A sustained material decline in prices from historical average prices could reduce PetroNova’s

future borrowing base, therefore reducing the bank credit available to the Corporation.

Volatility in oil and natural gas prices makes it difficult to estimate the value of producing properties for acquisitions

and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers may have

difficultly agreeing on the value of such properties. Price volatility also makes it difficult to budget for and project the

return on acquisitions and development and exploitation projects.

Financial Resources and Additional Funding Requirements

The Corporation currently has limited financial resources and no cash flow from operations and therefore will require

additional financing in order to carry out its oil and natural gas exploration, acquisition and development activities.

There can be no assurance that additional funding will be available, or available under terms favourable to the

Corporation. Failure to obtain such financing on a timely basis could cause the Corporation to have limited ability to

expend the capital necessary to undertake or complete future drilling programs, forfeit its interest in certain properties,

miss certain acquisition opportunities and reduce or terminate its operations. There can be no assurance that debt or

equity financing or cash generated by operations in the future, if any, will be available or sufficient to meet these

requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms

acceptable to the Corporation. Moreover, future activities may require the Corporation to alter its capitalization

significantly.

Financing by issuing additional securities from the Corporation’s treasury may result in a change of control of the

Corporation and dilution to holders of Common Shares. The constating documents of the Corporation allow it to issue

an unlimited number of Common Shares and an unlimited number of preferred shares, issuable in series.

There can be no assurance that significant additional losses will not occur in the near future or that the Corporation

will be profitable in the future. In the event of a commercial discovery, the Corporation’s operating expenses and

capital expenditures will likely increase as needed consultants, personnel and equipment associated with advancing

exploration, development and potentially commercial production are added.

47

The amounts and timing of such expenditures will depend on the progress of the Corporation’s exploration and

development plans, the results of consultants’ analyses and recommendations, the rate at which operating losses are

incurred, the execution of any joint venture agreements with strategic partners, the acquisition of additional properties

and other factors, many of which are not under the control of the Corporation. The Corporation expects to continue to

incur losses unless and until such time as it enters into commercial production from one or more of the properties that

it may have from time to time and generates sufficient revenues to fund continuing operations. The development of

any properties the Corporation may have from time to time will require the commitment of substantial resources to

conduct the Corporation’s exploration and development plans. There can be no assurance that the Corporation will

generate any revenues or achieve profitability or that the underlying assumed costs and expenses of the Corporation’s

exploration and development plans will prove to be accurate.

Historically, sources of funds available to the Corporation has been through the sale of equity and debt securities, and

sale of interest in its oil and gas properties. There is no guarantee that the Corporation will be able to sell equity or

debt securities or interest in oil and gas properties in the future. If the Corporation does not have sufficient capital for

its operations, this could result in delay or indefinite postponement of further exploration or development of any

properties the Corporation may have from time to time, which could have a material adverse effect on the

Corporation’s business, financial condition, results of operations and the value of the Common Shares.

Accounting Adjustments

The presentation of financial information in accordance with International Financial Reporting Standards (“IFRS”)

requires that management apply certain accounting policies and make certain estimates and assumptions which affect

reported amounts in the Corporation’s consolidated financial statements. The accounting policies may result in non-

cash charges to net income and write-downs of net assets in the consolidated financial statements. Such non-cash

charges and write-downs may be viewed unfavourably by the market and may result in an inability to borrow funds

and/or may result in a decline in the Common Share price.

Lower oil and gas prices may increase the risk of write-downs of the Corporation’s oil and gas property investments.

Under IFRS, property, plant and equipment and exploration and evaluation assets are aggregated into groups known

as Cash Generation Units (“CGU’s”) for impairment testing. CGUs are reviewed for indicators that the carrying value

of the CGU may exceed its recoverable amount. If an indication of impairment exists, the CGU’s recoverable amount

is then estimated. A CGU’s recoverable amount is defined as the higher of the fair value less costs to sell and its value

in use. If the carrying amount exceeds its recoverable amount an impairment loss is recoded to net earnings in the

period to reduce the carrying value of the CGU to its recoverable amount. While these impairment losses would not

affect cash flow, the charge to net earnings could be viewed unfavourably in the market.

Security and Guerrilla Activity in Colombia

Colombia has had a publicized history of security problems associated with certain narcotics crime organizations and

other terrorist groups. A 40-year armed conflict between the government forces of Colombia 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 many parts of the country. The

Caguan-Putumayo region has been prone to guerrilla activity in the past. Pipelines have also been targets, including

the Trans-Andean export pipeline which transports oil from the Caguan-Putumayo region. Two of the Corporation’s

properties, namely the PUT 2 and Tinigua Blocks, are located in the Caguan-Putumayo Basin. The Llanos Basin,

where the Llanos Blocks are located, has not experienced any significant anti-government insurgency conflict since

the Corporation commenced operations.

Since August 2012, there have been peace negotiations between the government and the Fuerzas Armadas

Revolucionarias de Colombia (“FARC”) guerrillas. The attempt by the president, Juan Manuel Santos, to end the

conflict is intended to bring further institutional strengthening and development, particularly to rural regions. The

government’s biggest challenge is perceived to be to ensure that the negotiations lead to a long-lasting peace and that

demobilised members of the FARC rejoin civilian life, rather than regrouping in criminal bands.

48

Continuing attempts to reduce or prevent guerrilla activity may disrupt the Corporation’s operations in the future. The

Corporation 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. Any increase in kidnapping and/or terrorist activity in Colombia

generally may disrupt supply chains and discourage qualified individuals from being involved with the Corporation’s

operations. Additionally, the perception that matters have not improved in Colombia may hinder the Corporation’s

ability to access capital in a timely or cost effective manner. The Corporation has limited insurance coverage to protect

itself against terrorist incidents.

Social Disruptions and Instability in Colombia

Companies operating in the oil and gas industry in Colombia have experienced various degrees of interruptions to

their operations as a result of social instability and labour disruptions. For example, in January 2012, certain companies

operating in the Llanos Basin postponed their exploration and drilling programs due to road blockades and civil

disruption along the main road providing access to their blocks by groups with grievances against other operators in

the area and not the Corporation. In 2013, there was a national agricultural strike to protest against the impact that

free-trade agreements have had on local producers who are now facing competition from foreign producers. This strike

extended for several days and included blockage of certain roads that diminished trade, distribution and transportation

activities. In March 2014, the Corporation temporarily suspended operations at the Corporation’s Canelo Sur-2

exploratory well located in the PUT 2 Block as a result of a community-related dispute in the region. See “General

Development of the Business – Three Year History of the Corporation – Year Ended December 31, 2014”.

The Corporation cannot provide assurances that this type of social instability or labour disruption will not be

experienced in future. The potential impact of future social instability, labour disruptions and any lack of public order

may have on the oil and gas industry in Colombia, and on the Corporation’s operations in particular, is not known at

this time. This uncertainty may affect operations in unpredictable ways, including disruptions of fuel supplies and

markets, ability to move equipment such as drilling rigs from site to site, or disruption of infrastructure facilities,

including pipelines, production facilities, public roads, and off-loading stations, which could be targets or experience

collateral damage as a result of social instability, labour disputes or protests. The Corporation may suffer loss of

production, or be required to incur significant costs in the future to safeguard its assets against such activities, incur

standby charges on stranded or idled equipment or to remediate potential damage to its facilities. There can be no

assurance that the Corporation will be successful in protecting itself against these risks and the related financial

consequences. Further, these risks may not in any part be insurable in the event the Corporation does suffer damage.

Indigenous Tribes

Certain regions in which the Corporation may have properties from time to time are inhabited by reclusive indigenous

tribes. As oil and gas exploration activity increases in these regions, the indigenous tribes continue to lose control of

their traditional territory and, as a result, have tended to move deeper into the jungle. The Corporation’s exploration

and development program for these regions may encroach on the traditional habitat of reclusive indigenous tribes. The

indigenous tribes that inhabit these regions may resist encroachment on their native lands. Additionally, certain non-

governmental organizations representing the interests of these reclusive indigenous tribes and advocating for their

rights could challenge the Corporation’s exploration and development plans on the basis that such plans infringe the

territorial rights of such reclusive indigenous tribes. Any such resistance to or objection made against the Corporation’s

exploration and development plans for these regions could delay the Corporation’s plans and have a material adverse

effect on the Corporation’s business, financial condition, results of operations and the value of the Common Shares.

Ability to Execute Exploration and Development Program and Minimum Work Commitments

It may not always be possible for the Corporation to execute its exploration and development strategies in the manner

in which the Corporation considers optimal. The Corporation’s exploration and development programs in Colombia

involve the need to obtain certain approvals from the relevant authorities, which may require conditions to be satisfied

or be contingent upon the exercise of discretion by the relevant authorities. It may not be possible for such conditions

to be satisfied.

49

In addition, the Corporation must fulfill certain minimum work commitments on the Colombian Blocks. There is no

assurance that all of the required commitments will be fulfilled within the time frames provided. Accordingly, the

Corporation may lose certain exploration rights on its Colombian Blocks and may be subject to certain financial

penalties that would be levied by the ANH or other governmental authority, as applicable.

Permits and Licences

The Corporation’s exploration and development activities in Colombia are dependent on receipt of government

approvals or permits to develop its properties. Any delays in receiving government approvals or permits or no

objection certificates may delay the Corporation’s operations or may affect the status of the Corporation’s contractual

arrangements or its ability to meet its contractual obligations.

Title to Assets

The acquisition of title to crude oil properties in Colombia is a detailed and time consuming process. Although all of

the Corporation’s properties are a result of awards and subsequent transfers directly by the ANH, they may be subject

to unforeseen title claims. While the Corporation will diligently investigate title to all of its properties and will follow

standard industry practice in obtaining satisfactory title opinions and while, to the best of the Corporation’s knowledge,

title to all of the Corporation’s properties is in good standing, this should not be construed as a guarantee of title. Title

to the properties may be affected by undisclosed and undetected defects.

In Colombia, legal title is not perfected until such time as the appropriate governmental authorities and the ANH

approve the assignment of a Participating Interest and issues a decree. This process can take many months. As a result,

it is common business practice for commercial parties to proceed with the completion of a purchase and sale

transaction, notwithstanding the fact that governmental approval may take months to properly reflect these business

dealings. In these cases, title review due diligence involves ensuring that the current title holder has started the different

authorization procedures, and also involves an update as to the status of the required authorizations.

Legal Systems

The Corporation is a corporation existing under the ABCA and is governed by the laws of Alberta and the applicable

federal laws of Canada. PetroNova International Inc. and PetroNova Colombia Inc. are companies existing under the

laws of the Cayman Islands and the Corporation’s Colombian branch, PetroNova Colombia - Branch, exists under the

laws of Colombia. Accordingly, the Corporation, its subsidiaries and its Colombian branch are subject to the legal

systems and regulatory requirements of a number of jurisdictions with a variety of requirements and implications for

shareholders of the Corporation.

International exploration and development activities may require protracted negotiations with host governments,

national oil companies and third parties. Foreign government regulations may favour or require the awarding of

drilling contracts or require foreign contractors to employ citizens of, or purchase supplies from, a particular

jurisdiction.

In the event of a dispute arising in connection with the Corporation’s foreign operations, the Corporation may be

subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the

jurisdictions of the courts of Canada or enforcing Canadian judgments in such other jurisdictions. The Corporation

may also be hindered or prevented from enforcing its rights with respect to a governmental instrumentality because

of the doctrine of sovereign immunity.

Colombia may have less of a developed legal system than jurisdictions with more established economies. This may

result in risks such as: (i) effective legal redress in the courts of such jurisdictions, whether in respect of a breach of

law or regulation or in an ownership dispute, being more difficult to obtain; (ii) a higher degree of discretion on the

part of governmental authorities; (iii) the lack of judicial or administrative guidance on interpreting applicable rules

and regulations; (iv) inconsistencies or conflicts between and within various laws, regulations, decrees, orders and

resolutions; or (v) relative inexperience of the judiciary and courts in such matters. In certain jurisdictions, the

commitment of local business people, government officials and agencies and the judicial system to abide by legal

50

requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licences

and agreements for business. These may be susceptible to revision or cancellation and legal redress may be uncertain

or delayed. There can be no assurance that joint ventures, licences, licence applications or other legal arrangements

will not be adversely affected by the actions of government authorities or others and the effectiveness of and

enforcement of such arrangements in these jurisdictions cannot be assured.

Markets and Marketing

The marketability and price of oil and natural gas that may be discovered or acquired by the Corporation will be

affected by numerous factors beyond its control including market fluctuations of prices. The Corporation’s ability to

market oil and natural gas in the future may depend upon its ability to acquire space on pipelines that deliver natural

gas to commercial markets including availability of processing and refining facilities and transportation infrastructure,

including access to facilities, pipelines and pipeline capacity and economic tariff rates over which the Corporation

may have limited or no control. To date, energy infrastructure, specifically in the form of pipelines to transport oil and

natural gas has not yet reached certain locations where the Corporation may have properties from time to time. Due

to the location of such properties, there is limited infrastructure currently available to transport oil and natural gas

from the sites of future wells to market. If the Corporation is unable to transport its oil and natural gas to market within

a reasonable time, the Corporation’s business, financial condition, results of operations, and the value of the Common

Shares could be materially adversely affected.

The Corporation may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines

and processing facilities, and related to operational and maintenance problems with such pipelines and facilities as

well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export

of oil and natural gas and many other aspects of the oil and natural gas business.

Any delay or failure to acquire access to, or improper operation or maintenance of, such pipelines and facilities could

have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects.

Global Financial Conditions

Global financial conditions may be subject to high volatility which could result, as they have in the past, in numerous

commercial and financial enterprises either going into bankruptcy or creditor protection or having had to be rescued

by governmental authorities. Recent market events and conditions, including disruptions in the international credit

markets and other financial systems and the American and European sovereign debt levels, have caused significant

volatility in commodity prices. These events and conditions have caused a decrease in confidence in the broader United

States and global credit and financial markets and have created a climate of greater volatility, less liquidity, widening

of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding

various actions by governments, concerns about the general condition of the capital markets, financial instruments,

banks, investment banks, insurers and other financial institutions can cause the broader credit markets to further

deteriorate and stock markets to decline substantially. While there are signs of economic recovery, these factors have

negatively impacted Corporation and are likely to continue to impact the performance of the global economy going

forward. These factors may impact the Corporation’s future ability to obtain equity, debt or bank financing on terms

favourable to the Corporation, or at all. Additionally, these factors, as well as other related factors, may cause decreases

in asset values that are deemed to be other than temporary, which may result in impairment losses. In addition, certain

of the Corporation’s customers could be unable to pay the Corporation, in the event that they are unable to access the

capital markets to fund their business operations.

Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply

and demand of these commodities due to the current state of the world economies, actions taken by OPEC and the

ongoing global credit and liquidity concerns. This volatility may in the future affect the Corporation’s ability to obtain

equity or debt financing on acceptable terms.

Reliance on Third Party Operators and Key Personnel

To the extent that the Corporation is not the operator of its properties, as is the case with the Llanos Blocks, it will be

dependent upon third party operators for the timing of activities and will be largely unable to control the activities of

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such operators. In addition, the Corporation’s success depends, to a significant extent, upon management and key

employees. The loss of the services of any such persons could have a material adverse effect on the Corporation’s

business, financial condition, results of operations and prospects. The Corporation does not have key person insurance

in effect for management. The contributions of these individuals to the immediate operations of the Corporation are

of central importance.

Ability to Attract and Retain Qualified Personnel

Recruiting and retaining qualified personnel is critical to the Corporation’s success. The number of persons skilled in

the acquisition, exploration, development and operation of oil and gas properties in Colombia is limited and

competition for such persons is intense. As the Corporation’s business activity grows, it will require additional key

financial, administrative, technical and operations staff. If PetroNova is not successful in attracting and training

qualified personnel, the efficiency of its operations could be affected, which could have a material adverse impact on

the Corporation’s future cash flows, net income, results of operations and financial condition.

Competition

The oil and natural gas industry is intensely competitive. Competition is particularly intense in the acquisition of

prospective oil and natural gas properties and oil and natural gas reserves. The Corporation’s competitive position

depends on its geological, geophysical and engineering expertise, its financial resources, its ability to develop its

properties and its ability to select, acquire and develop proved reserves. The Corporation competes with a substantial

number of other companies having larger technical staffs and greater financial and operational resources. Many such

companies not only engage in the acquisition, exploration, development and production of oil reserves, but also carry

on refining operations and market refined products. The Corporation also competes with other oil companies in

attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment

may be in short supply from time to time. In addition, equipment and other materials necessary to construct production

and transmission facilities may be in short supply from time to time. In addition, companies not previously invested

in oil may choose to acquire reserves to establish a firm supply or simply as an investment. Such companies may also

provide competition for the Corporation.

Availability of Equipment and Access Restrictions

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related

equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or

access restrictions may affect the availability of such equipment to the Corporation and may delay exploration and

development activities. To the extent the Corporation is not the operator of its oil and gas properties, the Corporation

will be dependent on such operators for the timing of activities related to such properties and will be largely unable to

direct or control the activities of the operators. There can be no guarantee that sufficient drilling and completion

equipment, services and supplies will be available when needed. Shortages could delay the Corporation’s proposed

exploration and development activities and could have a material adverse effect on the Corporation’s financial

condition.

Infrastructure in Colombia

The physical infrastructure of Colombia has not been adequately funded and maintained. Particularly affected are the

road networks, power generation and transmission, communication systems and building stock. The poor state of

certain physical infrastructure could disrupt the transportation of goods, supplies and production and, accordingly,

may add to the costs of doing business in Colombia. Such additional costs or business interruptions could materially

adversely affect the timing of the Corporation’s plans and the Corporation’s business, financial condition, results of

operations and the value of the Common Shares. Colombia has limited refinery and pipeline capacity. Refinery

capacity may be insufficient to accommodate the Corporation’s production in the event of an oil discovery.

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Disruptions in Production

Other factors affecting the production and sale of oil and natural gas that could result in decreases in profitability

include: (i) expiration or termination of leases, environmental permits or licences, or sales price re-determinations or

suspension of deliveries; (ii) future litigation; (iii) the timing and amount of insurance recoveries; (iv) work stoppages

or other labour difficulties; (v) worker vacation schedules and related maintenance activities; (vi) changes in the

market and general economic conditions; and (vii) the results of negotiations with various aboriginal communities in

the areas in which the Corporation operates. Weather conditions, equipment replacement or repair, fires, amounts of

rock and other natural materials and other geological conditions can have a significant impact on operating results.

Exploration and development activities are subject to numerous licencing requirements, relating mainly to the

environment. In the recent past, the Corporation and other oil and gas companies in Colombia have experienced

significant delays from Colombian authorities with respect to the issuance of such licences. Unanticipated licencing

delays can result in significant delays and cost overruns in the exploration and development of blocks, and could affect

the Corporation’s financial condition and results of operations. The Corporation cannot assure that these delays will

not continue or worsen in the future.

Gathering and Processing Facilities and Pipeline Systems

The Corporation delivers some of its products through pipeline systems which it does not own. The amount of oil and

natural gas that the Corporation can produce and sell is subject to the accessibility, availability, proximity and capacity

of these pipeline systems. The lack of availability of capacity in the pipeline systems could result in the Corporation’s

inability to realize the full economic potential of its production or in a reduction of the price offered for the

Corporation’s production. The Corporation currently produces oil in only one basin in Colombia that has seen an

increase in crude oil production, but a decrease in crude take away capacity as heavier density crude production

increases outpace lighter density crude production. Although pipeline expansions in Colombia are ongoing, the lack

of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to

market oil and natural gas production.

Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as

well as any delays in constructing new infrastructure systems and facilities could harm the Corporation’s business

and, in turn, the Corporation’s financial condition, results of operations and cash flows. All of the Corporation’s

production is delivered for shipment on facilities owned by third parties and over which the Corporation does not have

control.

From time to time, these facilities may discontinue or decrease operations, either as a result of normal servicing

requirements or as a result of unexpected events. A discontinuation or decrease of operations could materially

adversely affect the Corporation’s ability to process its production and to deliver the same for sale.

Environmental Regulation and Risks

The Corporation is subject to environmental laws and regulations that affect aspects of the Corporation’s past, present

and future operations. Extensive national, provincial and local environmental laws and regulations in Colombia will

and do affect nearly all of the operations of PetroNova.

These laws and regulations set various standards regulating certain aspects of health and environmental quality,

including air emissions, water quality, wastewater discharges and the generation, transport and disposal of waste and

hazardous substances; provide for penalties and other liabilities for the violation of such standards; and establish, in

certain circumstances, obligations to remediate current and former facilities and locations where operations are or

were conducted. In addition, special provisions may be appropriate or required in environmentally sensitive areas of

operation.

There is uncertainty around the impact of environmental laws and regulations, including those currently in force and

proposed laws and regulations, and PetroNova cannot predict what environmental legislation or regulations will be

enacted in the future or how existing or future laws or regulations will be administered, interpreted from time to time,

53

or enforced. It is not possible to predict the outcome and nature of certain of these requirements on the Corporation

and its business at the current time; however, failure to comply with current and proposed regulations can have a

material adverse impact on the Corporation’s business and results of operations by substantially increasing its capital

expenditures and compliance costs and its ability to meet its financial obligations, including debt payments. It may

also lead to the modification or cancellation of operating licenses and permits, penalties and other corrective actions.

Further, compliance with more stringent laws or regulations, or more vigorous enforcement policies of any regulatory

authority, could in the future require material expenditures by PetroNova for the installation and operation of systems

and equipment for remedial measures, any or all of which may have a material adverse effect on PetroNova.

Environmental regulation is becoming increasingly stringent and costs and expenses of regulatory compliance are

increasing. The Corporation’s activities have the potential to impair natural habitat, damage plant and wildlife, or

cause contamination to land or water that may require remediation under applicable laws and regulations. These laws

and regulations require the Corporation to obtain and comply with a variety of environmental registrations, licenses,

permits and other approvals. Environmental regulations place restrictions and prohibitions on emissions of various

substances produced concurrently with oil and natural gas and can impact on the selection of drilling sites and facility

locations, potentially resulting in increased capital expenditures. Both public officials and private individuals may

seek to enforce environmental laws and regulations against the Corporation.

Significant liability could be imposed on PetroNova for costs resulting from potential unknown and unforeseeable

environmental impacts arising from the Corporation’s operations, including damages, clean-up costs or penalties in

the event of certain discharges into the environment, environmental damage caused by previous owners of properties

purchased by PetroNova or non-compliance with environmental laws or regulations. While these costs have not been

material to the Corporation in the past, there is no guarantee that this will continue to be the case in the future.

Given the nature of the Corporation’s business, there are inherent risks of oil spills occurring at the Corporation’s

drilling and operations sites. Large spills of oil and oil products can result in significant clean-up costs. Oil spills can

occur from operational issues, such as operational failure, accidents and deterioration and malfunctioning of

equipment. In Colombia, oil spills can also occur as a result of sabotage and damage to the pipelines. Further, the

Corporation sells oil at various delivery stations and the oil is truck transported. There is an inherent risk of oil spills

caused by road accidents which the Corporation may still be deemed to be responsible for as the owner of the crude

oil.

All of these may lead to significant potential environmental liabilities, such as clean-up and litigation costs, which

may materially adversely affect the Corporation’s financial condition, cash flows and results of operations. Depending

on the cause and severity of the oil spill, the Corporation’s reputation may also be adversely affected, which could

limit the Corporation’s ability to obtain permits and affect its future operations.

To prevent and/or mitigate potential environmental liabilities from occurring, the Corporation has policies and

procedures designed to prevent and contain oil spills. The Corporation works to minimize spills through a program of

well-designed facilities that are safely operated, effective operations integrity management, continuous employee

training, regular upgrades to facilities and equipment, and implementation of a comprehensive inspection and

surveillance system. Also, the Corporation’s facilities and operations are subject to routine inspection by various

federal and provincial authorities in Colombia to evaluate the Corporation’s compliance with the various laws and

regulations.

Natural Disasters and Weather-Related Risks

PetroNova will be subject to operating hazards normally associated with the exploration and production of oil and

natural gas, including blow-outs, explosions, oil spills, cratering, pollution, earthquakes, hurricanes and fires. The

occurrence of any such operating hazards could result in substantial losses to the Corporation due to injury or loss of

life and damage to or destruction of oil and natural gas wells, formations, production facilities or other properties.

The majority of oil in the Llanos Basin is delivered by two pipelines to the coastal export locations and refineries.

Sales of oil could be disrupted by damage to these pipelines and/or road networks. Without other transportation

alternatives, sales of oil could be disrupted by landslides or other natural events which impact these pipelines. If oil

has to be trucked to the coastal export locations, operating and transport costs could materially increase.

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Regulatory

Various levels of governments impose extensive controls and regulations on oil and natural gas operations

(exploration, development, production, pricing, marketing and transportation). In Colombia, the oil and gas industry

regulatory body is the ANH. Governments may regulate or intervene with respect to exploration and production

activities, prices, taxes, royalties and the exportation of oil and natural gas. Amendments to these controls and

regulations may occur from time to time in response to economic or political conditions. The implementation of new

regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand

for crude oil and natural gas and increase the Corporation’s costs, either of which may have a material adverse effect

on the Corporation’s business, financial condition, results of operations and prospects. In order to conduct oil and

natural gas operations, the Corporation will require licenses from various governmental authorities. There can be no

assurance that the Corporation will be able to obtain all of the licenses and permits that may be required to conduct

operations that it may wish to undertake.

Income Taxes

The Corporation and its subsidiaries file all required income tax returns and the Corporation believes that it is in full

compliance with applicable Canadian, Cayman and Colombian tax laws; however, such returns are subject to

reassessment by the applicable taxation authority. In the event of a successful reassessment of the Corporation,

whether by re-characterization of exploration and development expenditures or otherwise, such reassessment may

have an impact on current and future taxes payable. Income tax laws relating to the oil and gas industry, such as the

treatment of resource taxation or dividends, may in the future be changed or interpreted in a manner that adversely

affects the Corporation. Furthermore, tax authorities having jurisdiction over the Corporation may disagree with how

the Corporation calculates its income for tax purposes or could change administrative practices to the Corporation’s

detriment.

Litigation

In the normal course of the Corporation’s operations, the Corporation may become involved in, named as a party to,

or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions,

related to, but not limited to, personal injuries, property damage, property tax, land rights, the environment and

contractual disputes. The outcome of any such legal proceedings cannot be predicted with certainty and may be

determined adversely to the Corporation and, as a result, could have a material adverse effect on the Corporation’s

assets, liabilities, business, financial condition and results of operations.

Risks of Foreign Operations Generally

The Corporation’s projects are all currently located in Colombia. Foreign operations are subject to political, economic

and other risks and uncertainties, including but not limited to, political and economic instability, revolution, terrorist

activities, border disputes, expropriation, renegotiations or modification of existing contracts, import, export and

transportation regulations and tariffs, taxation policies, including royalty and tax increases and retroactive tax claims,

exchange controls, limits on allowable levels of production, currency fluctuations, labour disputes and other

uncertainties arising out of foreign government sovereignty over the Corporation’s foreign operations.

If the Corporation’s operations are disrupted and/or the economic integrity of its projects is threatened for unexpected

reasons, its business may be harmed. Prolonged problems may threaten the commercial viability of its operations. The

Corporation’s operations may be adversely affected by changes in foreign government policies and legislation or

social instability and other factors which are not within the control of the Corporation, including, but not limited to:

nationalization, expropriation of property without fair compensation or marketable compensation, or renegotiation or

nullification of existing concessions and contracts; the imposition of specific drilling obligations and the development

and abandonment of fields; changes in energy and environmental policies or the personnel administering them;

changes in oil and natural gas pricing policies; the actions of national labour unions; currency fluctuations and

devaluations; currency exchange controls; economic sanctions; and royalty and tax increases and other risks arising

out of foreign governmental sovereignty over the areas in which the Corporation’s operations will be conducted, as

well as risks of loss due to civil strife, acts of war, terrorism, guerrilla activities and insurrections.

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PetroNova’s operations may also be adversely affected by laws and policies of Colombia affecting foreign trade,

taxation and investment. Based on past performance, the Corporation believes that the government of Colombia

supports the exploration and development of its oil and gas properties by foreign companies. Colombia’s federal

government has, over recent years, implemented policies that management considers to have been successful in

encouraging activity in the oil and gas industry in Colombia and in supporting a healthy business environment.

Nevertheless, there is no assurance that future political conditions in Colombia will not result in the government

adopting different policies respecting foreign development and ownership of oil, environmental protection and labour

relations.

Historically, commodity prices in Colombia have been below import parity prices. The Corporation cannot assure

investors that the government will not implement price controls in the future for political or other reasons, or that the

markets for oil, natural gas and refined products in Colombia will become equal to that of the international market.

In recent years, Colombia has developed a more market-oriented economy; however, previously, the economy had

been hampered by periods of significant instability, and experienced at various times, significant declines in gross

domestic product, hyperinflation, unstable currency, high government debt relative to gross domestic product,

elimination of tax benefit legislation, a weak banking system providing limited liquidity to enterprises, high levels of

loss-making enterprises that continued to operate due to the lack of effective bankruptcy proceedings, significant use

of barter transactions, illiquid promissory notes to settle commercial transactions, widespread tax evasion, growth of

a black and grey market economy, pervasive capital flight, high levels of corruption and the penetration of organised

crime into the economy, significant increases in unemployment and underemployment and the impoverishment of a

large portion of the population. Any deterioration of the investment climate of Colombia could have a material adverse

effect on the Corporation’s business, financial condition, results of operations, and the value of the Common Shares.

Operating in such an environment may make it more difficult for the Corporation to operate its business and finance

its activities. The Corporation cannot assure investors that recent positive trends in the economy of Colombia, such as the increase

in gross domestic product, will continue or will not be abruptly reversed by actions such as the elimination of tax

exoneration of other taxes or contributions. Moreover, fluctuations in international oil and natural gas prices, or other

factors, could adversely affect the economy of the country and the business, results of operation and prospects of the

Corporation, and the value of the Common Shares. In addition, financial problems or an increase in the perceived risks

associated with investing in emerging economies could dampen foreign investment in Colombia and adversely affect

Colombia’s economy. Any such problems could, additionally, have an adverse effect on the international financial

and commodities markets, the global economy, world oil prices and direct foreign investment in such country. Any

significant impairment could limit the Corporation’s access to capital and disrupt the operation of its business and

adversely affect its ability to execute its business strategy.

Foreign Currency

The Corporation’s operations and expenditures are to some extent paid in foreign currencies. As a result, the

Corporation is exposed to market risks resulting from fluctuations in foreign currency exchange rates. A material drop

in the value of any such foreign currency could result in a material adverse effect on the Corporation’s cash flow and

revenues. The Corporation also has subsidiaries that operate in different tax jurisdictions. To the extent revenues and

expenditures denominated in or strongly linked to the U.S. dollar are not equivalent, the Corporation is exposed to

exchange rate risk. The Corporation is exposed to the extent U.S. dollar revenues do not equal U.S. dollar expenditures.

In addition, a portion of expenditures in Colombia are denominated in pesos, which are difficult to hedge. The

Corporation is not currently using exchange rate derivatives to manage exchange rate risks.

Repatriation of Earnings

Currently there are no restrictions on the repatriation from Colombia of capital and distribution of earnings from

Colombia to foreign entities. However, there can be no assurance that restrictions on repatriation of capital or

distributions of earnings from Colombia will not be imposed in the future.

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Reserve Estimates

There are numerous uncertainties inherent in evaluating quantities of reserves and the net present value of future net

revenue to be derived therefrom, including many factors beyond the control of PetroNova. The reserves information

contained in the Petrotech Report and set forth herein, including information respecting the net present value of future

net revenue from reserves, represents an estimate only. This estimate is based on number of assumptions relating to

factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of

capital expenditures, marketability of production, future prices of oil and natural gas, operating costs and royalties and

other government levies that may be imposed over the producing life of the reserves. These assumptions were based

on price forecasts in use at the date the Petrotech Report was prepared and many of these assumptions are subject to

change and are beyond the control of PetroNova. Ultimately, the actual reserves attributable to PetroNova’s properties

and the future net revenue derived therefrom will vary from the estimates contained in the Petrotech Report and those

variations may be material and affect the market price of the Common Shares.

In accordance with applicable securities laws, the Corporation’s independent reserves evaluator has used forecast

prices and costs in estimating the reserves and net present values as summarized herein. Actual future net revenues

will be affected by other factors such as actual production levels, supply and demand, changes in governmental

regulation or taxation and the impact of inflation.

See “Presentation of Reserves Data and Other Oil and Gas Information” and “Statement of Reserves Data and Other

Oil and Gas Information – Additional Information Relating to Reserves Data – Significant Factors or Uncertainties”.

Reserve Replacement

PetroNova’s future oil and natural gas reserves and production and the cash flows to be derived therefrom are highly

dependent upon the Corporation successfully developing and increasing its current reserve base and acquiring or

discovering additional reserves. Without the continual addition of new reserves through exploration, acquisition or

development activities, any existing reserves PetroNova may have at any particular time and the production therefrom

will decline over time as such existing reserves are exploited. A future increase in reserves will depend not only on

PetroNova’s ability to develop any properties it may have from time to time, but also on its ability to select and acquire

suitable producing properties or prospects. There can be no assurance that PetroNova’s future exploration and

development efforts will result in the discovery and development of additional commercial accumulations of oil and

natural gas.

Exploration Risks

The exploration of the Corporation’s properties may have from time to time involves a high degree of risk that no

production will be obtained or that the production obtained will be insufficient to recover drilling and completion

costs. The costs of seismic operations and drilling, completing and operating wells are uncertain to a degree. Cost

overruns can adversely affect the economics of the Corporation’s exploration programs and projects. In addition, the

Corporation’s seismic operations and drilling plans may be curtailed, delayed or cancelled as a result of numerous

factors, including, among others, equipment failures, weather or adverse climate conditions, shortages or delays in

obtaining qualified personnel, shortages or delays in the delivery of or access to equipment, necessary governmental,

regulatory or other third party approvals and compliance with regulatory requirements.

Legislation

The government of Colombia has enacted legislation to protect foreign investment and other property against

expropriation and nationalization. However, there is no assurance that such protections would be enforced. This

uncertainty is due to several factors, including, the potential lack of political will to enforce legislation to protect

property against expropriation and nationalization, particularly depending on the political climate and political party

in power, the lack of independent judiciary and sufficient mechanisms to enforce judgments and potential for

corruption among government officials. Expropriation or nationalization of the Corporation’s business would be

detrimental to its operations and have a material adverse effect on the Corporation’s business, financial condition,

results of operations, and the value of the Common Shares.

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Share Price Volatility

The market price of the Common Shares may be volatile which may affect the ability of the holders of Common

Shares to sell the Common Shares at an advantageous price. Market price fluctuations in the Common Shares may be

due to the Corporation’s operating results failing to meet the expectations of securities analysts or investors in any

quarter, downward revision in securities analysts’ estimates, governmental regulatory action, adverse changes in

general market conditions or economic trends, material public announcements by the Corporation or its competitors

and industry related developments.

Dividends

The Corporation has not declared or paid any cash dividends on the Common Shares to date. The payment of dividends

in the future will be dependent on the Corporation’s earnings and financial condition and on such other factors as the

Board of Directors considers appropriate. Unless and until the Corporation pays dividends, shareholders may not

receive a return on their shares.

Issuance of Debt

From time to time, the Corporation may enter into transactions to acquire assets or the shares of other corporations.

These transactions may be financed in whole or in part with debt, which may increase the Corporation’s debt levels

above industry standards for oil and gas companies of similar size. Depending on future exploration and development

plans, the Corporation may require additional debt financing that may not be available or, if available, may not be

available on favourable terms. Neither the Corporation’s articles nor its by-laws limit the amount of indebtedness that

the Corporation may incur. The level of the Corporation’s indebtedness from time to time could impair the

Corporation’s ability to obtain additional financing in the future on a timely basis to take advantage of business

opportunities that may arise.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The Corporation considers acquisitions and dispositions of businesses and assets in the ordinary course of business.

Achieving the benefits of acquisitions depends, in part, on successfully consolidating functions and integrating

operations and procedures in a timely and efficient manner as well as the Corporation’s ability to realize the anticipated

growth opportunities and synergies from combining the acquired businesses and operations with those of the

Corporation.

The integration of acquired businesses will require substantial management effort, time and resources and may divert

management’s focus from other strategic opportunities and operational matters. In addition, management continually

assesses the value and contribution of services provided and assets required to provide such services. In this regard,

non-core assets may be periodically disposed of, so that the Corporation can focus its efforts and resources more

efficiently. Depending on the state of the market for such non-core assets, certain non-core assets of the Corporation,

if disposed of, could be expected to realize less than their carrying value on the financial statements of the Corporation.

Corruption

The Corporation’s operations are governed by the laws of many jurisdictions, which generally prohibit bribery and

other forms of corruption. The Corporation has policies in place to prevent any form of corruption or bribery, which

includes enforcement of policies against giving or accepting money or gifts in certain circumstances. It is possible that

the Corporation, some of its subsidiaries, or some of the Corporation or its subsidiaries’ employees or contractors,

could be charged with bribery or corruption as a result of the actions of employees or contractors. If the Corporation

is found guilty of such a violation, which could include a failure to take effective steps to prevent or address corruption

by its employees or contractors, the Corporation could be subject to onerous penalties and reputational damage. A

mere investigation itself could lead to significant corporate disruption, high legal costs and forced settlements (such

as the imposition of an internal monitor). In addition, bribery or corruption allegations or convictions could impair the

Corporation’s ability to work with governments or nongovernmental organizations. Such convictions or allegations

could result in the formal exclusion of the Corporation from a country or area, national or international lawsuits,

58

government sanctions or fines, project suspension or delays, reduced market capitalization and increased investor

concern. Further, from time to time, the Corporation may acquire a company that subsequently is subject to a bribery

or corruption charge, whereby the Corporation could assume onerous penalties and/or suffer reputational damage as

a result of activities in which the Corporation had no part.

Conflicts of Interests

Certain officers and directors of the Corporation are also officers and/or directors of other companies engaged in the

oil and gas business generally. As a result, situations may arise where the interest of such officers and directors conflict

with their interests as officers and directors of other companies. The resolution of such conflicts is governed by

applicable corporate laws, which require that officers and directors act honestly and in good faith with a view to the

best interests of the Corporation. Conflicts, if any, will be handled in a manner consistent with the procedures and

remedies set forth in the ABCA. The ABCA requires a director or officer of a corporation who: (i) is a party to a

material contract or material transaction or a proposed material contract or proposed material transaction with the

corporation; or (ii) is a director or officer of or has a material interest in any person who is a party to a material contract

or material transaction or a proposed material contract or proposed material transaction with the corporation, to

disclose the nature and extent of such interest to the corporation and, in the case of directors, refrain from voting on

any matter in respect of such contract or transaction unless otherwise provided by the ABCA.

Breach of Confidentiality

While discussing potential business relationships or other transactions with third parties, the Corporation may disclose

confidential information relating to the business, operations or affairs of the Corporation. Although confidentiality

agreements are signed by third parties prior to the disclosure of any confidential information, a breach could put the

Corporation at competitive risk and may cause significant damage to its business. The harm to the Corporation’s

business from a breach of confidentiality cannot presently be quantified, but may be material and may not be

compensable in damages. There is no assurance that, in the event of a breach of confidentiality, the Corporation will

be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely

manner, if at all, in order to prevent or mitigate any damage to its business that such a breach of confidentiality may

cause.

Uncertainty of Cost Estimates

Due to the early stage of development of the oil and gas industry in Colombia, the Corporation is unable to estimate

costs, including infrastructure improvement costs, transportation costs (including truck, river barge and helicopter

costs), seismic and drilling costs and production costs for its exploration and development plans for some of its

properties. The inability of the Corporation to estimate these costs could affect the commerciality of the resources and

reserves discovered on its properties or any other properties the Corporation may have from time to time, the economic

viability of the Corporation’s products and the ability of the Corporation to transport its products to market.

The Corporation will be subject to all the risks associated with establishing new oil and gas operations in a foreign

country, including the timing and cost of the construction of infrastructure and facilities, the availability and cost of

skilled labour and equipment, the need to obtain necessary environmental or other governmental approvals and

permits, and the availability of funds to finance construction and development activities. Any future profitability from

the Corporation’s business will depend upon the successful development of its current properties or any other

properties the Corporation may have from time to time.

Forward-Looking Information May Prove Inaccurate

Shareholders are cautioned not to place undue reliance on forward-looking information. By its nature, forward-

looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general

and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking

information or contribute to the possibility that predictions, forecasts or projections will prove to be materially

inaccurate.

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DESCRIPTION OF CAPITAL STRUCTURE

The authorized capital of PetroNova consists of an unlimited number of Common Shares without par value, an

unlimited number of preferred shares and the Series A Preferred Share. As at the date hereof: (i) 254,542,705 Common

Shares and 1 Series A Preferred Shares are issued and outstanding; and (ii) 15,070,000 Common Shares are reserved

for issuance pursuant to outstanding Options, 23,076,919 Common Shares are reserved for issuance pursuant to

outstanding Series A Warrants and 23,076,919 Common Shares are reserved for issuance pursuant to outstanding

Series B Warrants.

Common Shares

Holders of Common Shares are entitled to one vote for each Common Share held on all votes taken at meetings of

holders of Common Shares. The holders of Common Shares are entitled to receive any dividend declared by the

Corporation on Common Shares provided that the Corporation shall be entitled to declare dividends on the preferred

shares or on any of such other classes of shares without being obliged to declare any dividends on the Common Shares.

In the event of the dissolution of the Corporation, the holders of Common Shares are entitled to receive the remaining

property of the Corporation in equal rank with the holders of all other Common Shares subject to the rights, privileges

restrictions and conditions attaching to any other class of shares of the Corporation.

Preferred Shares

The preferred shares are issuable at any time and from time to time in one or more series. The Board of Directors is

authorized to fix the number of preferred shares which is to comprise each series and the designation, rights, privileges,

restrictions and conditions attaching to each series of preferred shares, which may include voting rights. The preferred

shares of each series will, with respect to the payment of dividends and the distribution of assets or return of capital

in the event of the liquidation, dissolution or winding-up of the Corporation, whether voluntary or involuntary, or any

other return of capital or distribution of the assets of the Corporation amongst its shareholders for the purpose of

winding up its affairs, be entitled to preference over the Common Shares and over any other shares of the Corporation

ranking junior to the preferred shares of that series. If any cumulative dividends or amounts payable on the return of

capital in respect of a series of preferred shares are not paid in full, all series of preferred shares shall participate

rateably in respect of accumulated dividends and return of capital.

Series A Preferred Share

The holder of the Series A Preferred Share is entitled to receive notice of, to attend and speak at any meeting of the

shareholders of the Corporation. Notwithstanding the foregoing, the holder of the Series A Preferred Share is not,

except to the extent permitted by virtue of the holder holding other securities of the Corporation, entitled either to vote

at any meeting of the shareholders of the Corporation or to sign a resolution in writing, other than:

(a) in respect of the right of the holder to nominate and elect one director of PetroNova in accordance

with the provisions of the Series A Preferred Share; and

(b) as a separate class (i) pursuant to the rights granted under the ABCA and (ii) upon any proposed

change to the articles of the Corporation to amend the minimum or maximum number of directors

permitted thereunder.

In addition to any other rights of the holder of the Series A Preferred Share resulting from the holder holding other

securities of the Corporation, the holder has the right to nominate and elect one director of the Corporation from time

to time in accordance with the procedure set out in the IFC ALAC Subscription Agreement. Such director so

nominated and elected will hold office until the close of the next annual meeting of shareholders of the Corporation

or until his or her removal or resignation. The nomination and election of the director may be conducted by a resolution

in writing signed by the holder, to be effective on the date of the Corporation’s annual meeting of shareholders or on

such other date as specified in such resolution. Only the holder of the Series A Preferred Share will be entitled to

remove the director elected by it. The holder will be entitled at any time, subject to applicable law, to remove the

director elected by it and to nominate and elect a successor director who will, promptly upon the removal of the

60

existing director, be appointed to the Board of Directors as a director to replace the individual previously elected. The

removal of the director may be conducted by a resolution in writing signed by the holder, to be effective on the date

specified in such resolution. If, as a result of death, disability, retirement, resignation, removal (with or without cause)

or otherwise, there shall exist or occur any vacancy on the Board of Directors with respect to the director elected, or

entitled to be elected, by the holder of the Series A Preferred Shares, or for any other reason there is at any time no

directors serving on the Board of Directors elected by the holder of the Preferred Shares, the resulting vacancy shall

be filled by an individual who shall be nominated and elected by the holder.

No dividends will be declared or paid by the Corporation on the Series A Preferred Share. Subject to applicable law,

including the ABCA, the Series A Preferred Share will be redeemed by the Corporation for a redemption price of

$0.01 immediately upon:

(a) the sale, transfer, assignment or any other disposition of the legal and/or beneficial title to the Series

A Preferred Share by the holder of the Series A Preferred Share to anyone other than IFC or an

affiliate or successor to either IFC or the IFC ALAC Fund;

(b) the time that any affiliate of either IFC or the IFC ALAC Fund who, at the relevant time, holds the

Series A Preferred Share is no longer an affiliate of either IFC or the IFC ALAC Fund;

(c) the time that the IFC, the IFC ALAC Fund and their respective affiliates together beneficially own

less (on an un-diluted basis) than ten percent (10%) of the outstanding Common Shares; and

(d) demand by the holder of the Series A Preferred Share.

In the event of a liquidation, dissolution or winding up of the Corporation, or other distribution of the assets of the

Corporation among its shareholders for the purpose of winding up or reorganizing its affairs, whether voluntarily or

involuntarily, there will be paid to the holder of the Series A Preferred Share, in respect of the Series A Preferred

Share held by such holder, in preference to and priority over any distribution or payment on any Common Share, or

any other shares of the Corporation ranking junior to the Series A Preferred Share, the amount of $0.01, and after such

payment such holder shall not be entitled to participate in any further distribution of property or assets of the

Corporation.

Options

The Option Plan provides that the Board of Directors may from time to time, in its discretion, and in accordance with

the requirements of the TSXV, grant to directors, officers, employees and consultants to the Corporation or its

subsidiaries, non-transferable Options, provided that the number of Common Shares reserved for issuance will not

exceed 10% of the issued and outstanding Common Shares. Such Options will be exercisable for a period of up to 5

years from the date of grant. In connection with the foregoing, the aggregate number of Common Shares available

for issuance under the Option Plan: (i) to any one individual participant in any 12-month period shall not exceed 5%

of the issued and outstanding Common Shares at the time of grant; and (ii) to any one consultant in any 12-month

period shall not exceed 2% of the issued and outstanding Common Shares at the time of grant. The exercise price of

the Options granted under the Option Plan will be determined from time to time by the Board of Directors but, in any

event, shall not be lower than the closing price of the Common Shares on the stock exchange on which the Common

Shares are then trading on the last trading day preceding the date of grant. In addition, the Board of Directors

determines when an Option will become exercisable and may determine that the Options will be exercisable in

instalments or pursuant to a vesting schedule.

Series A Warrants

The Series A Warrants were issued on September 28, 2012 pursuant to the 2012 Financing. Each whole Series A

Warrant entitles the holder thereof to acquire one Common Share at an exercise price of CDN$1.25 per Common

Share on or before September 28, 2015, subject to accelerated expiry in certain circumstances as described below. The

Series A Warrants are subject to adjustment in certain circumstances.

61

If, at any time, following one year from the date of issuance of the Series A Warrants (i) at least two exploration wells

have been drilled on the PUT 2 Block and one exploration well has been drilled on the Tinigua Block and (ii) the

trading price of the Common Shares on the TSXV (or other senior Canadian stock exchange on which the Common

Shares may then be listed), exceeds CDN$2.35 for 60 consecutive trading days or more, then, within five (5) business

days the Corporation may provide a notice of acceleration of the expiry of the Series A Warrants to the holders with

respect to all of the Series A Warrants held at such time by such holders, and such Series A Warrants will expire 60

days after the notice of acceleration is delivered to the holders.

Series B Warrants

The Series B Warrants were issued on September 28, 2012 pursuant to the 2012 Financing. Each whole Series B

Warrant entitles the holder thereof to acquire one Common Share at an exercise price of CDN$1.25 per Common

Share on or before September 28, 2015. The Series B Warrants are subject to adjustment in certain circumstances.

DIVIDENDS

The Corporation has not declared or paid any dividends on the Common Shares to date. The payment of dividends in

the future will be dependent on the Corporation’s earnings, financial condition, contractual restrictions and financing

agreement covenants, solvency tests imposed by corporate law and such other factors as the Board of Directors

considers appropriate.

MARKET FOR SECURITIES

The Common Shares are listed for trading on the TSXV under the symbol “PNA”. The following table sets out the

price range for, and trading volume of, the Common Shares as reported by the TSXV for each month during the

financial year ended December 31, 2014:

2014 High (CDN$) Low (CDN$) Volume

December 0.13 0.05 1,103,500

November 0.19 0.11 738,600

October 0.28 0.15 715,600

September 0.33 0.26 380,200

August 0.33 0.28 579,800

July 0.33 0.26 977,700

June 0.34 0.22 1,350,100

May 0.33 0.2 805,300

April 0.35 0.27 1,192,900

March 0.37 0.23 2,327,500

February 0.33 0.25 676,000

January 0.29 0.24 1,410,500

PRIOR SALES

The following table sets out, for each class of securities of the Corporation that is outstanding but not listed or quoted

on a marketplace, the price at which securities of the class have been issued during the financial year ended December

31, 2014, the number of securities of the class issued at the price and the date on which the securities were issued.

Date Type of Security(1) Number of Securities Issued Price(2)

April 24, 2014 Options 280,000 CDN$0.33

May 1, 2014 Options 1,446,000 CDN$0.32

August 26, 2014 Options 280,000 CDN$0.33

62

Notes:

(1) See “Description of Capital Structure”. (2) Represents the exercise price of the Options.

DIRECTORS AND EXECUTIVE OFFICERS

The following table provides the name and the province or state and country of residence of each of the directors and

executive officers of the Corporation, their position in the Corporation, their period of service as a director and their

principal occupation during the previous five years.

Name and Province or

State and Country of

Residence Position with PetroNova Director Since

Principal Occupation for Previous

Five Years

Antonio Vincentelli(3)

Ontario, Canada

President, Chief Executive

Officer and Chairman of the

Board of Directors

September 17, 2009 President and Chief Executive

Officer of the Corporation. Prior

thereto, a director of Inepetrol S.A.

and Inepetrol Corporation A.B.,

President and Chief Executive

Officer of Inepetrol Corporation

A.B. from August 2007 to August

2010 and President of Inepetrol S.A.

from June 2004 to August 2010.

Stelvio Di Cecco

Caracas, Venezuela

Chief Financial Officer and

Director

July 21, 2010 Chief Financial Officer of the

Corporation. In addition, a director

and Chair of the audit committee of

Inelectra. Prior thereto, Chief

Financial Officer of Inelectra from

2002 to August 2010.

Roberto Dañino(2)

Lima, Peru

Director June 13, 2011 Deputy Chairman of Hochschild

Mining plc (a gold and silver

producer) since February 2006 and

Chairman of Fosfatos del Pacifico (a

phosphates rock project) since

December 2010. From November

2003 until January 2006, General

Counsel and Senior Vice President

of the World’s Bank in Washington.

From July 2001 until November

2003, Mr. Dañino served as the

Prime Minister of Peru and

Ambassador to Washington.

Ricardo Halfen(1)(2)

Florida, United States

Director May 12, 2010 Director of Inelectra and Inepetrol

S.A.. From 2007 to December 2012,

held different leading positions in

the finance department of the

Inelectra group. Prior thereto, Vice-

president Finance and New Ventures

of Millennium P y C C.A., a

Venezuelan real estate development

company.

Judith Stripling(1)(2)(3)

Alberta, Canada

Director September 16, 2010 Independent businesswoman.

Former Executive Vice President

and Chief Financial Officer of Pace

Oil & Gas Ltd. from June 2010 until

April 2012. Prior thereto, Executive

63

Name and Province or

State and Country of

Residence Position with PetroNova Director Since

Principal Occupation for Previous

Five Years

Vice President and Chief Financial

Officer of Midnight Oil Exploration

Ltd. or its predecessors and affiliates

since July 2000.

Isaac Yanovich(3)

Cali, Colombia

Director June 13, 2011 Since 2006, self-employed

consultant. From 2002 until 2006,

President of Ecopetrol, Colombia’s

majority state-owned oil company.

Member of the board of directors of

several public companies in

Colombia and Brazil.

Marcel Apeloig(1)

Caracas, Venezuela

Director

August 12, 2014 President of Activalores Casa de

Bolsa (Caracas, Venezuela) and

former Director of Suroco Energy

Inc., Caracas Stock and Exchange

and the Venezuelan Association of

Executives in Finances.

José Paz

Caracas, Venezuela

Vice President, Operations N/A Vice President, Operations of the

Corporation since July 2010.

Director of Petrolera Kaki from

November 2006 to July 2010 and

Director of Petrolera Guiria from

December 2007 to July 2010. Vice

President, Operations of Inepetrol

S.A. and from December 1998 to

October 2006, Planning Coordinator

of Inemaka.

Notes:

(1) Member of the Audit Committee.

(2) Member of the Compensation Committee. (3) Member of the Reserves Committee.

The term of office of each director of the Corporation will expire at the close of the next annual shareholders meeting

of the Corporation. The Corporation’s officers are appointed by and serve at the discretion of the Board of Directors.

As at the date of this Annual Information Form, the directors and executive officers of the Corporation, as a group,

beneficially owned, or controlled or directed, directly or indirectly, 2,881,365 Common Shares representing

approximately 1.13 % of the issued and outstanding Common Shares.

The information as to the number of Common Shares beneficially owned, not being within the knowledge of the

Corporation, has been furnished by the respective directors and executive officers of the Corporation individually.

Cease Trade Orders

To the knowledge of the Corporation, no director or executive officer of the Corporation (nor any personal holding

company of any such persons) is, as of the date of this Annual Information Form, or was within ten years before the

date of this Annual Information Form, a director, chief executive officer or chief financial officer of any company

(including the Corporation), that: (a) was subject to a cease trade order (including a management cease trade order),

an order similar to a cease trade order or an order that denied the relevant company access to any exemption under

securities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an

“Order”), that was issued while the director or executive officer was acting in the capacity as director, chief executive

officer or chief financial officer; or (b) was subject to an Order that was issued after the director or executive officer

64

ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred

while that person was acting in the capacity as director, chief executive officer or chief financial officer.

Bankruptcies

To the knowledge of the Corporation, no director or executive officer of the Corporation (nor any personal holding

company of any such persons), or a shareholder holding a sufficient number of securities of the Corporation to affect

materially the control of the Corporation: (a) is, as of the date of this Annual Information Form, or has been within

the ten years before the date of this Annual Information Form, a director or executive officer of any company

(including the Corporation) that, while that person was acting in that capacity, or within a year of that person ceasing

to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency

or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver

manager or trustee appointed to hold its assets; or (b) has, within the ten years before the date of this Annual

Information Form, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or

become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver

manager or trustee appointed to hold the assets of the director, executive officer or shareholder.

Penalties or Sanctions

To the knowledge of the Corporation, no director or executive officer of the Corporation (nor any personal holding

company of any such persons), or a shareholder holding a sufficient number of securities of the Corporation to affect

materially the control of the Corporation, has been subject to: (a) any penalties or sanctions imposed by a court relating

to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a

securities regulatory authority; or (b) any other penalties or sanctions imposed by a court or regulatory body that would

likely be considered important to a reasonable investor in making an investment decision.

Conflicts of Interests

Certain officers and directors of the Corporation are also officers and/or directors of other companies engaged in the

oil and gas business generally. As a result, situations may arise where the interest of such officers and directors conflict

with their interests as officers and directors of other companies. The resolution of such conflicts is governed by

applicable corporate laws, which require that officers and directors act honestly and in good faith with a view to the

best interests of the Corporation. Conflicts, if any, will be handled in a manner consistent with the procedures and

remedies set forth in the ABCA. The ABCA requires a director or officer of a corporation who: (i) is a party to a

material contract or material transaction or a proposed material contract or proposed material transaction with the

corporation; or (ii) is a director or officer of or has a material interest in any person who is a party to a material contract

or material transaction or a proposed material contract or proposed material transaction with the corporation, to

disclose the nature and extent of such interest to the corporation and, in the case of directors, refrain from voting on

any matter in respect of such contract or transaction unless otherwise provided by the ABCA.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

Legal Proceedings

There are no legal proceedings that PetroNova is or was a party to, or that any of its property is or was the subject of,

during the year ended December 31, 2014, nor are any such legal proceedings known to PetroNova to be contemplated.

Regulatory Actions

There are no:

(a) penalties or sanctions imposed against the Corporation by a court relating to securities legislation

or by a securities regulatory authority during the year ended December 31, 2014;

65

(b) other penalties or sanctions imposed by a court or regulatory body against the Corporation that

would likely be considered important to a reasonable investor in making an investment decision;

and

(c) settlement agreements PetroNova entered into before a court relating to securities legislation or with

a securities regulatory authority during the year ended December 31, 2014.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Other than as set forth herein or as previously disclosed by the Corporation, there are no material interests, direct or

indirect, of any directors or executive officers of the Corporation, any shareholders who beneficially own, or control

or direct, directly or indirectly, more than 10% of the outstanding Common Shares, or any known associates or

affiliates of any such persons, in any transaction within the last three financial years or during the current financial

year which has materially affected or would materially affect the Corporation, or any of its subsidiaries.

AUDITORS, TRANSFER AGENT AND REGISTRAR

The Corporation’s auditors are Ernst & Young LLP, Chartered Accountants, at its offices located at 1000, 440 – 2nd

Avenue S.W., Calgary, Alberta T2P 5E9. The Corporation’s transfer agent and registrar for the Common Shares is

Computershare, located at 600, 530 – 8th Avenue S.W., Calgary, Alberta T2P 3S8.

MATERIAL CONTRACTS

Except for contracts entered into by the Corporation in the ordinary course of business, the Corporation has not entered

into any contracts within the most recently completed financial year or before the most recently completed financial

year, but which are still in effect, which can reasonably be regarded as presently material, other than the PRE

Agreement and the Suroco Agreement, copies of which are available under the Corporation’s profile on SEDAR at

www.sedar.com.

INTERESTS OF EXPERTS

Names of Experts

The only persons or companies who are named as having prepared or certified a report, valuation, statement or opinion

described or included in a filing, or referred to in a filing, made by the Corporation under NI 51-102 during, or relating

to the Corporation’s most recently completed financial year and whose profession or business gives authority to such

report, valuation, statement or opinion, are:

Ernst & Young LLP, the Corporation’s independent auditors; and

Petrotech, the Corporation’s independent reserves evaluator.

Interests of Experts

To the Corporation’s knowledge, no registered or beneficial interests, direct or indirect, in any securities or other

property of the Corporation or of one of the Corporation’s associates or affiliates: (i) were held by Petrotech or by its

“designated professionals” (as defined in Form 51-102F2) when Petrotech prepared the Petrotech Report; (ii) were

received by Petrotech or its designated professionals after Petrotech prepared the Petrotech Report; or (iii) are to be

received by Petrotech or its designated professionals.

Ernst & Young LLP has advised the Corporation that it is independent of the Corporation within the meaning of the

Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

66

In addition, none of the aforementioned persons or companies nor any director, officer or employee of the

aforementioned persons or companies is or is expected to be elected, appointed or employed as a director, officer or

employee of the Corporation or of any associate or affiliate of the Corporation.

ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of the

Corporation’s securities and securities authorized for issuance under equity compensation plans is contained in the

Corporation´s information circular for its most recent annual meeting of shareholders that involved the election of

directors. Additional financial information is contained in the Corporation’s audited financial statements and

management’s discussion and analysis for the year ended December 31, 2014. Additional information relating to

PetroNova is available under the Corporation’s profile on SEDAR at www.sedar.com.

APPENDIX A

FORM 51-101F2

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR

To the board of directors of PetroNova Inc. (the “Company”):

1. We have evaluated the Company’s reserves data as at December 31, 2014. The reserves data are estimates

of proved reserves and probable reserves and related future net revenue as at December 31, 2014, estimated

using forecast prices and costs.

2. The reserves data are the responsibility of the Company’s management. Our responsibility is to express an

opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation

Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers

(Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether

the reserves data are free of material misstatement. An evaluation also includes assessing whether the

reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed

to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount

rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December

31, 2014, and identifies the respective portions thereof that we have evaluated and reported on to the

Company’s board of directors:

Independent Qualified

Reserves Evaluator

Description and

Preparation Date of

Evaluation Report

Location of

Reserves (Country

or Foreign

Geographic Area)

Net Present Value of Future Net Revenue

(before income taxes, 10% discount rate)

Audited Evaluated Reviewed Total

Petrotech Engineering

Ltd.

Evaluation of the

Interests of PetroNova Inc. in CPO 7 and 13

Blocks in the Eastern

Llanos Basin, Colombia, December

31, 2014 prepared

March 20, 2015

Colombia

-

US$67,209,000

-

US$67,209,000

5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined

and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves

data that we reviewed but did not audit or evaluate.

6. We have no responsibility to update our report referred to in paragraph 4 for events and circumstances

occurring after its preparation date.

7. Because the reserves data are based on judgments regarding future events, actual results will vary and the

variations may be material.

EXECUTED as to our report referred to above.

PETROTECH ENGINEERING LTD., in Burnaby, B.C., Canada; Execution Date: March 20, 2015.

(signed) “John Yu”

APPENDIX B

FORM 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

Management of PetroNova Inc. (the “Corporation”) are responsible for the preparation and disclosure of information

with respect to the Corporation’s oil and gas activities in accordance with securities regulatory requirements. This

information includes reserves data which are estimates of proved reserves and probable reserves and related future net

revenue as at December 31, 2014, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Corporation’s reserves data. The report of the

independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this

report.

The Reserves Committee of the board of directors of the Corporation has:

(a) reviewed the Corporation’s procedures for providing information to the independent qualified

reserves evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected

the ability of the independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the board of directors has reviewed the Corporation’s procedures for assembling and

reporting other information associated with oil and gas activities and has reviewed that information with management.

The board of directors has, on the recommendation of the Reserves Committee, approved:

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves

data and other oil and gas information;

(b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on

the reserves data; and

(c) the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations

may be material.

(signed) “Antonio Vincentelli”

President and Chief Executive Officer

(signed) “Stelvio Di Cecco”

Chief Financial Officer

(signed) “Isaac Yanovich”

Director

(signed) “Ricardo Halfen”

Director

Dated: April 22, 2015