tga-ex991_12.htm

We have adopted the standard of 6 mcf: 1 bbl when converting natural gas to oil and 1 bbl: 6 mcf when converting oil to natural gas. Disclosure provided herein in respect of boe 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. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

All dollar amounts in this AIF, unless otherwise indicated, are stated in United States dollars ("US$"). TransGlobe Energy Corporation ("TransGlobe" or the "Company") uses the U.S. dollar as reporting currency for its consolidated financial statements. The exchange rates for the average of the indicative rates during the period and the end of period for the U.S. dollar in terms of Canadian dollars as reported by the Bank of Canada were as follows for each of the years ended December 31, 2019, 2018 and 2017.

This AIF may include certain statements deemed to be "forward-looking statements" or "future oriented financial information" within the meaning of applicable Canadian and United States securities laws. These statements relate to future events or the Company's future performance. All statements other than statements of historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "may", "will", "should", "expect", "plan", "anticipate", "continue", "believe", "estimate", "predict", "project", "potential", "targeting", "intend", "could", "might", "continue", "should" or the negative of these terms or other comparable terminology. These statements are only predictions. In addition, this AIF may contain forward-looking statements attributed to third-party industry sources. 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. The Company believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this AIF should not be unduly relied upon.

Undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur and may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Forward-looking statements in this AIF include, but are not limited to, statements with respect to:

Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that some or all of the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained in this AIF and certain documents incorporated by reference herein are expressly qualified by this cautionary statement.

Forward-looking information and statements contained in this document include the payment of dividends, including the timing and amount thereof, and the Company's intention to declare and pay dividends in the future. Future dividend payments, if any, and the level thereof is uncertain, as the Company's dividend policy and the funds available for the payment of dividends from time to time will be dependent upon, among other things, free cash flow, financial requirements for the Company's operations and the execution of its strategy, ongoing production maintenance, growth through acquisitions, fluctuations in working capital and the timing and amount of capital expenditures and anticipated business development capital, payment irregularity in Egypt, debt service requirements, general economic conditions and other factors beyond the Company's control. Further, the ability of the Company to pay dividends will be subject to applicable laws (including the satisfaction of the liquidity and solvency tests contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness.

Although the forward-looking statements contained in this AIF are based upon assumptions which management of the Company believes to be reasonable, the Company cannot assure investors that actual results will be consistent with these forward-looking statements. With respect to forward-looking statements contained in this AIF, the Company has made assumptions regarding: current commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the price of oil and gas; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; royalty rates; future operating costs; that the Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Company's conduct and results of operations will be consistent with its expectations; that the Company will have the ability to develop the Company's oil and gas properties in the manner currently contemplated; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; the estimates of the Company's reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; and other matters.

Actual operational and financial results may differ materially from TransGlobe's expectations contained in the forward-looking statements as a result of various risk factors, many of which are beyond the control of the Company. These risk factors include, but are not limited to:

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

The Company has included the above summary of assumptions and risks related to forward-looking information provided in this AIF in order to provide Shareholders with a more complete perspective on the Company's current and future operations and such information may not be appropriate for other purposes. The Company believes that the expectations reflected in the forward-looking statements contained in this AIF are reasonable, but no assurance can be given that these expectations will prove to be correct, and investors should not attribute undue certainty to, or place undue reliance on, such forward-looking statements. Such statements speak only as of the date of this AIF. If circumstances or management’s beliefs, expectations or opinions should change, the Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable Canadian and United States securities laws. Please consult the Company's SEDAR profile at www.sedar.com and the Company's profile on the Electronic Data Gathering and Retrieval System of the U.S. Securities and Exchange Commission ("EDGAR") at www.sec.gov for further, more detailed information concerning these matters.

Netback is a measure of operating results and is computed as sales net of royalties (all government interests, net of income taxes), operating expenses, current taxes and selling costs. The Company's netbacks include sales and associated costs of production from inventoried crude oil sold during the period. Royalties and taxes associated with inventoried crude are recognized at production. Netbacks fluctuate depending on the timing of entitlement oil sales. Management believes that netback is a useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses. Netback does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

In this AIF, the following words and phrases have the following meanings, unless the context otherwise requires:

"ABCA" means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder;

“Arta” means the Arta field in the West Gharib concession in the Egyptian Eastern Desert;

"Brent" means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea;

"Business Day" means a day, other than a Saturday or Sunday, or a statutory holiday, on which major Canadian chartered banks are open for business in Calgary, Alberta;

“Cardium” means the Cardium formation that spans a large area from southwest Alberta to northeast British Columbia, with the producing area concentrated along the eastern slopes of the Rocky Mountains to the northwest of Calgary;

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook maintained by The Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time;

“Debentures” means the C$97,750,000 aggregate principal amount of 6.00% convertible unsecured subordinated debentures which matured on March 31, 2017;

"Dry Hole" or "Dry Well" or "Non-Productive Well" means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well;

"EDGAR" means the Electronic Data Gathering and Retrieval System of the U.S. Securities and Exchange Commission;

"Exploratory Well" means a well drilled either in search of a new, as-yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir;

"GLJ Report" means the report of GLJ dated February 4, 2020 evaluating the crude oil, natural gas and NGL reserves of the Company as at December 31, 2019;

"IFRS" means International Financial Reporting Standards as issued by the International Accounting Standards Board;

“K-South” means the southern area of the K field in the West Bakr concession in the Egyptian Eastern Desert;

“M-Field” means the M field in the West Bakr concession in the Egyptian Eastern Desert;

"NI 51-101" means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities;

"NI 51-102" means National Instrument 51-102 - Continuous Disclosure Obligations;

"RHSE&S Committee" means the Reserves, Health, Safety, Environment & Social Responsibility Committee;

"SEDAR" means the System for Electronic Document Analysis and Retrieval of the Canadian Securities Administrators;

"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp.), as amended, including the regulations promulgated thereunder, each as amended from time to time;

"TransGlobe" or the "Company" means TransGlobe Energy Corporation, a corporation organized and registered under the laws of Alberta, Canada, and as the context requires, its subsidiary companies;

Certain other terms used herein but not defined herein are defined in NI 51-101, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.

TransGlobe was incorporated on August 6, 1968 and was organized under variations of the name "Dusty Mac" as a mineral exploration and extraction venture under The Company Act (British Columbia). In 1992, the Company entered the oil and gas exploration and development industry in the United States and later in Yemen, Canada and Egypt, ceasing operations as a mining company. The Company changed its name to TransGlobe Energy Corporation on April 2, 1996 and on June 9, 2004, the Company continued from the Province of British Columbia to the Province of Alberta pursuant to the ABCA. The Company's U.S. oil and gas properties were sold in 2000 to fund opportunities in Yemen and the Company's previous Canadian oil and gas assets and operations were divested in early 2008 to assist with the funding of opportunities in Egypt and Yemen. In 2015, the Company relinquished and divested all of its interests in Yemen. In 2016, the Company re-entered Canada with the acquisition of production and working interests in certain assets in west central Alberta.

TransGlobe and its subsidiaries are engaged in oil and natural gas exploration, development and production, and the acquisition of oil and natural gas properties in Egypt and Alberta, Canada. The Company currently employs 69 full-time employees and 6 full-time consultants.

The Common Shares have been listed on the TSX under the symbol "TGL" since November 7, 1997 and on the Nasdaq under the symbol "TGA" since January 18, 2008. Prior to listing on the Nasdaq, the Company had its U.S. listing on the American Stock Exchange since 2003. The Common Shares have been listed on the AIM under the symbol "TGL" since June 29, 2018.

The Company's principal office is located at 2300, 250 - 5th Street S.W., Calgary, Alberta, T2P 0R4. The Company's registered office is located at 2400, 525 - 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

The following organization chart and table present the name and jurisdiction of incorporation of the Company’s material subsidiaries as at the date of this document. The chart and table do not include all of the subsidiaries of TransGlobe. The assets and revenues of excluded subsidiaries did not individually exceed 10%, and in aggregate exceed 20%, of the total consolidated assets or total consolidated revenues of TransGlobe as at the date of this document.

TransGlobe's Canadian properties are owned by TransGlobe Energy Corporation. The following table sets out the name and jurisdiction of incorporation of the subsidiaries beneficially owned, controlled or directed, directly or indirectly, by TPI. Unless otherwise indicated, the Company owns, directly or indirectly, 100% of the voting securities of all the subsidiaries below.

Unless the context otherwise requires, reference in this AIF to "TransGlobe" or the "Company" includes the Company and its direct and indirect wholly-owned subsidiaries.

During the past three years, TransGlobe has developed its business interests through a combination of acquisitions, divestitures, exploration and development.

In 2017, TransGlobe engaged in a drilling program that included a return to Canada, drilling 15 wells in Egypt and three wells in Canada. The exploration drilling program at NW Gharib and SW Gharib, consisting of nine wells in aggregate, yielded two oil discoveries (NWG 26ST and NWG 27ST). The exploration program at South Alamein consisted of one well which was cased, tested and subsequently abandoned. The Company fulfilled its exploration work program commitments in NW Gharib and SW Gharib in 2017. In addition to the exploration program, the Company drilled seven development oil wells and one appraisal oil well in NW Gharib, West Gharib, West Bakr, and Canada resulting in six oil wells.

Reserves at 2017 year-end were lower compared to 2016 year-end primarily due to 2017 production and negative technical revisions of undeveloped Canadian Mannville gas locations. The Company drilled four development oil wells (one in K-South, one in the Arta Red Bed pool, and two in the NW Gharib Red Bed pool) during the year. In addition, the Company filed for and received its second, third and fourth development leases in NW Gharib. In Canada, the Company successfully drilled three development oil wells in the Harmattan area. The Company produced a total of 5.7 MMboe of crude oil, natural gas and natural gas liquids in 2017. One additional Arta Red Bed development well and one K South development well were drilled and rig released subsequent to December 31, 2017.

On February 10, 2017, TransGlobe announced the execution of a $75 million crude oil prepayment agreement between TPI and Mercuria. The prepayment agreement has a term of four years, maturing March 31, 2021, with advances bearing interest at a substantially similar rate as the Company's Debentures at then-current LIBOR rates. Funding under the prepayment agreement is revolving, with each advance to be satisfied through the delivery of crude oil to Mercuria pursuant to the marketing contract described below. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75 million subject to compliance with the terms and conditions of the prepayment agreement, including maintenance of a cover ratio which is calculated by dividing the value of forecasted production of crude oil over the applicable period by the outstanding obligations of TPI under the prepayment agreement. If crude oil is not delivered in satisfaction of an advance, the obligations in respect of that advance are ultimately payable in cash. The obligations of TPI under the prepayment agreement and the marketing contract described below are guaranteed by the Company and TPI's subsidiaries, and are supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries.

In conjunction with the prepayment agreement, on February 10, 2017, TPI entered into a marketing contract with Mercuria. Pursuant to the marketing contract, TPI will deliver and Mercuria will market up to 9 million barrels of TPI's crude oil entitlement production from its West Bakr and West Gharib oil fields. Mercuria will receive a per barrel marketing fee, and will use commercially reasonable efforts to achieve the highest and best price for the crude oil delivered under the marketing contract. The pricing of crude oil sales will be based on indexed market prices at the time of sale. Subject to earlier termination of the marketing agreement in accordance with the terms thereof, deliveries of crude oil under the marketing agreement will terminate on the later of: (i) the delivery of 9 million barrels of crude oil; (ii) the prepayment agreement maturity date (March 31, 2021); or (iii) satisfaction of all amounts outstanding under the prepayment agreement.

On May 16, 2017, TransGlobe announced it had entered into a credit agreement for an RBL with ATB. Pursuant to the credit agreement, the RBL commitment was up to a maximum of C$30 million. The amount available to be drawn on the RBL will be dependent upon the borrowing base, which is determined with reference to the Company’s proved oil and gas reserves in Canada, as evaluated in the most recent annual reserves report(s) and delivered pursuant to the credit agreement. As of the closing date, the borrowing base was set at C$30 million (reduced to C$25 million on July 11, 2019). TransGlobe initially used the funds available under the RBL to repay the existing C$15 million vendor-take-back loan outstanding, which had an interest rate of 10% per annum. Additional funds were allocated as necessary to carry out the Company’s capital expenditure program in Canada.

TransGlobe's 2018 drilling program included drilling eight development oil wells in Egypt (two in Arta, two in NW Gharib, two in K-South, and two in M-field) and four exploration wells (two in NW Sitra, two in S Ghazalat). In Canada, the Company successfully drilled six gross (five net) development oil wells in the Harmattan area.

2P reserves at year-end 2018 were 4% lower than 2017 primarily due to production of 5.3 MMboe, substantially offset by net positive revisions of 3.5 MMboe. The net positive revisions reflect additions from a discovery at S Ghazalat, extensions at West Bakr, improved recovery in Egypt, and infill drilling in Canada, offset by a negative revision related to minor asset performance in Egypt and economic factors in Canada.

TransGlobe produced an average of 14,439 boe/d in 2018 (2017 - 15,506 boe/d). Egypt average production was 12,150 bbls/d (2017 - 12,822 bbls/d), including heavy crude oil production of 11,197 bbls/d (2017 - 11,613 bbls/d) and light & medium crude oil production of 953 bbls/d (2017 - 1,209 bbls/d). In Canada average production was 2,289 boe/d (2017 - 2,684 boe/d) including 558 bbls/d of light & medium crude oil (2017 – 589 bbls/d), 780 bbls/d of natural gas liquids (2017 – 988 bbls/d) and 5,707 mcf/d of conventional natural gas (2017 – 6,644 mcf/d).

The Board approved the reinstatement of dividend payments in 2018. Subject to Board approval the Company will aspire to pay a semi-annual dividend to Shareholders determined at each period after consideration for: (i) ongoing production maintenance; (ii) growth through acquisitions; (iii) maintaining a conservative balance sheet to manage commodity price volatility; (iv) payment irregularity in Egypt and solvency requirements; and (v) the cash flow generating capability of the business. In August 2018, the Board approved a dividend payment to Shareholders of $0.035/Common Share payable on September 14, 2018.

TransGlobe's 2019 drilling program included drilling six development wells in Egypt (five in West Bakr and one in NW Gharib) and two exploration wells (one in West Bakr and one in NW Gharib). Facilities were also installed at S Ghazalat 6X. In Canada, the Company successfully drilled three

one-mile horizontal development oil wells and one two-mile outpost appraisal well on lands acquired in 2018, located south of the Harmattan area and north of the Lochend area, which the Company refers to as South Harmattan.

TransGlobe produced an average of 16,041 boe/d in 2019 (2018 - 14,439 boe/d). Egypt average production was 13,713 bbls/d (2018 - 12,150 bbls/d), including heavy crude oil production of 12,840 bbls/d (2018 - 11,197 bbls/d) and light & medium crude oil production of 873 bbls/d (2018 - 953 bbls/d). In Canada average production was 2,328 boe/d (2018 - 2,289 boe/d) including 814 bbls/d of light & medium crude oil (2018 – 558 bbls/d), 582 bbls/d of natural gas liquids (2018 – 780 bbls/d) and 5,594 mcf/d of conventional natural gas (2018 – 5,707 mcf/d).

2P reserves at year-end 2019 were up 4% from 2018 primarily due to Proved plus Probable (“2P“) reserves replacement of 135% (excluding economic factors) against 5.8 MMboe of production. Production outperformed forecasts, primarily at West Bakr, which led to positive 2P technical revisions of 4.4 MMboe.

In 2019, the Company relinquished the South Alamein and NW Sitra concessions and received approval for the S Ghazalat development lease from EGPC and the Ministry of Petroleum, with first oil produced at the end of December 2019.

Constructive negotiations with EGPC to amend, extend and consolidate the Company’s Eastern Desert concession agreements have continued through the year. While the Company believes that alignment has been reached on the major components of a revised concession agreement that would incentivize the Company to significantly ramp up investment targeting increased production and reserves in these mature fields, EGPC internal processes to validate and approve any revised agreement are complex and time consuming, and may not result in an agreement.

Mr. Herrick retired from the Company effective January 1, 2020. Mr. Herrick was the Executive Vice President of the Company from March 18, 2019 to January 1, 2020. Prior to this, Mr. Herrick held the position of Vice President and Chief Operating Officer of the Company from April 1999 to March 17, 2019.

On March 11, 2020, the Company decided to reduce its 2020 capital program (before capitalized G&A) from US$37.1 million to US$7.1 million and to suspend its dividend in order to manage cash until such time that it is appropriate to reinstate the dividend. Those decisions were made in light of global reaction to the spread of COVID-19 and the resultant reduction in oil demand, compounded by OPEC+, led by Saudi Arabia and Russia, failing to reach an agreement on constraining output in face of lower global demand to support global oil prices and the stated intention of certain OPEC member countries to discount future deliveries and increase crude oil supply into the market. The Board will evaluate its decision on future dividend payments on a semi-annual basis going forward. See "Dividend Policy" and "Risk Factors".

TransGlobe did not complete any significant acquisitions during its most recently completed financial year for which disclosure is required under Part 8 of NI 51-102.

TransGlobe is engaged in the exploration, development and production of crude oil and natural gas in Egypt and Canada. The Company also regularly reviews potential acquisitions and new international exploration blocks to supplement its exploration and development activities.

TransGlobe has had operations in Egypt during the past 16 years. The Company also operated in Canada from 1999 to 2008, and made a re-entry into Canada in December 2016. In Egypt, the Company currently has an interest in four PSCs: West Gharib, West Bakr, NW Gharib, and S Ghazalat. In Canada, the Company owns production and working interests in certain facilities in the Cardium light oil and Mannville liquid-rich gas assets in the Harmattan area of west central Alberta.

A significant portion of the Company's operations occur outside of Canada and therefore are subject to political and regulatory risk in those other jurisdictions. See "Risk Factors".

There is considerable competition in the worldwide oil and natural gas industry, including in Egypt and Canada where the Company's assets, activities, and employees are located. Operators more established than the Company, with access to broader technical skills, technology, larger amounts of capital and other resources, and are active in the industry in Egypt and Canada, where the Company has operations. This represents a significant risk for the Company, which must rely on modest resources as compared to some of its competitors. See "Risk Factors - Competition".

The Company operates under the jurisdiction of a number of regulatory bodies and agencies that set forth numerous prohibitions and requirements with respect to planning and approval processes related to land use, sustainable resource management, waste management, responsibility for the release of presumed hazardous materials, protection of wildlife and the environment, and the health and safety of workers. Legislation provides for restrictions and prohibitions on the transport of dangerous goods and the release or emission of various substances, including substances used and produced in association with certain oil and gas industry operations. The legislation addresses various permits, including for drilling, well completion,

installation of surface equipment, air monitoring, surface and ground water monitoring in connection with these activities, waste management and access to remote or environmentally sensitive areas.

Historically, environmental protection requirements have not had a significant financial or operational effect on TransGlobe's capital expenditures, earnings or competitive position. Subject to any changes in current environmental protection legislation, or in the way the legislation is interpreted in the jurisdictions in which it operates, TransGlobe does not presently anticipate environmental protection requirements will have a significant effect on such matters in 2020. The Company is exposed to potential environmental liability in connection with its business of oil and gas exploration and production. See "Risk Factors".

The Company's RHSE&S Committee reviewed and approved fundamental policies pertaining to health, safety, environment and social responsibility which have the potential to impact the Company's activities and strategies. The RHSE&S Committee reported to the Board on TransGlobe's performance with respect to applicable laws, regulations and Company policies and also in respect to emerging trends, issues and regulations related to health, safety and environment. The RHSE&S Committee is comprised of a majority of independent directors and continues to report to the Board on TransGlobe's performance with respect to applicable laws, regulations and Company policies and also in respect to emerging trends, issues and regulations related to health, safety and environment.

TransGlobe acknowledges that investors, particularly large institutional investors, are seeking improved disclosure from the companies they invest in on the material risks, opportunities, financial impacts and governance processes related to climate change. TransGlobe is in the early stages of evaluating the impact of climate-change related risks on its business and strategy. In 2020, TransGlobe is committed to taking appropriate steps, commensurate with its size and available resources, to better understanding and assessing the materiality of these risks to its business, including the Board’s oversight of climate-related risks and opportunities and management’s role in assessing and managing climate-related risks and opportunities. By 2021, TransGlobe expects to be able to provide more disclosure of how climate-related issues may be relevant in its current governance, strategy, and risk management practices. In doing so, the Company expects to improve the transparency and reporting of its sustainability performance, including as it relates to climate change related risks, and will consider existing standards such as the Global Reporting Initiative Sustainability Reporting Standards, the Sustainability Accounting Standards Board’s documentation, and recommendations issued by the Task Force for Climate Related Financial Disclosures. The Company’s disclosures are expected to evolve and mature as understanding, data analytics, and modeling of climate-related issues become more widespread. See “Risk Factors – Climate Change” for more details of certain climate change related risks that affect, and may in the future affect, TransGlobe’s business.

TransGlobe employs individuals with various professional skills in the course of pursuing its business plan. These professional skills include, but are not limited to, geology, geophysics, engineering, financial, accounting and business skills, which are widely available in the industry. Drawing on significant experience in the oil and gas business, TransGlobe believes its management team has a demonstrated track record of bringing together all of the key components to a successful exploration and production company, including: strong technical skills; expertise in planning and financial controls; the ability to execute on business development opportunities; capital markets expertise; and an entrepreneurial spirit that allows TransGlobe to effectively identify, evaluate and execute on its business plan.

Our operational results and financial condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas regions. Any decline in oil and natural gas prices could have an adverse effect on our financial condition. We mitigate such price risk through closely monitoring the various commodity markets and establishing hedging programs, as deemed necessary, to fix netbacks on production volumes. See "Statement of Reserves Data and other Oil and Gas Information - Other Oil and Gas Information - Forward Contracts" for our current hedging program.

All of the Company's Egyptian blocks are PSCs between the host government and the contractor. The government takes their share of production based on the terms and conditions of the respective contracts. The contractors' share of all taxes and royalties are paid out of the government's share of production.

The PSCs provide for the government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, if any, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSC. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Unutilized cost sharing oil or excess cost oil (maximum cost recovery less actual cost recovery) is shared between the government and the contractor as defined in the specific PSCs. Each PSC is treated individually in respect of cost recovery and production sharing purposes. The remaining production sharing oil (total production, less gross royalty, less cost oil) is shared between the government and the contractor as defined in the specific PSCs. None of the Egyptian PSCs contain minimum production or sales requirements, and there are no restrictions with respect to pricing of the Company's sales volumes. Except as otherwise disclosed in this AIF, all crude oil sales are priced at current market rates at the time of sale.

The following tables summarize the Company's international PSC terms for the first tranche(s) of production for each block. All of the contracts have different terms for production levels above the first tranche, which are unique to each contract. The government's share of production increases and the contractor's share of production decreases as the production volumes go to the next production tranche. TransGlobe is the operator of, and has a 100% working interest in, all PSCs.

Block	West Gharib		West Bakr		NW Gharib
Year acquired	2007		2011		2013
Block Area (acres)		22,725		11,143		11,199
Expiry date	2024-2026		Apr 2020¹		2036-2037
Extensions
Exploration	N/A		N/A		N/A
Development	+ 5 years		+ 5 years		+ 5 years

Production Tranche (mbopd)	0-5		0-50		0-5

Max. cost oil	30%		30%		25%
Excess cost oil
Contractor	30%		0%		5%
Depreciation per quarter
Operating	100%		100%		100%
Capital	6%		5%		5%
Production Sharing Oil:
Contractor	30%		15%		15%
Government	70%		85%		85%

In Egypt, the Company drilled six development wells and two exploration wells in 2019. Five developments wells were drilled at West Bakr (M-10 Twin, K-8 WDW, K-10 WDW, H-30 and K-63) and one development well was drilled at NW Gharib (NWG 38A-8 Inj). One exploration well was drilled at West Bakr (HW-2X) and one exploration well was drilled at NW Gharib (NWG 38D-1). Both exploration wells drilled in 2019 were confirmed as oil discoveries. Production facilities were installed at S Ghazalat, resulting in S Ghazalat-6X’s upper Bahariya reservoir being brought on stream on December 24, 2019. The primary focus of the 2019 Egypt capital program was to sustain/grow Eastern Desert production and to evaluate the S Ghazalat exploration concession in the Western Desert.

In Canada, the Company equipped and tied in six gross (five net) Cardium oil wells (from the 2018 capital program) in the Harmattan area in January 2019. The 2019 drilling program commenced in the third quarter of 2019 and consisted of three Cardium development oil wells (one-mile horizontal wells) drilled from existing pads and one Cardium outpost well (two-mile horizontal well) to appraise the land acquired south of Harmattan in 2018. The Company had stimulated, equipped for production and successfully put on stream all four wells prior to year-end. The three development wells in the core Harmattan area in the 2019 drilling program were focused on reserves conversions, moving the reserves from the undeveloped to developed categories.

The report on reserves data in Form 51-101F2 and the report of management and directors on oil and gas disclosure in Form 51-101F3 are attached as Schedules "A" and "B", respectively, to this AIF, which forms are incorporated herein by reference.

The statement of reserves data and other oil and gas information set forth below GLJ Report is dated February 4, 2020, with the effective date being December 31, 2019.

All of the Company's reserves herein reported were evaluated by independent evaluators in accordance with NI 51-101 for the year ended December 31, 2019. In 2019, GLJ, independent petroleum engineering consultants based in Calgary, Alberta, were retained by the Company's RHSE&S Committee to independently evaluate 100% of TransGlobe's reserves as at December 31, 2019.

The reserves data set forth below (the "Reserves Data") was prepared by GLJ with an effective date of December 31, 2019 and December 31, 2018, respectively. The Reserves Data summarizes the crude oil, natural gas liquids and natural gas reserves of the Company and the net present values of future net revenue for these reserves using forecast prices and costs. The Company reports in U.S. currency and therefore the reports have been converted to U.S. dollars at the prevailing conversion rate at December 31 of the respective years. See "Currency and Exchange Rates". All of the Company's reserves are located in the province of Alberta, Canada and Egypt.

The GLJ Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in NI 51-101 and the COGE Handbook. The Reserves Data conforms to the requirements of NI 51-101. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which the Company believes is important to the readers of this information.

All evaluations and reviews of future net revenue are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net revenue shown below is representative of the fair market value of the Company's properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserves estimates of crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGLs and natural gas reserves may be greater than or less than the estimates provided herein.

In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserves recovery, timing and amount of capital expenditures, marketability of crude oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies, and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery, and estimates of future net revenues associated with reserves may vary and such variations may be material. The actual production, revenues, taxes and development and operating expenditures with respect to the reserves associated with the Company's properties may vary from the information presented herein and such variations could be material. In addition, there is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variances could be material.

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 information relating to the Company's reserves contains forward-looking statements relating to future net revenues, forecast capital expenditures, future development plans and costs related thereto, forecast operating costs and anticipated production. See "Forward-Looking Statements" and "Risk Factors".

Possible reserves are those additional reserves that are less certain to be recovered than probable resources. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

	Light & Medium								Conventional
	Crude Oil				Heavy Crude Oil				Natural Gas				Natural Gas Liquids				Total
	Gross¹		Net²		Gross¹		Net²		Gross¹		Net²		Gross¹		Net²		Gross¹		Net²
By Category	(MMbbls)		(MMbbls)		(MMbbls)		(MMbbls)		(Bcf)		(Bcf)		(MMbbls)		(MMbbls)		(MMboe)		(MMboe)
Proved
Developed Producing		2.7		2.1		11.2		5.5		14.2		11.8		2.3		1.7		18.5		11.3
Developed Non-Producing		0.3		0.2		1.7		0.8		0.3		0.3		0.0		0.0		2.1		1.1
Undeveloped		1.9		1.6		1.3		0.6		4.7		4.3		0.8		0.7		4.8		3.6
Total Proved		4.9		4.0		14.2		6.8		19.2		16.4		3.1		2.5		25.4		16.0
Probable		4.4		3.3		9.4		4.2		18.9		17.2		3.0		2.6		19.9		12.9
Proved+Probable		9.3		7.3		23.6		11.0		38.1		33.6		6.1		5.1		45.3		28.9
Possible		3.9		2.6		9.6		4.3		13.3		11.6		2.2		1.8		18.0		10.7
Proved+Probable+ Possible		13.2		9.9		33.2		15.3		51.4		45.2		8.3		6.9		63.3		39.6

	Light & Medium
	Crude Oil				Heavy Crude Oil				Total Bbls
	Gross¹		Net²		Gross¹		Net²		Gross¹		Net²
By Category	(MMbbls)		(MMbbls)		(MMbbls)		(MMbbls)		(MMbbls)		(MMbbls)
Proved
Developed Producing		0.8		0.5		11.2		5.5		12.1		6.0
Developed Non-Producing		0.2		0.1		1.7		0.8		1.9		0.9
Undeveloped		0.3		0.2		1.3		0.6		1.6		0.8
Total Proved		1.3		0.9		14.2		6.8		15.6		7.7
Probable		1.8		1.1		9.4		4.2		11.2		5.2
Proved+Probable		3.1		2.0		23.6		11.0		26.7		12.9
Possible		2.4		1.3		9.6		4.3		12.0		5.7
Proved+Probable+ Possible		5.5		3.3		33.2		15.3		38.7		18.6

	Light & Medium								Conventional
	Crude Oil				Heavy Crude Oil				Natural Gas				Natural Gas Liquids				Total Bbls
	Gross¹		Net²		Gross¹		Net²		Gross¹		Net²		Gross¹		Net²		Gross¹		Net²
By Category	(MMbbls)		(MMbbls)		(MMbbls)		(MMbbls)		(Bcf)		(Bcf)		(MMbbls)		(MMbbls)		(MMboe)		(MMboe)
Proved
Developed Producing		1.8		1.6		—		—		14.2		11.8		2.3		1.7		6.5		5.3
Developed Non-Producing		0.1		0.1		—		—		0.3		0.3		0.0		0.0		0.2		0.1
Undeveloped		1.6		1.4		—		—		4.7		4.3		0.8		0.7		3.2		2.8
Total Proved		3.5		3.1		—		—		19.2		16.4		3.1		2.5		9.9		8.3
Probable		2.6		2.2		—		—		18.9		17.2		3.0		2.6		8.7		7.7
Proved+Probable		6.1		5.3		—		—		38.1		33.6		6.1		5.1		18.6		16.0
Possible		1.6		1.3		—		—		13.3		11.6		2.2		1.8		6.0		5.0
Proved+Probable+ Possible		7.7		6.6		—		—		51.4		45.2		8.3		6.9		24.6		21.0

The estimated future net revenues presented in the tables below do not represent fair market value. The estimated future net revenues presented below are calculated using the price forecasts and inflation rates set forth below under "Pricing Assumptions".

	Before Income Tax¹											After Income Tax¹										Unit Value Before Tax (discounted at
US$	Discounted at %/yr											Discounted at %/yr										10%/year)
$MM		—	%	5%		10%		15%		20%		0%		5%		10%		15%		20%		($/Boe)
Proved
Developed Producing		214.9			183.6		161.2		144.4		131.4		214.9		183.6		161.2		144.4		131.4		14.23
Developed Non-Producing		17.8			14.9		12.7		10.9		9.5		17.8		14.9		12.7		10.9		9.5		11.90
Undeveloped		73.8			42.7		26.4		17.2		11.7		65.0		38.5		24.3		16.1		11.1		7.33
Total Proved		306.4			241.2		200.3		172.5		152.6		297.7		237.0		198.2		171.4		151.9		12.52
Probable		248.9			147.0		98.0		70.9		54.3		215.0		130.9		89.4		65.9		51.2		7.59
Proved+Probable		555.3			388.2		298.3		243.5		206.9		512.6		367.9		287.6		237.3		203.1		10.32
Possible		254.9			142.1		94.2		69.4		54.5		225.8		130.2		88.3		66.0		52.3		8.82
Proved+Probable+ Possible		810.2			530.2		392.5		312.8		261.3		738.4		498.2		375.9		303.3		255.5		9.91

	Before Income Tax¹											After Income Tax¹											Unit Value Before Tax (discounted at
US$	Discounted at %/yr											Discounted at %/yr											10%/year)
$MM		—	%	5	%	10	%	15	%	20	%		—	%	5	%	10	%	15	%	20	%	($/Bbl)
Proved
Developed Producing		128.8		116.3		106.3		98.0		91.2			128.8		116.3		106.3		98.0		91.2			17.65
Developed Non-Producing		14.8		12.4		10.6		9.2		8.0			14.8		12.4		10.6		9.2		8.0			11.53
Undeveloped		12.2		10.0		8.3		7.0		6.0			12.2		10.0		8.3		7.0		6.0			11.06
Total Proved		155.9		138.8		125.2		114.2		105.1			155.9		138.8		125.2		114.2		105.1			16.27
Probable		102.0		77.0		60.0		48.1		39.5			102.0		77.0		60.0		48.1		39.5			11.45
Proved+Probable		257.9		215.7		185.2		162.3		144.6			257.9		215.7		185.2		162.3		144.6			14.32
Possible		128.3		89.8		67.1		52.6		42.9			128.3		89.8		67.1		52.6		42.9			11.80
Proved+Probable+ Possible		386.1		305.5		252.3		215.0		187.5			386.1		305.5		252.3		215.0		187.5			13.55

	Before Income Tax											After Income Tax											Unit Value Before Tax (discounted at
US$	Discounted at %/yr											Discounted at %/yr											10%/year)
$MM		—	%	5	%	10	%	15	%	20	%		—	%	5	%	10	%	15	%	20	%	($/Boe)
Proved
Developed Producing		86.0		67.3		54.9		46.4		40.2			86.0		67.3		54.9		46.4		40.2			10.35
Developed Non-Producing		3.0		2.5		2.1		1.8		1.5			3.0		2.5		2.1		1.8		1.5			14.24
Undeveloped		61.6		32.6		18.1		10.2		5.7			52.8		28.5		16.0		9.1		5.1			6.35
Total Proved		150.6		102.4		75.1		58.3		47.5			141.8		98.3		73.0		57.2		46.9			9.04
Probable		146.9		70.1		38.0		22.8		14.9			113.0		53.9		29.4		17.8		11.7			4.96
Proved+Probable		297.5		172.4		113.1		81.2		62.3			254.8		152.2		102.3		75.0		58.6			7.08
Possible		126.6		52.3		27.2		16.7		11.5			97.6		40.5		21.3		13.3		9.4			5.43
Proved+Probable+ Possible		424.1		224.7		140.2		97.9		73.9			352.3		192.7		123.6		88.4		68.0			6.69

	Revenue		Royalties		Operating Costs²		Development Costs		Well Abandonment and Reclamation Costs²		Future Net Revenue Before Income Taxes³		Income Taxes³		Future Net Revenue After Income Taxes³
Reserves Category	(US$MM)		(US$MM)		(US$MM)		(US$MM)		(US$MM)		(US$MM)		(US$MM)		(US$MM)
Proved Reserves
Canada		373.5		55.9		120.1		36.9		9.9		150.6		8.8		141.8
Egypt		914.1		550.8		195.2		12.2		—		155.9		—		155.9
Total Company		1,287.6		606.8		315.3		49.2		9.9		306.4		8.8		297.7
Proved+Probable Reserves
Canada		732.9		103.8		219.3		98.7		13.5		297.5		42.7		254.8
Egypt		1,630.3		995.8		353.9		22.7		—		257.9		—		257.9
Total Company		2,363.1		1,099.6		573.2		121.4		13.5		555.3		42.7		512.6
Proved+Probable+Possible Reserves
Canada		1,001.6		150.0		298.1		113.7		15.7		424.1		71.8		352.3
Egypt		2,437.6		1,493.7		528.7		29.2		—		386.1		—		386.1
Total Company		3,439.3		1,643.7		826.8		142.8		15.7		810.2		71.8		738.4

"Development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

"Exploration costs" means 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 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:

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on:

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

Other criteria that must also be met for the categorization of reserves are provided in Section 5.5.4 of the COGE Handbook.

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

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 estimator'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.

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves 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 reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

A qualitative 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 reserves estimates will be 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.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in Section 5 of the COGE Handbook.

The forecast cost and price assumptions assume changes in wellhead selling prices and take into account inflation with respect to future operating and capital costs.

For the reserves, crude oil benchmark reference pricing, as at December 31, 2019, inflation and exchange rates utilized by GLJ in the Reserves Data, which were GLJ's then current forecasts at the date of the Reserves Data, were as follows:

	WTI Cushing Oklahoma		Edmonton Par Price 40 API		Brent Reference Price		AECO Gas Price		Ethane		Propane		Butane		Pentane		Inflation Rates %		Exchange Rate
Year	(US$/bbl)		(C$/bbl)		(US$/bbl)		(C$/MMBtu)		(C$/bbl)		(C$/bbl)		(C$/bbl)		(C$/bbl)		Year		(C$/US$)
Forecast
2020		61.00		71.71		67.00		2.08		6.42		28.68		48.76		77.80		—		0.760
2021		63.00		74.03		68.00		2.35		7.36		31.09		51.82		79.22		2.00		0.770
2022		66.00		76.92		71.00		2.55		8.05		34.62		54.62		83.33		2.00		0.780
2023		68.00		80.13		73.00		2.65		8.39		36.06		56.89		86.54		2.00		0.780
2024		70.00		82.69		75.00		2.75		8.73		37.21		58.71		89.10		2.00		0.780
2025		72.00		85.26		76.00		2.85		9.08		38.37		60.53		91.67		2.00		0.780
2026		74.00		87.82		78.00		2.91		9.29		39.52		62.35		94.23		2.00		0.780
2027		75.81		90.14		79.81		2.97		9.48		40.56		64.00		96.55		2.00		0.780
2028		77.33		92.09		81.33		3.03		9.69		41.44		65.38		98.50		2.00		0.780
2029		78.88		94.08		82.88		3.09		9.91		42.33		66.79		100.49		2.00		0.780
Thereafter	Escalate oil, gas and product prices at 2.0% per year thereafter																+2.0%/year		+0%/year

The weighted average historical price in US$ realized by the Company in Egypt, for the year ended December 31, 2019 for crude oil was $55.50/bbl.

The weighted average historical price in US$ realized by the Company in Canada, for the year ended December 31, 2019 for crude oil and natural gas liquids was $51.02/bbl and $22.93/bbl, respectively, and for conventional natural gas was $1.33/Mcf.

	LIGHT & MEDIUM CRUDE OIL									HEAVY CRUDE OIL
	Gross Proved			Gross Probable			Gross Proved Plus Probable			Gross Proved			Gross Probable			Gross Proved Plus Probable
FACTORS	(MMbbl)			(MMbbl)			(MMbbl)			(MMbbl)			(MMbbl)			(MMbbl)
December 31, 2018		5.8			3.8			9.6			14.0			8.0			22.1
Discoveries		—			—			—			—			—			—
Extensions and improved recovery		0.5			0.6			1.0			1.1			0.3			1.4
Technical Revisions		(0.6	)		(0.2	)		(0.8	)		3.7			1.1			4.8
Acquisitions		—			—			—			—			—			—
Dispositions		—			—			—			—			—			—
Economic Factors		(0.2	)		0.2			—			—			(0.1	)		—
Production		(0.6	)		—			(0.6	)		(4.7	)		—			(4.7	)
December 31, 2019		4.9			4.4			9.3			14.2			9.4			23.6

	CONVENTIONAL NATURAL GAS									NATURAL GAS LIQUIDS
	Gross Proved			Gross Probable			Gross Proved Plus Probable			Gross Proved			Gross Probable			Gross Proved Plus Probable
FACTORS	(Bcf)			(Bcf)			(Bcf)			(MMbbl)			(MMbbl)			(MMbbl)
December 31, 2018		21.6			16.5			38.1			3.4			2.6			6.0
Discoveries		—			—			—			—			—			—
Extensions and improved recovery		1.5			1.6			3.1			0.2			0.2			0.4
Technical Revisions		(0.6	)		1.8			1.2			(0.2	)		0.4			0.2
Acquisitions		—			—			—			—			—			—
Dispositions		—			—			—			—			—			—
Economic Factors		(1.2	)		(1.0	)		(2.2	)		(0.1	)		(0.3	)		(0.4	)
Production		(2.1	)		—			(2.1	)		(0.2	)		—			(0.2	)
December 31, 2019		19.2			18.9			38.1			3.1			3.0			6.1

	LIGHT & MEDIUM CRUDE OIL								HEAVY CRUDE OIL
	Gross Proved			Gross Probable		Gross Proved Plus Probable			Gross Proved			Gross Probable			Gross Proved Plus Probable
FACTORS	(MMbbl)			(MMbbl)		(MMbbl)			(MMbbl)			(MMbbl)			(MMbbl)
December 31, 2018		1.9			1.8		3.6			14.0			8.0			22.1
Discoveries		—			—		—			—			—			—
Extensions and improved recovery¹		—			—		—			1.1			0.3			1.4
Technical Revisions²		(0.2	)		—		(0.2	)		3.7			1.1			4.8
Acquisitions		—			—		—			—			—			—
Dispositions		—			—		—			—			—			—
Economic Factors³		—			—		—			—			(0.1	)		—
Production		(0.3	)		—		(0.3	)		(4.7	)		—			(4.7	)
December 31, 2019		1.3			1.8		3.1			14.2			9.4			23.6

	LIGHT & MEDIUM CRUDE OIL									CONVENTIONAL NATURAL GAS
	Gross Proved			Gross Probable			Gross Proved Plus Probable			Gross Proved			Gross Probable			Gross Proved Plus Probable
FACTORS	(MMbbl)			(MMbbl)			(MMbbl)			(Bcf)			(Bcf)			(Bcf)
December 31, 2018		4.0			2.0			6.0			21.6			16.5			38.1
Discoveries		—			—			—			—			—			—
Extensions and improved recovery¹		0.5			0.6			1.0			1.5			1.6			3.1
Technical Revisions²		(0.4	)		(0.2	)		(0.6	)		(0.6	)		1.8			1.2
Acquisitions		—			—			—			—			—			—
Dispositions		—			—			—			—			—			—
Economic Factors³		(0.2	)		0.2			(0.0	)		(1.2	)		(1.0	)		(2.2	)
Production		(0.3	)		—			(0.3	)		(2.1	)		—			(2.1	)
December 31, 2019		3.5			2.6			6.1			19.2			18.9			38.1

Undeveloped reserves are attributed by GLJ in accordance with 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 the COGE Handbook. In general, undeveloped reserves are planned to be developed over the next two years.

In some cases, it will take longer than two years to develop these reserves. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals). For more information, see "Risk Factors" herein.

The following tables set forth the gross proved undeveloped reserves and the gross probable undeveloped reserves, each by product type, attributed to the Company in the most recent three financial years.

A total of 4.7 Bcf of conventional natural gas, 1.9 MMbbl of light crude oil and medium crude oil, 1.3 MMbbl of heavy crude oil and 0.8 MMbbl of NGLs were assigned in the GLJ Report under forecast prices and costs as gross proved undeveloped reserves as at December 31, 2019, representing approximately 19% of total proved reserves, together with $49.2 million of associated undiscounted future capital expenditures. The proved undeveloped reserves are generally associated with infill/development drilling locations supported by offset well data.

The Company plans to develop twenty four percent of its proved undeveloped reserves over the next two years. These reserves are attributed to the Company’s Harmattan property in Canada and West Gharib and West Bakr concessions in Egypt. The remaining proved undeveloped reserves will be developed between 2022 and 2024 deferred due to the availability of processing capacity at the Company’s Harmattan 12-18-031-02W5M battery in Canada and higher-priority opportunities in Egypt. Although TransGlobe expects the development of the proved undeveloped reserves attributed to the Company's assets to be consistent with that set out above, current industry conditions and other uncertainties as discussed under "Risk Factors" and "Canadian Industry Conditions" herein could result in development of such proved undeveloped reserves on a different schedule than set out above.

A total of 14.6 Bcf of conventional natural gas, 2.6 MMbbl of light crude oil and medium crude oil, 2.3 MMbbl of heavy crude oil and 2.3 MMbbl of NGLs were assigned in the GLJ Report under forecast prices and costs as gross probable undeveloped reserves as at December 31, 2019, representing approximately 48% of total probable reserves, together with $72.2 million of associated undiscounted future capital expenditures. The probable undeveloped reserves are generally associated with infill/development drilling locations supported by offset well data.

The Company’s probable undeveloped reserves are attributed to Harmattan and Lone Pine in Canada and the S Ghazalat, West Bakr and NW Gharib concessions in Egypt. The Company’s probable undeveloped reserves are scheduled to be developed over the next eight years scheduled to maximize the processing capacity at the Company’s Harmattan 12-18-031-02W5M battery and the Company’s Harmattan 09-05-031-02W5M compressor station in Canada and higher-priority opportunities in Egypt. Approximately fifteen per cent of the Company’s probable undeveloped reserves will be developed over the next two years. Although TransGlobe expects the development of the probable undeveloped reserves attributed to the Company's assets to be consistent with that set out above, current industry conditions and other uncertainties as discussed under "Risk Factors" and "Canadian Industry Conditions" herein could result in development of such probable undeveloped reserves on a different schedule than set out above.

The process of evaluating 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 prices and costs change. The reserves estimates contained herein are based on current production forecasts, prices and economic conditions and other factors and assumptions that may affect the reserves 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; (viii) unexpected or unusually high abandonment and reclamation costs; (ix) unusually high development costs; (x) unusually high operating costs; (xi) contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations; and (xii) other government levies imposed over the life of the reserves. Although every reasonable effort is made to ensure that reserves estimates are accurate, reserves 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, reserves 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 reserves estimates can arise from changes in year-end prices, commodity prices, reservoir performance, governmental restrictions, economic conditions, geologic conditions or production. These revisions can be either positive or negative. See "Risk Factors".

Changes in future commodity prices relative to the forecasts described above under "Pricing Assumptions" could have a negative impact on the reserves associated with the Company's assets, and in particular on the development of undeveloped reserves, unless future development costs are adjusted in parallel. The Company's assets include a significant amount of proved and probable undeveloped reserves. At the forecast prices and costs used in the GLJ Report, these development activities are expected to be economic. However, should oil and natural gas prices decrease materially, these activities may need to be deferred to ensuing years to remain economic or may not be pursued at all. Other than the foregoing and the factors disclosed or described herein, the Company does not anticipate any other significant economic factors or other significant uncertainties which may affect any particular components of the reserves data in respect of the Company's assets.

The following table sets forth the development costs deducted in the estimation of future net revenue attributable to: (i) proved reserves (in total) estimated using forecast prices and costs; and (ii) proved plus probable reserves (in total) estimated using forecast prices and costs.

To fund its capital program, including future development costs, the Company will consider various financing alternatives, including retention of funds from operations, debt financing and issuance of additional Common Shares and other securities. The Company will evaluate the appropriate financing alternatives closely and make use of such options dependent on the given investment situation and the capital markets. If cash flows are other than projected, capital expenditure levels may be adjusted. In addition, depending on a number of factors including commodity prices, industry conditions and the Company's financial and operating results, funds from credit facilities and equity financings may not be available on terms acceptable to the Company, which could also result in adjustments to the capital program as required. There can be no guarantee that funds will be available or that the Company will be able to allocate funding to develop all of the reserves attributed in the GLJ Report. Failure to develop those reserves would have a negative impact on future production and cash flow and could result in negative revisions to reserves. For example, on March 11, 2020, the Company decided to reduce its 2020 capital program (before capitalized G&A) from US$37.1 million to US$7.1 million and to suspend its dividend in order to manage cash until such time that it is appropriate to reinstate the dividend. Those decisions were made in light of global reaction to the spread of COVID-19 and the resultant reduction in oil demand, compounded by OPEC+, led by Saudi Arabia and Russia, failing to reach an agreement on constraining output in face of lower global demand to support global oil prices and the stated intention of certain OPEC member countries to discount future deliveries and increase crude oil supply into the market.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates set forth above and would reduce the reserves and future net revenue to some degree depending upon the funding sources utilized. The Company does not anticipate that interest or other funding costs would make further development of the Company's assets uneconomic. See "Significant Factors or Uncertainties Affecting Reserves Data".

The following table sets forth the number and status of wells in which the Company has a working interest as at December 31, 2019. All of the Company's wells are located onshore.

The following table sets out the Company's developed and undeveloped land holdings as at December 31, 2019.

Pursuant to the PSC for NW Sitra in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment for two wells and 300 square kilometers of 3-D seismic during the initial three-and-a-half-year exploration period, which commenced on January 8, 2015. The Company requested and received a six-month extension of the initial exploration period to January 7, 2019. The Company met its financial and operating commitments and based on well results did not elect to enter the second exploration phase. The concession was relinquished on January 7, 2019.

Pursuant to the approved S Ghazalat development lease, the Company is committed to drilling one exploration well during the initial four year period of the 20 year development lease. The Company has issued a production guarantee in the amount of $1.0 million which will be released when the commitment well has been drilled.

Development of properties with no attributable reserves are subject to current industry conditions and uncertainties as indicated under "Risk Factors" and "Canadian Industry Conditions" herein. In addition, the Company expects that funding of development operations on such properties will be evaluated in the context of the Company's total capital requirements having regard to rates of return, the likelihood of success and risked return versus cost of capital, and availability and reliability of methods of hydrocarbon delivery.

Development of the Company's properties with no attributed reserves are subject to current industry conditions and uncertainties as indicated under "Risk Factors" herein. In addition, we expect that funding of development operations on such properties will be evaluated in the context of our total capital requirements having regard to rates of return, the likelihood of success and risked return versus cost of capital, and availability and reliability of methods of hydrocarbon delivery.

In conjunction with the prepayment agreement executed in 2017, TPI has also entered into a marketing contract with Mercuria to market 9 million barrels of TPI’s Egypt entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale. In conjunction with the prepayment and marketing agreements, the Company is committed to hedge 60% of its forecasted proved entitlement production.

Subject to the Company's Hedging Policy, TransGlobe uses hedging arrangements from time to time as part of its risk management strategy to manage commodity price fluctuations and stabilize cash flows for future exploration and development programs. The hedging program is actively monitored and adjusted as deemed necessary to protect the cash flows from the risk of commodity price exposure.

The nature of TransGlobe’s operations exposes it to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and, when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings at each reporting period. TransGlobe has not obtained collateral or other security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts. The derivative financial instruments are initiated within the guidelines of the Company's Hedging Policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.

Refer to the annual Consolidated Financial Statements for our commitments under all hedging agreements as at December 31, 2019.

In Egypt, estimated future abandonment and reclamations costs related to properties evaluated have not been taken into account by GLJ. Under the terms of the PSCs, ownership in the facilities and wells is transferred to the Government of Egypt through cost recovery. Therefore the future abandonment and reclamation costs have been assessed a zero value.

In connection with the Company's Canadian operations, the Company will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. The expected total reserve well abandonment and reclamation costs, net of estimated salvage value, included in the GLJ Report for the 209.7 net wells under the proved reserves category is $9.9 million undiscounted, of which a total of $0.6 million is estimated to be incurred through 2020. These estimates include costs for all wells with no reserves assigned.

In addition to the costs referenced above, operating expenses for lands and facilities without wells are included in the future net revenues. The total amount of these expenses are $0.2 million undiscounted, of which $0.1 million is estimated to be incurred in 2020.

In 2019, the Company did not pay any income taxes in Canada and does not anticipate any taxes payable in the near future. In Egypt, the Company's income tax liabilities are paid out of the government's share of production. As such, all current income tax liabilities in Egypt are settled immediately as they become due.

The following table summarizes the capital expenditures (including capitalized general and administrative expenses) related to the Company's activities for the year ended December 31, 2019:

The Company did not incur any capital expenditures related to the acquisition of proved or unproved properties in the year ended December 31, 2019.

The following tables set forth the gross and net exploratory and development wells which the Company drilled in Egypt and Canada during the year ended December 31, 2019:

Current development activities are focused on the West Gharib, West Bakr, NW Gharib and S Ghazalat concessions in Egypt, and the Harmattan area in Canada. Other key areas for 2020 include exploration drilling at West Bakr, NW Gharib and S Ghazalat in Egypt.

The following table sets out the volume of the Company's daily production (working interest before royalties) estimated for the year ending December 31, 2020 by GLJ which is reflected in the estimate of future net revenue (Forecast Price Case) disclosed in the prior reserves summary tables.

	Egypt				Canada						Total
	Light & Medium Crude Oil		Heavy Crude Oil		Light & Medium Crude Oil		Conventional Natural Gas		Natural Gas Liquids		Company
	Gross		Gross		Gross		Gross		Gross		Gross
	(Bbls/d)		(Bbls/d)		(Bbls/d)		(Mcf/d)		(Bbls/d)		(Boe/d)
Proved Developed Producing		746		9,847		807		5,123		787		13,040
Proved Developed
Non-Producing		87		572		13		37		7		685
Proved Undeveloped		118		433		—		—		—		551
Total Proved¹		951		10,852		820		5,161		793		14,277
Total Probable²		518		1,118		46		115		22		1,724
Total Proved Plus Probable		1,469		11,970		866		5,276		815		16,000

The following tables set out the volume of the Company's daily production (working interest before royalties) estimated for the year ending December 31, 2020 for the Company's fields that account for 20% or more of the of the estimated production by country disclosed above.

	Egypt
	S Ghazalat		K-Field		Arta		H-Field		Other fields				Total
	Light & Medium Crude Oil		Heavy Crude Oil		Heavy Crude Oil		Heavy Crude Oil		Light & Medium Crude Oil		Heavy Crude Oil		Egypt
	Gross		Gross		Gross		Gross		Gross		Gross		Gross
	(Bbls/d)		(Bbls/d)		(Bbls/d)		(Bbls/d)		(Bbls/d)		(Bbls/d)		(Bbls/d)
Proved Developed Producing		-		2,810		2,462		2,255		746		2,320		10,593
Proved Developed
Non-Producing		-		287		27		250		87		8		659
Proved Undeveloped		118		-		-		433		-		-		551
Total Proved		118		3,098		2,488		2,938		833		2,329		11,804
Total Probable		385		195		131		250		133		542		1,636
Total Proved Plus Probable		503		3,293		2,619		3,188		966		2,871		13,440

	Canada
	Harmattan						Other fields						Total
	Light & Medium Crude Oil		Conventional Natural Gas		Natural Gas Liquids		Light & Medium Crude Oil		Conventional Natural Gas		Natural Gas Liquids		Canada
	Gross		Gross		Gross		Gross		Gross		Gross		Gross
	(Bbls/d)		(Mcf/d)		(Bbls/d)		(Bbls/d)		(Mcf/d)		(Bbls/d)		(Boe/d)
Proved Developed Producing		784		4,596		776		23		527		11		2,448
Proved Developed
Non-Producing		13		37		7		-		-		-		26
Proved Undeveloped		-		-		-		-		-		-		-
Total Proved		797		4,634		782		23		527		11		2,473
Total Probable		46		104		22		-		11		-		87
Total Proved Plus Probable		843		4,738		804		23		538		11		2,560

The following table summarizes certain information in respect of sales volumes, product prices received, royalties paid, operating expenses and resulting netbacks made by the Company (and its subsidiaries) for the periods indicated:

	2019
	Quarter Ended
	Mar. 31			Jun. 30			Sep. 30			Dec. 31
Average Daily Production Volumes
Egypt¹
Heavy Crude Oil (Bbls/d)		12,692			13,785			12,909			11,984
Light & Medium Crude Oil (Bbls/d)		925			878			841			847
Canada²
Light & Medium Crude Oil (Bbls/d)		894			788			666			908
Conventional Natural Gas (Boe/d)		944			955			942			889
Natural Gas Liquids (Bbls/d)		470			533			585			735
Combined (Boe/d)		15,924			16,940			15,943			15,362
Average Daily Sales Volumes
Egypt
Heavy Crude Oil (Bbls/d)		11,873			12,876			11,199			11,354
Light & Medium Crude Oil (Bbls/d)		866			820			730			803
Canada
Light & Medium Crude Oil (Bbls/d)		894			788			666			908
Conventional Natural Gas (Boe/d)		944			955			942			889
Natural Gas Liquids (Bbls/d)		470			533			585			735
Combined (Boe/d)		15,047			15,973			14,122			14,688
Average Price Received
Egypt¹
Heavy Crude Oil (US$/Bbl)		54.93			60.58			54.58			51.69
Light & Medium Crude Oil (Bbls/d)		54.93			60.58			54.58			51.69
Canada
Light & Medium Crude Oil (Bbls/d)		48.53			55.35			49.94			50.57
Conventional Natural Gas (US$/Mcf)		1.94			0.89			0.70			1.81
Natural Gas Liquids (US$/Bbl)		31.80			24.55			19.75			18.81
Combined (US$/Boe)		51.11			55.81			49.56			47.51
Royalties and Taxes
Egypt¹
Heavy Crude Oil (US$/Bbl)		32.44			36.33			35.67			36.75
Light & Medium Crude Oil (Bbls/d)		32.44			36.33			35.67			36.75
Canada
Light & Medium Crude Oil (Bbls/d)		4.23			1.18			2.29			2.71
Conventional Natural Gas (US$/Mcf)		0.71			0.20			0.38			0.45
Natural Gas Liquids (US$/Bbl)		4.23			1.18			2.29			2.71
Combined (US$/Bbl)		28.11			31.32			30.48			27.31
Operating and Transportation Expenses
Egypt¹
Heavy Crude Oil (US$/Bbl)		8.52			8.35			8.95			11.85
Light & Medium Crude Oil (Bbls/d)		8.52			8.35			8.95			11.85
Canada^4,5,6
Light & Medium Crude Oil (Bbls/d)		8.48			9.65			8.64			8.03
Conventional Natural Gas (US$/Mcf)		1.41			1.61			1.44			1.34
Natural Gas Liquids (US$/Bbl)		8.48			9.65			8.64			8.03
Combined (US$/Bbl)		8.52			8.54			8.90			11.19
Selling Costs
Egypt¹
Heavy Crude Oil (US$/Bbl)		0.41			0.08			0.07			0.57
Light & Medium Crude Oil (Bbls/d)		0.41			0.08			0.07			0.57
Canada
Light & Medium Crude Oil (Bbls/d)		—			—			—			—
Conventional Natural Gas (US$/Mcf)		—			—			—			—
Natural Gas Liquids (US$/Bbl)		—			—			—			—
Combined (US$/Bbl)		0.35			0.07			0.06			0.47
Netback Received⁷
Egypt¹
Heavy Crude Oil (US$/Bbl)		13.56			15.82			9.89			2.52
Light & Medium Crude Oil (Bbls/d)		13.56			15.82			9.89			2.52
Canada^8,9
Light & Medium Crude Oil (Bbls/d)		35.82			44.52			39.01			39.83
Conventional Natural Gas (US$/Mcf)		(0.18	)		(0.92	)		(1.12	)		0.02
Natural Gas Liquids (US$/Bbl)		19.09			13.72			8.82			8.07
Combined (US$/Bbl)		14.13			15.88			10.12			4.97

The following table indicates the Company's average daily volumes from its important fields for the year ended December 31, 2019:

TransGlobe’s dividend policy is to return capital to shareholders through semi-annual payments of a significant portion of free cash flow. For these purposes, free cash flow is defined as net cash generated by operating activities less capital expenditures, debt repayments, and anticipated business development capital, calculated on an annual basis.

The declaration and payment of future dividends is subject to the sole discretion of the Board of Directors of the Company and may vary dependent upon a number of factors, including: commodity price volatility, production levels, compliance with any restrictions on the payment of dividends contained in any agreements and/or legislation that the Company is subject to, foreign exchange movements, operating costs, capital expenditures, anticipated business development capital requirements, royalties, and taxes. Dependent upon the foregoing and other factors deemed relevant by the Board and management of the Company to the declaration and payment of dividends, the Company may change its dividend policy at any time. On March 11, 2020, in light of global oil price disruption, the Company decided to suspend its dividends in order to manage cash until such a time that it is appropriate to reinstate. The Board will evaluate its decision on future dividend payments on a semi-annual basis going forward. See "Recent Developments" and "Risk Factors". Dividends are not guaranteed. Any reduction of dividends may have an adverse effect on the market price of the Company’s Common Shares.

No dividends were paid by the Company during the year ended December 31, 2017. During the year ended December 31, 2018, the Company paid a dividend of $0.035 per share on September 14, 2018 to shareholders of record on August 31, 2018. The Company has paid the following dividends on its Common Shares during the year ended December 31, 2019.

TransGlobe is authorized to issue an unlimited number of Common Shares without nominal or par value. As at March 12, 2020 there were 72,492,071 Common Shares issued and outstanding.

Each Common Share entitles its holder to: (i) vote at any meeting of Shareholders of the Company; (ii) to receive any dividend declared by the Company; and (iii) to receive the remaining property of the Company upon dissolution.

The Company's articles have been filed in accordance with NI 51-102 and are available on the Company's SEDAR profile at www.sedar.com and the Company's EDGAR profile at www.sec.gov.

TransGlobe's Common Shares trade on the TSX and the AIM under the symbol TGL and on the Nasdaq under the symbol TGA.

The following table sets out the monthly high and low closing prices and the total monthly trading volumes for the Common Shares on the Nasdaq for the indicated periods:

(U.S. dollars, except volumes)	Price Range
	High		Low
	($/share)		($/share)		Volume
2019
January		2.09		1.73		2,256,842
February		2.12		1.84		1,410,169
March		2.17		1.75		2,925,097
April		1.95		1.79		2,281,151
May		1.92		1.50		2,344,959
June		1.55		1.39		2,579,875
July		1.55		1.35		2,639,609
August		1.53		1.33		2,604,154
September		1.52		1.33		3,395,042
October		1.48		1.12		2,895,529
November		1.26		1.12		2,882,556
December		1.48		1.12		4,252,761
2020
January		1.46		1.22		2,966,086
February		1.30		1.08		2,596,242
March (1 to 11)		1.11		0.69		1,715,033

The following table sets out the monthly high and low closing prices and the total monthly trading volumes for the Common Shares on the TSX for the indicated periods:

(Canadian dollars, except volumes)	Price Range
	High		Low
	(C$/share)		(C$/share)		Volume
2019
January		2.75		2.29		1,062,613
February		2.81		2.44		663,301
March		2.88		2.34		1,750,946
April		2.62		2.37		1,163,306
May		2.58		2.02		1,850,800
June		2.06		1.83		1,725,444
July		2.05		1.75		1,025,893
August		2.04		1.75		1,013,433
September		2.01		1.75		849,305
October		1.74		1.51		549,786
November		1.64		1.42		600,156
December		1.93		1.48		844,472
2020
January		1.89		1.58		995,452
February		1.75		1.43		501,838
March (1 to 11)		1.47		0.87		383,496

The following table sets out the monthly high and low closing prices and the total monthly trading volumes for the Common Shares on the AIM for the indicated periods:

(British pound sterling, except volumes)	Price Range
	High		Low
	(£/share)		(£/share)		Volume
2019
January		1.54		1.39		680
February		1.56		1.39		98
March		1.59		1.39		20,844
April		1.50		1.40		10
May		1.50		1.20		408
June		1.24		1.09		85,634
July		1.19		1.04		106,000
August		1.21		1.11		26,927
September		1.19		1.14		28,820
October		1.14		0.95		54,858
November		1.00		0.93		50,535
December		1.12		0.92		39,174
2020
January		1.12		0.98		11,340
February		1.01		0.93		37,410
March (1 to 11)		0.88		0.73		480

The following table summarizes the issuance of stock options, which are convertible into Common Shares, during the year ended December 31, 2019:

ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER

As at the date hereof, none of the Company's securities are subject to escrow or contractual restrictions on transfer.

The name and place of residence of each director and officer, the offices held by each in the Company, the principal occupation of each director and officer, the period served as director or officer and the aggregate number of securities of the Company owned by such individuals as at March 12, 2020 is set as below:

Name and Place of Residence	Position Held	Year Became Director or Officer	Principal Occupation and Positions for the Past Five Years
David B. Cook Texas, U.S.	Chairman of the Board and Director	2014	Former Head of Strategy for INEOS Oil & Gas. Prior thereto, Mr. Cook was CEO INEOS DeNoS, located in London, UK having taken that role following the sale to INEOS, DONG Oil and Gas (part of the DONG Energy group, now Orsted) where he was also CEO. Prior to that he was Executive Officer and Head of Oil and Gas at the Abu Dhabi National Energy Company ("TAQA") where he led the Company's upstream and midstream interests in the Middle East, North America, the United Kingdom and Europe. Before joining TAQA, he served as Vice President for BP Russia, responsible for BP’s non-TNK-BP exploration and production activities in Russia. Mr. Cook has held a variety of global technical, commercial and managerial positions based from the U.S., UK, Russia and the Middle East as well as board of director roles.
Randy C. Neely ⁽¹⁾ London, England	President, Chief Executive Officer and Director	2012	President of the Company since January 10, 2018 and previously Vice President Finance and CFO since May 8, 2012. Elected to the Board in May 2018 and was appointed as President and CEO of the Company in January 2019. Prior to joining TransGlobe was Chief Financial Officer at Zodiac Exploration Inc. and Chief Financial Officer at BlackPearl Resources Inc. Industry professional with over 25 years' experience.
Carol Bell⁽²⁾⁽³⁾ London, England	Director	2019	Former Managing Director of Chase Manhattan Bank’s Global Oil & Gas Group, Head of European Equity Research at JP Morgan and several years as an equity research analyst in the oil and gas sector at Credit Suisse First Boston and UBS Phillips & Drew. Over 35 years of experience in the natural resource sector. Currently sits on the Board at BlackRock Commodities, Bonheur ASA, Ophir Energy plc and Tharisa plc and has served or serves on several private and charitable boards.
Ross G. Clarkson ⁽⁴⁾ British Columbia, Canada	Director	1995	Appointed to the Board of Directors in October of 1995 and served as President and CEO until January 2018 with more than 40 years of oil and gas exploration, management and executive experience. In January 2018, was appointed as CEO until January 2019. Mr. Clarkson retired as an executive officer from the Company effective January 1, 2019.
Edward LaFehr⁽²⁾⁽⁴⁾ Alberta, Canada	Director	2019	Chief Executive Officer of Baytex Energy Corporation effective May 2017 and President from July 2016 to April 2017. Previously he served as COO of TAQA's global operations and was located in Abu Dhabi from April 2014 - June 2016 and President of TAQA's North America division located in Calgary from October 2012 - April 2014. Mr. LaFehr has 35 years of experience in the oil and gas industry working with Amoco, BP, Talisman and Abu Dhabi National Energy Company ("TAQA"), holding senior positions in North American, Europe and the Middle East regions.
Steven Sinclair⁽²⁾⁽³⁾ Alberta, Canada	Director	2017	Previously served as Senior Vice President and Chief Financial Officer of ARC Resources Ltd until his retirement in 2014. Mr. Sinclair has over 30 years' financial and operating experience and senior management experience.
Susan M. MacKenzie⁽³⁾⁽⁴⁾ Alberta, Canada	Director	2014	Served as Chief Operating Office with Oilsands Quest Inc., a NYSE Amex-listed oil sands company from April – September, 2010. Prior thereto, Ms. MacKenzie was employed for 12 years at PetroCanada, where she held senior roles including Vice President, Human Resources and Vice President of In-Situ Development and Operations. Ms. MacKenzie was with Amoco Canada Petroleum Company Ltd. for 14 years in a variety of engineering and leadership roles in natural gas, conventional and heavy oil exploration.
Edward D. Ok ⁽¹⁾ London, England	Vice-President, Finance and Chief Financial Officer	2018	Vice President, Finance and Chief Financial Officer of the Company since January 2018 and with the Company since 2012 in senior financial roles. Prior to joining TransGlobe was at Zodiac Exploration. Mr. Ok is a Chartered Accountant with over 10 years industry experience.
Geoff Probert⁽¹⁾ London, England	Vice President, and Chief Operating Officer	2019	Vice President and Chief Operating Officer of the Company since May 18, 2019 with over 30 years experience in international oil and gas exploration and development.
Marilyn Vrooman-Robertson Alberta, Canada	Corporate Secretary	2017	Corporate Secretary of the Company since 2017 and previously served as Assistant Corporate Secretary of the Company. Governance professional with over 18 years' experience. A student of the International Chartered Secretary Association and a member of Governance Professionals of Canada.

Except as otherwise disclosed herein, no current director or executive officer of the Company has, within the last ten years prior to the date of this document, been a director, chief executive officer or chief financial officer of any issuer (including the Company) that:

Except as otherwise disclosed herein, no current director or executive officer or securityholder holding a sufficient number of securities of the Company to affect materially the control of the Company has, within the last ten years prior to the date of this document, been a director or executive officer of any company (including the Company) that, while such 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 for compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

Dr. Bell was formerly the non-executive chairman of Barcud Derwen Ltd. ("Barcud Derwen"), a private television facilities house based in Wales and Scotland. Barcud Derwen was put into administration by its board of directors in June 2010 whereby the majority of its assets were sold. Following the sale of Barcud Derwen's assets, Dr. Bells ceased involvement with Barcud Derwen.

In addition, no current director or executive officer or securityholder holding a sufficient number of securities of the Company to affect materially the control of the Company has, within the last ten years prior to the date of this document, 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 securityholder.

No current director or executive officer or securityholder holding a sufficient number of securities of the Company to affect materially the control of the Company has been subject to: (i) 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 (ii) 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.

Directors and officers of the Company may, from time to time, be involved with the business and operations of other oil and gas issuers, in which case a conflict may arise. Conflicts of interest, if any, which arise will be subject to and governed by procedures prescribed by the ABCA, which require a director or officer of a corporation who is a party to, or is a director or an officer of, or has a material interest in any person who is a party to, a material contract or proposed material contract with the Company to disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under the ABCA. See "Risk Factors".

Other than as described below, there is no person or corporation who is named as having prepared or certified a statement, report or valuation described and included in the filing, or referred to in a filing, made under NI 51-102 by the Company during, or relating to the Company's most recently completed financial year whose profession or business gives authority to the report, valuation, statement or opinion made by the person, or Company, other than GLJ, the Company's independent engineering evaluator, and Deloitte LLP, the Company's independent auditor.

There were no registered or beneficial interests, direct or indirect, in any securities or other property of the Company or of one of its associates or affiliates: (i) held by GLJ or by the "designated professionals" (as defined in Form 51-102F2 to NI 51-102) of GLJ, when GLJ prepared the report, valuation, statement or opinion referred to herein as having been prepared by GLJ; (ii) received by GLJ or by the "designated professionals" of GLJ, after the time specified above; or (iii) to be received by GLJ or by the "designated professionals" of GLJ; except in each case for the ownership of Common Shares, which in respect of GLJ and GLJ's "designated professionals", as a group, has at all relevant times represented less than 1% of the outstanding Common Shares. In addition, neither GLJ, nor any director, officer or employee of GLJ, is or is expected to be elected, appointed or employed as a director, officer or employee of the Company or of any associate or affiliate of the Company.

Deloitte LLP is independent of the Company within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta and the rules and standards of the Public Company Accounting Oversight Board and the securities laws and regulations administered by the U.S. Securities and Exchange Commission.

Except as described below, there are no legal proceedings material to the Company to which the Company is or was a party to, or in respect of which any of its properties are or were the subject of, during the 2019 financial year, nor are there any such proceedings known to be contemplated. In addition, there were no penalties or sanctions imposed against the Company by a court relating to securities legislation or by a securities regulatory authority during the 2019 financial year, no other penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered important to a reasonable investor in making an investment decision, and no settlement agreements entered into by the Company before a court relating to securities legislation or with a securities regulatory authority during the 2019 financial year.

On March 31, 2015, TG Holdings Yemen, Inc., a wholly-owned subsidiary of TransGlobe, relinquished its 13.8% interest in a concession in western Yemen known as "Block 32". In 2018, the Ministry of Oil and Minerals of the Republic of Yemen raised claims against the contractor parties, including TG Holdings, Yemen Inc. The claims mirror others that the Ministry has previously brought against other international oil companies on their departure from Yemen. The claims variously relate to accounting practices, environmental and asset integrity/retirement claims, claims related to payment of customs duties and penalties, claims related to amounts allegedly owing to third parties for employment and facilities usage claims, and claims related to the handover of the concession. The Ministry’s claims have been partially quantified at US$105.3mm. The Ministry’s success in recent history with claims of this nature appears to have been limited; those of which we are aware have been wholly or substantially dismissed. TG Holdings has defended the Ministry’s claims, asserting that they are without merit, and arguing that TG Holdings is not a proper party to the proceeding, having previously assigned its entire interest and the associated liabilities to the other contractor parties. A hearing was held in February 2020, and the parties are currently preparing written closing arguments.

None of the Company's directors, executive officers or persons or companies that beneficially own or control or direct, directly or indirectly or a combination of both, more than 10% of the Company's Common Shares, or their associates and affiliates, had any material interest, direct or indirect, in any transaction with the Company within the three most recently completed financial years or during the current financial year that has materially affected or would reasonably be expected to materially affect the Company.

The transfer agent and registrar for the Common Shares is Computershare Trust Company of Canada at its principal offices in Calgary and Toronto.

Other than discussed herein, there are no material contracts, other than the contracts entered into in the ordinary course of business, that are material to the Company and that were entered into within the most recently completed financial year, or before the most recently completed financial year but are still in effect other than the C$25 million reserves-based lending facility agreement dated May 16, 2017, with first amendment dated May 11, 2018 and second amendment dated July 11, 2019, described under "General Development of the Business - 2017", which is available on the Company's profile on SEDAR at www.sedar.com

The audit committee of the Company (the "Audit Committee") is currently comprised of Steven Sinclair (Chair), Dr. Carol Bell and Edward LaFehr. The following chart sets out the assessment of each Audit Committee member's independence, financial literacy and relevant educational background and experience supporting such financial literacy.

It is within the mandate of the Company’s Audit Committee to approve all audit and non-audit related fees. The Audit Committee is informed routinely as to the non-audit services to be provided by the auditor pursuant to this pre-approval process. The auditors also present the estimate for the annual audit related services to the Audit Committee for approval prior to undertaking the annual audit of the financial statements.

The Audit Committee’s pre-approval procedure is to approve all non-audit services to be performed by the Company’s auditors in advance of the engagement of the Company’s auditors to perform such services. The pre-approval process involves management presenting the Audit Committee with a description of any proposed non-audit services. The Audit Committee considers the appropriateness of such services and whether the provision of those services would impact the auditor’s independence, including the magnitude of the potential fees. Once the committee has satisfied itself of its concerns, if any, it then votes either in favor of or against contracting the Company’s auditors to perform the proposed non-audit services.

The full text of the Company's audit committee charter is included in Schedule "C" to this AIF.

The aggregate fees for professional services billed to TransGlobe by Deloitte LLP during the fiscal years ended December 31, 2019 and December 31, 2018 were as follows:

The nature of the services provided by Deloitte LLP under each of the categories indicated in the table is described below.

Audit fees were for professional services rendered by Deloitte LLP for the audit of the Company’s annual financial statements, as well as for the review of the Company's interim quarterly financial statements.

Audit related fees were for professional services rendered by Deloitte LLP for assurance services that are reasonably related to the performance of the audit of the Company’s annual financial statements (not included in audit fees).

Tax fees were for tax compliance, including the review of tax returns, tax advice and tax planning and advisory services relating to common forms of domestic and international taxation (i.e. income tax, capital tax, goods and services tax and payroll tax).

During the fiscal years ended December 31, 2019 and 2018, no other fees were incurred other than those described above.

Companies carrying on business in the crude oil and natural gas sector in Canada are subject to extensive controls and regulations imposed through legislation of the federal government and the provincial governments in the jurisdictions where the companies have assets or operations. While such regulations do not affect the Company's operations in any manner that is materially different than the manner in which they affect other similarly-sized industry participants with similar assets and operations, investors should consider such regulations carefully. Although laws and regulations are a matter of public record, the Company is unable to predict what additional laws, regulations or amendments governments may enact in the future.

The Company holds interests in crude oil and natural gas properties, along with related assets, primarily in the province of Alberta. The Company's assets and operations are regulated by administrative agencies deriving authority from underlying legislation enacted by the applicable level of government. Regulated aspects of the Company's upstream crude oil and natural gas business include all manner of activities associated with the exploration for and production of crude oil and natural gas, including, among other matters: (i) permits for the drilling of wells; (ii) technical drilling and well requirements; (iii) permitted locations and access of operation sites; (iv) operating standards regarding conservation of produced substances and avoidance of waste, such as restricting flaring and venting; (v) minimizing environmental impacts; (vi) storage, injection and disposal of substances associated with production operations; and (vii) the abandonment and reclamation of impacted sites. In order to conduct crude oil and natural gas operations and remain in good standing with the applicable federal or provincial regulatory scheme, producers must comply with applicable legislation, regulations, orders, directives and other directions (all of which are subject to governmental oversight, review and revision, from time to time). Compliance in this regard can be costly and a breach of the same may result in fines or other sanctions. The discussion below outlines certain pertinent conditions and regulations that impact the crude oil and natural gas industry in Western Canada.

Producers of crude oil are entitled to negotiate sales contracts directly with crude oil purchasers. As a result, macroeconomic and microeconomic market forces determine the price of crude oil. Worldwide supply and demand factors are the primary determinant of crude oil prices; however, regional market and transportation issues also influence prices. The specific price depends, in part, on crude oil quality, prices of competing fuels, distance to market, availability of transportation, value of refined products, supply/demand balance and contractual terms of sale.

Negotiations between buyers and sellers determines the price of natural gas sold in intra-provincial, interprovincial and international trade. The price received by a natural gas producer depends, in part, on the price of competing natural gas supplies and other fuels, natural gas quality, distance to market, availability of transportation, length of contract term, weather conditions, supply/demand balance and other contractual terms. Spot and future prices can also be influenced by supply and demand fundamentals on various trading platforms.

The pricing of condensates and other NGLs such as ethane, butane and propane sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such prices depend, in part, on the quality of the NGLs, price of competing chemical stock, distance to market, access to downstream transportation, length of contract term, supply/demand balance and other contractual terms.

On August 28, 2019, Bill C-69 came into force, replacing, among other things, the National Energy Board Act (the "NEB Act") with the Canadian Energy Regulator Act (Canada) (the "CERA"), and replacing the National Energy Board (the "NEB") with the Canadian Energy Regulator ("CER"). The CER has assumed the NEB's responsibilities broadly, including with respect to the export of crude oil, natural gas and NGLs from Canada. The legislative regime relating to exports of crude oil, natural gas and NGL from Canada has not changed substantively under the new regime.

Exports of crude oil, natural gas and NGLs from Canada are subject to the CERA and remain subject to the National Energy Board Act Part VI (Oil and Gas) Regulation (the "Part VI Regulation"). While the Part VI Regulation was enacted under the NEB Act, it will remain in effect until 2022, or until new regulations are made under the CERA. The CERA and the Part VI Regulation authorize crude oil, natural gas and NGLs exports under either short-term orders or long-term licences. For natural gas, the maximum duration of an export licence is 40 years; for crude oil and other gas substances (e.g. NGLs), the maximum term is 25 years. To obtain a crude oil export licence, a mandatory public hearing with the CER is required; however, there is no public hearing requirement for the export of natural gas and NGLs. Instead, the CER will continue to apply the NEB's written process that includes a public comment period for impacted persons. Following the comment period, the CER completes its assessment of the application and either approves or denies the application. The CER can approve an application if it is satisfied that proposed export volumes are not greater than Canada's reasonably foreseeable needs, and if the proposed exporter is in compliance with the CERA and all associated regulations and orders made under the CERA. Following the CER's approval of an export licence, the federal Minister of Natural Resources is mandated to give his or her final approval. While the Part VI Regulation remains in effect, approval of the cabinet of the Canadian federal government ("Cabinet") is also required. The discretion of the Minister of Natural Resources and Cabinet will be framed by the Minister of Natural Resources' mandate to implement the CERA safely and efficiently, as well as the purpose of the CERA, to effect "oil and natural gas exploration and exploitation in a manner that is safe and secure and that protects people, property and the environment".

The CER also has jurisdiction to issue orders that provide a short-term alternative to export licences. Orders may be issued more expediently, since they do not require a public hearing or approval from the Minister of Natural Resources or Cabinet. Orders are issued pursuant to the Part VI Regulation for up to one or two years depending on the substance, with the exception of natural gas (other than NGLs) for which an order may be issued for up to twenty years for quantities not exceeding 30,000 m3 per day.

As to price, exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the CER and the federal government. The Company does not directly enter into contracts to export its production outside of Canada.

As discussed in more detail below, one major constraint to the export of crude oil, natural gas and NGLs outside of Canada is the deficit of overall pipeline and other transportation capacity to transport production from Western Canada to the United States and other international markets. Although certain pipeline and other transportation projects are underway, many contemplated projects have been cancelled or delayed due to regulatory hurdles, court challenges and economic and other socio-political factors. Major pipeline and other transportation infrastructure projects typically require a significant length of time to complete once all regulatory and other hurdles have been cleared. In addition, production of crude oil, natural gas and NGLs in Canada is expected to continue to increase, which may further exacerbate the transportation capacity deficit.

Producers negotiate with pipeline operators (or other transport providers) to transport their products to market on a firm or interruptible basis. Transportation availability is highly variable across different jurisdictions and regions. This variability can determine the nature of transportation commitments available, the number of potential customers that can be reached in a cost-effective manner and the price received. Due to growing production and a lack of new and expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced low commodity pricing relative to other markets in the last several years.

Under the Canadian constitution, interprovincial and international pipelines fall within the federal government's jurisdiction and require a regulatory review and approval by Cabinet. However, recent years have seen a perceived lack of policy and regulatory certainty at a federal level. The federal government amended the federal approval process with the CER, which aims to create efficiencies in the project approval process while upholding stringent environmental and regulatory standards. However, as the CER has not yet undertaken a major project approval, it is unclear how the new regulator operates compared to the NEB and whether it will result in a more efficient approval process. Lack of regulatory certainty is likely to influence investment decisions for major projects. Even when projects are approved on a federal level, such projects often face further delays due to interference by provincial and municipal governments. Additional delays causing further uncertainty result from legal opposition related to issues such as Indigenous rights and title, the government's duty to consult and accommodate Indigenous peoples, and the sufficiency of all relevant environmental review processes. Export pipelines from Canada to the United States face additional unpredictability as such pipelines require approvals of several levels of government in the United States.

In the face of such regulatory uncertainty, the Canadian crude oil and natural gas industry has experienced significant difficulty expanding the existing network of transportation infrastructure for crude oil, natural gas and NGLs, including pipelines, rail, trucks and marine transport. Improved access to global markets through the Midwest United States and export shipping terminals on the west coast of Canada could help to alleviate downward pressure on commodity prices. Several proposals have been announced to increase pipeline capacity from Western Canada to Eastern Canada, the United States, and other international markets via export terminals. While certain projects are proceeding, the regulatory approval process and other factors related to transportation and export infrastructure have led to the delay, suspension or cancellation of a number of pipeline projects.

With respect to the current state of the transportation and exportation of crude oil from Western Canada to domestic and international markets, the Enbridge Line 3 Replacement from Hardisty, Alberta, to Superior, Wisconsin, formerly expected to be in-service in late 2019, continues to experience permitting difficulties in the United States and is now expected to be in-service in the latter half of 2020. The Canadian portion of the replaced pipeline began commercial operation on December 1, 2019.

The Trans Mountain Pipeline expansion received Cabinet approval in November 2016. Following a period of sustained political opposition in British Columbia, the federal government purchased the Trans Mountain Pipeline from Kinder Morgan Cochin ULC in August 2018. However, the Trans Mountain Pipeline expansion experienced a setback when, in August 2018, the Federal Court of Appeal identified deficiencies in the NEB's environmental assessment and the Government's Indigenous consultations. The Court quashed the accompanying Certificate of Public Convenience and Necessity and directed Cabinet to correct these deficiencies. On June 18, 2019, Cabinet re-approved the Trans Mountain Pipeline expansion and directed the NEB to issue a certificate of public convenience and necessity for the project. Ongoing opposition by Indigenous groups continues to affect the progress of the Trans Mountain Pipeline. Along with its approval of the expansion, the federal government also announced the launch of the first step of a multi-step process of engagement with Indigenous groups for potential Indigenous economic participation in the pipeline. Following a public comment period initiated after the approval, the NEB ruled that NEB decisions and orders issued prior to the Federal Court of Appeal decision quashing the original Certificate of Public Convenience and Necessity will remain valid unless the CER (having replaced the NEB) decides that relevant circumstances have materially changed, such that there is a doubt as to the correctness of a particular decision or order. Construction commenced on the Trans Mountain Pipeline in late 2019, and is proceeding concurrently alongside CER hearings with landowners and affected communities to determine the final route for the Trans Mountain Pipeline. The Federation of British Columbia Naturalists, an environmental group that was denied standing in the December 2019 judicial review, appealed the Federal Court of Appeal’s standing decision to the Supreme Court of Canada. The appeal was dismissed on March 5, 2020

In December 2019, the Federal Court of Appeal heard a judicial review application brought by six Indigenous applicants challenging the adequacy of the federal government's further consultation on the Trans Mountain Pipeline expansion. Two First Nations subsequently withdrew from the litigation after reaching a deal with Trans Mountain. On February 4, 2020, the Federal Court of Appeal dismissed the remaining four appellants' application for judicial review, upholding Cabinet's second approval of the Trans Mountain Pipeline expansion from June 2019.

In addition to the direct challenges to the Trans Mountain Pipeline expansion, on April 25, 2018, the British Columbia Government submitted a reference question to the British Columbia Court of Appeal, seeking to determine whether it has the constitutional jurisdiction to amend the Environmental Management Act (the "BC EMA") to impose a permitting requirement on carriers of heavy crude within British Columbia. The British Columbia Court of Appeal answered the reference question unanimously in the negative. This decision was affirmed on appeal to the Supreme Court of Canada.

While it was expected that construction on the Keystone XL Pipeline, owned by the Canadian company TC Energy Corporation ("TC Energy") would commence in the first half of 2019, pre-construction work was halted in late 2018 when a United States Federal Court Judge determined the underlying environmental review was inadequate. The United States Department of State issued its final Supplemental Environmental Impact Statement in late 2019, and in January 2020, the United States Government announced its approval of a right-of-way that would allow the Keystone XL Pipeline to cross 74 kilometers of federal land. TC Energy announced in January 2020 that it plans to begin mobilizing heavy equipment for pre-construction work in February 2020, and that work on pipeline segments in Montana and South Dakota will begin in August 2020. Nevertheless, the Keystone XL pipeline remains subject to legal and regulatory barriers. In December 2019, a federal judge in Montana rejected the United States Government's request to dismiss a lawsuit by Native American tribes attempting to block required pipeline permits. The tribes claim that a permit issued in March 2019 would allow the pipeline to disturb cultural sites and water supplies in violation of tribal laws and treaties. Furthermore, the 1.9-kilometer long segment of the pipeline that will cross the Canada-United States Border remains dependant on the receipt of a grant of right-of-way and temporary use permit from the United States Bureau of Land Management and other related federal land authorizations.

Bill C-48 received royal assent on June 21, 2019, enacting the Oil Tanker Moratorium Act, which imposes a ban on tanker traffic transporting certain crude oil and NGLs products in excess of 12,500 metric tones to or from British Columbia's north coast. See "Canadian Industry Conditions – Regulatory Authorities and Environmental Regulation – Federal".

On February 19, 2019, the Government of Alberta announced that it would lease 4,400 rail cars capable of transporting 120,000 bbls/day of crude oil out of the province to help alleviate the high price differential plaguing Canadian oil prices. The Alberta Petroleum Marketing Commission would purchase crude oil from producers and market it, using the expanded rail capacity to transport the marketed oil to purchasers. However, in the spring of 2019, the Government of Alberta indicated that the rail program will be cancelled by assigning the transportation contracts to industry proponents. On February 11, 2010, the Government of Alberta announced that it had sold $10.6 billion worth of crude-by-rail contracts to the private sector.

In February, 2020, the federal government announced that trains hauling more than 20 cars carrying dangerous goods, including crude oil and diluted bitumen, would be subject to speed limits reduced by 50 per cent, following two derailments that led to fires and oil spills in Saskatchewan.

Natural gas prices in Alberta and British Columbia have also been constrained in recent years due to increasing North American supply, limited access to markets and limited storage capacity. Companies that secure firm access to transport their natural gas production out of Western Canada may be able to access more markets and obtain better pricing. Companies without firm access may be forced to accept spot pricing in Western Canada for their natural gas, which in the last several years has generally been depressed (at times producers have received negative pricing for their natural gas production).

Required repairs or upgrades to existing pipeline systems have also led to further reduced capacity and apportionment of firm access, which in Western Canada may be further exacerbated by natural gas storage limitations. However, in September 2019, the CER approved a policy change by TC Energy on its NOVA Gas Transmission Ltd. pipeline network, which carries much of Alberta’s gas production, to give priority to deliveries into storage. The change has served to somewhat stabilize supply and pricing, particularly during periods of maintenance on the system. January 2020 has seen the narrowest price differential between Canadian and United States Natural Gas benchmarks since early 2019.

Additionally, while a number of liquefied natural gas export plants have been proposed for the west coast of Canada, with 24 export licences issued since 2011, government decision-making, regulatory uncertainty, opposition from environmental and Indigenous groups, and changing market conditions have resulted in the cancellation or delay of many of these projects. Nonetheless, in October 2018, the joint venture partners of the LNG Canada liquefied natural gas export terminal announced a positive final investment decision to proceed with the project, which will allow LNG Canada to transport natural gas from northeastern British Columbia to the LNG Canada liquefaction facility and export terminal in Kitimat, BC, via the Coastal GasLink pipeline, which will be built and operated by TC Energy (the "CGL Pipeline"). Pre-construction activities began in November 2018, with a completion target of 2025. In late 2019, TC Energy announced that it would sell 65% of its interest in the CGL Pipeline to investment companies KKR & Co Inc. and Alberta Investment Management Corporation while remaining the pipeline operator. The transaction is expected to close in the first half of 2020. The CGL Pipeline's route was altered as a result of feedback that LNG Canada received from Indigenous groups in the area, and on May 1, 2019, the British Columbia Oil and Gas Commission (the "BC Commission") approved the current planned route for the CGL Pipeline. However, the CGL Pipeline has faced intense opposition. For example, a challenge to the approval process of the CGL Pipeline was launched in August 2018, contending that it should have been subject to the federal review instead of a provincial review. In July 2019, the NEB confirmed that the CGL Pipeline was properly subject to provincial jurisdiction. In addition, protests involving the Hereditary Chiefs of the Wet'suwet'en First Nation and their supporters have caused delays of construction activities on the CGL Pipeline. Coastal Gaslink Pipeline Ltd. obtained an injunction on December 31, 2019, and enforcement of the injunction started in February 2020.

In December 2019, the CER approved a 40-year export licence for the Kitimat LNG project, a proposed joint venture between Chevron Canada Limited and Woodside Energy International (Canada Limited), a subsidiary of Australian Energy Ltd. This licence remains subject to Cabinet approval, and Chevron Canada Limited has indicated that it is interested in selling its 50 percent interest in Kitimat LNG. The Woodfibre LNG Project is a small-scale LNG processing and export facility near Squamish, British Columbia. The BC Commission approved a project permit for Woodfibre LNG, a subsidiary of Singapore-based Pacific Oil and Gas Ltd. in July 2019. Pre-construction agreements for Woodfibre LNG are in the process of being revised and finalized. A project by GNL Québec Inc. is working through the federal impact assessment process for the construction and operation of a LNG facility and export terminal located on Saguenay Fjord, an inlet which feeds into the St. Lawrence River. The Goldboro LNG project, located in Nova Scotia, proposed by Pieridae Energy Ltd., would see LNG exported from Canada to European markets. Pieridae has agreements with Shell, upstream, and with Uniper, a German utility, downstream. The federal government has issued Goldboro LNG a 20-year export licence, and Pieridae Energy Ltd. has forecast a positive final investment decision for 2020. The Cedar LNG Project near Kitimat by Cedar LNG Export Development Ltd. is currently in the environmental assessment stage, with British Columbia's Environmental Assessment Office conducting the environmental assessment on behalf of the Impact Assessment Agency of Canada ("IA Agency").

In early August 2019, Enbridge initiated an open season for the Enbridge mainline system, which has historically operated as a common carrier pipeline system, wherein producers could nominate volumes to ship through the pipeline. The changes that Enbridge intends to implement in the open season include the transition of the mainline system from a common carrier to a primarily contract carrier pipeline, wherein producers will have to commit to reserved space in the pipeline for a fixed term, with only 10% of available capacity reserved for nominations. As a result, shippers seeking firm capacity on the Enbridge system would no longer be able to rely on the nomination process and would have to enter long-term contracts for service.

Several shippers challenged Enbridge's open season and, in particular, Enbridge's ability to engage in an open season without prior regulatory approval. Following an expedited hearing process, the CER decided to shut down the open season, citing concerns about fairness and uncertainty regarding the ultimate terms and conditions of service.

On December 19, 2019, Enbridge applied to the CER for a hearing for the right to hold an open season. The CER is expected to establish a timeline for the process in early 2020. Interveners will have the opportunity to make written submissions, and then an oral hearing will take place later in the year. A final decision from the CER is expected in early 2021.

On December 2, 2018, the Government of Alberta announced that, commencing January 1, 2019, it would mandate a short-term reduction in provincial crude oil and crude bitumen production. As contemplated in the Curtailment Rules, as amended effective October 1 2019, the Government of Alberta, on a monthly basis, subjects crude oil producers producing more than 20,000 bbls/d to curtailment orders that limit their production according to a pre-determined formula that allocates production limits proportionately amongst all operators subject to curtailment orders.

Where an operator to whom a curtailment order applies is a joint venture or partnership, the partners or joint venturers may enter into an agreement respecting the allocation of the combined production among themselves to comply with the curtailment order.

Curtailment first took effect on January 1, 2019, limiting province-wide production of crude oil and crude bitumen to 3.56 million bbls/d. The curtailment rate dropped gradually over the course of 2019 as a result of decreasing price differentials and volumes of crude oil and crude bitumen in storage. Allowable production for March 2020 and April 2020 is set at 3.81 million bbls/d.

The Government of Alberta introduced certain policy changes to the curtailment program in late 2019, including giving the Minister of Energy the power to set revised production limits for a producer following a merger or acquisition, and creating an exemption for newly drilled conventional oil wells. Furthermore, the Government of Alberta created a special production allowance, effective October 28, 2019, that allows crude oil production in excess of a curtailment order, provided that the extra production is shipped out of Alberta by rail.

Curtailment volumes affect sixteen of over 300 producers in Alberta. The Curtailment Rules are set to be repealed by December 31, 2020.

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico came into force on January 1, 1994. The three NAFTA signatories have been working towards replacing NAFTA. On November 30, 2018, Canada, Mexico, and the United States signed a new trade agreement, widely referred to as the United States Mexico Canada Agreement (the "USMCA"), sometimes referred to as the Canada United States Mexico Agreement, or "CUSMA". Legislative bodies in the three signatory countries must ratify the USMCA before it comes into force. Mexico's senate ratified the USMCA in June 2019. In late December 2019, the United States' House of Representatives approved the USMCA, and the USMCA received approval from the United States Senate on January 16, 2020. On January 29, 2020, the Government of Canada tabled Bill C-4 to ratify the USMCA. According to Bill C-4, the USMCA will come into force two months after the House of Commons and the Senate pass Bill C-4. Until then, NAFTA remains the North American trade agreement currently in force. As the United States remains Canada's primary trading partner and the largest international market for the export of crude oil, natural gas and NGLs from Canada the implementation of the final version ratified version of the USMCA could have an impact on Western Canada's crude oil and natural gas industry at large, including the Company's business.

Under the terms of NAFTA's Article 605, a proportionality clause prevents Canada from implementing policies that limit exports to the United States and Mexico, relative to the total supply produced in Canada. Canada remains free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of Canada as compared to the proportion prevailing in the most recent 36 month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply. Further, all three signatory countries are prohibited from imposing a minimum or maximum price requirement on exports (where any other form of quantitative restriction is prohibited) and imports (except as permitted in the enforcement of countervailing and anti-dumping orders and undertakings). NAFTA also requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of such changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements.

The Government of Alberta's curtailment program complies with NAFTA's Article 605, under which Canada must make available a consistent proportion of the crude oil and bitumen produced to the other NAFTA signatories. As a result of the proportionality rule, reducing Canadian supply reduced the required offering under NAFTA, with the result that the amount of crude oil and bitumen that Canada is required to offer, while Canadian crude oil

prices are depressed, may be reduced. It is possible that the USMCA will come into force before the Government of Alberta's curtailment order is set to be repealed by the end of 2020.

The USMCA does not contain the proportionality rules of NAFTA's Article 605. The elimination of the proportionality clause removes a barrier in Canada's transition to a more diversified export portfolio. While diversification depends on the construction of infrastructure allowing more Canadian production to reach Eastern Canada, Asia, and Europe, the USMCA may allow for greater export diversification than currently exists under NAFTA.

Canada has also pursued a number of other international free trade agreements with other countries around the world. As a result, a number of free trade or similar agreements are in force between Canada and certain other countries while in other circumstances Canada has been unsuccessful in its efforts. Canada and the European Union recently agreed to the Comprehensive Economic and Trade Agreement ("CETA"), which provides for duty-free, quota-free market access for Canadian crude oil and natural gas products to the European Union. Although CETA remains subject to ratification by 14 of the 28 national legislatures in the European Union, provisional application of CETA commenced on September 21, 2017. In light of the United Kingdom's departure from the European Union on January 31, 2020, the United Kingdom and Canada are expected to work towards a new trade agreement through the 11-month implementation period, during which the United Kingdom will transition out of the European Union. As such, CETA will remain in place until December 31, 2020.

Canada and ten other countries have agreed on the text of the Comprehensive and Progressive Agreement for Trans-Pacific Partnership ("CPTPP"), which is intended to allow for preferential market access among the countries that are parties to the CPTPP. The CPTPP is in force among the first seven countries to ratify the agreement – Canada, Australia, Japan, Mexico, New Zealand, Vietnam, and Singapore.

While it is uncertain what effect CETA, CPTPP, or any other trade agreements will have on the crude oil and natural gas industry in Canada, the lack of available infrastructure for the offshore export of crude oil and natural gas may limit the ability of Canadian crude oil and natural gas producers to benefit from such trade agreements.

The respective provincial governments (i.e. the Crown), predominantly own the mineral rights to crude oil and natural gas located in Western Canada, with the exception of Manitoba (which only owns 20% of the mineral rights). Provincial governments grant rights to explore for and produce crude oil and natural gas pursuant to leases, licences and permits for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. The provincial governments in Western Canada's provinces conduct regular land sales where crude oil and natural gas companies bid for leases to explore for and produce crude oil and natural gas pursuant to mineral rights owned by the respective provincial governments. Oil and natural gas leases generally have a fixed term; however, a lease may generally be continued after the initial term where certain minimum thresholds of production have been reached, all lease rental payments have been paid on time and other conditions are satisfied.

To develop crude oil and natural gas resources, it is necessary for the mineral estate owner to have access to the surface lands as well. Each province has developed its own process for obtaining surface access to conduct operations that operators must follow throughout the lifespan of a well, including notification requirements and providing compensation for affected persons for lost land use and surface damage.

Each of the provinces of Western Canada have implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or licence. In addition, Alberta has a policy of "shallow rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for new leases and licences. British Columbia has a policy of "zone specific retention" that allows a lessee to continue a lease for zones in which they can demonstrate the presence of oil or natural gas, with the remainder reverting to the Crown.

In addition to Crown ownership of the rights to crude oil and natural gas, private ownership of crude oil and natural gas (i.e. freehold mineral lands) also exists in Western Canada. In the provinces of Alberta, British Columbia, Saskatchewan and Manitoba approximately 19%, 6%, 20% and 80%, respectively, of the mineral rights are owned by private freehold owners. Rights to explore for and produce such crude oil and natural gas are granted by a lease or other contract on such terms and conditions as may be negotiated between the owner of such mineral rights and crude oil and natural gas explorers and producers.

An additional category of mineral rights ownership includes ownership by the Canadian federal government of some legacy mineral lands and within Indigenous reservations designated under the Indian Act (Canada). Indian Oil and Gas Canada ("IOGC"), which is a federal government agency, manages subsurface and surface leases, in consultation with the applicable Indigenous peoples, for exploration and production of crude oil and natural gas on Indigenous reservations.

Until recently, oil and natural gas activities conducted on Indian reserve lands were governed by the Indian Oil and Gas Act (the "IOGA") and the Indian Oil and Gas Regulations, 1995 (the "1995 Regulations"). In 2009, Parliament passed An Act to Amend the Indian Oil and Gas Act, amending and modernizing the IOGA (the "Modernized IOGA"), however the amendments were delayed until the federal government was able to complete stakeholder consultations and update the accompanying Regulations (the "2019 Regulations"). The Modernized IOGA and the 2019 Regulations came into force on August 1, 2019. At a high level, the Modernized IOGA and the 2019 Regulations govern both surface and subsurface IOGC Leases, establishing the terms and conditions with which an IOGC leaseholder must comply. The two enactments also establish a substitution system whereby provincial oil and natural gas/environmental regulatory authorities act on behalf of the federal government to ensure greater symmetry between federal and provincial regulatory standards. The Company does not have operations on Indian reserve lands.

Each province has legislation and regulations that govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of oil sands projects and crude oil, natural gas and NGLs production. Royalties payable on production from lands where the Crown does not hold the mineral rights are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined by provincial regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable typically depends in part on prescribed reference prices, well productivity, geographic location, field discovery date, method of recovery and the type or quality of the petroleum substance produced.

Occasionally, the governments of Western Canada's provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and may be introduced when commodity prices are low to encourage exploration and development activity. In addition, such programs may be introduced to encourage producers to undertake initiatives using new technologies that may enhance or improve recovery of crude oil, natural gas and NGLs.

The federal government also announced in late 2018 that it would make $1.6 billion available to the oil and natural gas industry in light of worsening commodity price differentials. The aid package has been administered through federal agencies including the Business Development Bank of Canada, Natural Resources Canada, Export Development Canada, and Innovation, Science and Economic Development Canada. Export Development Canada has lent or guaranteed $629 million among 37 companies, of $1 billion available to oil and natural gas producers. The Bank of Canada has made 892 loans totalling $207.5 million out of its $500 million commercial loan allotment in the aid package. Innovation, Science and Economic Development Canada announced $49 million each for two projects to help Alberta companies building facilities to turn propane into polypropylene, a type of plastic not currently produced in Canada, but often used in packaging and labels. Natural Resources Canada distributed $37 million of a $50 million commitment under its Clean Growth Program for nine projects that help oil and natural gas companies reduce their carbon footprints.

Producers and working interest owners of crude oil and natural gas rights may also carve out additional royalties or royalty-like interests through non-public transactions, which include the creation of instruments such as overriding royalties, net profits interests and net carried interests.

In Alberta, the provincially-set royalty rates apply to Crown-owned mineral rights. In 2016, the Government of Alberta adopted a modernized royalty framework (the "Modernized Framework") that applies to all wells drilled after December 31, 2016. The previous royalty framework (the "Old Framework") will continue to apply to wells drilled prior to January 1, 2017 for a period of ten years ending on December 31, 2026. After the expiry of this ten-year period, these older wells will become subject to the Modernized Framework. The Royalty Guarantee Act (Alberta), came into effect on July 18, 2019, and provides that no major changes will be made to the current oil and natural gas royalty structure for a period of at least 10 years.

The Modernized Framework applies to all hydrocarbons other than oil sands which will remain subject to their existing royalty regime. Royalties on production from non-oil sands wells under the Modernized Framework are determined on a "revenue-minus-costs" basis with the cost component based on a Drilling and Completion Cost Allowance formula for each well, depending on its vertical depth and/or horizontal length. The formula is based on the industry’s average drilling and completion costs as determined by the Alberta Energy Regulator (the "AER") on an annual basis.

Producers pay a flat royalty rate of 5% of gross revenue from each well that is subject to the Modernized Framework until the well reaches payout. Payout for a well is the point at which cumulative gross revenues from the well equals the Drilling and Completion Cost Allowance for the well set by the AER. After payout, producers pay an increased post-payout royalty on revenues of between 5% and 40% for crude oil and pentanes and 5% and 36% for methane, ethane, propane and butane, all determined by reference to the then current commodity prices of the various hydrocarbons. Similar to the Old Framework, the post-payout royalty rate under the Modernized Framework varies with commodity prices. Once production in a mature well drops below a threshold level where the rate of production is too low to sustain the full royalty burden, its royalty rate is adjusted downward towards a minimum of 5% as the mature well's production declines. As the Modernized Framework uses deemed drilling and completion costs in calculating the royalty and not the actual drilling and completion costs incurred by a producer, low cost producers benefit if their well costs are lower than the Drilling and Completion Cost Allowance and, accordingly, they continue to pay the lower 5% royalty rate for a period of time after their wells achieve actual payout.

Oil and natural gas producers are responsible for calculating their royalty rate on an ongoing basis. The Crown's royalty share of production is payable monthly, and producers must submit their records showing the royalty calculation. The Mines and Minerals Act was amended in 2014, and shortened the window during which producers can submit amendments to their royalty calculations before they become statute-barred, from four years to three. Both the 2014 and 2015 production years became statute barred on December 31, 2018, as the pre-amendment four-year period applied for the years up to and including 2014. Going forward, producers will only have three years to amend their royalty calculations.

The Old Framework is applicable to all conventional crude oil and natural gas wells drilled prior to January 1, 2017 and bitumen production. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for conventional crude oil production under the Old Framework range from a base rate of 0% to a cap of 40%. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for natural gas production under the Old Framework range from a base rate of 5% to a cap of 36%. The Old Framework also includes a natural gas royalty formula which provides for a reduction based on the measured depth of the well below 2,000 metres deep, as well as the acid gas content of the produced gas. Under the Old Framework, the royalty rate applicable to NGLs is a flat rate of 40% for pentanes and 30% for butanes and propane. Currently, producers of crude oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, at a rate of $3.50 per hectare, and make monthly royalty payments in respect of crude oil and natural gas produced.

Oil sands production is also subject to Alberta's royalty regime. The Modernized Framework did not change the oil sands royalty framework. Prior to payout of an oil sands project, the royalty is payable on gross revenues of an oil sands project. Gross revenue royalty rates range between 1% and 9% depending on the market price of crude oil, determined using the average monthly price, expressed in Canadian dollars, for Western Texas

Intermediate crude oil at Cushing, Oklahoma. Rates are 1% when the market price of crude oil is less than or equal to $55 per barrel and increase for every dollar of market price of crude oil increase to a maximum of 9% when crude oil is priced at $120 or higher. After payout, the royalty payable is the greater of the gross revenue royalty based on the gross revenue royalty rate of between 1% and 9% and the net revenue royalty based on the net revenue royalty rate. Net revenue royalty rates start at 25% and increase for every dollar of market price of crude oil increase above $55 up to 40% when crude oil is priced at $120 or higher.

The Government of Alberta has from time to time implemented drilling credits, incentives or transitional royalty programs to encourage crude oil and natural gas development and new drilling. In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources, including as applied to coalbed methane wells, shale gas wells and horizontal crude oil and natural gas wells.

Freehold mineral taxes are levied for production from freehold mineral lands on an annual basis on calendar year production. Freehold mineral taxes are calculated using a tax formula that takes into consideration, among other things, the amount of production, the hours of production, the value of each unit of production, the tax rate and the percentages that the owners hold in the title. On average, in Alberta the tax levied is 4% of revenues reported from freehold mineral title properties. The freehold mineral taxes would be in addition to any royalty or other payment paid to the owner of such freehold mineral rights, which are established through private negotiation.

Royalties on production from privately-owned freehold lands are negotiated between the mineral freehold owner and the lessee under a negotiated lease or other contract. Producers and working interest participants may also pay additional royalties to parties other than the mineral freehold owner where such royalties are negotiated through private transactions.

In addition to the royalties payable to the mineral owners (or to other royalty holders if applicable), producers of crude oil and natural gas from freehold lands in each of the Western Canadian provinces are required to pay freehold mineral taxes or production taxes. Freehold mineral taxes or production taxes are taxes levied by a provincial government on crude oil and natural gas production from lands where the Crown does not hold the mineral rights. A description of the freehold mineral taxes payable in each of the Western Canadian provinces is included in the above descriptions of the royalty regimes in such provinces.

Where oil and natural gas leases fall under the jurisdiction of the IOGC, the IOGC is responsible for issuing crude oil and natural gas agreements between Indigenous groups and producers, and collecting and distributing royalty revenues. The exact terms and conditions of each crude oil and natural gas lease dictate the calculation of royalties owed, which may vary depending on the involvement of the specific Indigenous group. Ultimately, the relevant Indigenous group must approve the royalty rate for each lease.

The Canadian crude oil and natural gas industry is currently subject to environmental regulation under a variety of Canadian federal, provincial, territorial and municipal laws and regulations, all of which are subject to governmental review and revision from time to time. Such regulations provide for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain crude oil and natural gas industry operations, such as sulphur dioxide and nitrous oxide. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well, facility and pipeline sites. Compliance with such regulations can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licences and authorizations, civil liability and the imposition of material fines and penalties. In addition to these specific, known requirements, future changes to environmental legislation, including anticipated legislation for air pollution and greenhouse gas ("GHG") emissions, including carbon dioxide equivalents (“CO2e”), may impose further requirements on operators and other companies in the crude oil and natural gas industry.

Canadian environmental regulation is the responsibility of both the federal and provincial governments. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law will prevail. The federal government has primary jurisdiction over federal works, undertakings and federally regulated industries such as railways, aviation and interprovincial transport including interprovincial pipelines.

On August 28, 2019, with the passing of Bill C-69, the CERA and the Impact Assessment Act ("IAA") came into force and the NEB Act and the Canadian Environmental Assessment Act, 2012 ("CEAA 2012") were repealed. In addition, the IA Agency replaced the Canadian Environmental Assessment Agency ("CEA Agency").

Bill C-69 introduced a number of important changes to the regulatory regime for federally regulated major projects and associated environmental assessments. Previously, the NEB administered its statutory jurisdiction as an integrated regulatory body. Now, the CERA separates the CER's administrative and adjudicative functions. A board of directors and a chief executive officer will manage strategic, administrative and policy considerations while adjudicative functions will fall into the purview of a group of independent commissioners. The CER has assumed the jurisdiction previously held by the NEB over matters such as the environmental and economic regulation of pipelines, transmission infrastructure and offshore renewable energy projects, including offshore wind and tidal facilities. In its adjudicative role, the CERA tasks the CER with reviewing applications for the development, construction and operation of these projects, culminating in their eventual abandonment.

"Designated projects" under the IAA include interprovincial or international pipelines that require more than 75km of new right of way, and will require an impact assessment as part of their regulatory review. The impact assessment, conducted by a review panel, jointly appointed by the CER and the IA Agency, includes expanded criteria the review panel may consider when reviewing an application. The impact assessment also requires

consideration of the project's potential adverse effects, the overall societal impact and the expanded public interest that a project may have. The impact assessment must look at the direct result of the project's construction and operation, including environmental, biophysical and socio-economic factors, including consideration of a gender-based analysis, climate change, and impacts to Indigenous rights. Designated projects include pipelines that require more than 75km of new right of way and pipelines located in national parks. Large scale in situ oil sands projects not regulated by provincial greenhouse gas emissions and certain refining, processing and storage facilities will also require an impact assessment.

Once a review or assessment is commenced under either the CERA or IAA, there are limits on the amount of time the relevant regulatory authority will have to issue its report and recommendation. Designated projects will go through a planning phase to determine the scope of the impact assessment, which the federal government has stated should provide more certainty as to the length of the full review process. Applications for non-designated projects will follow a similar process as under the NEB Act. There is significant uncertainty surrounding the impact of Bill C-69 on oil and natural gas projects. There was significant opposition from industry and others in respect of Bill C-69, and notwithstanding its stated purpose, there is concern that the changes brought about by Bill C-69 will result in projects not being approved or increased delays in approvals. The Minister of Natural Resources has a mandate to implement the CER efficiently and effectively, but the CER's ability to expedite the project approval process has not yet been substantially tested. The Government of Alberta is challenging the constitutionality of Bill C-69, and has submitted a reference question to the Alberta Court of Appeal. This case is expected to be heard in the fall of 2020.

On May 12, 2017, the federal government introduced Bill C-48 in Parliament. This legislation is aimed at providing coastal protection in northern British Columbia by prohibiting crude oil tankers carrying more than 12,500 metric tonnes of crude oil or persistent crude oil products from stopping, loading, or unloading crude oil in that area. Parliament passed Bill C-48 as the Oil Tanker Moratorium Act which received royal assent on June 21, 2019. The enactment of this statute may prevent pipelines from being built, and export terminals from being located on, the portion of the British Columbia coast subject to the moratorium (north of 50°53′00′′ north latitude and west of 126°38′36′′ west longitude) and, as a result, may negatively impact the ability of producers to access global markets.

The AER is the principal regulator responsible for all energy resource development in Alberta. It derives its authority from the Responsible Energy Development Act and a number of related legislation including the Oil and Gas Conservation Act (the "OGCA"), the Oil Sands Conservation Act, the Pipeline Act, and the Environmental Protection and Enhancement Act. The AER is responsible for ensuring the safe, efficient, orderly and environmentally responsible development of hydrocarbon resources including allocating and conserving water resources, managing public lands, and protecting the environment. The AER's responsibilities exclude the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as the Alberta Ministry of Energy's responsibility for mineral tenure. The objective behind a single regulator is an enhanced regulatory regime that is intended to be efficient, attractive to business and investors, and effective in supporting public safety, environmental management and resource conservation while respecting the rights of landowners.

The Government of Alberta relies on regional planning to accomplish its responsible resource development goals. Its approach to natural resource management provides for engagement and consultation with stakeholders and the public and examines the cumulative impacts of development on the environment and communities by incorporating the management of all resources, including energy, minerals, land, air, water and biodiversity. While the AER is the primary regulator for energy development, several other governmental departments and agencies may be involved in land use issues, including the Alberta Ministry of Environment and Parks, the Alberta Ministry of Energy, the Aboriginal Consultation Office and the Land Use Secretariat.

The Government of Alberta's land-use policy for surface land in Alberta sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land-use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans. As a result, several regional plans have been implemented. These regional plans may affect further development and operations in such regions.

The AER monitors seismic activity across Alberta, in the context of assessing the risks associated with, and instances of, earthquakes induced by hydraulic fracturing. In an ongoing process spanning between February 19, 2015 to December 9, 2019, the AER has developed monitoring and reporting requirements that apply to all oil and natural gas producers working in certain areas where the likelihood of an earthquake is higher, and implemented the requirements in Subsurface Order Nos. 2, 6, and 7. The regions with seismic protocols in place that are aimed at limiting the impact and potential of induced earthquakes from hydraulic fracturing are Fox Creek, Red Deer, and Brazeau (the "Seismic Protocol Regions"). The Company does not have operations in Fox Creek, Red Deer, and Brazeau and natural gas producers in each of the Seismic Protocol Regions are subject to a "traffic light" reporting system that sets thresholds on the Richter scale of earthquake magnitude. The thresholds vary among the Seismic Protocol Regions, and trigger a sliding scale of obligations from the oil or natural gas producers operating there. The obligations range from no action required, to informing the AER and invoking an approved response plan, to ceasing operations and informing the AER. The AER has the discretion to suspend oil or natural gas producers' operations while it conducts investigations following a seismic event, and only when the AER has assessed ongoing risk of earthquakes in a specific area and/or required the oil or natural gas producer to update its response plan, can operations resume. The AER may extend these requirements to other areas of Alberta if necessary, subject to the results of the AER's ongoing province-wide monitoring.

The AER administers the licensee Liability Management Rating Program (the "AB LMR Program"). The AB LMR Program is a liability management program governing most conventional upstream crude oil and natural gas wells, facilities and pipelines. It consists of three distinct programs: the Licensee Liability Rating Program (the "AB LLR Program"), the Oilfield Waste Liability Program (the "AB OWL Program") and the Large Facility Liability Management Program (the "AB LFP"). If a licensee's deemed liabilities in the AB LLR Program, the AB OWL Program and/or the AB LFP exceed its deemed assets in those programs, the AB LMR Program requires the licensee to provide the AER with a security deposit and may restrict the licensee's ability to transfer licences. This ratio of a licensee's assets to liabilities across the three programs is referred to as the licensee's liability management rating ("LMR"). Where the AER determines that a security deposit is required, the failure to post any required amounts may result in the initiation of enforcement action by the AER.

The AER previously assessed the LMR of all licensees on a monthly basis and posted the individual ratings on the AER's public website. However, in December 2019 the AER ceased posting the detailed LMR report, stating that resource and budget limitations have impacted its ability to maintain and administer the AB LMR Program. Licensees can continue to access their individual LMR calculations through the AER's Digital Data Submission System. The AER is currently reviewing the AB LMR Program as it no longer considers the LMR value alone to be a good indicator of a company's financial health. It is unclear if, or when, any changes will be made to the current regulatory framework. Any changes to the AB LMR Program may affect the Company's ability to obtain or transfer licenses.

Complementing the AB LMR Program, Alberta's OGCA establishes an orphan fund (the "Orphan Fund") to help pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program and the AB OWL Program if a licensee or working interest participant becomes insolvent or is unable to meet its obligations. Licensees in the AB LLR Program and AB OWL Program, including the Company, fund the Orphan Fund through a levy administered by the AER. A separate orphan levy applies to persons holding licences subject to the AB LFP. Collectively, these programs are designed to minimize the risk to the Orphan Fund posed by the unfunded liabilities of licensees and to prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines.

On January 31, 2019, the Supreme Court of Canada overturned the lower courts' decisions in Redwater Energy Corporation (Re) (“Redwater”), holding that there is no operational conflict between the abandonment and reclamation provisions contained in the provincial OGCA, the liability management regime administered by the AER and the federal bankruptcy and insolvency regime. As a result, receivers and trustees can no longer avoid the AER's legislated authority to impose abandonment orders against licensees or to require a licensee to pay a security deposit before approving a transfer when such a licensee is subject to formal insolvency proceedings. This means that insolvent estates can no longer disclaim assets of a bankrupt licensee that have reached the end of their productive lives and represent a liability and deal with the company’s valuable assets for the benefit of the company's creditors, without first satisfying abandonment and reclamation obligations.

In response to the lower courts' decisions in Redwater, the AER issued several bulletins and interim rule changes to govern the AER's administration of its licensing and liability management programs. In response to Redwater’s trajectory through the Courts, the AER introduced amendments to its liability management framework. The AER amended its Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals, which deals with licensee eligibility to operate wells and facilities, to require the provision of extensive corporate governance and shareholder information, including whether any director and officer was a director or officer of an energy company that has been subject to insolvency proceedings in the last five years. All transfers of well, facility and pipeline licences in the province are subject to AER approval. As a condition of transferring existing AER licences, approvals and permits, all transfers are now assessed on a non-routine basis and the AER now requires all transferees to demonstrate that they have an LMR of 2.0 or higher immediately following the transfer, or to otherwise prove to the satisfaction of the AER that it can meet its abandonment and reclamation obligations. The AER may make further rule changes at any time. The Supreme Court of Canada's Redwater decision alleviates some of the concerns that the AER's rule changes were intended to address, however the AER has indicated it is in the process of reviewing the current framework.

The AER has also implemented the Inactive Well Compliance Program (the "IWCP") to address the growing inventory of inactive wells in Alberta and to increase the AER's surveillance and compliance efforts under Directive 013: Suspension Requirements for Wells ("Directive 013"). The IWCP applies to all inactive wells that are noncompliant with Directive 013 as of April 1, 2015. The objective is to bring all inactive noncompliant wells under the IWCP into compliance with the requirements of Directive 013 within five years. As of April 1, 2015, each licensee is required to bring 20% of its inactive wells into compliance every year, either by reactivating or suspending the wells in accordance with Directive 013 or by abandoning them in accordance with Directive 020: Well Abandonment. The list of current wells subject to the IWCP is available on the AER's Digital Data Submission System. The AER has announced that from April 1, 2015 to April 1, 2016, the number of noncompliant wells subject to the IWCP fell from 25,792 to 17,470, with 76% of licensees operating in the province having met their annual quota. From April 1, 2016 to April 1, 2017, this number fell from 17,470 to 12,375 noncompliant wells, with 81% of licensees operating in the province having met their annual quota. The IWCP will complete its fifth year on March 31, 2020 but the AER has not released its subsequent annual reports on compliance levels since 2017.

As part of its strategy to encourage the decommissioning, remediation and reclamation of inactive or marginal oil and natural gas infrastructure, the AER announced a voluntary area-based closure ("ABC") program in 2018. The ABC program is designed to reduce the cost of abandonment and reclamation operations though industry collaboration and economies of scale. Participants seeking the program incentives must commit to an inactive liability reduction target to be met through closure work of inactive assets. The Corporation is not participating in the voluntary ABC program.

Climate change regulation at both the federal and provincial level has the potential to significantly affect the future of the crude oil and natural gas industry in Canada. The impacts of federal or provincial climate change and environmental laws and regulations are uncertain. It is currently not possible to predict the extent of future requirements. Any new laws and regulations (or additional requirements to existing laws and regulations) could have a material impact on the Company's operations and cash flow.

Canada has been a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") since 1992. Since its inception, the UNFCCC has instigated numerous policy experiments with respect to climate governance. On April 22, 2016, 197 countries, including Canada, signed the Paris Agreement, committing to prevent global temperatures from rising more than 2° Celsius above pre-industrial levels and to pursue efforts to limit this rise to no more than 1.5° Celsius. As of December 23, 2019, 187 of the 197 parties to the convention have ratified the Paris Agreement. In December 2019, the United Nations annual Conference of the Parties took place in Madrid, Spain. The Conference concluded with the attendees delaying decisions about a prospective carbon market and emissions cuts until the next climate conference in Glasgow in 2020. However, the European Union reached an agreement about "The European Green New Deal" that aims to lower emissions to zero by 2050.

Following the Paris Agreement and its ratification in Canada, the Government of Canada pledged to cut its emissions by 30% from 2005 levels by 2030. Further, on December 9, 2016, the Government of Canada released the Pan-Canadian Framework on Clean Growth and Climate Change (the "Framework"). The Framework provided for a carbon-pricing strategy, with a carbon tax starting at $10/tonne in 2018, increasing annually until it reaches $50/tonne in 2022. This system applies in provinces and territories that request it and in those that do not have a carbon pricing system in place that meets the federal standards. On June 21, 2018, the federal government enacted the Greenhouse Gas Pollution Pricing Act (the "GGPPA"), which came into force on January 1, 2019. This regime has two parts: an emissions trading system for large industry and a regulatory fuel charge

imposing an initial price of $20/tonne of GHG emissions. Under current federal plans, this price will escalate by $10 per year until it reaches a price of $50/tonne in 2022. Starting April 1, 2020, the minimum price permissible under the GGPPA is $30/tonne of GHG emissions.

Six provinces and territories have introduced carbon-pricing systems that meet federal requirements: British Columbia, Quebec, Prince Edward Island, Nova Scotia, Newfoundland and Labrador, and the Northwest Territories. The federal fuel charge regime took effect in Saskatchewan, Manitoba, Ontario, and New Brunswick on April 1, 2019 and in the Yukon and Nunavut on July 1, 2019. The federal fuel charge regime took effect in Alberta on January 1, 2020. Alberta, Saskatchewan, and Ontario have referred the constitutionality of the GGPPA to their respective Courts of Appeal. In both the Saskatchewan and Ontario references, the appellate Courts ruled in favour of the constitutionality of the GGPPA. The Attorneys General of Saskatchewan and Ontario have appealed these decisions to the Supreme Court of Canada and the Court is set to hear the appeals in March 2020. On February 24, 2020, the Alberta Court of Appeal determined that the GGPPA is unconstitutional. It is unclear whether the Alberta reference will be appealed and heard with the Saskatchewan and Ontario appeals or, relatedly, whether those scheduled hearings will be delayed as a result. However, each of Saskatchewan, Ontario and Alberta will participate in the scheduled hearings, along with the Attorneys General of Quebec, New Brunswick, Manitoba and British Columbia and various other interested parties.

On April 26, 2018, the federal government passed the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the "Federal Methane Regulations"). The Federal Methane Regulations seek to reduce emissions of methane from the crude oil and natural gas sector, and came into force on January 1, 2020. By introducing a number of new control measures, the Federal Methane Regulations aim to reduce unintentional leaks and intentional venting of methane, as well as ensuring that crude oil and natural gas operations use low-emission equipment and processes. Among other things, the Federal Methane Regulations limit how much methane upstream oil and natural gas facilities are permitted to vent. These facilities would need to capture the gas and either re-use it, re-inject it, send it to a sales pipeline, or route it to a flare. In addition, in provinces other than Alberta and British Columbia (which already regulate such activities), well completions by hydraulic fracturing would be required to conserve or destroy gas instead of venting. The federal government anticipates that these actions will reduce annual GHG emissions by about 20 megatonnes by 2030.

In October 2018, the federal government announced a pricing scheme as an alternative for large electricity generators so as to incentivize a reduction in emissions intensity, rather than encouraging a reduction in generation capacity.

Finally, the federal government has also enacted the Multi-Sector Air Pollutants Regulation under the authority of the Canadian Environmental Protection Act, 1999, which seeks to regulate certain industrial facilities and equipment types, including boilers and heaters used in the upstream oil and natural gas industry and to limit the emission of air pollutants such as nitrogen oxides and sulphur dioxide.

On November 22, 2015, the Government of Alberta introduced a Climate Leadership Plan (the "CLP"). Under this strategy, the Climate Leadership Act (the "CLA") came into force on January 1, 2017 and established a fuel charge intended to first outstrip and subsequently keep pace with the federal price. On December 14, 2016, the Oil Sands Emissions Limit Act came into force, establishing an annual 100 megatonne limit for GHG emissions from all oil sands sites, excluding some attributable to upgraders, the electric energy portion of cogeneration and other prescribed emissions.

In June 2019, the Government of Alberta pivoted in its implementation of the CLP and repealed the CLA. The Carbon Competitiveness Incentives Regime ("CCIR") remained in place. As a result, the federally imposed fuel charge took effect in Alberta on January 1, 2020, at a rate of $20/tonne. In accordance with the GGPPA, this will increase to $30/tonne on April 1, 2020. However, on December 4, 2019, the federal government approved Alberta's proposed Technology Innovation and Emissions Reduction ("TIER") regulation intended to replace the CCIR, so the regulation of emissions from heavy industry remains subject to provincial regulation, while the federal fuel charge still applies. The TIER regulation came into effect on January 1, 2020.

The TIER regulation operates differently than the former facility-based CCIR, and instead applies industry-wide to emitters that emit more than 100,000 tonnes of CO2e per year in 2016 or any subsequent year. The 2020 target for most TIER-regulated facilities is to reduce emissions intensity by 10% as measured against that facility's individual benchmark (which is, generally, its average emissions intensity during the period from 2013 to 2015), with a further 1% reduction for each subsequent year. The facility-specific benchmark does not apply to all facilities. Certain facilities, such as those in the electricity sector, are compared against the good-as-best-gas standard, which measures against the emissions produced by the cleanest natural gas-fired generation system. Similarly, for facilities that have already made substantial headway in reducing their emissions, a different "high-performance" benchmark is available to ensure that the cost of ongoing compliance takes this into account. As with the former CCIR, the TIER regulation targets emissions intensity rather than total emissions. Under the TIER regulation, facilities in high-emitting sectors can opt-in to the program despite the fact that they do not meet the 100,000 tonne threshold. A facility can opt-in to TIER regulation if it competes directly against another TIER-regulated facility or if it has annual CO2e emissions that exceed 10,000 tonnes per year and belongs to an emissions-intensive or trade exposed sector with international competition. In addition, the owner of two or more "conventional oil and gas facilities" may apply to have those facilities regulated under the TIER regulation. To encourage compliance with the emissions intensity reduction targets, TIER-regulated facilities must provide annual compliance reports and facilities that are unable to achieve their targets may either purchase credits from other facilities, purchase carbon offsets, or pay a levy to the Government of Alberta.

The Government of Alberta previously signaled its intention through the CLP to implement regulations that would lower annual methane emissions by 45% by 2025. Pursuant to this goal, the Government of Alberta enacted the Methane Emission Reduction Regulation (the "Alberta Methane Regulations") on January 1, 2020, and the AER simultaneously released an updated edition of Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting. The release of Directive 060 complements a previously released update to Directive 017: Measurement Requirements for Oil and Gas Operations that took effect in December 2018. Together, these new Directives represent Alberta's first step toward achieving its 2025 goal, as outlined in the Alberta Methane Regulations; however, the Government of Alberta and the federal government have not yet reached an equivalency agreement with respect to the Alberta Methane Regulations and the Federal Methane Regulations.

Alberta was also the first jurisdiction in North America to direct dedicated funding to implement carbon capture and storage technology across industrial sectors. Alberta has committed $1.24 billion through 2025 to fund two commercial-scale carbon capture and storage projects. Both projects will help reduce the CO2 emissions from the oil sands and fertilizer sectors, and reduce GHG emissions by 2.76 million megatonnes per year. On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010. It deemed the pore space

underlying all land in Alberta to be, and to have always been the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.

In 2015, the federal government's Extractive Sector Transparency Measures Act (the "ESTMA") came into effect, which imposed mandatory reporting requirements on certain entities engaged in the "commercial development of oil, gas or minerals", including exploration, extraction and holding permits. All companies subject to ESTMA must report payments over C$100,000 made to any level of a Canadian or foreign government (including indigenous groups), including royalty payments, taxes (other than consumption taxes and personal income taxes), fees, production entitlements, bonuses, dividends (other than ordinary dividends paid to Shareholders), infrastructure improvement payments and other prescribed categories of payments.

Investors should carefully consider the risk factors set out below and consider all other information contained herein and in the Company's other public filings before making an investment decision. The risks set out below are not an exhaustive list and should not be taken as a complete summary or description of all the risks associated with the Company's business and the oil and natural gas business generally. The Company's business could also be affected by additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial. If any of these risks actually occur, it could materially harm the Company's business, financial condition, results of operations, cash flows or impair the Company's ability to implement business plans or complete development activities as scheduled. In that case, the market price of the Common Shares could decline.

The Company engaged with the Egyptian government to amend, extend and consolidate the Company’s Eastern Desert concession agreements. If successful, this will provide the Company with a single concession with improved terms that would result in better cash flow and increased opportunity for capital reinvestment in Egypt.

Failure to successfully amend, extend and consolidate the Company’s Eastern Desert concession agreements could cause the Company to miss certain acquisition opportunities and reduce or terminate its operations earlier. To the extent that the merger of the Eastern Desert Concessions is unavailable or available on onerous terms, the Company's ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be affected materially and adversely as a result.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserves and associated cash flow information set forth in this document are estimates only. Generally, estimates of economically recoverable oil and natural gas reserves and the future net cash flows from such estimated reserves are based upon a number of variable factors and assumptions, such as:

For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different evaluators, or by the same evaluators at different times may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates and such variations could be material.

The estimation of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves. Such variations could be material.

In accordance with applicable securities laws, GLJ has used forecast prices and costs in estimating the reserves and future net cash flows. Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived from the Company's oil and natural gas reserves will vary from the estimates contained in the reserves evaluations, and such variations could be material. The reserves evaluations are based in part on the assumed success of activities the Company intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom and contained in the reserves evaluations will be reduced to the extent that such activities do not achieve the level of success assumed in the reserves evaluations.

At December 31, 2019, undeveloped reserves represented 19% of the Company’s total proved reserves and 48% of the Company’s probable reserves. See "Undeveloped Reserves" for details of our development plans for these reserves. 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. The Company’s reserves data assumes that the Company can and will make these expenditures and conduct these operations successfully, which assumptions may not prove to be correct. If the Company chooses not to spend the capital to develop these undeveloped reserves, or if the Company is not otherwise able to successfully develop these undeveloped reserves, the Company will be required to write-off these reserves. The Company’s petroleum contracts and leases require the Company to drill wells that are commercially productive and to maintain the production in paying quantities, and if the Company is unsuccessful in drilling such wells and maintaining such production, the Company could lose its rights under such petroleum contracts and leases. The Company’s future production levels and, therefore, its future cash flow and income are highly dependent on successfully developing its proved plus probable undeveloped reserves.

The Company's revenues, profitability, cash flows and future rate of growth are highly dependent on commodity prices. Commodity prices may fluctuate widely in response to relatively minor changes in the supply of and demand for crude oil, NGLs and natural gas, market uncertainty and a variety of additional factors that are beyond the Company’s control, such as:

The lack of access to other markets and firm pipeline capacity and limits on availability of capacity in gathering and processing facilities continues to affect the western Canadian oil and natural gas industry and limits the ability to transport produced crude oil and natural gas to market resulting in surplus production and western Canadian realized prices being significantly discounted relative to other markets. See "Industry Conditions - Transportation Constraints and Market Access" and "Industry Conditions - Curtailment". In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability of oil and natural gas companies to export crude oil and natural gas, and could result in the Company’s inability to realize the full economic potential of its production. See "Gathering and Processing Facilities, Pipeline Systems and Rail" below.

Commodity prices have historically been, and continue to be, extremely volatile. The Company expects this volatility to continue. The Company’s risk management arrangements will not fully mitigate the effects of price volatility and may also curtail benefits from future increases in commodity prices.

A further or extended decline in commodity prices could materially and adversely affect the Company’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. Significant or extended price declines could also materially and adversely affect the amount of crude oil, NGLs and natural gas that the Company can produce economically, which may result in the Company having to make significant downward adjustments to its reserves estimates. A reduction in production could also result in a shortfall in expected cash flows and require the Company to reduce capital spending or borrow funds or issue equity to cover any such shortfall. Any of these factors could negatively affect the Company’s ability to replace its production and its future rate of growth.

The demand for energy, including crude oil, NGLs and natural gas, is generally linked to broad-based economic activities. If there was a slowdown in economic growth, an economic downturn or recession or other adverse economic or political development in the United States, Europe or Asia, there could be a significant adverse effect on global financial markets and commodity prices. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. Global or national health concerns, including the outbreak of pandemic or contagious diseases, such as the recent COVID-19 (coronavirus), may adversely affect the Company by (i) reducing global economic activity thereby resulting in lower demand for crude oil, NGL and natural gas, (ii) impairing its supply chain (for example, by limiting the manufacturing of materials or the supply of services used in the Company operations), and (iii) affecting the health of its workforce, rendering employees unable to work or travel. These and other factors disclosed elsewhere in this Annual Information Form that affect the demand for crude oil, NGLs and natural gas and the Company's business and industry would ultimately have an adverse impact on the Company's results of operations and cash flow.

The trading price of the securities of oil and natural gas issuers is subject to volatility based on factors related and unrelated to the financial performance or prospects of the issuers involved. Factors related to the Company’s performance include variations in the Company’s financial condition, results of operations, cash flow and prospects. Factors unrelated to the Company’s performance include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices, and/or negative investor sentiment towards the oil and natural gas industry. In recent years, the volatility of oil and gas commodity prices, and the securities of issuers that explore, develop and produce them, has increased due, in part, to the implementation of computerized trading and the decrease of discretionary commodity trading. Similarly, recent market prices in the securities of oil and gas producers relative to other industry sectors have led to lower oil and gas representation in certain key equity market indices. The volatility, trading volume and market price of oil and gas issuers have been impacted by increasing investment levels in passive funds that track major indices and only purchase securities included in such indices and subsequently dispose of those securities if they are excluded from such indices. These factors have impacted the volatility and liquidity of certain securities and put downward pressure on the market price of those securities, including the Common Shares. Accordingly, the price at which the Common Shares will trade cannot be accurately predicted and may remain volatile.

In order to finance future operations or acquisition opportunities, the Company may raise funds through the issuance of Common Shares or the issuance of debt instruments or securities convertible into Common Shares. The Company cannot predict the size of future issuances of Common Shares or the issuance of debt instruments or other securities convertible into Common Shares or the effect, if any, that future issuances and sales of the Company's securities will have on the market price of the Common Shares.

Shareholders may sell their Common Shares in the future to realize their investment. Sales of substantial amounts of Common Shares, or the perception that such sales could occur, could materially adversely affect the market price of the Common Shares available for sale compared to the demand to buy Common Shares. Such sales may also make it more difficult for the Company to sell equity securities in the future at a time and price that is deemed appropriate. There can be no guarantee that the price of the Common Shares will reflect their actual or potential market value or the underlying value of the Company’s net assets.

The Company is principally aiming to achieve capital growth and, therefore, Common Shares may not be suitable as a short-term investment. Consequently, the share price may be subject to greater fluctuation on small volumes of shares traded, and thus the Common Shares may be difficult to sell at a particular price. Prospective investors should be aware that the value of an investment in the Company may go down as well as up and that the market price of the Common Shares may not reflect the underlying value of the Company. There can be no guarantee that the value of an investment in the Company will increase. Investors may therefore realize less than, or lose all of, their original investment.

The Company considers acquisitions of businesses and assets in the ordinary course of business, including acquisitions in new geographical areas. Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner and the Company's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of acquired businesses may require substantial management effort, time and resources diverting management's focus from other strategic opportunities and operational matters.

As a result, the Company may be subject to growth related risks including capacity constraints and pressure on its internal systems and controls. The ability of the Company to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expand, train and manage its employee base. The inability of the Company to deal with this growth may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

The Company’s cash flow from operating activities may not be sufficient to fund its ongoing activities at all times and, from time to time, the Company may require additional financing in order to carry out its oil and natural gas acquisition, exploration and development activities. Failure to obtain financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. Due to the conditions in the oil and natural gas industry and/or global economic and political volatility, the Company may, from time to time, have restricted access to capital and increased borrowing costs. The current conditions in the oil and natural gas industry have negatively impacted the ability of oil and natural gas companies to access, and the cost of, additional financing.

As a result of global economic and political conditions and the domestic lending landscape, the Company may, from time to time, have restricted access to capital and increased borrowing costs. Failure to obtain suitable financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Company’s cash flow from operating activities decreases as a result of lower oil and natural gas prices or otherwise, it will affect the Company’s ability to expend the necessary capital to replace its reserves or to maintain its production. To the extent that external sources of capital become limited, unavailable or available on onerous terms, the Company's ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be affected materially and adversely as a result. In addition, the future development the Company’s petroleum properties may require additional financing and there are no assurances that such financing will be available or, if available, will be available upon acceptable terms. Alternatively, any available financing may be highly dilutive to existing shareholders. Failure to obtain any financing necessary for the Company’s capital expenditure plans may result in a delay in development or production on the Company’s properties.

The petroleum industry is competitive in all of its phases. The Company competes with numerous other entities in the exploration, development, production and marketing of oil and natural gas. The Company’s competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of the Company and as such, the Company may be at a competitive disadvantage in the identification, acquisition and development of properties that complement the Company’s operations. Some of these companies not only explore for, develop and produce oil and natural gas, but also carry on refining operations and market oil and natural gas on an international basis. As a result of these complementary activities, some of these competitors may have greater and more diverse competitive resources to draw on than the Company and less volatility in their earnings and the market price of their equity. The Company’s ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price, process, and reliability of delivery and storage. To a lesser extent, the Company also faces competition from companies that supply alternative sources of energy, such as wind or solar power. Other factors that could affect competition in the marketplace include additional discoveries of hydrocarbon reserves by the Company’s competitors, the cost of production and political and economic factors and other factors outside the Company’s control.

The petroleum industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies that may increase the viability of reserves or reduce production costs. Other companies may have greater financial, technical and personnel resources that allow them to implement and benefit from such technological advantages. There can be no assurance that the Company will be able to respond to such competitive pressures and implement such technologies on a timely basis, or at an acceptable cost. If the Company does implement such technologies, there is no assurance that the Company will do so successfully. One or more of the technologies currently utilized by the Company or implemented in the future may become obsolete. If the Company is unable to utilize the most advanced commercially available

technology, or is unsuccessful in implementing certain technologies, its business, financial condition and results of operations could also be adversely affected in a material way.

In the last several years, the U.S. and certain European countries have experienced significant political events that have cast uncertainty on global financial and economic markets. Since the 2016 U.S. presidential election, the American administration has withdrawn the United States from the Trans-Pacific Partnership and the United States Congress has passed sweeping tax reform, which, among other things, significantly reduces U.S. corporate tax rates. This has affected the competitiveness of other jurisdictions, including Canada. In addition, NAFTA has been renegotiated and on November 30, 2018, Canada, the U.S. and Mexico signed the USMCA which will replace NAFTA once ratified by the three signatory countries. The USMCA was ratified by Mexico's Senate in June 2019 and by the United States' Senate in January 2020. The Canadian Parliament has not yet passed legislation to implement the USMCA. See "Industry Conditions - The North American Free Trade Agreement and Other Trade Agreements". The U.S. administration has also taken action with respect to the reduction of regulation, which may also affect relative competitiveness of other jurisdictions. It is unclear exactly what other actions the U.S. administration will implement, and if implemented, how these actions may impact Canada and in particular the oil and natural gas industry. Any actions taken by the current U.S. administration may have a negative impact on the Canadian economy and on the businesses, financial conditions, results of operations and the valuation of Canadian oil and natural gas companies, including the Company.

In addition to the political disruption in the U.S., the impact of the United Kingdom's exit from the European Union remains to be determined. Some European countries have also experienced the rise of anti-establishment political parties and public protests held against open-door immigration policies, trade and globalization. Conflict and political uncertainty also continues to progress in the Middle East. To the extent that certain political actions taken in North America, Europe and elsewhere in the world result in a marked decrease in free trade, access to personnel and freedom of movement, it could have an adverse effect on the Company’s ability to market its products internationally, increase costs for goods and services required for the Company’s operations, reduce access to skilled labour and negatively impact the Company’s business, operations, financial conditions and the market value of the Common Shares.

A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by such governments on matters that may impact the oil and natural gas industry, including attempts to balance between economic development and environmental and social policy. For example, Alberta elected a new government in 2019 that is supportive of the Trans Mountain Pipeline expansion project while a minority government in British Columbia remains opposed to the project and has attempted to regulate the transport of heavy oil products into and through British Columbia. Though the Supreme Court of Canada unanimously rejected the government of British Columbia's proposed regulation of the transport of heavy oil products into and through British Columbia, disputes remain between provincial and federal governments. Continued uncertainty and delays have led to decreased investor confidence, increased capital costs and operational delays for producers and service providers operating in the jurisdiction.

The federal Government of Canada was re-elected in 2019, but in a minority position. The ability of the minority federal government to pass legislation will be subject to whether it is able to come to agreement with, and garner the support of, the other elected parties, most of whom are opposed to the development of the oil and natural gas industry. The minority federal government will also be required to rely on the support of the other elected parties to remain in power, which provides less stability and may lead to an earlier subsequent federal election. Political instability, at both the federal and provincial level, continues to create regulatory uncertainty, the effects of which become apparent on an ongoing basis, particularly with respect to carbon pricing regimes, curtailment of crude oil production and transportation and export capacity, and may affect the business of participants in the oil and natural gas industry.

See "Industry Conditions - Climate Change Regulation", "Industry Conditions - Transportation Constraints and Market Access", "Industry Conditions - Curtailment" and "Industry Conditions - The North American Free Trade Agreement and other Trade Agreements".

The Company delivers crude oil through gathering, processing pipeline systems and export cargo terminals that the Company does not own or control. The amount of crude oil that the Company can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing pipeline systems and scheduling of export cargos (in Egypt). The lack of availability of capacity in any of the gathering, processing pipeline systems and export cargo terminals, and in particular the export cargo terminals in Egypt, could result in the Company's inability to realize the full economic potential of its production, sales or in a reduction of the price offered for the Company's production.

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, fire, explosion, blowouts, cratering, sour gas releases, spills and other environmental hazards. These typical risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property, the environment and personal injury. If any of these types of events were to occur, they could result in failure to discover hydrocarbons and if discovered delay in or loss of production, environmental damage, injury to persons or loss of life. They could also result in significant delays to drilling programmes, a partial or total shutdown of operations, significant damage to equipment owned or used by the Company and personal injury, wrongful death or other claims related to loss being brought against the Company. These events could result in the Company being required to take corrective measures, incurring significant civil liability claims, significant fines or penalties as well as criminal sanctions potentially being enforced against the Company and/or its officers. The Company may also be required to curtail or cease operations on the occurrence of such events. Any of the above could have a material adverse effect on the Company’s business, prospects, financial condition or results of operations.

Whilst the Company intends to implement certain policies and procedures to identify and mitigate such hazards, develop appropriate work plans and approvals for high-risk activities and prevent accidents from occurring, these procedures may not be sufficiently robust or appropriately followed by the Company’s staff or third-party contractors to prevent accidents. Particularly, the Company may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Company.

Oil and natural gas drilling and production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the

occurrence of any of these risks may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

The oil and gas industry in Egypt is not as efficient or developed as the oil and gas industry in North America. As a result, the Company's exploration and development activities may take longer to complete and may be more expensive than similar operations in North America. The availability of technical expertise, specific equipment and supplies may be more limited than in North America. The Company expects that such factors will subject its operations to economic and operating risks that may not be experienced in North American operations.

The Company is and may in the future be exposed to third party credit risk through its contractual arrangements with the Government of Egypt. Significant changes in the crude oil industry, including fluctuations in the commodity prices and economic conditions, environmental regulations, government policy, royalty rates and other geopolitical factors, could adversely affect the Company's ability to realize the full value of its accounts receivable from the Government of Egypt. Historically, the Company has had a significant account receivables outstanding from the Government of Egypt. While the Government of Egypt has made regular payments on these amounts owing, the timing of these payments has historically been longer than normal industry standard. The receivable balance due from the Egyptian Government has been reduced to a manageable level as a result of the Company's direct marketing initiative and continued payments from the Egyptian Government. However, there remains a balance due from the Egyptian Government, and there can be no assurance that future payments will occur on a more-timely basis or occur at all. In the event the Government of Egypt fails to meet its obligation, such failures could materially adversely affect the Company's financial and operational results.

The majority of the Company's current production is located in Egypt. As such, and in addition to the specific political risks mentioned above, the Company is subject to political, economic, and other uncertainties, including, but not limited to, expropriation of property without fair compensation, changes in energy policies or the personnel administering them, a change in oil or natural gas pricing policy, the actions of national labour unions, nationalization, currency fluctuations and devaluations, renegotiation or nullification of existing concessions and contracts, exchange controls and royalty and tax increases and retroactive tax claims, investment restrictions, import and export regulations and other risks arising out of foreign governmental sovereignty over the areas in which the Company's operations are conducted, as well as risks of loss due to civil strife, acts of war, terrorist activities and insurrections, economic sanctions, the imposition of specific drilling obligations and the development and abandonment of fields.

The Egyptian government could adopt new policies that might result in substantially hostile attitudes towards foreign investments such as the Company's. In an extreme case, government actions could result in forced renegotiation of the Company's existing contracts, termination of contract rights and expropriation of its assets (including crude oil inventory) or resource nationalization. Loss of property (damage to, or destruction of, the Company’s wells, production facilities or other operating assets) and/or interruption of its business plans (including lack of availability of drilling rigs, oilfield equipment or services if third party providers decide to exit the region or inability of the Company's service equipment providers to deliver necessary items for the Company to continue operations) as a direct or indirect result of political protests, demonstrations or civil unrest in Egypt could have a material adverse impact on the Company's results of operations and financial condition. In addition, the Company cannot provide assurance that future political developments in Egypt, including changes in government, changes in laws or regulations, export restrictions or further civil unrest or other disturbances, would not have an adverse impact on ongoing operations, the Company's ability to comply with its current contractual obligations, the Company's ability to lift and sell its crude oil inventory to third parties, or on the terms or enforceability of its production sharing and concession agreements or other contracts with governmental entities.

The Company's operations may also be adversely affected by laws and policies of Canada and Egypt affecting foreign trade, taxation and investment. In the event of a dispute arising in connection with the Company's operations in Egypt, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdictions of the courts of Canada or enforcing Canadian judgments in such other jurisdictions. The Company may also be hindered or prevented from enforcing its rights with respect to a governmental instrumentality because of the doctrine of sovereign immunity. Accordingly, the Company's exploration, development and production activities in Egypt could be substantially affected by factors beyond the Company's control, any of which could have a material adverse effect on the Company.

If the Company's operations are disrupted and/or the economic integrity of its projects are threatened for unexpected reasons, its business may be harmed. These unexpected events may be due to technical difficulties, operational difficulties which impact the production, transport or sale of the Company's products, security risks related to terrorist activities and insurrections, difficult geographic and weather conditions, unforeseen business reasons or otherwise. Prolonged problems may threaten the commercial viability of its operations.

The amount of future cash dividends paid by the Company, if any, will be subject to the discretion of the Board and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends. Depending on these and various other factors, many of which will be beyond the control of the Company, the dividend policy of the Company from time to time could be reduced or suspended entirely.

The market value of the Common Shares may deteriorate if cash dividends are reduced or suspended. Furthermore, the future treatment of dividends for tax purposes will be subject to the nature and composition of dividends paid by the Company and potential legislative and regulatory changes. Dividends may be reduced during periods of lower funds from operations, which result from lower commodity prices and any decision by the Company to finance capital expenditures or property acquisitions using funds from operations.

To the extent that external sources of capital, including the issuance of additional Common Shares, become limited or unavailable, the ability of the Company to make the necessary capital investments to maintain or expand petroleum and natural gas reserves and to invest in assets, as the case may be, will be impaired.

From time to time, the Company may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline. However, to the extent that the Company engages in price risk management activities to protect itself from commodity price declines, it may also be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, the Company's hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances in which:

On the other hand, failure to protect against decline in commodity prices exposes the Company to reduced liquidity when prices decline. A sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Company would enter into derivative contracts on future volumes. This could make such transactions unattractive, and, as a result, some or all the Company’s production volumes forecasted for 2020 and beyond may not be protected by derivative arrangements.

Similarly, from time to time the Company may enter into agreements to fix the exchange rate of C$ to US$ or other currencies in order to offset the risk of revenue losses if the C$ increases in value compared to other currencies. However, if the C$ declines in value compared to such fixed currencies, the Company will not benefit from the fluctuating exchange rate.

The Company is subject to relinquishment obligations under its title documents which oblige the Company to relinquish certain proportions of its concession lease and licence areas and thereby reduce the Company’s acreage. Additionally, the Company may be unable to drill all of its prospects or satisfy its minimum work commitments prior to relinquishment and may be unable to meet its obligations under the title documents. Failure to meet such obligations could result in concessions, leases and licences being suspended, revoked or terminated which could have a material adverse effect on the Company's business.

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 Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, the reserves from the Company's assets, and the production from them, will decline over time as the Company produces from such reserves. The Company's participation in the West Gharib, West Bakr, NW Gharib, S Ghazalat, and South Alamein production sharing contracts in Egypt represent major undertakings. The exploration programs in Egypt are high-risk ventures with uncertain prospects for ongoing success. A future increase in the reserves attributable to the Company's assets will depend on both the ability of the Company to explore and develop the Company's assets and its ability to select and acquire suitable producing properties or prospects. There is no assurance that the Company will be able to find satisfactory properties to acquire or participate in. Moreover, management of the Company may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participations uneconomic. There is also no assurance that the Company will discover or acquire further commercial quantities of oil and natural gas.

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) as well as skilled personnel trained to use such equipment in the areas where such activities will be conducted. Demand for such limited equipment and skilled personnel, or access restrictions, may affect the availability of such equipment and skilled personnel to the Company and may delay exploration and development activities.

Oil and natural gas production operations are also subject to geological and seismic risks, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

As is standard industry practice, the Company is not fully insured against all risks, nor are all risks insurable. Although the Company maintains liability insurance and business interruption insurance in an amount that it considers consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered. See "Risk Factors - Insurance". In either event, the Company could incur significant costs.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of applicable laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites.

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Although the Company believes that it will be in material compliance with current applicable environmental legislation related to the Company's assets, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

In addition, some the Company’s properties have been operated by predecessors or previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under the Company’s control. Joint and several strict liabilities may be incurred in connection with such releases of petroleum hydrocarbons, hazardous substances and wastes on, under or from the Company’s properties. Private parties, including lessors of properties on which the Company operates and the owners or operators of properties adjacent to the Company’s operations and facilities where the Company’s petroleum hydrocarbons, hazardous substances or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as seek damages for noncompliance with environmental laws and regulations or for personal injury or damage to property or natural resources. Such properties and the substances disposed or released on or under them may be subject to laws which could require the Company to remove previously disposed substances, wastes and petroleum hydrocarbons, remediate contaminated property or perform remedial or closure operations to prevent future contamination, the cost of which could have a material adverse effect on the Company’s business, financial condition and results of operations. The Company may not be able to recover some or any of these costs from sources of contractual indemnity or insurance, as pollution and similar environmental risks generally are not insurable or fully insurable, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance.

Although the Company believes that it is in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

Climate change concerns could result in increased operating costs and reduced demand for the Company’s products or securities, while the potential physical effects of climate change could disrupt the Company’s production and cause it to incur significant costs in preparing for or responding to those effects.

Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing public, government and investor attention is being paid to global climate issues and to emissions of greenhouse gases, including emissions of carbon dioxide and methane from the production and use of crude oil, NGLs and natural gas.

Foreign and domestic governments continue to evaluate and implement policy, legislation and regulations focused on restricting emissions commonly referred to as greenhouse gas (GHG) emissions and promoting adaptation to climate change and the transition to a low-carbon economy. See "Industry Conditions – Climate Change Regulation" for more information. Given the evolving nature of climate change policy and the control of GHG and resulting requirements, it is expected that current and future climate change regulations will have the effect of increasing the Company’s operating expenses, and, in the long-term, potentially reducing the demand for oil and natural gas and related products, resulting in a decrease in the Company’s profitability and a reduction in the value of its assets. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulation", "Risk Factors – Non-Governmental Organizations", and "Risk Factors – Reputational Risk".

Claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under certain laws or that such energy companies provided misleading disclosure to the public and investors of current or future risks associated with climate change. As a result, individuals, government authorities or other organizations may make claims against oil and gas companies, including the Company, for alleged personal injury, property damage, or other potential liabilities. While the Company is not a party to any such litigation or proceedings, it could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely affect the demand for and price of securities issued by the Company, impact its operations and have an adverse impact on its financial condition.

Given the perceived elevated long-term risks associated with regulatory changes or other market developments related to climate change, there have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other institutional investors, promoting direct engagement and dialogue with companies in their portfolios on climate change action (including exercising their voting rights on matters relating to climate change) and increased capital allocation to investments in low-carbon assets and businesses while decreasing the carbon intensity of their portfolios through, among other measures, divestments. Certain stakeholders have also pressured commercial and investment banks to reduce or stop financing oil and gas and related infrastructure projects. The impact of such efforts require the Company’s management to dedicate significant time and resources to these climate change related concerns, may adversely affect the Company’s operations, the demand for and price the Company’s securities and may negatively impact the Company’s cost of capital and access to the capital markets.

The Company is committed to improving the transparency and reporting of its sustainability performance, and will consider existing standards such as the Global Reporting Initiative Sustainability Reporting Standards, the Sustainability Accounting Standards Board’s documentation, and recommendations issued by the Task Force for Climate Related Financial Disclosures. If the Company is not able to meet future sustainability reporting requirements of regulators or current and future expectations of investors or other stakeholders, its business and ability to attract and retain skilled employees, obtain regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities and raise capital may be adversely affected.

Based on the Company’s current understanding, the potential physical risks resulting from climate change are long-term in nature associated with a high degree of uncertainty regarding timing, scope and severity of potential impacts. Unlike certain large multi-national, integrated energy companies, the Company does not conduct fundamental research regarding the scientific inquiry of climate change. However, many experts believe global climate change could increase extreme variability in weather patterns such as increased frequency of severe weather, rising mean temperature and sea levels, and long-term changes in precipitation patterns. Extreme hot and cold weather, heavy snowfall, heavy rainfall and wildfires may restrict the Company’s ability to access its properties and cause operational difficulties, including damage to equipment and infrastructure. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions.

From time to time, the Company provides forecasts of expected quantities of future crude oil, NGLs and natural gas production and other financial and operating results. These forecasts are based on a number of estimates and assumptions, including that none of the risks associated with the Company’s operations summarized in this Annual Information Form materialize. Production forecasts, specifically, are based on assumptions such as:

Shareholders and prospective investors are cautioned not to place undue reliance on the Company's 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.

The Company has become increasingly dependent upon the availability, capacity, reliability and security of its information technology infrastructure and its ability to expand and continually update this infrastructure, to conduct daily operations. The Company depends on various information technology systems to estimate reserves quantities, process and record financial data, manage the Company’s land base, manage financial resources, analyze seismic information, administer contracts with operators and lessees and communicate with employees and third-party partners.

Further, the Company is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Company’s information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to business activities or the Company’s competitive position. In addition, cyber-phishing attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, and credit card details (and money) by disguising as a trustworthy entity in an electronic communication, have become more widespread and sophisticated in recent years.

Increasingly, social media is used as a vehicle to carry out cyber-phishing attacks. Information posted on social media sites, for business or personal purposes, may be used by attackers to gain entry into the Company’s systems and obtain confidential information. The Company restricts the social media access of its employees and periodically reviews, supervises, retains and maintains the ability to retrieve social media content. Despite these efforts, as social media continues to grow in influence and access to social media platforms becomes increasingly prevalent, there are significant risks that the Company may not be able to properly regulate social media use and preserve adequate records of business activities.

If the Company becomes a victim to a cyber-phishing attack it could result in a loss or theft of the Company's financial resources or critical data and information or could result in a loss of control of the Company's technological infrastructure or financial resources. The Company’s employees are often the targets of such cyber-phishing attacks, as they are and will continue to be targeted by parties using fraudulent "spoof" emails to misappropriate information or to introduce viruses or other malware through "Trojan horse" programs to the Company’s computers. These emails appear to be legitimate emails, but direct recipients to fake websites operated by the sender of the email or request recipients to send a password or other confidential information through email or to download malware.

The Company maintains policies and procedures that address and implement employee protocols with respect to electronic communications and electronic devices and conducts regular cyber-security risk assessments and training and education programs for its employees. The Company also employs encryption protection of its confidential information on all computers and other electronic devices. Despite the Company’s efforts to mitigate such cyber-phishing attacks through education and training, cyber-phishing activities remain a serious problem that may damage its information technology infrastructure. The Company applies technical and process controls in line with industry-accepted standards to protect its information, assets and systems, including a written incident response plan for responding to a cyber-security incident. However, these controls may not adequately prevent cyber-security breaches. Disruption of critical information technology services, or breaches of information security, could have a negative effect on the Company's performance and earnings, as well as its reputation, and any damages sustained may not be adequately covered by the Company’s current insurance coverage, or at all. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Company’s business, financial condition and results of operations.

Beyond the risks inherent in the petroleum industry, the Company is subject to additional political risks resulting from doing business in Egypt. Since 2011, there has been significant civil unrest and widespread protests and demonstrations throughout the Middle East, including Egypt. Abdel Fattah el-Sisi was elected President of Egypt in 2014 following several years of widespread protests, demonstrations and civil unrest. Since this time, political

and economic stability has returned to the country leading to a positive impact in business confidence. As a result of this political and economic stability, on 11 November 2016, the International Monetary Fund ("IMF") approved a three-year, US$12 billion extended arrangement under the Extended Fund Facility with Egypt to support the Egyptian authorities' proposed economic reform.

To date, Egypt has received approximately US$11.9 billion in funds from the IMF. The IMF noted that the Egyptian government achieved its main objectives under the program, and that the Egyptian economy has “improved markedly since 2016, supported by the authorities’ strong ownership of their reform program and decisive upfront policy actions”. Although inflation remains high in Egypt, certain economic reform policies have led to Egypt's CPI inflation falling to approximately 10.8% at the end of 2019. Inflation in Egypt remains highly volatile leading to significant economic impacts over which the Company does not have control, including but not limited to, living costs, operational costs, transportation costs, employment levels, borrowing/lending rates and currency valuation. The Company cannot predict the impact of inflation on oil and natural gas products, and any major changes may have a material adverse effect on the Company's business, financial condition, results of operations and cash flows by decreasing the Company's profitability, increasing its costs, limiting its access to capital and decreasing the value of its assets.

The Company’s business, operations or financial condition may be negatively impacted as a result of any negative public opinion towards the Company or as a result of any negative sentiment toward, or in respect of, the Company's reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups' negative portrayal of the industry in which the Company operates as well as their opposition to certain oil and natural gas projects. Potential impacts of negative public opinion or reputational issues may include delays or interruptions in operations, legal or regulatory actions or challenges, blockades, increased regulatory oversight, reduced support for, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses and increased costs and/or cost overruns. The Company’s reputation and public opinion could also be impacted by the actions and activities of other companies operating in the oil and natural gas industry, particularly other producers, over which the Company has no control. Similarly, the Company's reputation could be impacted by negative publicity related to loss of life, injury or damage to property and environmental damage caused by the Company’s operations. In addition, if the Company develops a reputation of having an unsafe work site, it may impact the ability of the Company to attract and retain the necessary skilled employees and consultants to operate its business. Opposition from special interest groups opposed to oil and natural gas development and the possibility of climate related litigation against governments and fossil fuel companies may impact the Company’s reputation. See "Risk Factors - Climate Change".

Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, regulatory and legal risks, among others, must all be managed effectively to safeguard the Company’s reputation. Damage to the Company’s reputation could result in negative investor sentiment towards the Company, which may result in limiting the Company’s access to capital, increasing the cost of capital, and decreasing the price and liquidity the Company’s securities.

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

The Company's lenders use the Company's reserves, commodity prices, applicable discount rate and other factors to periodically determine the Company's borrowing base. Commodity prices continue to be depressed and have fallen dramatically since 2014. Commodity prices are volatile as a result of various factors including actions taken to limit OPEC and non-OPEC production and increasing production by U.S. shale producers. Depressed commodity prices could reduce the Company's borrowing base credit facilities, reducing the funds available to the Company under its credit facilities. This could result in the requirement to repay a portion, or all, of the Company's indebtedness.

If the Company's lenders require repayment of all or a portion of the amounts outstanding under its credit facilities for any reason, including for a default of a covenant or the reduction of a borrowing base, there is no certainty that the Company would be in a position to make such repayment. Even if the Company is able to obtain new financing in order to make any required repayment under its credit facilities, it may not be on commercially reasonable terms or terms that are acceptable to the Company. If the Company is unable to repay amounts owing under credit facilities, the lenders under the credit facilities could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness.

The Supreme Court of Canada's decision in Redwater may give rise to new covenants and restrictions under the Company’s Canadian credit facility, should LMR levels fall below existing agreed-upon thresholds, including further limitations on asset dispositions and acquisitions. The Company may also be required to provide additional reporting to its lenders regarding its existing and/or budgeted abandonment and reclamation obligations, its decommissioning expenses, its LMR and/or any notices or orders received from an energy regulator in any applicable province. See also "Industry Conditions - Environmental Regulation - Liability Management Rating Program".

Historically, the Company's capital and operating costs have risen during periods of increasing commodity prices. These cost increases result from a variety of factors beyond the Company's control. Increased levels of drilling activity in the petroleum industry in recent periods has led to increased costs of certain drilling equipment, materials and supplies. Such costs may rise faster than increases in the Company's revenue, thereby negatively affecting its profitability, cash flow and ability to complete development activities as scheduled and on budget.

Future oil and natural gas exploration may involve unprofitable efforts from dry wells as well as from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, completing (including hydraulic fracturing), operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.

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 approvals or consents, and shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, it is not possible to eliminate production delays and declines from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.

The operations and management of the Company require the recruitment and retention of a skilled workforce, including engineers, technical personnel and other professionals. The loss of key members of such workforce, or a substantial portion of the workforce as a whole, could result in the failure to implement the Company’s business plans which could have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

Competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Company will be able to continue to attract and retain all personnel necessary for the development and operation of its business. The Company does not have any key personnel insurance in effect. Contributions of the existing management team to the immediate and near term operations of the Company are likely to be of central importance. In addition, certain of the Company’s current employees are senior and have significant institutional knowledge that must be transferred to other employees prior to their departure from the workforce. If the Company is unable to: (i) retain current employees; (ii) successfully complete effective knowledge transfers; and/or (iii) recruit new employees with the requisite knowledge and experience, the Company could be negatively impacted. In addition, the Company could experience increased costs to retain and recruit these professionals.

Effective internal controls are necessary for the Company to provide reliable financial reports and to help prevent fraud. Although the Company will undertake a number of procedures in order to help ensure the reliability of its financial reports, including those imposed on it under Canadian securities laws, U.S. securities laws and under the AIM Rules for Companies, the Company cannot be certain that such measures will ensure that the Company will maintain adequate control over financial processes and reporting. Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm the Company’s results of operations or cause it to fail to meet its reporting obligations. If the Company or its independent auditors discover a material weakness, the disclosure of that fact, even if quickly remedied, could reduce the market’s confidence in the Company’s financial statements and harm the trading price of the Common Shares.

The Company may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In addition, the Company may be exposed to third party credit risk from operators of properties in which the Company has a working or royalty interest. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry, generally, and the Company’s joint venture partners may affect a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner.

The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company is unable to predict changes in a counterparty's creditworthiness or ability to perform. Even if the Company accurately predicts the sudden changes, the Company's ability to negate the risk may be limited depending upon market conditions and the contractual terms of the transactions. During periods of declining commodity prices, the Company's derivative receivable positions generally increase, which increases the Company’s counterparty credit exposure.

To the extent that any of such third-parties go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in the Company being unable to collect all or a portion of any money owing from such parties. Any of these factors could materially adversely affect the Company's financial and operational results.

The Company's involvement in the exploration for and development of oil and natural gas properties may result in the Company becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property damage, personal injury or other hazards. Although the Company maintains insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities. In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, the Company may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment

of any uninsured liabilities would reduce the funds available to the Company. The occurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

In the normal course of the Company's operations, it 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 personal injuries, property damage, property tax, land rights, the environment and contract disputes. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to the Company and as a result, could have a material adverse effect on the Company's assets, liabilities, business, financial condition and results of operations. Even if the Company prevails in any such legal proceedings, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from business operations, which could have an adverse effect on the Company's financial condition.

In Canada, liabilities in respect of the decommissioning of its wells, fields and related infrastructure are derived from legislative and regulatory requirements concerning the decommissioning of wells and production facilities and require the Company to make provisions for and/or underwrite the liabilities relating to such decommissioning. It is difficult to accurately forecast the costs that the Company would incur in satisfying any decommissioning obligations. When such decommissioning liabilities crystallize, the Company would be liable either on its own or jointly and severally liable for them with any other former or current partners in the field. In the event that it is jointly and severally liable with other partners and such partners default on their obligations, the Company would remain liable and its decommissioning liabilities could be magnified significantly through such default. Any significant increase in the actual or estimated decommissioning costs that the Company incurs may adversely affect its financial condition.

In Egypt, under model concession agreements and the Fuel Material Law, liabilities in respect of decommissioning movable and immovable assets (other than wells) passes to the Egyptian Government through the transfer of ownership from the contractor to the government under the cost recovery process. While the current risk to the Company of becoming liable for decommissioning liabilities in Egypt is low, future changes to legislation could result in decommissioning liabilities in Egypt. Any increase in Egyptian decommissioning liabilities could adversely affect the Company's financial condition.

In relation to petroleum wells, the contractor is responsible for decommissioning non-producing wells under a decommissioning plan approved by EGPC. If EGPC agrees that a producing well is not economic, then the contractor will be responsible for decommissioning the well under an EGPC approved decommissioning plan. EGPC, at its own discretion, may not require a well to be decommissioned if it wants to preserve the ability to use the well for other purposes. As EGPC has discretion on decommissioning wells, there is a risk that the Company could incur well decommissioning costs. In accordance with the respective concession agreements, expenses approved by EGPC are recoverable through the cost recovery mechanism.

World oil and natural gas prices are quoted in US$. The Company's exposure to currency exchange rate risks is primarily limited to Canadian general and administrative expenses which are paid for in C$, British pound sterling and Egyptian pound cash balances. A low value of the Canadian dollar relative to the United States dollar, British pound sterling and Egyptian pound may positively affect the price the Company receives for its oil and natural gas production, it could also result in an increase in the price for certain goods used for the Company's operations, which may have a negative impact on the Company's financial results. The Company prepares its financial statements in US$ and, as a result, the Company's statement of comprehensive income, statement of cash flows and statement of financial position are impacted by changes in exchange rates between C$, British pound sterling, Egyptian pounds and US$.

To the extent that the Company engages in risk management activities related to foreign exchange rates, there is a credit risk associated with counterparties with which the Company may contract.

An increase in interest rates could result in a significant increase in the amount the Company pays to service debt, resulting in a reduced amount available to fund its exploration and development activities, and if applicable, the cash available for dividends and could negatively impact the market price of the Common Shares.

From time to time, the Company may enter into transactions to acquire assets or shares of other entities. These transactions may be financed in whole or in part with debt, which may increase the Company's debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, the Company may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither the Company's articles nor its by-laws limit the amount of indebtedness that the Company may incur. The level of the Company's indebtedness from time to time could impair the Company's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

The Common Shares trading on the AIM are denominated in British Pounds whereas the Common Shares trading on the TSX are in Canadian dollars and on the Nasdaq in United States dollars. Fluctuations in the exchange rate between the currencies, including the pound sterling, will affect the value of the Common Shares and any dividends the Company may declare in the future, denominated in the local currency of investors outside of Canada.

AIM is a market designed primarily for emerging or smaller growing companies which carry a higher than normal financial risk and tend to experience lower levels of liquidity than larger companies. Accordingly, AIM may not provide the liquidity normally associated with the Official List of the UK Listing Authority (the "Official List") or some other stock exchanges. The Common Shares may therefore be difficult to sell compared to the shares of companies listed on the Official List and the share price may be subject to greater fluctuations than might otherwise be the case. An investment in shares traded on AIM carries a higher risk than those listed on the Official List.

There can be no guarantee that the Common Shares will trade at the same price on the TSX, AIM and Nasdaq. Due to different investor sentiments, liquidity levels, transaction costs, taxation rates, regulations or foreign exchange rates. Additionally, TSX, AIM and Nasdaq operate in different time zones and, for instance, news flow from external sources such as regulatory regime changes which affect the Company may be acted upon earlier by an investor on one market ahead of the other.

During the AIM admission process, the Board engaged brokers in both Canada and the UK to manage the migration of shares between the registers kept in Canada and the UK, but there can be no guarantee that this arrangement will eliminate all arbitrage opportunities between the shares traded on the TSX and AIM or that such procedures will be effective.

Recent models of the Egyptian concession agreement in Egypt include restrictive wording that require the government's consent for any direct or "indirect" assignment of rights under the concession, which could be interpreted to include acquiring the voting or equity shares of the contractor party to an Egyptian concession. The government's position on the matter is neither clear nor unified, raising ambiguity and the risk that an executed assignment offshore could be revisited by the government and EGPC. If so revisited, this could result in the contractor being required to obtain the government's consent to deeds of assignment, liability for assignment bonuses and/or the government seeking termination for breach of the concession agreement. There are no reported cases of a concession being terminated on such grounds. The Company considers the continued communication, correspondences and dealings subsequent to the completion of the Company's acquisition as limiting the probability that such risks will materialize. To date, EGPC has recognized and dealt with the Company as though no such approval was required or, if required, was deemed to have been given by EGPC at the time of the transaction.

The Company is not required under Canadian law to offer new Common Shares to existing Shareholders on a pre-emptive basis as is required of companies incorporated under the UK Companies Act 2006. As such, it may not be possible for existing Shareholders to participate in future share issues, which may dilute an existing Shareholder’s interest in the Company. However, there are various protections afforded to Shareholders as a result of Canadian securities laws. Additionally, the Company and the Board have undertaken to Canaccord Genuity Limited, its UK Nominated Advisor, that for as long as the Common Shares remain quoted on AIM, the Company will obtain approval by special resolution for issuance of Common Shares in certain circumstances. Shareholders not participating in future offerings may be diluted. The Company may in the future issue options and/or warrants to subscribe for new Common Shares, including (without limitation) to certain advisers, employees, directors, senior management and consultants. The exercise of such warrants and/or options would result in dilution of the shareholdings of other investors.

The Company is not subject to the provisions of the UK City Code on Takeovers and Mergers and it is emphasized that, although the Common Shares are trading on AIM, the Company will not be subject to takeover regulation in the UK. However, Canadian laws applicable to the Company provide for early warning disclosure requirements and for takeover bid rules for bids made to security holders in various jurisdictions in Canada.

The Company is continued under the laws of the Province of Alberta, Canada, and as at March 12, 2020 the majority of the Company's directors are residents of Canada and all of its officers are residents of the United Kingdom. Consequently, it may be difficult for investors from outside of Canada, to effect service of process upon the Company or upon those directors or officers, or to realize judgments of non-Canadian courts. Furthermore, it may be difficult for non-Canadian investors to enforce judgments of non-Canadian courts based on civil liability provisions of the non-Canadian securities laws in a Canadian court against the Company or any of the Company's Canadian resident directors. There is substantial doubt whether an original lawsuit could be brought successfully in Canada against any of such persons or the Company predicated solely upon such non-Canadian civil liabilities.

The Company currently conducts the majority of its operations through its foreign subsidiaries and foreign branches. Therefore, the Company could be dependent on the cash flows of these subsidiaries to meet its obligations. The ability of its subsidiaries to make payments to the Company may be constrained by, among other things: the level of taxation, particularly corporate profits and withholding taxes, in the jurisdictions in which it operates; the introduction of exchange controls or repatriation restrictions or the availability of hard currency to be repatriated; and contractual restrictions with third parties. For example, certain governments have imposed a number of monetary and currency exchange control measures that include restrictions on the free disposition of funds deposited with banks and tight restrictions on transferring funds abroad, with certain exceptions for transfers related to foreign trade and other authorized transactions approved by a country's central bank. These central banks may require prior authorization and may or may not grant such authorization for the Company's foreign subsidiaries to transfer funds to it and there may be a tax imposed with respect to the expatriation of the proceeds from the Company's foreign subsidiaries.

Although title reviews may be conducted in Canada prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise. Due in part to the nature of property rights development historically in Canada as well as the common practice of splitting legal and beneficial title, public registries are not determinative of actual rights held by parties. Further, the fragmented nature of oil and gas rights, which may be held by the government or private individuals and companies, and may be split among a great number of different granting documents, means that despite best efforts of parties, latent defects may not be immediately discoverable. As such, the actual interest of the Company in properties may accordingly vary from the Company's records. If a title defect does exist, it is possible that the Company may lose all or a portion of the properties to which the title defect relates, which may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. There may be valid challenges to title or legislative changes, which affect the Company's title to the oil and natural gas properties the Company controls in Canada that could impair the Company's activities on them and result in a reduction of the revenue received by the Company.

As the Company is engaged in the Canadian petroleum industry, its operations are subject to certain unique provisions of the Income Tax Act (Canada) (the "Tax Act") Canadian Tax Act and applicable provincial income tax legislation relating to characterization of costs incurred in its business which effects whether such costs are deductible and, if deductible, the rate at which they may be deducted for the purposes of calculating taxable income. The Company files all required income tax returns and believes that it is in full compliance with the provisions of the Tax Act and all other applicable provincial tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment of the Company, 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 natural 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 Company. Furthermore, tax authorities having jurisdiction over the Company may disagree with how the Company calculates its income for tax purposes or could change administrative practices to the Company's detriment.

There can be no assurance that the governments in the jurisdictions in which the Company has assets will not adopt new royalty regimes, or modify the existing royalty regimes, which may have an impact on the economics of the Company's projects. An increase in royalties would reduce the Company's earnings and could make future capital investments, or the Company's operations, less economic. See "Industry Conditions - Royalties and Incentives".

In order to conduct oil and natural gas operations, the Company will require regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities at the municipal, provincial and federal level. There can be no assurance that the Company will be able to obtain all of the permits, licenses, registrations, approvals and authorizations that may be required to conduct operations that it may wish to undertake in the time required or on terms and conditions acceptable to the Company. Any failure to renew, maintain or obtain the required permits, licences, registrations, approvals and authorizations or the revocation or termination of existing permits, licences, registrations, approvals and authorizations, may disrupt the Company’s operations and could have a material adverse effect on the Company’s business, financial position and results of operations.

Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including exploration, development, production, pricing, marketing and transportation). 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 Company's costs, either of which may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under high pressure into tight rock formations that were previously unproductive to stimulate the production of crude oil, NGLs and natural gas. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase the Company's costs of compliance and doing business, as well as delay the development of oil and natural gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that the Company is ultimately able to produce from its reserves.

Water is an essential component the Company’s Canadian drilling and hydraulic fracturing processes. Limitations or restrictions on the Company’s ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought), could materially and adversely impact its operations. Severe drought conditions can result in local water authorities taking steps to restrict the use of water in their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If the Company is unable to obtain water to use in its operations from local sources, it may need to be obtained from new sources and transported to drilling sites, resulting in increased costs, which could have a material adverse effect on its financial condition, results of operations and cash flows.

In addition, the Company must dispose of the fluids produced from oil and gas production operations, including produced water, which it does directly or through the use of third-party vendors. The legal requirements related to the disposal of produced water into a non-producing geologic formation

by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities.

Government authorities may issue orders to temporarily shut down or to curtail the injection depth of existing wells in the vicinity of seismic events. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated laws and regulations regarding waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by the Company or by commercial disposal well vendors that the Company may use from time to time to dispose of produced water. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and gas activities utilizing injection wells for produced water disposal. Any one or more of these developments may result in the Company or its vendors having to limit disposal well volumes, disposal rates and pressures or locations, or require the Company or its vendors to shut down or curtail the injection of produced water into disposal wells, which events could have a material adverse effect on the Company’s business, financial condition and results of operation.

Alberta has developed liability management programs designed to prevent taxpayers from incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder is unable to satisfy its regulatory obligations. Changes to the Alberta LMR Program administered by the AER, or other changes to the requirements of liability management programs, may result in significant increases to the Company’s compliance obligations. The impact and consequences of the Supreme Court of Canada's decision in Redwater on the AER's rules and policies, lending practices in the crude oil and natural gas sector and on the nature and determination of secured lenders to take enforcement proceedings are expected to evolve as the consequences of the decision are evaluated and considered by regulators, lenders and receivers/trustees. In addition, the Alberta LMR Program may prevent or interfere with the Company’s ability to acquire or dispose of assets, as both the vendor and the purchaser of oil and natural gas assets must be in compliance with the liability management programs (both before and after the transfer of the assets) for the applicable regulatory agency to allow for the transfer of such assets. See "Industry Conditions - Liability Management Rating Program".

Certain directors or officers of the Company may also be directors or officers of other oil and natural gas companies and as such may, in certain circumstances, have a conflict of interest. Conflicts of interest, if any, will be subject to and governed by procedures prescribed by the ABCA which require a director of officer of a corporation who is a party to, or is a director or an officer of, or has a material interest in any person who is a party to, a material contract or proposed material contract with the Company to disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under the ABCA.

The oil and natural gas exploration, development and operating activities conducted by the Company may, at times, be subject to public opposition. Such public opposition could expose the Company to the risk of higher costs, delays or even project cancellations due to increased pressure on governments and regulators by special interest groups including Aboriginal groups, landowners, environmental interest groups (including those opposed to oil and natural gas production operations) and other non-governmental organizations, blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced support of the federal, provincial or municipal governments, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses, and direct legal challenges, including the possibility of climate-related litigation. There is no guarantee that the Company will be able to satisfy the concerns of the special interest groups and non-governmental organizations and attempting to address such concerns may require the Company to incur significant and unanticipated capital and operating expenditures.

In addition, the Company's oil and natural gas properties, wells and facilities could be the subject of a terrorist attack. If any of the Company's properties, wells or facilities are the subject of terrorist attack it may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. The Company does not have insurance to protect against the risk from terrorism.

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Company's securities and options to purchase securities, if applicable, is contained in the Company's Information Circular for the most recent annual meeting of Shareholders that involved the election of directors. Additional financial information is provided for in the Company's financial statements and the management's discussion and analysis for the year ended December 31, 2019. These documents, along with other documents affecting the rights of securityholders and other information relating to the Company, may be found on SEDAR at www.sedar.com and in the Company's Annual Report on Form 40-F for the fiscal year ended December 31, 2019, filed on EDGAR at www.sec.gov.

Management of TransGlobe Energy Corporation (the "Company") are responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data.

An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the independent qualified reserves evaluator is presented in Schedule A of this Annual Information Form.

The Reserves Committee of the Board of Directors has reviewed the Company'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

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

Our Audit Committee Charter outlines the specific roles and duties of the Committee’s members.

The Audit Committee is a committee of the Board of Directors appointed to assist the Board in monitoring (1) the integrity of the financial statements of the Company, (2) compliance by the Company with legal and regulatory requirements related to financial reporting, (3) qualifications, independence and performance of the Company's independent auditors, (4) performance of the Company’s accounting, internal controls and financial reporting process and monitoring business risks.

The Audit Committee has the power to conduct or authorize investigations into any matters within its scope of responsibilities, with full access to all books, records, facilities and personnel of the Company, its auditors and its legal advisors. In connection with such investigations or otherwise in the course of fulfilling its responsibilities under this charter, the Audit Committee has the authority to independently retain special legal, accounting, or other consultants to advise it, and may request any officer or employee of the Company, its independent legal counsel or independent auditor to attend a meeting of the Audit Committee or to meet with any members of, or consultants to, the Audit Committee. In its capacity as a committee of the Board of Directors, the Audit Committee has the power to determine the amount of Company funds that are appropriate for payment of (1) compensation to the Company’s independent auditor engaged for the purpose of preparing audit reports and performing other audit and non-audit services, (2) independent counsel and other advisers as it determines necessary to carry out its duties and (3) ordinary administrative expenses as it determines necessary to carry out its duties. The Audit Committee also has the power to create specific sub-committees with all of the investigative powers described above.

The Board of Directors and Audit Committee, as representatives of the Company's shareholders, have the ultimate authority and responsibility to retain and evaluate the independent auditor, to nominate annually the independent auditor to be proposed for shareholder approval and to determine appropriate compensation for the independent auditor. In the course of fulfilling its specific responsibilities hereunder, the Audit Committee must maintain free and open communication between the Company's independent auditors, Board of Directors and Company management. The responsibilities of a member of the Audit Committee are in addition to such member's duties as a member of the Board of Directors.

While the Audit Committee has the responsibilities and powers set forth in this charter, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company's financial statements are complete, accurate, and in accordance with generally accepted accounting principles. This is the responsibility of management. Nor is it the duty of the Audit Committee to conduct investigations, to resolve disagreements, if any, between management and the independent auditor (other than disagreements regarding financial reporting), or to assure compliance with laws and regulations or the Company's own policies.

		Page

ABBREVIATIONS		3
CONVERSIONS		3
CURRENCY AND EXCHANGE RATES		4
FORWARD-LOOKING STATEMENTS		4
NON-GAAP MEASURES		6
CERTAIN DEFINITIONS		6
TRANSGLOBE ENERGY CORPORATION		8
GENERAL DEVELOPMENT OF THE BUSINESS		9
DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES		10
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION		16
DIVIDEND POLICY		33
DESCRIPTION OF CAPITAL STRUCTURE		33
MARKET FOR SECURITIES		34
PRIOR SALES		35
ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER		35
DIRECTORS AND OFFICERS		36
INTERESTS OF EXPERTS		37
LEGAL PROCEEDINGS AND REGULATORY ACTIONS		38
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		38
TRANSFER AGENT AND REGISTRAR		38
MATERIAL CONTRACTS		38
AUDIT COMMITTEE INFORMATION		39
CANADIAN INDUSTRY CONDITIONS		41
RISK FACTORS		52
ADDITIONAL INFORMATION		65

SCHEDULE "A"	Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor
SCHEDULE "B"	Report of Management and Directors on Oil and Gas Disclosure
SCHEDULE "C"	Charter of Audit Committee


To Convert From	To	Multiply By
Mcf	cubic metres	0.28174
cubic metres	cubic feet	35.494
bbls	cubic metres	0.159
cubic metres	bbls oil	6.293
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
gigajoules	MMBtu	0.950

	2019	2018	2017
End of Period	C$1.30	C$1.36	C$1.25
Period Average	C$1.33	C$1.30	C$1.30


Name of TPI Subsidiary	Purpose	Jurisdiction of Incorporation	Ownership
TransGlobe West Gharib Inc.	Owns TransGlobe's interest in the West Gharib concession in Egypt.	Turks & Caicos Islands, B.W.I.	100%
TransGlobe West Bakr Inc.	Owns TransGlobe's interest in the West Bakr concession in Egypt.	Turks & Caicos Islands, B.W.I.	100%
TG NW Gharib Inc.	Owns TransGlobe's interest in the NW Gharib concession in Egypt.	Turks & Caicos Islands, B.W.I.	100%
TG S Ghazalat Inc.	Owns TransGlobe's interest in the S Ghazalat concession in Egypt.	Turks & Caicos Islands, B.W.I.	100%

		Future Net Revenue Before Taxes^3,4 (discounted at 10%/year)		Unit Value Before Tax^3,4 (discounted at 10%/year)
Reserves Category	Product Type	(US$MM)		($/Boe)
Total Proved	Light & Medium Crude Oil¹		87.3		12.51
	Heavy Crude Oil¹		109.8		16.08
	Conventional Natural Gas²		3.2		1.45
Proved+Probable	Light & Medium Crude Oil¹		134.2		10.81
	Heavy Crude Oil¹		156.2		14.23
	Conventional Natural Gas²		7.9		1.43
Proved+Probable +Possible	Light & Medium Crude Oil¹		176.3		10.96
	Heavy Crude Oil¹		202.7		13.24
	Conventional Natural Gas²		13.5		1.65


Oil and Natural Gas Liquids		Natural Gas

bbl	barrel	Mcf	thousand cubic feet
bbls	barrels	Mcf/d	thousand cubic feet per day
Mbbls	thousand barrels	MMcf/d	million cubic feet per day
MMbbls	million barrels	MMBtu	million British Thermal Units
bbls/d	barrels per day	Bcf	billion cubic feet
bopd	barrels of oil per day
Mbopd	thousand barrels of oil per day
NGLs	natural gas liquids

Other

boe	barrel of oil equivalent
boe/d	barrel of oil equivalent per day
MMboe	million barrels of oil equivalent
km²	square kilometres
m³	cubic metres
$M	thousands of dollars
$MM	millions of dollars
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

	Forecast Prices and Costs
	Proved Reserves		Proved Plus Probable Reserves
Year	(US$MM)		(US$MM)
2020		3.4		9.5
2021		7.8		13.1
2022		13.0		14.6
2023		11.3		13.6
2024		13.8		27.4
Remaining		—		43.2
Total Undiscounted		49.2		121.4
Discounted @ 10%		36.3		78.4

	Oil Wells								Natural Gas Wells
	Producing				Non-Producing				Producing				Non-Producing
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Egypt		113.0		112.7		105.0		104.9		—		—		—		—
Canada		63.0		60.4		15.0		13.7		60.0		53.6		20.0		15.7
Total		176.0		173.1		120.0		118.6		60.0		53.6		20.0		15.7

	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Egypt		25,035		25,035		—		—		25,035		25,035
Canada		10,050		8,629		36,332		33,197		46,382		41,826
Total		35,085		33,664		36,332		33,197		71,417		66,861

Ex-dividend date	Record date	Payment date	Per share amount
March 28, 2019	March 29, 2019	April 18, 2019	$0.035
August 30, 2019	August 31, 2019	September 13, 2019	$0.035

Date of Issuance		Number of Stock Options				Price per Stock Option
March 20, 2019			976,027			C$2.83

Name and Place of Residence	Independent	Financially Literate	Relevant Education and Experience
Steven Sinclair Alberta, Canada	Yes	Yes	Mr. Sinclair is a corporate director. Mr. Sinclair previously served as Senior Vice President and Chief Financial Officer of ARC Resources Ltd until his retirement in 2014 and is currently a director and chair of the audit committee of a Calgary headquartered private oil and gas Company. Mr. Sinclair has over 30 years of financial and operating experience. Mr. Sinclair received his Bachelor of Commerce degree from the University of Calgary in 1978 and his Chartered Accountant's designation in 1981.
Carol Bell London, England	Yes	Yes	Dr. Bell is an independent businesswoman and corporate director with over 35 years experience in the natural resources sector. Dr. Bell was Managing Director, Global Oil & Gas Group of Chase Manhattan Bank from 1997 - 1999. Prior thereto, Dr. Bell was Managing Director, Equity Research at JP Morgan from 1991 - 1997, Vice President, Equity Research Credit Suisse First Boston from 1990 - 1991, European Oil Analyst with UBS Phillips & Drew from 1986 - 1990, Commercial Executive with Charterhouse Petroleum plc 1983 - 1986 and Commercial Analyst with RTZ Oil & Gas Limited 1980 - 1983. Dr. Bell has a MA, Natural Sciences, BA Earth Sciences and a PhD Archeology.
Edward LaFehr Alberta, Canada	Yes	Yes	Mr. LaFehr is President and CEO of Baytex Energy Corporation. Mr. LaFehr has over 35 years experience in the oil and gas industry working with Amoco, BP, Talisman Energy Inc. and Abu Dhabi National Energy Company ("TAQA"), holding senior positions in North American, Europe and the Middle East regions. Prior to joining Baytex, Mr. LaFehr President of TAQA's North American oil and gas business based in Calgary and subsequently COO for TAQA, globally. Mr. LaFehr holds Masters degrees in geophysics and mineral economics from Stanford University and the Colorado School of Mines respectively.

	Fiscal Year Ended		Fiscal Year Ended
(U.S. dollars)	December 31, 2019		December 31, 2018
Audit Fees		476,745		356,370
Audit Related Fees		8,842		18,581
Tax Fees		119,213		21,983
TOTAL		604,799		396,934

GLJ PETROLEUM CONSULTANTS LTD

Per:	"Originally signed by"
	Leonard L. Herchen, P. Eng.
	Vice President
	GLJ Petroleum Consultants Ltd

Per:	(Signed) Randy C. Neely	Per:	(Signed) Edward LaFehr
	Randy Neely		Edward LaFehr
	President, Chief Executive Officer and Director		Director and Chair of the Reserves, Health Safety Environment and Social Responsibility Committee


Per:	(Signed) Geoff Probert	Per:	(Signed) David C. Cook
	Geoff Probert		David Cook
	Vice-President, Chief Operating Officer		Director and Chairman of the Board